With the age of hyperscalers ramping up, Meta is the latest major tech firm to ask FERC for market-based rate authority as it sets up its own internal power marketer: Atem Energy (ER25-3440).
Meta, which owns Facebook and Instagram, is one of many firms developing artificial intelligence applications that have been a major contributor to the resumption of overall power growth after a couple of decades of stagnation.
Atem Energy is a Delaware-based company that has been formed to act as a power marketer to sell energy, capacity and certain ancillary services at wholesale in the United States. The firm’s MBR application does not specify where it will market power.
Meta is not the first big tech firm to seek MBR authorization: Alphabet’s Google has had it since 2010 (ER10-2835), Amazon since 2015 (ER15-1905) and Microsoft since 2021 (ER21-964). Companies in other sectors have been at it even longer, notably Walmart, which set up its in-house power marketer, Texas Retail Energy, in 2002.
A major company setting up its own power marketer to secure power supplies comes with some benefits, but significant costs as well, Electric Advisors Consulting’s Frank Lacey said in an email.
“In the plus column, you can design an electricity product tailor-made to your needs, including renewable attributes, risk management strategies, billing allocations and other,” Lacey said. “You can also avoid the profit margins built into other suppliers’ products.
“On the flip side of that coin, you have to build out an energy team, presumably with some trading and risk management expertise,” he said. “You have to be registered with FERC to sell electricity at market-based rates. You need to be a member of each RTO you have facilities in and bear those costs, including credit requirements.”
If Meta wants to become a state-regulated retailer to supply its facilities, it needs to register with their regulatory commissions and set up data exchanges with the relevant utilities, he added.
“You have to bear the risk of your own energy hedges and non-hedged positions, and as an RTO market participant, you own a share of the marketwide risk should any market participants go bankrupt,” Lacey said. “If the company has the resources to do all of this, it might make sense. On the other hand, I would think a company like Meta would have enough horsepower to attract a lot of attention from the existing suppliers in the market.”
Neither Atem nor its upstream ownership at Meta own any facilities that are for the generation, transmission or distribution of electric power. Meta CEO Mark Zuckerberg owns more than 10% of its shares, which triggers additional requirements, but he does not “directly or indirectly own or control a 10% or greater voting interest” in any generator or other energy assets in the United States, the application said.
The lack of existing assets in the power markets means Atem lacks horizontal or vertical market power, which satisfies the requirements for FERC to grant MBR authority, the application said.
The application seeks authority to sell ancillary services at market rates in CAISO, ISO-NE, MISO, NYISO, PJM and SPP. Atem asked for an effective date of Nov. 16, 2025, for its MBR authority.
BOSTON — Energy experts and officials stressed the importance of proactive transmission planning, interconnection reform and increased demand-side flexibility at Raab Associates’ New England Electricity Restructuring Roundtable on Sept. 19.
Speakers at the event reflected on the challenges the One Big Beautiful Bill Act (OBBBA) and the Trump administration’s executive actions have created for clean energy development in New England, but they generally expressed optimism around the region’s ability to withstand the federal headwinds.
“There will be pain, there will be companies that close, there will be less deployment as a result of the changes at the federal level,” said Nathan Phelps, managing director of regulatory advocacy at Vote Solar.
However, “solar will not fall off a cliff” because “the price of solar has come down a lot, and it continues to be an attractive investment,” Phelps said.
The OBBBA dramatically expedites the expiration of federal tax credits for wind and solar developers, and new projects must either begin construction by July 5, 2026, or come online by Dec. 31, 2027, to qualify for the full tax credits established by the Inflation Reduction Act. (See U.S. Clean Energy Sector Faces Cuts and Limitations.)
In New England, the looming tax credit phaseout has caused a mad dash for solar developers to try to lock in credits for later-stage projects, which may boost development in the short-term. Meanwhile, projects unable to begin construction in time for the deadlines likely will face increased risks of cancellation or major delay.
While the longer-term effects of the shift in federal policy are less clear, the Trump administration’s antagonism toward offshore wind in particular threatens to undermine the buildout of a strong regional supply chain and workforce, which could have effects extending well beyond Trump’s second term. (See Tax Credit Phaseout Threatens Projects, Jobs in New England.)
In the wake of the Trump administration’s stop-work order on Revolution Wind, “it’s really hard to have any confidence around what we can expect from the federal level,” Phelps said.
Alicia Barton, CEO of Vineyard Offshore, emphasized the importance of offshore wind for meeting load growth in the coming decades.
“I don’t think we have a choice — the region needs offshore wind,” Barton said.
She declined to comment on the halt on Revolution Wind, which is being developed by Ørsted, but said Vineyard Wind, which is being developed by Vineyard Offshore and Avangrid, still aims to achieve commercial operations by the end of the year.
“We are still constructing, we are still moving forward,” Barton said, adding that Vineyard Wind has created 3,400 jobs, including 1,400 union jobs.
Speakers also discussed how reducing the soft costs of renewable development — including costs and delays associated with siting, permitting and interconnection — could help mitigate the effects of federal policy changes.
On interconnection, “the most important near-term thing is implementation of Order 2023,” said Caitlin Marquis, managing director at Advanced Energy United.
FERC Order 2023 requires transmission operators to adopt first-ready, first-served cluster processes for interconnection. ISO-NE’s first cluster study under the new rules will begin in October.
“ISO-NE deserves a lot of credit for holding a robust stakeholder process to implement Order 2023,” Marquis said, while emphasizing that interconnection reform must go further than Order 2023 compliance to better integrate interconnection planning into the transmission planning process.
