WASHINGTON —The oil and gas industry drills about 70,000 wells per year, according to Jamie Beard, founder and executive director of Project InnerSpace, a nonprofit that aims to accelerate the development of next-generation geothermal energy.
If geothermal could hit the same numbers ― using the fracking and horizontal drilling technologies developed by oil and gas — it could meet 75% of the world’s demand for electricity and a major chunk of its heating and cooling, she said.
“Heating and cooling is 50% of the geothermal opportunity, but it does not get 50% of the attention,” Beard said. “It’s very sexy to go after power. It catches headlines. Heat is not as sexy, unfortunately. … But if you think about it … if we knock that out with geothermal, that’s 50% of the world’s energy demand.”
Beard was speaking March 4 on stage at Geothermal House, an event intended to promote geothermal as a clean, 24/7 resource now being enthusiastically embraced by the oil and gas industry, Republican leaders in Congress and the Trump administration. Cosponsored by InnerSpace and right-leaning nonprofit Citizens for Responsible Energy Solutions (CRES), the conference even had its own Trump-friendly acronym, MAGMA (Making America Geothermal: Modern Advances), emblazoned on red baseball caps.
In a closing keynote at the event, Energy Secretary Chris Wright, formerly the CEO of fracking company Liberty Energy, laid out the administration’s approach to geothermal as a crossover technology with huge potential. Shale drilling technology is “tailor-made for geothermal,” he said. “We can mine simply massive amounts of heat from underground that we can use to produce electricity; we can use to produce district heating or process heating right at the surface and, done right, can even help produce cooling.”
Framing geothermal as a resource for energy abundance, meeting energy demand from artificial intelligence and cutting electricity prices, Wright said, “We’ve got to put capital to work. I want to be a service provider and help the government get out of the way; make it easier to get regulatory approvals, easier to do innovations, easier to take that next step.
“We don’t want AI somewhere else, not just because we want jobs and investment here, but AI is going to drive scientific progress and national security,” Wright said. “We can’t afford to lose this industry … and the only way to get it here is to implement President Trump’s agenda of affordable, reliable, abundant, secure energy.”
‘Ready to Go’
Republican lawmakers including Sen. John Curtis (Utah), Rep. Randy Weber (Texas) and Rep. August Pfluger (Texas.) echoed Wright’s call for the government to get out of the way of geothermal development, adding permitting reform and transmission expansion to the geothermal to-do list.
“Sometimes it’s easier to drill for oil and gas than it is for heat,” Curtis said in his opening keynote. Geothermal is “not as reliant as the other energy sources are on subsidies. [It’s] not as reliant as the other energy sources are on forcing the market. The market is ready to go.”
The fact that states are now competing to be industry leaders is another sign of the technology’s growth and acceptance.
Speaking at a recent webinar on geothermal hosted by the Atlantic Council, Colorado Gov. Jared Polis (D) boasted of new permitting processes in his state that provide “one of the most expedited, reliable permitting regimes for geothermal in the country.” (See With Demand Growth Across US, Geothermal is Poised for its Moment.)
Weber pointed to his state’s recent approval of its first geothermal well, a 3-MW project that Houston-based Sage Geosystems is developing to provide power to San Miguel Electric Cooperative.
The Texas Railroad Commission’s approval “is a major step forward, and it underscores Texas’ commitment and Texas’ potential to lead in this space,” he said. “We have the infrastructure; we have the workforce and the experience from the oil and gas people.
“We can drill, baby, drill … especially on geothermal,” Weber said.
Backing up the lawmakers, Simon Seaton, CEO of the Society of Petroleum Engineers, said the oil and gas industry is “taking geothermal seriously.”
The technical overlap between the two technologies “is huge,” he said. “Only the oil and gas industry actually has the track record to develop and scale geothermal and bring it quickly into the energy mix to address challenges like energy security, increased demand for AI and data centers, as well as carbon-emission reductions.”
Historically, geothermal energy has been limited to areas with active or volcanic geology, like Iceland and California’s Salton Sea.
But an online map developed by InnerSpace shows that every congressional district in the country has geothermal potential, at the very least for residential and commercial heating and cooling, while in the West, the heat beneath the surface could be tapped to produce power, Beard said.
Wright did not mention the pilot projects in his remarks March 4, and DOE has not responded to NetZero Insider’s questions on the status of the funding, and whether the $60 million for the first-round projects has been paused or frozen.
In March 2024, DOE also released one of its Pathways to Commercial Liftoff reports on next-generation geothermal, which estimated that the U.S. could add between 90 and 300 GW of new geothermal generation by 2050.
Despite its apparent advantages in geothermal, the U.S. will likely face strong competition from China in next-gen geothermal development, some speakers at Geothermal House said. Chris Barnard, president of the American Conservation Coalition, a nonprofit focused on building a conservative climate movement, called for the government to “identify key things that we want to focus on, and then actually go and do them.”
“That’s one of the problems that we’ve seen with the federal government here in America … there’s just so much duplication, so many things just fall through the cracks,” Barnard said. “And when we want to compete with China, the reality is, when they want to go do something, they just go and do it. We need to have a bit of that mentality in our federal government as well.”
AUSTIN, Texas — An estimated 800 industry stakeholders gathered in the heart of Texas Feb. 25-27 for Infocast’s ERCOT Market Summit to discuss and share opinions on the unprecedented expansion of energy demand.
