The 7th U.S. Circuit Court of Appeals has tossed a temporary injunction against Indiana’s right of first refusal law and sent the case back to a lower court, leaving plaintiff LS Power with more work ahead of it to increase competitively bid transmission projects in MISO.
The court decided LS Power’s arguments were directed at the wrong party and said the company should have named MISO, not the Indiana Utility Regulatory Commission (IURC), as the source depriving it of the chance to bid on long-range transmission projects. The appeals court remanded the case to the district court that issued a preliminary injunction against the right of first refusal (ROFR) law and vacated the injunction (25-1024). The controversy again awaits proceedings from the U.S. District Court for the Southern District of Indiana.
The higher court concluded in its March 13 order that LS Power lacked standing to request the injunction because MISO is the entity responsible for assigning projects from its long-range transmission portfolios to developers. The court also said that because the preliminary injunction was meant for Indiana regulators alone, MISO isn’t beholden to the ban.
The case has raised questions about who administers Indiana’s ROFR law.
LS Power, a competitive transmission developer in MISO, has claimed for months that Indiana’s ROFR is unconstitutional and violates the dormant commerce clause by treating in-state developers differently from out-of-state developers. The company won a preliminary injunction barring Indiana regulators from enforcing the law in December 2024, days before MISO approved a $21.8 billion long range transmission plan for MISO Midwest, raising doubts on who could build projects in the state. (See “Indiana ROFR Reversal Complicates Project Assignment,” MISO Board Endorses $21.8B Long-range Transmission Plan.)
‘An Unusual Situation’
The 7th Circuit acknowledged the case presented “an unusual situation,” with gray area over whether IURC has the authority to enforce the state’s ROFR. It eventually sided with counsel for the Indiana commissioners, who said commissioners are powerless to designate or reassign developers to the regional transmission projects MISO plans and approves.
“Even the subsections of the statute that mention the IURC make clear that the IURC functions only as a notice repository, not as an enforcer of the rights of first refusal,” the court said of the IURC’s role in the ROFR. It said a “genuine redress would have to operate against” MISO.
However, the district court reasoned months before that because IURC enforces the ROFR, MISO would “no longer be permitted to recognize an incumbent’s right of first refusal” and would treat the law as void.
But the 7th Circuit said incumbents taking advantage of their right to first dibs on construction only file notices of intent and descriptions of construction with the state regulatory body, noting that they don’t ask permission.
Furthermore, the court said a preliminary injunction of a state law “does not change the applicability of the law in question to non-parties.”
MISO, meanwhile, has no intention of competitively bidding the Indiana share of its long-range transmission projects.
In an amicus brief in the case, MISO said it did not view itself as bound by the injunction, even though its tariff requires it to follow all applicable state laws. The RTO said the district court’s preliminary injunction “does not direct MISO to take any action, nor does it prohibit MISO from taking any action.”
The court agreed and said because LS Power named Indiana commissioners as defendants and failed to mention MISO in its request for injunctive relief, the company ensured the lower court “could not operate against MISO directly.”
LS Power has attempted to close that gap through FERC. The company in February filed a complaint against MISO, arguing the grid operator should be forced to obey preliminary injunctions of state laws and should open about $1 billion in new long-range transmission projects in Indiana for competitive solicitation. (See LS Power Files Complaint Against MISO over Indiana ROFR.)
The apparent uncertainty over the IURC’s authority drew a dissenting opinion from Circuit Judge Michael Scudder, who argued that ROFR enforcement can be traced to Indiana regulators. Scudder said Indiana law provides “every indication” that IURC has the power to prevent an incumbent transmission owner from building and operating a transmission project in the state.
“Everyone agrees that the commission is the regulatory agency with authority over public utilities in Indiana,” he wrote. “Everyone agrees that HEA 1420 is a law ‘relating to public utilities.’ … It defies belief that the Indiana General Assembly vested the commission with broad enforcement authority, but the commissioners are nevertheless powerless to impose any limitation on a utility company’s ability to construct, own, operate or maintain electric transmission facilities within the state. To adopt that view is to conclude that Indiana law does not mean what it says.”
Scudder said he would have affirmed the district court’s preliminary injunction.
But the 7th Circuit’s majority judges agreed that ordering the IURC to block construction of interstate, MISO-approved transmission lines “would force the IURC into a power struggle with FERC over whether legitimately assigned and important projects” could be built.