Marquis also highlighted the potential benefits of processes that allow new resources to share interconnection service with existing ones. She noted that ISO-NE has a surplus interconnection service option in its tariff but that stakeholders seek more flexibility.
At the state level, the administration of Massachusetts Gov. Maura Healey (D) has “made good strides” toward a more proactive approach for resource interconnection but is seeking to “consolidate some of the siloed processes into a more comprehensive planning process,” said Michael Judge, undersecretary at the Massachusetts Executive Office of Energy and Environmental Affairs.
He said state officials hope to replace the Capital Investment Project process, a provisional program intended to enable fixed distribution interconnection costs, with a proactive interconnection planning process incorporated into the utilities’ five-year electric-sector modernization plans.
Rob Gramlich, president of Grid Strategies, praised increased transmission planning initiatives taking place across New England. He noted that ISO-NE rated poorly in a pre-Order 2023 interconnection “report card” but that the Order 2023 compliance changes should help address some of the issues. (See Transmission Report Card Grades MISO ‘B,’ Southeast ‘F’.)
“Transmission planning is the key solution here,” he said.
Demand Response
Multiple speakers stressed the need to focus on demand response and flexibility.
For policymakers looking to decarbonize at the lowest possible cost, “one resource is way more important than all the others, and that’s the demand side,” said Paul Hibbard, principal at the Analysis Group and former chair of the Massachusetts Department of Public Utilities.
Hibbard said unlocking the full potential of demand response will require “fundamental changes” to rate design and programmatic spending.
“The technological hurdle to this is not a big one, it’s really getting the price incentives up and running and the infrastructure in place,” he said, adding that states must begin this work as soon as possible given the “painfully slow” pace of ratemaking.
Massachusetts’ electric utilities aim to finish deploying advanced metering infrastructure across their service territories by the end of the decade, which should enable increased retail price incentives to reduce demand during peak periods.
“Electrification depends on it, affordability depends on it, and ultimately the commonwealth’s decarbonization policy depends on it,” Hibbard said.
PHILADELPHIA — Virginia Gov. Glenn Youngkin requested that PJM reopen the nomination process for two open seats on its Board of Managers to consider two candidates recommended by the states.
Speaking at a technical conference on the state of PJM, Youngkin said there needs to be real reform immediately at PJM, with states being given a greater voice in decision-making atop the list. Much of the full-day conference focused on the prospect of governance reforms and how the RTO can meet the challenge of rising data center load.
The request comes after Youngkin and Pennsylvania Gov. Josh Shapiro co-signed a letter to the Board of Managers urging the RTO to consider nominating former FERC Commissioners Mark Christie (R) and Allison Clements (D) to serve as board members and for a larger discussion to be launched on setting aside two seats for candidates nominated by member states.
The PJM Nominating Committee instead opted to nominate Robert Ethier, a former ISO-NE executive, and Le Xie, faculty co-director of the Power and AI Initiative at the Harvard School of Engineering and Applied Sciences. The Members Committee is set to vote on appointing Xie and Ethier during its Sept. 25 meeting, which is the voting deadline FERC granted in response to PJM’s request for a delay. (See Robert Ethier, Le Xie Nominated for PJM Board.)
In response, seven state governors signed onto a letter expressing disappointment that Christie and Clements were not nominated, saying that would have signaled that PJM is listening to the states. They wrote that the lack of board representation for consumers and state regulators is a core concern for the governors.
“Our recommendation was intended to provide a constructive solution that would have both strengthened PJM’s governance and signaled that voices representing the public interest are afforded a meaningful place in decision-making at PJM,” the governors wrote. “The Nominating Committee’s decision to disregard our recommendation indicates that our concerns for our consumers are not being taken seriously and underscores how the states’ role in PJM is being minimized.”
“PJM cannot expect to continue making decisions that affect the daily lives of our citizens and the economic future of each of the states while hiding behind stale process and refusing to grant the opportunities for meaningful input that exist in other RTOs,” they continued. “This is a fundamental and existential challenge: PJM must find ways to provide sufficient representation for the millions of consumers we represent.”
The governors added that they do not mean to discredit the qualifications of Ethier and Xie but believe they do not have the backgrounds needed to address the crisis state leaders see. They advised the board “to embrace a new, more meaningfully collaborative, vision for PJM’s relationship with the states as a whole and to take steps to ensure greater ratepayer representation as the RTO makes major decisions in the coming months.”
“Please recognize the urgency of this moment — the need is not simply for indisputably talented individuals like Dr. Ethier and Dr. Xie, but for leaders who understand the uniqueness of PJM’s member states, our citizens and our shared responsibility for the reliability and affordability of electricity,” they said. “There is a pressing need to restore trust in PJM’s governance and legitimacy.”
‘Move More Quickly’
Speaking at the conference, Youngkin said PJM has failed to forecast rising load in its footprint in time to get ahead of it, introducing interconnection bottlenecks and causing a resource adequacy crisis.
“And that is why we are working on legislation that will allow Virginia to reassess whether our utilities will continue to be part of PJM. Virginia will need to decide what is best for Virginia ratepayers. This doesn’t mean that we are walking away, but it does mean that collectively we recognize we need to represent and protect our ratepayers. And that means sending a clear, unifying signal that PJM must modernize, must reform. PJM must improve its planning and, above all, PJM must work to restore confidence that recently has been so badly lost.”