According to ERCOT projections, demand will reach 152 GW by 2030, up 73% from its current record peak of 85.51 GW set in 2023. A flood of data centers, cryptocurrency miners, new residents, and electrification of oil and gas production in the Permian Basin is driving that demand, which will require more generation and transmission and distribution infrastructure.
That has left the Texas grid operator, the industry and the state’s policy makers and regulators scrambling to find the best way forward to deal with the coming tsunami.
Legislators have responded with Senate Bill 6, which would create rules and policies for large loads looking to hook up to the grid. The bill would hit data centers with minimum transmission charges and require generation co-located with load to serve the Texas grid during grid emergencies.
ERCOT plans to add real-time co-optimization and a new dispatchable reliability reserve service within the year. The Texas Energy Fund, voted into law in 2023, offers about $5 billion for new dispatchable generation. At the same time, the Public Utility Commission is considering whether to approve 765-kV lines into the Permian Basin to serve that load.
Will it be enough?
“We’re used to integrating 5%, 8% growth … I don’t think that we’ve ever even conceived of the magnitude of loads trying to move in so quickly in such concentrated areas,” said Scott Bruns, director of power markets for Enverus. “It’s a three-legged stool. It’s the load, it’s the generation, it’s the transmission, and we can generally build all of those in sort of sync and phase. But right now, we’re having the conversation of, ‘If we build 20 GW of demand tomorrow, do we have the ability to transmit it?’ Then, do we have the ability to generate versus whatever generation sources we want to choose?”
“The grid was always built to manage load. Whatever the load wanted to do or whenever the lights came on, generation had to spin up. Whenever the lights were turned back on, [generation] had to back down,” said Clayton Greer, vice president of Cholla Petroleum’s energy division. “That was all fine for the last 100 years. That has all been turned on its head with these data-center-type loads.”
State Sen. Phil King (R) laid out SB6 during a Feb. 27 Senate Business and Commerce hearing, saying, “These large load customers’ demand for electricity is requiring ERCOT to plan for load growth at dramatically higher levels than experienced ever in the history of Texas and, frankly, ever in the history of the United States.”
In just 2025 alone, Oracle and Open AI announced Abilene, Texas, would be the first site of its $500 billion artificial intelligence network of data centers called the Stargate Project. Apple made a big splash with another $500 billion investment in a server-manufacturing facility in the Houston region to meet the demand.
Most recently, startup developer Last Energy said Feb. 28 it plans to build 30 micro nuclear reactors, with a combined capacity of about 600 MW, north of Abilene. The company has filed an interconnection request with ERCOT and is prepping an early site permit with the Nuclear Regulatory Commission.
ERCOT told stakeholders in February it had 99 GW of flexible large loads — defined as 75 MW connected to a transmission service provider or 20 MW when connected to a resource request — in various stages of study. In 2022, it had 2.6 MW.
“Some of these requests in excess of 1,000 MW are really starting to pose a risk to things like frequency stability or other kind of larger cascading events that we just haven’t seen with loads in the past,” said ERCOT’s Agee Springer, senior manager of grid interconnections. “The size of these interconnections, I think, is a potential risk for [system] reliability.”
Building out ERCOT’s aging grid to serve load will not come cheap. The proposed EHV transmission lines into the Permian Basin will cost at least $30 billion, in addition to normal upgrades.
“There’s going to be a time sometime in this decade, sometime in the next decade if reform isn’t achieved, where a customer will open their bill and more than half of the charges will derive not from their choices in retail electric provider, but in charges that result from centrally planned, socialized cost grid decisions,” said NRG Energy’s Travis Kavulla, vice president of regulatory affairs.
NRG has joined the party too, saying during its February quarterly earnings conference call that it plans to build 5.4 GW of combined-cycle gas plants to serve data centers in Texas and Virginia. The latter leads all worldwide regions in operational data centers with about 4.6 GW of facilities, more than doubling second-place Beijing.
“One of the things that we’ll need to make sure that as we grow the load, that we don’t continue to alienate individual customers. … Eventually the consumer is going to notice, and they’re going to take up their pitchforks,” Bruns said. “And so, we need to make sure that as we bring these loads in, that it’s not onerous to the rest of the system.”
EHV Lines Offer a Lifeline
One solution to the large load conundrum could be EHV lines. ERCOT has proposed 345- and 765-kV lines as options for its Permian Basin Reliability Plan. It also has proposed using EVH facilities as part of an upgraded transmission backbone.
The PUC, faced with a May deadline to decide which way to go, is holding a workshop March 7 that features equipment vendors and infrastructure builders offering their perspectives. Commission Chair Thomas Gleeson said he wants to ensure what he’s hearing from the transmission and distribution utilities is “accurate and reflects reasonable expectation from those manufacturers.”
“I know that we’re behind on building transmission, particularly to the Permian customers,” he said. “There are no solutions. There are only trade-offs, and so we want to make sure that we build enough transmission, particularly to the Permian, where their demand is just going to skyrocket. But it has to be done at a reasonable cost and on a reasonable timeline. Any delay of getting that transmission to the Permian is not acceptable, because we’re probably 10 to 15 years behind on what they already need.”
The plan is receiving a thumbs up from many stakeholders.