“The dissenting opinion would in effect conscript the IURC to enforce the dormant commerce clause rather than carry out its more general duties to enforce Indiana public utility laws,” the court said.
A key New Jersey Senate committee has backed two measures seeking to limit the energy that artificial intelligence data centers can take out of the transmission and distribution system.
Forecasts predict the state will struggle to meet a dramatic surge in electricity demand in the next two decades.
The Senate Environment and Energy Committee backed S4143, which would require power for data centers to be from clean energy sources or nuclear power plants, or a combination of both. It also requires “no net decrease of verifiable … renewable energy and energy from nuclear power plants supplied to the transmission and distribution system.”
The bill, which passed March 17 on a 3-2 party line vote, also would require that AI data centers seeking local permits submit an energy use plan to the New Jersey Board of Public Utilities (BPU) for approval.
In a separate 3-2 vote, the committee also backed a nonbinding resolution, SR125, that urges all states within the PJM region to “enact policies that will require data centers to obtain their electricity from new zero- or low-emission sources of energy.”
The two measures highlighted the state’s growing concern over handling the expected increase in data centers and AI facilities, as well as the conflicting desire to reap the economic benefits of the high-investment facilities.
Chairman Sen. Bob Smith (D), who co-sponsored the bill and the resolution, said after the hearing that data and AI centers consume 10 to 20 times as much energy as other facilities. While the state “would love to have them,” the centers need to pay their way, he said.
“These bills are designed to put some logic and sanity into future development in AI data,” he said. “My contention is that we, the ratepayers of New Jersey, shouldn’t be paying for them. We should require that they bring their own energy, not consume the energy we’re already using and the energy storage that we already paid for, the transmission lines that we already paid for. They need a bigger financial responsibility.”
He said he expects to promote the resolution to other states in the PJM region to pass similar resolutions and pressure PJM to comply.
Supply Shortfall
The committee’s vote followed the March 13 release of the first draft of the next state Energy Master Plan, which predicts a 66% increase in electricity demand by 2050 if the state pursues the same strategy outlined in the 2019 master plan. The new plan predicts much greater increases if the state follows one of the three suggested paths detailed in the plan, which advocates for greater electrification.
State and PJM officials say the dramatic future power imbalance stems from the slow pace of new energy sources coming online and the faster rate fossil fuel generators are closing. The expected development of data centers and AI facilities, with their heavy use of electricity, is another key driver of the demand surge. (See NJ Releases Electrification-focused Energy Master Plan.)
New Jersey officials say the supply shortfall is a key reason behind a 20% hike in residential electricity rates set to take effect in June as a result of a Basic Generation Service (BGS) auction in February. (See NJ Conference Confronts Electricity Demand Squeeze.)
Environmental group members who spoke at the nearly three-hour hearing in Trenton welcomed the two measures, with some saying that without the protection of S4143, the state could end up using carbon-emitting generation sources.
“This data center growth could derail New Jersey’s progress toward clean energy goals and lead to increased fossil fuels,” said Taylor McFarland, conservation manager for the Sierra Club’s New Jersey chapter. “It’s critical for New Jersey to be ahead of the curve and already have regulations and restrictions in place for these data centers so that our environment and our wallets are protected.
“The only way to best tackle the challenge is by requiring data centers to operate through additionality of power instead of (it) being extracted” from existing sources. “Most importantly, this additional power must come from clean energy sources so that we avoid the addition of extracted and polluting fossil fuel driven power.”
Deterrent Effect
Business groups, however, expressed concern the requirements of the bill would deter AI and data center developers from coming to the state.
Ray Cantor, a lobbyist for New Jersey Business & Industry Association (NJBIA), one of the state’s largest business groups, said he agreed with the sentiment of the bill but said the requirements would be excessive and prompt developers to look to other states.
“AI centers coming to New Jersey need to have their own source of power,” he said. “They are enormous drains or energy users, and we are a net importer of energy. We don’t have enough power generated in New Jersey … to supply these AI data centers.”
But he worried that the bill put “certain impediments in place.”
“It requires an energy usage plan. That energy usage plan is not just saying you have to use have your own energy. It’s talking about how you construct your building. It’s talking about the water systems you must use, and other facets of that building,” he said. “It’s just another regulatory process, another regulatory approval that is really not needed … for these facilities to be located. I think they know how to build their own facilities well enough without us telling them.”