Opening the technical conference, Shapiro said PJM is at an inflection point where the states have empowered it with increasing authority to not only coordinate power flows but also ensure resource adequacy. Now it has responded too slowly to reform its interconnection process to facilitate the generation growth needed to meet rising demand.
He said the situation has been made more difficult by the Trump administration creating barriers and cutting funding for new generation. PJM was founded in Philadelphia nearly a century ago, and there’s an opportunity now to reform its governance to provide more opportunity to work with its member states.
In a press conference following his address, Shapiro said PJM should revise its leadership structure to provide more authority over decision-making to the states. And while he prefers to take a cooperative approach, he’s prepared to seek legislation requiring utilities to leave PJM absent changes.
He said PJM will need to become more sensitive to the needs of the states and consumers, including giving a voice to those entrusted to lead the states, as well as cultivating a more direct connection between state utility commissions and PJM leadership than currently exists. For those changes to be effective, he said PJM has months, not years.
“We need PJM to move more quickly … if PJM cannot do that, Pennsylvania will look to go it alone,” he said.
Maryland Gov. Wes Moore said the unified voice of 13 governors underscores the crisis at PJM, with families facing double-digit rate increases driven by the mismanagement of the regional grid. Grid oversight lacks transparency and responsiveness, which creates a need for states to have more of a hand in governance, he said.
Following the conference, 11 states signed onto a joint statement of intent outlining plans to create a PJM Governors’ Collaborative to “promote greater state and consumer representation in the governance and decision-making processes of PJM.”
The group would not hold regulatory or enforcement power, but would coordinate communications among PJM, state regulators and elected officials, FERC, the Organization of PJM States Inc (OPSI) and Consumer Advocates of the PJM States (CAPS). It also could provide technical support on topics before PJM, identify issues for the states to address, and “develop and advance joint positions and strategies related to PJM issues.” Only West Virginia and Kentucky did not sign onto the statement.
POUGHKEEPSIE, N.Y. — It was standing room only at the Town Board meeting here Sept. 3. A glance at the agenda for the night, dominated by property maintenance orders and police officer hires, would not hint at what drew so much of the public out on a Wednesday evening. But it quickly became apparent once residents began speaking.
“Lithium battery stations often go on fire,” one said. “There’s been many of them, and I understand that you can’t use water to put them out … so they let fire smolder, just pouring toxins into the air.”
The board was considering whether to adopt new zoning codes to regulate the construction of battery energy storage systems (BESS) that would overturn an 18-month moratorium. Public comment both for and against the rules went on for about three hours at the meeting, with people voicing concerns about fire safety, pollution, environmental impact and grid stability.
“I think batteries will help us be less dependent on polluting plants, like the one in Newburgh,” another resident said. “My electric bills are going up; there are consistent rate hikes. I think batteries can help keep our bills low.”
Town Supervisor Rebecca Edwards said New York state recently adopted fire codes for BESS, the strictest in the U.S. Councilmember Ann Shershin said if the town wanted solar projects, it would need BESS nearby.
Councilmember Michael Cifone said he didn’t see the benefit to the town’s residents and expected it to go to developers and utilities.
After more discussion, several failed amendments and one minor adjustment to construction setbacks, the seven-member board narrowly passed the zoning rules along party lines, with the four Democrats voting in favor. This makes Poughkeepsie one of the first municipalities in New York to overturn a BESS construction moratorium.
This scene is playing out in towns and cities across New York as the state pursues its goal of 6 GW of energy storage by 2030. The Hudson Valley, New York City and Long Island are at the forefront of a massive battery rollout. Because of the state’s strong home rule provisions, municipalities have significant power over whether BESS facilities get built. A bill to get BESS under state siting authority died in committee in 2025.
Similar debates are being held on Staten Island and in Mahopac. Westchester County passed a local law upping safety requirements for BESS systems after a fire in 2023. That same year, National Grid pulled out of a BESS and solar installation in the Adirondacks because of community outcry. Another battery battle is gearing up in Kingston where Terra-Gen is planning a 250-MW facility on the site of a closed high school. Local officials and state representatives are divided on the issue, per Energy Storage News.
The Poughkeepsie Town Board had been thinking about BESS zoning for roughly a year. In September 2024, the matter was brought to its attention when locals learned of a local project and descended on the board with demands and questions.
Key Capture Energy, the developer of the project, had been eyeing an industrial parcel owned by Vassar College since 2019, Phil Denara, director of development for the company, said in an interview in 2024. The company wanted to build a 20-MW/80-MWh battery energy storage project there because it was close to a local substation. The project fell through before the zoning ordinance could be passed.
“We’re attracted to continuing to develop in New York primarily because of the policy mandates that are driving a lot of the industry,” Denara said. “The Climate Leadership and Community Protection Act set an initial storage target which has been doubled by Gov. [Kathy] Hochul.”
Denara said the industry needed to “take ownership” and respond to the concerns of local residents and officials.
“We’re coordinating a lot at the local level, educating local communities and ensuring that they understand that this technology is important for our decarbonization goals both in New York state and more broadly across the globe,” he said.
Fire Safety
One of the most frequently voiced concerns in the debate over BESS facilities is over fire safety. In Facebook groups opposing local BESS projects, people share videos of e-bikes exploding. Others share conspiracy theories about Chinese military-linked companies infiltrating the U.S. battery storage supply chain.
But the recurring star of the show is the Moss Landing Fire in California, when in January a 300-MW BESS caught fire. People in nearby areas were evacuated. The cause of the fire remains under investigation, and EPA is leading an ongoing cleanup.