“ERCOT’s 765- versus 345-kV plan is some of the best long-term planning I’ve seen come out of ERCOT in over 10 years,” said former Oncor planner and current Owl Electric Reliability Consulting principal Ken Donohoo. “They’re finally talking about the right topic, transfer capability, not just about thermal limits or voltage limits or so on. It’s about transferring those megawatts across the grid.”
“It does sound like 765, especially for the Permian Basin, is the perfect solution,” said Sumeet Mudgal, transmission planning manager with photovoltaic manufacturer Qcells. “We have to also think about the contingencies. If we are adding a line that is going to carry 5,000 to 4,000 MW, we can’t just build one 765-kV line. We should think of adding another path that is able to carry an equivalent amount of power. I think a 765 backbone transmission is what probably will become our future.”
There’s a slight kink in the plan.
Texas State Sen. Charles Schwertner (R), chair of the powerful Business and Commerce Committee, filed a bill (SB1665) Feb. 27 that requires the PUC to conduct a study before approving a 765-kV line. The study, which would assess costs to residential customers, supply chain and workforce limits, and mitigation of cost overruns, is to be submitted to a third party for review.
“We need to do it now. If we don’t do it now, inflation and supply chain issues will only increase those costs,” warned ENGIE’s Bob Helton.
How Reliable are Future Projections?
Taking part in a panel discussing ERCOT’s market design, Katie Coleman, who represents Texas Industrial Energy Consumers, was asked about the grid operator’s load projections and whether all of it will show up. Saying a demand peak of 105 GW or 110 GW is a “better number” than ERCOT’s 152 GW projection, “I’ve said this 1,000 times, like I’m screaming into the void, but you cannot forklift a transmission planning number for resource adequacy purposes. They’re measuring two completely different things. There’s also this optics issue of the load over here, but you’re not counting any of that in the resource adequacy analysis, so you’ve got to do something to align those two.
“I don’t think putting all that load in a resource adequacy analysis is the right thing to do,” she added, noting that developers are putting a capacity number in their interconnection request that finds its way into transmission and resource adequacy planning numbers alike.
“I think the other thing that we’re seeing is a very different type of interconnection activity than what my traditional industrial and manufacturing clients have done,” Coleman said. “You have an end user who wants to use electricity to produce some product. They have their own business plans that they can discuss with the utility. There’s just a race to market in this area. You’ve got people putting in speculative interconnection requests.”
Coleman and other speakers also raised concerns with ERCOT’s Capacity, Demand and Reserves (CDR) report. Delayed for two months while staff revised the load forecast and renewable capacity, the report indicated negative reserve margins within two years under the most dire scenarios. (See ERCOT’s Revised CDR Report Met with Doubts.)
“Now, all of a sudden, it looks like Armageddon. Well, the facts on the ground haven’t changed really since the prior CDR,” Coleman said, saying her clients don’t like to put money around the report. “It’s a dangerous thing to use these types of tools which are so susceptible to sensitivities and inputs to move big dollars around.”
“The CDR itself is a static snapshot in time,” Luminant’s Ned Bonskowski said. “It does not reflect market dynamism, it doesn’t reflect behavioral responses from demand loads, load flexibility. It doesn’t reflect market signals that will incentivize supply to come in.”
“The more finicky or the more fussy that we get with the CDR, the less useful it is,” added Beth Garza, ERCOT’s former market monitor now with R Street Institute.
“Even if you doubt the CDR, no one can doubt that Texas is a tight market,” Kavulla said. “It’s not unreasonable, candidly, for people to have policy concerns around adding incremental loads, and frankly, good luck finding another market and another state that doesn’t have those same concerns. Everyone has those same concerns.”
Renewables Fight Headwinds
While the focus in Texas may be on dispatchable generation (i.e., nuclear and thermal), renewables continue to set production records that justify ERCOT CEO Pablo Vegas’ frequent references to an “all-of-the-above” strategy for resources.
On March 2, renewables set a new mark for renewables-to-load ratio, at 76%. With March arriving like the proverbial lion, wind (28.47 GW), solar (24.82) and storage resources (4.83 GW) all set record highs with the calendar’s turn. According to a January report, solar and batteries account for 82% of the resources in ERCOT’s interconnection queue, or 320 GW of capacity.
Yet the clean energy resources continue to face headwinds at the State Capitol, where proposed legislation (SB819) has been filed that would require only renewable developers to jump through additional hoops for operating permits. Neighboring property owners also would gain new authority to block the developments.
“I’m going to do my best to be diplomatic here,” said the Advanced Power Alliance’s Judd Musser, who tried his very best. He said the bill is “couched as siting and permitting,” except that it’s not.
“It’s a discriminatory and punitive permitting bill towards two resources and only two resources: wind and solar,” Musser said. “It would be a devastating blow to our industry. It would take us from a market here in ERCOT, where we’ve done the most business for the last 30 years, to probably the place where we would do the least.
“As a state that has thrived in harvesting our own kind of homegrown energy for so long, I think it would be a real shame to jeopardize that in the name of partisan politics or just the fact that maybe somebody doesn’t like to look at something,” he added.
Musser warned that the legislation will send a negative message to potential investors that could have lasting effects on the state.
“[Investors] want to be here because of a friendly tax environment and access to a skilled workforce and all those things,” he said. “If you send the message to them as a legislature that you’re going to pull the rug on them or you’re going to move the goal post … I think we really risk this Texas miracle that we talk so much about kind of falling by the wayside.”