Michael Egenton, a lobbyist for the New Jersey State Chamber of Commerce, suggested the state consider offering incentives to companies that want to put AI and data centers in the state if they use renewable energy.
“We should be encouraging them to open up operations in our state, and not placing hurdles, impediments, mandates and fines for compliance,” he said.
Reporting Emissions
The committee also backed S4117, the Climate Corporate Data Accountability Act, which would require companies with annual revenues of $1 billion or more to report their annual greenhouse emissions to the New Jersey Department of Environmental Protection (DEP) and nonprofits selected by the DEP.
The bill requires the companies to report for four years their “Scope 1” emissions, or the direct emissions by the company, and their “Scope 2” emissions, those that stem from the company’s electricity, heat and cooling systems. The companies after five years would have to report their “Scope 3” emissions, which includes those from purchased goods and services, business travel, employee commutes, and the processing and use of sold products.
The bill also enables the DEP to set a fee on the companies to recover administration costs.
Doug O’Malley, executive director of Environment NJ, said the $1 billion threshold ensures only large companies would be affected, and the emissions reporting requirements would force them to calculate how much pollution they generate.
That will “ensure that the largest companies know what their emissions are, with the idea that obviously knowledge is power, sunlight is the best disinfectant,” he said. “And then with that knowledge, we can ultimately look to reductions from the largest emitters in this country.”
Business groups expressed concern at the burden reporting would place on companies, especially small and medium-sized business and especially if they had to report in other states with similar requirements, such as California, as well.
Cantor, of the NJBIA, which opposes the bill, said reporting emission on “Scope 3 is extremely difficult.”
“It’s costly, it’s expensive, it’s confusing, and I don’t believe that this sort of gets us to where we want to go,” he said. “It’s going to require those customers and suppliers to do their own investigation, and they may not be sophisticated enough to do that, to report back to you. It’s going to impact a lot of New Jersey businesses.”
Dean LaForest of ISO-NE presented the results of the RTO’s 2023/24 load power factor (LPF) audit, which found most regional LPF areas to be noncompliant with the standards for low-load, high-voltage conditions.
The system generally graded out better on the standards applying to high-load, low-voltage conditions. However, within regional areas found to be compliant with the standards, regional entities frequently were out of compliance with the standards, ISO-NE found.
LaForest said ISO-NE found “no significant improvement year-over-year in LPF zone compliance.” He said gaining more insight into transmission and distribution operators’ systems “should help focus efforts on where compliance improvements within a zone are needed the most.”
He noted that ISO-NE will share more specific details of the audit directly with the region’s transmission and distribution operators.
Transmission Cost Allocations
Also at the NEPOOL Reliability Committee (RC), stakeholders approved transmission cost allocations for a pair of Eversource infrastructure replacement projects.
The projects, located in Connecticut, include relay replacements on a substation and replacements of aging and deteriorating transmission structures. The projects combined have an estimated $15 million in pool transmission facility costs.
Transmission Outage Scheduling
Anthony Stevens of ISO-NE discussed a series of minor changes to the RTO’s operating procedures governing transmission outage scheduling. The changes will explicitly allow the RTO to approve long-term transmission outages without first having to issue an interim approval of the outages. The changes also clarify the definitions of outage statuses and add language about “alternate dates” used for repositioning outages.
Stevens also presented changes to the RTO’s operating procedures for metering and telemetering criteria. ISO-NE proposes to expand the equipment temperature range to allow for “additional conditions in which data center type HVAC redundancy is in place,” Stevens said.
ISO-NE plans to seek a vote on the operating procedure changes at the RC in April.
Also at the meeting, stakeholders voted to support changes to ISO-NE operating procedures regarding protection outages, settings and coordination. ISO-NE proposes to “add language clarifying that automatic sectionalizing schemes do not require OP-24 Appendix D forms.”
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.
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.
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.
“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.
“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.”
“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.
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.”
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.
“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.
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 staff have not validated the Monitor’s analysis on the impact the TCPF had on prices, adding that in the past those estimates were not “true ‘but for’ analysis.” Since the Monitor’s recommendation also has included different line ratings, he said it’s not clear that constraints would no longer bind at the TCPF.
“PJM does not believe the implementation of the transmission constraint penalty factor is improper, but rather reflects actual operator actions to maintain transmission system reliability in prices,” Shields said.
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.
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.”
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.
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 EPE’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 related story, 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, 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.
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.
EPE 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.
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.
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.