The environmental impacts are unclear. While local scientists at Elkhorn Slough, a national estuary reserve near Moss Landing, found that heavy metal contamination spiked in the aftermath of the fire, they aren’t certain about long-term ecological or health consequences.
“We don’t know yet what is going to happen in terms of the estuary habitats here,” said Ivano Aiello, a scientist at San Jose State University who studies the wetland dynamics of the area. “We are monitoring the microbes; we are monitoring the [animals, from] invertebrates all the way up to the sea otters, to understand whether those metals are moving through the food web.”
The Moss Landing site previously was a gas plant. Aiello said that it was unclear whether the pollution seen from the battery fire was comparable to the effects of previous emissions.
“We use sediments as a time machine,” Aiello said. “Once the emergency ends here, it’s one of the things I’d like to use the core samples as a way to assess.”
Matthew Paiss, a technical adviser on energy storage safety for Sandia National Laboratories and former firefighter, lives near Moss Landing. He said that in general, consumer-grade rechargeable lithium batteries were not manufactured to the same high standards as utility-scale batteries.
“People are looking for the cheapest battery they can, and if your job is as a gig employee and you’re delivering Uber Eats, and your $500 battery loses capacity, you’re going to take it to a local shop and get a couple cells changed out,” Paiss said. This kind of tweaking, coupled with hard physical wear and tear, was the cause of most failures, he said.
Paiss has studied the general causes of BESS failures using BESS Failure Database data from the Energy Policy Research Institute. In general, he said utility-scale battery fires occur because of installation errors and failures with overall protection systems. The Moss Landing facility kept many of their batteries in old buildings on site, which may have contributed to the fire by reducing “fire segmentation,” he said.
“Best practices moving forward are to limit the amount of propagation,” he said. “That’s why we’re seeing a lot of outdoor containers.”
Lakshmi Srinivasan, the team lead for EPRI’s energy storage program, said that since 2011, the rate of BESS fires has declined worldwide as the industry improves safety. Of the failures they’ve been able to isolate causes for, the battery cells themselves were not the most likely to cause fires. Other components, installation problems, bad thermal management and HVAC systems were the most common causes.
“The key takeaway from this work was actually that we know how to engineer controls and the balance of the system to prevent these kinds of failures going forward,” she said.
Local Government Outreach
What seemed to have the most impact on the Poughkeepsie Town Board’s decision to implement zoning was a panel discussion in June in which the Dutchess County Mayors and Supervisors Association met with experts to discuss BESS facilities.
The meeting, held at the Board of Cooperative Educational Services Conference Center, attracted policy wonks, local government officials, firefighters, first responders and concerned citizens. The crowd listened to presentations by Paul Rogers, a former New York City Fire Department lieutenant working for the Energy Safety Resource Group; Jeffrey Seidman, a Vassar College professor; and Jennifer Manierre, director of clean energy siting for the New York State Energy Research and Development Agency.
Seidman helped organize the meeting with town Supervisor Edwards. What originally had been an “old boys club” for local government officials became, for one night, a policy discussion forum.
Seidman explained the benefits of utility-scale batteries, primarily load shifting, enhanced grid reliability and reduced use of expensive peaker plants. Batteries would help reduce energy costs if built in sufficient numbers across the state, he argued.
“Demand for electricity is going up absolutely everywhere,” Seidman said. This meant more demand for substations and transmission lines. “Batteries save us money by not making us have to do those expensive upgrades.”
Manierre offered NYSERDA’s service to help local officials with zoning and planning and explained the role of batteries in the state energy plan.
Rogers reviewed the New York Fire Code development process, the safety considerations afforded to firefighters and the relative risks of fires at battery plants compared to more conventional buildings. Each facility needs to have an on-call person to handle emergencies and coordinate with first responders, he explained.
“We put these things in place to try to help … because our thing is to keep everyone safe,” Rogers said. “I’ll never say ‘never,’ but we significantly reduce the risk of an event taking place,”
Battery storage facilities were required by the fire code to undergo large-scale fire testing, he explained. This meant that manufacturers needed to test-burn entire battery cabinets.
“What the [testing] proves and validates is that if something takes place that it doesn’t leave the container, it stays in the container,” Rogers said.
Seidman told RTO Insider that local organizers were setting up another forum in Ulster County, where several battery facilities are planned. He hopes that by mid-November, a similarly productive conversation can happen there too.
“I think a lot of people are not ideologically or otherwise opposed to batteries, but they just don’t mean anything to them,” Seidman said. “Like, ‘why should we put our necks out?’”
Seidman said that he received a good response from town officials after the meeting and that one had invited him to a local temple to give a talk on batteries. He said he hopes his efforts can make a difference for the climate and local air quality.
“I’d love to make this a traveling road show,” he said. “This is something I would like to repeat.”
As NYISO continues its Capacity Market Structure Review, the Market Monitoring Unit used its second-quarter State of the Market report to highlight potential issues with how the ISO forecasts resource availability, with the late June heat wave as a test case.
All-in prices were up across all zones of the New York Control Area, driven by an increase in natural gas prices. But “in addition to the gas prices, I think the extraordinarily high load level that peaked in late June … certainly added a lot to real-time prices,” Pallas LeeVanSchaick, vice president of Potomac Economics, told the Installed Capacity Working Group on Sept. 8.