Major regional and interregional transmission lines might be big investments, but they tend to produce more benefits than expected, RMI said in a report published Feb. 28.
“High Voltage, High Reward Transmission” looked into seven case studies from around the country — in all of the ISOs and RTOs — to look into how they actually benefited residential, commercial and industrial customers.
“There’s … huge momentum towards regional planning with [FERC] Order 1920, and we really want regulators and planners to feel confidence in this type of high-voltage, long-distance transmission to meet the energy challenges of today and tomorrow and really provide lasting value for consumers and businesses, especially when we’re kind of facing an affordability crisis in this country,” RMI’s Tyler Farrell, a co-author of the report, said in an interview.
The seven projects were built for different reasons — reliability, economics and meeting public policy — and all of them had benefits that exceeded their costs, even using conservative assessments. They include the Cross-Sound Cable between New York and New England; PJM’s TrAIL project; the Paddock-to-Rockdale line between MISO and PJM; MISO’s CapX2020 line; SPP’s Beaver-to-Oklahoma City line; ERCOT’s Bakersfield-to-Kendall project; and CAISO’s Valley-to-Colorado River line.
Five of the seven lines were built with economic benefits in mind, and they all had positive cost-benefit ratios. The three projects in which cost-benefit analyses were performed in the planning process all wound up beating those predictions in real-world operations. FERC has a standard that such lines exceed the ratio of 1:1.25; all five beat that easily.
The other two lines were reliability projects, and in addition to keeping the lights on, they led to unexpected economic benefits, RMI said.
Transmission investments are typically meant to last 40 years, but the lines in the study were all paid off in eight to 34 years. Farrell said projects can sometimes keep running much longer than four decades. One example from outside the study is the Pacific DC Intertie, which links the Pacific Northwest and Southern California and has been in operation for more than 50 years.
“When they were built, the administrator for [the Bonneville Power Administration] said that these lines pay for the construction costs of these lines every single year, for their entire lifetime,” Farrell said. “And now we’re in 2025 and yes, they made investments into those lines since then, but those lines are still in operation and delivering huge savings to people across the Pacific Northwest and in California.”
The report looks at three main ways transmission saves money: reduced congestion, access to cheaper generation, and access to renewable sources of generation that meet public policy goals. Some lines also have unique benefits.
“Transmission infrastructure, beyond its initial driver, is designed to adapt to unforeseen changes or events,” the report said. “Several projects have enabled the significant integration of renewable resources like solar, wind and storage, far exceeding original expectations because of substantial decreases in technology costs. This has lowered generation costs for ratepayers. Additionally, many projects have played critical roles in maintaining grid reliability during unforeseen extreme events, such as winter storms and heat waves, ensuring that the lights remain on for consumers.”
Texas spent billions on the Competitive Renewable Energy Zone lines to connect wind resources to the state’s major cities, but an unexpected benefit was that they enabled the electrification of oil and gas drilling in the Permian Basin, the report said.
Across all seven of the projects studied, congestion relief savings made up most of the benefits to ratepayers, and the report said it was the most straightforward benefit new transmission offers because it cuts fuel and variable costs, ensuring the grid operates as efficiently as possible.
Another recent RMI report, “Mind the Regulatory Gap,” highlighted how most transmission dollars lately were flowing to local projects, which often lack the same oversight as regional and interregional planning processes. It was cited in a complaint consumer groups filed last year asking FERC to address that gap, the comments for which are due March 20. (See Consumer Groups Seek Independent Oversight of Local Tx Planning.)
With most transmission costs going into those local projects, the industry is not at risk of gold-plating the grid by shifting more of its focus to regional and interregional projects, Farrell said.
“I actually think that regional planning is the opposite of that, which is really cost-effective planning versus local planning, which is non-cost-effective planning,” Farrell said. “It’s literally just reliability planning and building the system from the ground up, versus the top down, which is what regional planning looks like.”
New England energy market revenues increased by roughly 150% in the winter of 2024/25 compared to the prior winter, growing from about $1.6 billion to about $4 billion, ISO-NE COO Vamsi Chadalavada told the NEPOOL Participants Committee on March 6.
The increased costs were driven by consistently cold weather, Chadalavada said, adding that this winter was the first with lower-than-normal average temperatures since 2014. Despite that, the system did not experience any capacity deficiency events and maintained adequate oil inventories, he noted.
Natural gas accounted for about 40% of the total energy, followed by nuclear around 23%, imports around 21%, hydropower around 5%, renewables around 4% and oil around 2%.
Chadalavada noted that scheduled LNG injections into the gas system increased to 22.4 Bcf compared to the five-year average of 16.6 Bcf.
Spot payments for the RTO’s Inventoried Energy Program, which compensated thermal resources for maintaining stored fuel on-site, were triggered on five days. The two-year program expired at the end of February.
ISO-NE does not plan to renew the program, which cost about $80 million per winter. The RTO noted in a memo in February that “it has not found that the program provided a notable incremental impact on the regions’ fuel inventories.”
Tariff Uncertainty
ISO-NE also spoke with the committee about the uncertainty surrounding tariffs imposed by President Donald Trump on Canadian imports.
While the RTO has argued that the tariffs should not apply to electricity, it has requested authorization from FERC to collect them in case it is directed to do so by the Trump administration. (See ISO-NE Braces for Tariffs on Canadian Electricity.)