LeeVanSchaick offered a breakdown of the performance of fossil fuel generators, emergency capacity and large curtailable loads during the heat wave. He said the MMU wanted to highlight these resources because they have not been the focus of prior capacity accreditation discussions.
“It’s sort of outside the standard analyses that we do,” he said. “It has to do with capacity accreditation. … Obviously we and … NYISO and other regional market operators have spent a lot of time on how to improve capacity accreditation.”
The analysis compared the performance of fossil fuel resources systemwide during the June heat wave against their weighted average equivalent demand forced outage rate (EFORd), which measures how much capacity a resource could reliably provide when in demand. During peak hours in the heat wave, the MMU found that units were out of service more than predicted by their average EFORd.
“The concern here is if you look at the stuff that was unavailable due to either forced outages or performance, the number comes out to 24.9% on the 24th, compared to an average EFORd of 5.9%,” LeeVanSchaick said. This means that EFORd is being calculated too low because it is not taking into account how certain generators are being used, he said.
Some fossil fuel plants, like peakers, are dispatched to run at high outputs very rarely. These plants are aging, which reduces their ability to operate at high output. If they aren’t called on to push high power out frequently, EFORd will not capture when they fail to function at those levels, leading to far more optimistic rates. This problem also occurred with steam turbine units during the heat wave.
“This heat wave presented a unique opportunity because we haven’t seen conditions where so many units were asked to operate at high levels,” he said.
In addition, some capacity that was available to the ISO was not recognized by its real-time model as available. About 213 MW that previously participated in the Capacity Limited Resource and Emergency Capacity programs were not scheduled and did not produce energy; 73 MW of capacity that were not scheduled but produced voluntarily were also not recognized.
“What we found was that there was not an operating procedure to utilize these megawatts that was ready to be used on these days,” LeeVanSchaick said. “Although the conditions and operating reserve shortages would have warranted using this capacity, it wasn’t actually scheduled.”
Roughly 90% of large loads across 600 MW of demand response programs voluntarily curtailed during the peak load hour June 24, he said. These were resources participating in the Special Case Resource (SCR), Demand-Side Ancillary Service (DSASP), distributed energy resource and Behind-the-Meter Net Generation programs.
These DR actions had some inefficiencies. Over 200 MW of SCRs were curtailed when they could have provided DSASP reserves; 70 MW of SCRs curtailed for four hours as requested but then increased consumption during the peak, meaning they weren’t deployed when they were most valuable.
“We’re going to need to think further about how to potentially refine these programs so that these things are consistent for resources to be participating efficiently,” LeeVanSchaick said.
The U.S. Department of Energy is kicking off its Speed to Power initiative by seeking input on large-scale grid projects that would serve large-scale data centers.
The move is the latest in a series of efforts President Donald Trump initiated hours after his inauguration to boost American energy production. There has been an emphasis on boosting production and consumption of fossil fuels while hindering development of intermittent renewable energy resources, but energy infrastructure also is a priority.
DOE said Speed to Power is centered on multi-gigawatt generation, transmission and grid infrastructure projects that will enable the U.S. to accelerate artificial intelligence buildout.
“With the Speed to Power initiative, we’re leveraging the expertise of the private sector to harness all forms of energy that are affordable, reliable and secure to ensure the United States is able to win the AI race,” Energy Secretary Chris Wright said in a Sept. 18 news release.
The same day, DOE’s Grid Deployment Office issued a request for information that would help it identify projects that enable minimum incremental load of 3 GW and support up to 20 GW of incremental load.
These can include building new interregional transmission (minimum 1,000 MVA); reconductoring existing lines (minimum 500 MVA); bringing retired thermal generation facilities back online or using their interconnection capacity for new “reliable” power generation; and constructing new generation.
DOE reminded respondents about the funding and technical assistance programs available for such projects.
The interactive map offers some of the information developers need as they conduct site assessments, including: power demand from data centers that are planned, under construction or in operation; fiber-optic cable networks; transmission lines; power plants; substations; natural gas pipelines; day and night population; NERC reserve margins; FEMA risk indexes; and railroads.
DOE said its launch of Speed to Power will “ensure the United States has the power needed to win the global artificial intelligence race while continuing to meet growing demand for affordable, reliable and secure energy.”
The Problem Solvers Caucus, a bipartisan group of House members, has released a framework for energy infrastructure permitting legislation as momentum for a bill grows in Congress.
The caucus’ Permitting, Energy and Environment Working Group, led by Reps. Scott Peters (D-Calif.) and Gabe Evans (R-Colo.) and co-chairs Reps. Brian Fitzpatrick (R-Pa.) and Tom Suozzi (D-N.Y.), developed the framework over the past few months by working with energy producers, industry experts, members of relevant congressional committees and other stakeholders.
“America faces a choice between cheap, abundant energy from all-of-the-above sources or higher energy prices, falling behind China and an increased risk of blackouts,” Peters said in a statement. “It’s obvious where we need to go. To get there, we know we need to update our environmental laws to meet the challenges of today and invest in a grid for this century. This platform represents a bipartisan commitment to set aside ideology and solve this problem for the American people. I look forward to working with my colleagues to keep the momentum going and turn this into legislation that can pass both chambers of Congress.”
The framework for permitting reform covers a range issues from efforts to streamline reviews under the National Environmental Policy Act to changing how the largely untested National Interest Electric Transmission Corridors (NIETCs) work by allowing just one line (rather than a broader region) to qualify as a corridor. The NIETCs are designated by the Department of Energy and any lines qualify for backstop siting at FERC.
The NIETC process would be amended to allow for simultaneous state and federal reviews (recognizing state authority), and it would require DOE to act on applications within 90 days.
The process for judicial review of DOE- and FERC-approved linear infrastructure projects would be consolidated under the exhaustion and judicial review provisions of the Federal Power Act.
The framework includes categorical exemptions for simple updates to existing linear infrastructure, especially in disaster-prone areas. The Forest Service’s management and wildfire mitigation activities in utility rights-of-way should be expedited.
To help meet rising demand, the framework calls for FERC to initiate interregional planning (excluding ERCOT), with Congress providing “strong guidance on the allocation of the costs of these infrastructure projects” while excluding cost allocation to customers who receive no or trivial benefits.
On domestic supply chains, the Problem Solvers Caucus calls for DOE to “regularly assess electricity generation and transmission supply chains for security and resilience.”
“Reforming our permitting system is crucial, and this framework meets the moment for much-needed change. The demand for affordable and reliable energy of all kinds becomes increasingly urgent,” Evans said in a statement. “By cutting through red tape, we can meet energy demand, lower costs, strengthen national security and create high-quality jobs in America, while being responsible stewards of the environment and maintaining our position of global leadership and not cede ground to China. The urgency is real, and I am proud of this bipartisan push for change.”
The caucus’ permitting reform framework was welcomed by Grid Action Executive Director Christina Hayes, who said it shows Democrats and Republicans can come together to find solutions that strengthen the grid, cut red tape and speed up the development of transmission infrastructure.
“As demand for electricity soars, driven by the rapid growth of artificial intelligence, new data centers, and the everyday needs of families and businesses, the urgency of bipartisan action has never been clearer,” Hayes said. “This framework recognizes that meeting those demands means modernizing our permitting system so that transmission projects can move forward quickly, reliably and affordably.”
The Bonneville Power Administration has entered into a five-year power purchase agreement to buy wave energy from a test facility managed by Oregon State University (OSU), the agency said.
BPA will buy up to 20 MW/hour of test energy output from the OSU-administered PacWave project starting in 2026 at a purchase price of 75% of the CAISO Western Energy Imbalance Market’s index price, according to the PPA published Sept. 16.
Dan Hellin, PacWave’s director, called the agreement “a significant milestone for PacWave and Oregon State University.”
“We feel that it demonstrates the value of wave energy as an emerging renewable resource and provides a practical pathway for PacWave-generated electricity to enter the grid,” Hellin told RTO Insider. “This agreement not only validates PacWave’s role as a leading open-ocean wave energy test facility but also ensures that the technologies we host are evaluated under real-world market conditions — an essential step toward advancing wave energy from an experimental concept to commercial reality.”
Funded by the U.S. Department of Energy and the state of Oregon, the agreement with BPA concerns one of two facilities under development by PacWave. The project is an open wave energy testing facility and sits seven miles off the Oregon coast. The university submitted a small generator interconnection application in 2015, and BPA has partnered with OSU to ensure the project meets the requirements for new generation in the agency’s balancing authority.
In March 2021, FERC issued a license for construction and operation of the wave project, and the facility was completed in early 2025, according to PacWave’s website.
BPA has agreed to buy energy at a delivery point within a Central Lincoln Public Utility District-owned distribution facility, according to the agreement.
Specifically, BPA entered the agreement under the Northwest Power Act’s section on conservation and resource acquisition. The agency can acquire output under the section if the resource is not a major resource, is experimental, has the “potential” to provide cost-effective services, and if BPA has included the resource in its annual budget to Congress.
The project meets all four conditions, BPA stated, noting the agreement covers only 20 MW of energy per hour and that the project is intended to test the potential of wave energy.
“Because the wave energy industry is in its early stages, the reliability, availability and economics of the various wave energy converter technologies are currently uncertain,” the agreement states. “The project will provide BPA, OSU and the project clients an opportunity to learn more about the operational characteristics and commercial feasibility of wave energy technologies, which will provide BPA with information regarding the industry’s potential cost-effectiveness.”
OSU will select four clients and provide “each with access to an offshore testing berth with a 5-MW-capable power and data cable connection to the shoreside grid connection facility,” the agreement states.
The partners expect the project will begin generating in the spring of 2026.
“This is a small resource purchase that makes economic sense for BPA customers and helps meet BPA’s responsibility to foster emerging technologies in support of its strategic plan, regional and national energy goals,” BPA said in an announcement.
In 2021, the Hawaii Natural Energy Institute announced it would receive $6 million from the Naval Facilities Engineering Command to research wave energy conversion technology. (See Hawaii Wave Energy Project Gets $6M in US Navy Funding.)
The U.S. clean energy industry is so over tax credits.
The passage of the Republicans’ One Big Beautiful Bill Act ─ extending President Trump’s 2017 tax cuts and decimating former President Biden’s 2022 renewable energy tax credits ─ was a shock to the system and already is slowing the growth of solar and wind in the United States.
But slowing down was not at all on the minds of the 37,000 industry professionals ─ and 1,325 exhibitors ─ who descended on Las Vegas Sept. 8-11 for RE+, the largest renewable energy trade show in the country.
What I heard, at more than one session over the four-day conference, was that if the industry had to lose the federal incentives, it could not have happened at a better time. Trump’s scorched-earth war on renewables may be a political reality, but the exploding growth in electricity demand from data centers, manufacturing and electrification is driving economic and technological change at a scale and speed well beyond the president’s control.