ISO-NE and NYISO have retained an outside counsel to engage with the Department of the Treasury and plan to make the case that electricity should not be covered by the tariffs, and if it is, RTOs should not be tasked with collecting the tariffs, a representative of ISO-NE said.
The RTO’s understanding is, because the secretary of the Treasury has not issued regulations to bring electricity into the scope of the import tariffs, there is no current tariff on electricity imports, the representative noted. Neither the executive order creating the tariffs nor the notice of implementation published in the Federal Register on March 6 explicitly reference electricity.
“I think the biggest thing at this stage is that we continue to seek more clarity,” ISO-NE spokesperson Matt Kakley said.
Committee Votes
The PC voted to support ISO-NE’s compliance proposal for FERC Order 904, which prevents transmission providers from compensating generators for reactive power within the standard power factor range.
The committee also supported changes to ISO-NE’s billing policy to account for a recently accepted change to the RTO’s financial assurance policy allowing an affiliate company to guarantee the payment of Pay-for-Performance charges. (See FERC Approves ISO-NE Capacity Market Collateral Requirements.)
Minnesota regulators voted unanimously Feb. 28 to require that Amazon demonstrate a need for a 250-unit fleet of backup diesel generators at its proposed data center in the central portion of the state.
The Minnesota Public Utilities Commission rejected Amazon’s late December petition to sidestep the state’s certificate of need process for its planned data center campus in Becker (CN-24-435).
During the meeting, Commissioner Joe Sullivan said his mind was “gravitating” toward the plain language of the state statute, which stipulates that any developer of a power plant capable of 50 MW or more must prove the facility is essential over cleaner or more inexpensive alternatives.
Amazon’s planned diesel fleet could generate as much as 600 MW. However, attorneys for Amazon and local labor union representatives argued that the generators should sidestep permitting because they would be strictly for emergency backup, not be connected to the grid and not affect ratepayers.
The topic has also reached the Minnesota Legislature, where Republicans are sponsoring a bill to change state law to exempt Amazon from a certificate of need. If passed, the PUC’s decision to require Amazon’s justification could be moot. The involvement of regulators and legislators demonstrates the uncharted territory of how hundreds of acres of proposed data center should be regulated.
Minnesota Department of Commerce associate counsel AnneMarie Curtin argued that state law is clear in that Amazon’s proposed emergency power fleet meets the definition of a large energy facility that requires a certificate of need.
Commissioner John Tuma said the sheer number of diesel generators proposed by Amazon is a “little shocking.”
“These are not expected to run more than a few times a year and less than 15 hours a year for the regular testing and maintenance that’s required for those systems,” argued Christina Brusven, appearing on behalf of Amazon Web Services. She said similar generators are stationed outside hospitals and government centers, albeit on a smaller scale.
Commissioner Hwikwon Ham pointed out that a “huge load” like Amazon’s that can drop suddenly from the MISO system can trigger an over-frequency event, especially considering the nearby “sensitive” Monticello Nuclear Generating Plant. He said he wondered whether Amazon’s proposed backup would be able to handle such a situation and said he would raise the issue during the certificate of need proceeding.
Tuma said perhaps behind-the-meter generation is not the best way to handle backup power at a site with such large power needs. He urged both Xcel Energy and Amazon to reexamine their ideas about the most appropriate source of emergency power.
“Maybe we can figure out something that benefits both the grid and the system and keeps it safe because, ‘This is a large load dropping off’ does scare me. These are loads that we are not used to dealing with. … This is something that’s new, and we need to understand what it means for the security of the system,” Tuma said. He urged Xcel to prepare answers on how the load could reliably trip offline and “meaningful alternatives” to the diesel fleet.
“I keep hearing from these Amazons and all these [companies] that they want to do the right thing, and they want clean energy, and that’s why they want to plop their data center right next to that solar facility, so I want to hear that those discussions have happened,” Tuma said.
Commission Chair Katie Sieben asked why Amazon did not simply file a certificate of need with its site permitting materials and then lobby for the bill in the legislature. She said it is “frustrating” that Amazon continues to “squeeze” the commission over ambiguous language in state law. She suggested that Amazon might sue the commission if the law is passed.
Brusven said it’s not Amazon’s goal to put the commission in a “difficult position.”
“It is. You did,” Sieben responded and suggested that Amazon could have been “farther along” in the permitting process at this point had it already opted to explain its need.
Sieben said she expected interested parties in the forthcoming certificate of need process to push Amazon for more environmentally friendly options like biodiesel.
MISO estimates its savings and efficiencies benefited its members to the tune of just over $5 billion in 2024.
It’s the first time MISO’s annual Value Proposition has averaged above $5 billion, though benefits in 2023 came close. (See MISO Estimates 2023 Member Savings Near $5B.) MISO said the 2024 range of cost savings is anywhere from $4.52 billion to $5.75 billion. The RTO subtracts membership dues from overall benefit estimates.
The RTO estimates its membership benefits annually through its Value Proposition study, where it attempts to quantify the benefits of its membership against non-RTO entities. MISO does not track cost savings to individual market participants but said members could expect $15 in savings to every dollar spent on MISO membership in 2024.
Per usual, the bulk of the savings (this time anywhere from $2.9 billion to $3.9 billion) is derived from members’ access to capacity sharing across MISO’s large geographic footprint. Efficiency gains from MISO’s energy and ancillary service markets rank second at anywhere from $881 million to $974 million. MISO’s ability to optimize the use of members’ renewable resources through grid planning again took third place at $403 million to $474 million.
MISO said its reliability category was on average less beneficial in 2024 ($337 million) than it was in 2023 ($346 million) because 2024 held fewer extreme weather conditions.
MISO said the value of its membership is poised to increase over the coming years as the fleet decarbonizes. It estimated cumulative benefits at $50 billion since 2007, when it first began producing the annual approximation.
In a press release, Senior Vice President and Chief Strategy Officer Andre Porter said members benefit from MISO’s “market efficiencies, grid planning and operational enhancements across a large and diverse footprint.”
The House Energy and Commerce Subcommittee on Energy held a hearing March 5 to discuss meeting the growing demand for power, with each party’s members claiming the other side’s policies were hindrances.
Data centers, industrial shoring and other factors are driving up demand now as thermal generation is retiring, subcommittee Chair Bob Latta (R-Ohio) said.
“Meanwhile, subsidized intermittent energy resources and public policy decisions in favor of renewable energy are flooding interconnection queues and making baseload power from coal, natural gas and nuclear near uneconomic,” Latta said. “Generation developers continue experiencing ongoing supply chains constraints for distribution transformers and generation turbines.”
The ranking member of the subcommittee, Rep. Kathy Castor (D-Fla.), pointed to recent disruptions in the federal bureaucracy.
“It’s rather absurd that we’re tackling strengthening our electrical system while Elon Musk and the Trump administration are taking a sledgehammer to the Department of Energy, and especially the initiatives that strengthen and modernize the grid,” Castor said. “The new administration has spent weeks illegally shutting down DOE grants and loans and partnerships that make energy safe, reliable and affordable.”
The administration’s tariffs on the country’s largest trading partners are making key grid and generation components more expensive, in addition to the higher power prices already being felt especially in northern states, she added.
While members took shots at their political opponents, both Latta and Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said the growing demand was an opportunity to seize economic growth and keep the U.S. as the leader in artificial intelligence.
“It means that companies are investing in America,” Pallone said. “The cutting-edge technologies are being developed here, and the families are making investments of decarbonizing their homes and vehicles. These are good things.”
Basin Electric Power Cooperative CEO Todd Brickhouse said the co-op is experiencing some of the same rapid load growth as other parts of the country. It serves 3 million customers living across 12% of the U.S.’ territory in nine states.
“Basin is currently increasing its generation portfolio by more than 40%, and we are increasing our transmission mileage by more than 20% over the next decade; we will spend $12 billion on these endeavors,” Brickhouse said. “That compares to currently $8.5 billion of assets on our balance sheet today.”
Improvements in federal permitting would help get that work done, with Brickhouse recounting how one transmission project required two different assessments from different bureaus under the Department of the Interior. Basin is also adding 1,500 MW of new renewable resources to help meet that load growth.
“This has required years of planning and development work, and these business decisions were made based on the availability of production tax credits [PTCs],” Brickhouse said. “We understand and we support the need to put our country on a sustainable physical path, but the immediate removal of PTCs will not allow utilities to plan for and avoid increased costs, and this will also immediately harm ratepayers.”
The tariffs will also make that $12 billion of overall expenditure more costly for ratepayers as Basin recovers the funds from ratepayers over the next several decades, Brickhouse added.
PJM is seeing load growth driven by new data centers and manufacturing, said Senior Vice President for Governmental and Member Services Asim Haque.
“PJM expects its summer peak to climb to 220,000 MW over the next 15 years,” Haque said. “To compare, our all-time summer peak, which occurred in 2006, is 165,563 MW.”
For years, PJM had a healthy reserve margin, but the load growth and some retirements are eating into that now, with the tighter supply-and-demand balance leading to higher capacity prices. With interconnection queue and capacity market reforms in recent years, the RTO has almost caught up with its queue backlog and is about to implement its new system, Haque said.
“We want as much supply as we can get in order to meet this growing demand, whether that’s delaying retirements, new supply, that supply in our queue and even additional supply on top of that,” Haque said.
PJM has cleared 50 GW of primarily renewable resources through its queue, which are having challenges related to financing, the supply chain, and state and federal siting processes. Repealing the Inflation Reduction Act and its tax credits for renewables would add financial strains to those projects, Haque said.
One way the customers behind the new demand could help the situation is by ensuring that they can offer some flexibility to the grid, said Tyler Norris, a James B. Duke fellow at Duke University.
The average use rate for the grid is just 53%, meaning that almost half of generation is sitting idle at most times, said Norris, the lead author on a recent study on data center load flexibility. (See US Grid has Flexible Headroom for Data Center Demand Growth.)
“Our analysis finds that with modest flexibility from new large loads, the grid can accommodate significant demand growth without major new infrastructure,” Norris said. “The U.S. power system is already designed to handle extreme peaks and demand, meaning that in most hours, a substantial portion of the power system is unutilized. …
“Flexible load strategies can provide a bridge, while long-lead resources such as new transmission and clean firm generation are developed.”
Noel Black, Southern Co. senior vice president of regulatory affairs, argued his firm’s vertically integrated, traditionally regulated model has prepared the region it serves well for the new load growth, in part by completing the new nuclear reactors at Plant Vogtle.