K Kaufmann
New figures from industry analyst Wood Mackenzie show that U.S. utilities currently have 17 GW of new electricity projects under construction specifically for large loads like data centers. An additional 99 GW of large-load projects are “committed,” meaning they have interconnection agreements, contracts or other solid financial arrangements.
Solar and storage made up 82% of new generation coming online in the first half of 2025.
“So, we’re in this state where there’s sort of two truths, two experiences, two realities,” said Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association, which sponsors RE+ with the Smart Electric Power Alliance.
While the politics may remain “intensely chaotic and intensely unpredictable, there’s opportunity for entrepreneurship; there’s opportunity for innovation; there’s opportunity for success,” Hopper said during an industry update Sept. 10. “The market will take over politics, and we will ultimately win.”
Bifurcated Realities
I experienced a similar sense of bifurcated realities at RE+ as I attended panels and workshops and cruised the trade show floor.
Politics remains the industry’s Achilles’ heel. Leaders have yet to let go of their quixotic belief that at some point, they will be able to break through the ideological noise in Washington, D.C., with facts, figures and common sense.
A panel on how to frame clean energy policies for conservatives basically replayed many of the talking points I have been hearing at energy conferences for the past year or more, even before Trump was elected for a second term.
Eric Goodwin, vice president of business development at OMCO Solar, a steel company that manufactures solar tracking systems, talked about keeping a focus on jobs and drawing Trump’s attention through targeted use of social media.
Heather Reams, president and CEO of Citizens for Responsible Energy Solutions, a right-leaning clean energy advocacy group, argued that, the OBBBA notwithstanding, the industry must continue to engage with congressional Republicans. Like Hopper, Reams called for a shift in priorities, from tax credits to innovation.
Tom Starrs, vice president of regulatory affairs at EDP Renewables, and Isaiah Menning, external affairs director of the American Conservation Coalition, both stressed the importance of building local support in rural areas where solar and wind projects often face opposition.
As always, the views and voices expressed here were authoritative, thoughtful and pragmatic, and unlikely to have any major impact. The problem is we have a president and administration that have little to no interest in facts that in any way counter their own skewed, fossil-fueled vision of what American energy policy might look like.
They are equally uninterested in any kind of constructive dialogue with the renewable energy industry, as witnessed by the almost complete absence of representatives from the Department of Energy at RE+, from Energy Secretary Chris Wright on down.
PERC vs. TOPCon
Had Wright been there, he would have seen an industry that is vital, optimistic and determined to out-innovate, out-AI and outlast Trump and his backward-looking energy policies.
Artificial intelligence was everywhere, with a small army of startups rolling out new products that can cut times and cost to design virtual power plants and microgrids, review contracts or local ordinances, promote home electrification and send robots to inspect solar panels out in the middle of nowhere.
Solar and storage companies from China and India also were highly visible on the trade show floor, many of them figuring out how to work around Trump’s tariffs and comply with OBBBA’s stricter domestic content requirements.
SolarSpace, a top Chinese manufacturer of solar cells and panels, is partnering with several American investors to build a solar manufacturing plant, according to John Van, a sales manager. While he was reluctant to provide details or name names, he said the new plant is scheduled to go online by the end of the year, and half of its initial 2 GW of panel capacity already is sold.
What’s significant here is that SolarSpace and other Chinese and Indian companies are producing solar cells and panels that are more efficient and durable than cells and panels currently being manufactured in the U.S. The American industry still is using PERC (passivated emitter and rear cell) technology, while the rest of the world has moved on to TOPCon (tunnel oxide passivated contact) and HJT (heterojunction with intrinsic thin layer) technologies. (The links connect to fairly wonky descriptions of the technologies.)
TOPCon and HJT panels are more expensive, but more efficient, which means projects using these technologies may not need as much land ─ a core issue for solar projects in rural areas. But rolling out these advanced technologies in the U.S. has stalled, in part due to legal disputes over intellectual property and patent ownership.
U.S. producers also have stuck with PERC because they can manufacture more panels at lower prices, despite their lower efficiency and durability.
In other words, Trump’s tariffs and domestic content requirements are not advancing the onshoring of solar manufacturing or fostering U.S. competitiveness, while Chinese and Indian firms are figuring out the business models that will enable them to enter the U.S. market and potentially offer better products.
The Interoperability Challenge
What one could see and hear at RE+ ─ at least what I’ve written about so far ─ is the tip of the proverbial iceberg, what’s visible above the water line. The changes needed to respond to current system challenges ─ political, economic and technological ─ can happen only when you drill down to explore the patterns, trends, behaviors and attitudes that lie below, according to Matt McDonnell, managing partner of the Current Energy Group, a policy and analysis outfit.
McDonnell was one of the speakers at a half-day workshop Sept. 8, laying out a holistic, “systems thinking” approach to grid planning and design, sponsored by the GridWise Architecture Council, commonly called GWAC.
“What are the assumptions and beliefs that people hold about the system? How do we really, really challenge some of these things that we take for granted … conventional wisdom, the way things have always been done?” he said.
Part of working toward such fundamental changes in the electric power system means nudging regulators and other industry stakeholders “down this iceberg model stack to really be challenging some of these underlying features that are below the surface often in proceedings.”
Taking the example of grid resilience following extreme weather events, traditional patterns and thinking might focus on grid upgrades or “hardening” that “drives up costs while often offering suboptimal performance,” McDonnell said. “Poles keep getting rebuilt and ice storms come through and keep knocking them down.”