“Straightforward regulatory models like ours, where the accountability for the grid is clearly understood, are producing results enabling this innovation economy,” Black said. “In short, the Southeast remains open for business. Regions with unusually complex regulatory processes are experiencing slower infrastructure build out. I think this may be why the concept of co-location has become so popular in certain parts of the country.”
The Electric Power Supply Association, which represents independent power producers active in markets and some of which are pursuing co-location deals, released a statement on the hearing arguing that organized markets were poised to meet the growing demand.
“Appropriately structured competitive wholesale markets can drive innovation and competition and ensure that ratepayers are not exposed to any unnecessary or inefficient investment,” EPSA CEO Todd Snitchler said. “Given the uncertainty surrounding how fast demand will grow in the coming decades, it is critical that investment risk be borne by developers and not shouldered by ratepayers.”
A record 49 GW of clean energy generation came online in the U.S. in 2024, nearly 33% more than in 2023, the American Clean Power Association reported March 5.
Clean energy accounted for 93% of the new capacity added nationwide in 2024, ACP said in its new “Snapshot of Clean Power in 2024,” a condensed preview of the annual market report the trade organization will publish for members next month.
ACP paints a picture of momentum and acceleration of the buildout of U.S. clean energy, which for the purposes of the report is defined as wind, solar and storage.
It took more than 20 years for the U.S. to reach 100 GW of utility-scale clean power capacity, five years to reach 200 GW, then just three years to reach 313 GW.
ACP also repeated the all-of-the-above energy message it has been offering since November, when it became clear that a strong fossil fuel supporter would replace a staunch supporter of renewable energy as president of the United States.
“The only way to meet skyrocketing energy demand is to embrace all American energy resources,” ACP CEO Jason Grumet said in the announcement of the Snapshot. “The clean energy sector’s dominant performance in 2024 demonstrates the unique role clean power is playing in bringing electricity online now to support increased manufacturing and data centers.”
Breaking the 2024 total down into its components, some numbers are more impressive than others. The 33 GW of utility-scale solar and 11 GW of storage installed both far surpassed the previous records, but the 4 GW of land-based wind that came online in 2024 was the smallest amount in a decade.
An ACP map shows 175 MW of U.S. clean energy projects in advanced development or construction at the end of 2024. | American Clean Power Association
And while the single offshore wind farm that came online in 2024 did in fact set a record, it was a minor distinction: It offers only 132 MW, and it was competing against a 12-MW pilot project and a 30-MW near-shore facility that constituted the entirety of the U.S. offshore wind portfolio at the start of the year.
Other facts, figures and highlights from the 2024 Snapshot include:
The fourth quarter was the strongest quarter ever for solar installations (nearly 14 GW) and the second largest for clean energy in total (18.8 GW).
Onshore wind remains the largest U.S. renewable sector, but solar is closing in fast: 33.3 GW of utility-scale solar was installed, bringing the total to 129.7 GW, while 3.9 GW of new capacity brought the land-based wind total to 154.6 GW.
New natural gas generation totaled just 2.4 GW.
Nearly 9 GW of generation was retired, with coal- (50%) and gas-fired facilities (43%) accounting for most of the total.
Forty states now have more than 1 GW of installed clean power capacity, up from 37 in 2023; a dozen states saw their clean power portfolios increase by 1 GW or more.
The pipeline of projects in advanced development or under construction reached 175.2 GW by the end of the year; solar accounted for about half at 89.4 GW, but that was 5% less than a year earlier; battery storage accounted for a quarter of the pipeline at 45.1 GW, which was 49% more than a year earlier.
Forty-six clean-energy primary component manufacturing projects came online nationwide, providing $22 billion in direct investment; 85% of those projects were in states that voted for Donald Trump in the 2024 presidential election; and 79 new projects were announced to create or expand production.
Clean power generation is operational in 86% of congressional districts; 79% of the total capacity is within Republican-held congressional districts; and 77% of new capacity added in 2024 was within Republican districts.
FERC has approved two new NERC reliability standards that address the risks from energy sources with inconsistent output by requiring utilities to perform energy reliability assessments (ERAs) and develop plans to minimize the risk of any forecast energy emergencies.
According to the commission’s Feb. 26 letter order (RD25-5), BAL-007-1 (Energy reliability assessments) will take effect on the first day of the first calendar quarter that is 24 calendar months after the effective date of FERC’s order, or April 1, 2027. TOP-003-7 (Transmission operator and balancing authority data and information specification and collection) will become enforceable six months earlier than the other standard. NERC suggested this timeline when it submitted both standards Jan. 6. (See NERC Submits Energy Assurance Standards to FERC.)
FERC noted that Calpine, Ameren and Public Citizen each filed motions to intervene before the deadline of Feb. 5; however, neither these nor any other party has submitted comments or protests so far.
Both BAL-007-1 and TOP-003-7 were developed under Project 2022-03 (Energy assurance with energy-constrained resources), in response to weather-dependent resources like solar and wind generators to replace traditional inertial generation. NERC said in its filing that “traditional capacity-based planning methods and strategies may not identify [the] risks” associated with these resources and their inconsistent output resulting from volatility in weather and load.
BAL-007-1 will require balancing authorities to perform near-term ERAs and create operating plans to identify and minimize the possibility of forecasted energy emergencies. Assessments performed under the standard must review the resources necessary to serve demand while also providing operating reserves for the grid.