Should the focus be on grid reliability or “energy service reliability?” he said. “Is what we really care about the poles and wires staying up all the time, or do we care about customers having access to energy even during extreme weather events?”
GWAC sees this kind of systems approach as integral to developing flexible and interoperable energy services that will allow individual buildings or groups of buildings ─ like data centers ─ to interact with the grid, from distribution up to transmission, to improve reliability and cut costs for consumers.
The proliferation of grid-edge technologies has created an “interoperability challenge,” said Shawn Chandler, a director at consulting firm Guidehouse. Distributed generation and computing power can be combined “to get all that sensing and all that information into a hybrid, decentralized system that brings together … system distribution operations, customer service, market operations and regulators.”
“If you can do that, then all your information flows are leading to the same outcome, which is [that] we want the most optimization, and most importantly, we avoid what I would call unintended consequences,” he said.
Ultimate Inertia
The language may be a bit abstract and jargony, but the connections to the industry’s current debates on how to meet demand growth are immediate and clear.
Under Trump’s drive to stand up new fossil-fueled and nuclear generation ─ at the tip of the iceberg ─ is the basic assumption that the need for new power can be met only with traditional, 24/7 dispatchable forms of generation.
What drives such assumptions is the deeply engrained industry desire for quick and simple solutions that require little change in business or regulatory models, an approach that increasingly is untenable.
Radical and rapid growth in electricity demand presents complex challenges that call for new and complex solutions.
The factors under the waterline here include backed-up supply chains for natural gas turbines, with delivery times of three to five years or more. Building out new plants, natural gas pipelines and transmission lines could mean ongoing utility bill increases for consumers, an unintended consequence and political minefield for any candidate for public office. New approaches to affordability will be critical.
Technology may move faster than policy or regulation, but the ultimate inertia in the system is rooted in human attitudes and behavior. What I saw at RE+ is that clean energy is moving fast and more than ready to embrace the complex challenges ahead. Trump or anyone else holding on to simple, outdated solutions will be left in the dust.
Livewire Columnist K Kaufmann has been writing about clean energy for 20 years. She now writes the E/lectrify newsletter.
Texas regulators have proposed new rules on large load forecasting criteria and net metering following the state’s recent biennial legislative session and opened them up to public comment.
The two projects are among four active dockets related to Senate Bill 6’s implementation. One of the state Senate’s top priorities, the legislation, among other things, directed the Public Utility Commission to determine a cost allocation for large loads to ensure they’re paying their fair share of infrastructure expenses. (See Texas Bills Targeting Renewables Come up Short.)
The PUC has recommended that to gather as much feedback as possible, the large-load criteria be standardized to include loads exceeding 25 MW. The criteria intentionally excludes loads below 25 MW, which primarily interconnect at the distribution level (58480).
PUC Chair Thomas Gleeson said during the commission’s Sept. 18 open meeting that he has yet to agree projects should be included in ERCOT’s load forecast if they meet a pair of criteria by submitting attestations to the transmission or distribution service provider. He asked stakeholders to comment on the benefits provided by submitting attestations that show “significant, verifiable progress” toward: 1) completion of required site-related studies and engineering services and 2) obtaining state and local regulatory approvals required before a project’s energization.
“I’m going to need to be sold on having this in this rule going forward,” he said.
The proposed net-metering rulemaking will apply to large loads and existing generation resources and establish the criteria for ERCOT’ s study of the arrangements. It sets the procedural steps for staff to complete their study of a net-metering proposal within 120 days and the commission’s procedure to approve, with or without conditions, or deny a net-metering proposal within 60 days after ERCOT files its study results and recommendations (58479).
ERCOT staff was on hand to share details of ERCOT’s studies of the net-metering arrangements’ reliability effects while the rule is being developed. They said the studies will evaluate the effects on transmission security, resource adequacy and the stranding or underuse of existing transmission facilities.
The analysis will consist of a before-and-after capacity reserve margin evaluation using ERCOT’s most recent capacity, demand and reserves (CDR) report as a baseline. Reserve margin effects over the next five years will be reported for both the forecasted peak load hour and net load hour in line with the CDR reserve margin reporting requirements.
Participants in ERCOT’s market have until Oct. 17 to file initial comments or request a public hearing. Reply comments are due by Oct. 31.
SETEX Reliability Project
The PUC once again delayed action on Entergy Texas’ proposed 500-kV single-circuit transmission line in northeastern Texas after hearing oral arguments from more than a dozen landowners or their attorneys (57648).
Gleeson promised the commission would reach a decision on the transmission line during its Oct. 2 open meeting. The project has 61 proposed routes, with PUC staff and Gleeson each favoring different routes.
“As I sit here right now, I’m still not prepared to make a decision,” he said. “I think it’s appropriate to extend it one more meeting to take into account everything that was said and to make sure that anything we’re considering from that oral argument is in the record.”
The 150-mile SETEX Area Reliability Project has drawn opposition from local landowners, who requested a rehearing of the State Office of Administrative Hearings’ decision to recommend a certificate of convenience and necessity for the line. The project’s various routes range from 131 to 160 miles, and its costs are projected to be between $1.33 billion and $1.52 billion.
“Entergy Texas is sympathetic to the concerns landowners may have about the line,” said attorney Everett Britt, representing Entergy. “Each of the 61 routing options before you satisfies the need for the project. It is viable and constructible. We’ve heard a number of arguments and issues raised today. We do think these have been addressed, if not by parties here today than in the extensive briefing and exceptions filed in this case.”