Assessment periods will begin no more than two days after the operating day, and cover between five days and six weeks. The standard allows BAs to specify how often they perform ERAs; all time periods must be covered unless the BA can demonstrate that an ERA is not needed for a specific time period because the risk of an energy emergency is low.
BAs can perform the near-term ERA for their work areas alone or jointly with other BAs for multiple areas at a time. Minimum elements that must be in near-term ERAs include:
forecast or assumed demand profiles;
resource capabilities and operational limits (including fuel supply);
energy transfers with other BAs; and
known grid transmission constraints that limit the ability of generation to deliver their output to load.
TOP-003-7 introduces relatively minor updates to TOP-003-6.1 intended to “ensure that [BAs] have the necessary data to perform the [near-term] ERAs” by adding them to the activities for which they “must have documented data specifications to collect data from relevant entities.”
This requirement is the reason for the gap between the two standards’ effective dates. NERC told FERC in January that staggering them would give entities time to collect the data needed for the assessments required under BAL-007-1.
FERC’s order constitutes final agency action, the commission said. Requests for rehearing must be filed within 30 days of the order’s issuance.
GLASSBORO, N.J. — Facing a projected 40% hike in regional electricity demand by 2030, New Jersey needs to rapidly craft a plan on how to boost generation and develop its transmission and distribution system, according to speakers at a Feb. 27 conference on the state’s energy future.
Power demand from data centers and artificial intelligence projects, along with the expected increase in electric vehicle use and building electrification, are driving demand forecasts that project a power shortfall without significant action, industry stakeholders and state officials said at Meeting New Jersey’s Energy Needs, held at and hosted by Rowan University’s Steve Sweeney Center for Public Policy.
The most visible sign of the shortfall was the Basic Generation Service auction held by the New Jersey Board of Public Utilities in February, which will trigger a hike of about 20% in the average residential bill in June.
“It’s a supply-and-demand issue … We need more electrons on the grid,” BPU President Christine Guhl-Sadovy told the conference of about 150 energy executives, government officials and other stakeholders. She added that it is “unrealistic to think that this kind of price shock can be absorbed by ratepayers without impact.”
Yet it is not clear in the current, uncertain political and energy environments where the additional supply to New Jersey, an energy importer, will come from, speakers said. The stalling of the state’s offshore wind projects, and the lack of clarity over the future economics of solar and other forms of renewable energy generation in the face of opposition to subsidies from the Trump administration, could upend the state’s expected reliance on those sources, speakers said. (See NJ Abandons 4th OSW Solicitation.)
“All these trends are evident in New Jersey,” former state Sen. Bob Gordon, a former BPU commissioner, said as he introduced a panel of generation company executives. “And we’re starting to see some real impacts of the supply-demand imbalance.”
The disruptions are unfolding amid ongoing warnings by PJM that aging fossil fuel plants are going offline at a faster rate than replacement plants are arriving, and the RTO is struggling to maintain a generation balance.
“The supply-demand crunch has come to us quickly,” said Asim Haque, senior vice president for PJM, who underscored the urgency of the situation by noting that the RTO saw its highest ever winter peak demand this year on Jan. 20, Martin Luther King Jr. Day.
In assessing how to boost generation, states need to understand that different generators have different “capabilities of how they can contribute to reliability on the system,” he said.
The suddenly oncoming demand suggests the state should move cautiously in its rush toward electrification, said Michael J. Renna, CEO of South Jersey Industries, which owns several natural gas distribution utilities in the state.
New Jersey’s heating-fueled winter peak is three times as high as the air-conditioning-driven summer peak, and “the grid, including all the way down to the utility levels, is built for the summer peak,” Renna said.
“You rush to electrification, you’ve got big problems, because neither the grid nor the utility systems are capable of moving that much electricity, let alone the fact that we have a generation cap,” he said.
He suggested the state instead focus on decarbonization by using gas with lower carbon content that can be used on existing infrastructure, such as “renewable natural gas or green hydrogen that can safely be blended with the geologic natural gas.”
Tim Sullivan, CEO of the New Jersey Economic Development Authority, which funded much of the state’s offshore wind initiatives, said he continues to believe that the economic and employment benefits of wind generation, and the escalating pressure to add supply sources, will return wind to the fore.
“We are not giving up on wind,” he said. “One of the reasons I’m confident in that is that we actually are seeing, outside of Jersey, progress in offshore wind projects. You’ve got electrons that are flowing in Virginia, New York and Massachusetts that are hitting their grids.
“It’s very hard to disabuse me of the notion that the best way forward for New Jersey” is to address the supply-demand imbalance with offshore wind, he said.
Nor is the state going to shy from the energy challenge presented by the demands of AI projects, Sullivan said.
“AI across the country, across the globe, is going to be an energy monster,” he said. He acknowledged that AI projects need “hundreds of megawatts to a gigawatt of power, and they need hundreds of acres of space,” both of which are limited in New Jersey.
Nevertheless, Gov. Phil Murphy is “smartly positioning the state to be a leader, not a follower, in AI,” Sullivan said. He noted that the state recently launched a program that will award $500 million in tax credits to support AI infrastructure and cited the example of a $1.2 billion state-of-the-art data center planned by CoreWeave. The company signed a lease in October on 280,000 square feet of space at the former global headquarters of pharmaceutical giant Merck in North Jersey.
Harnessing Existing Infrastructure
Hanging over any solution that helps boost generation is how to overcome the challenging task of connecting a project to the state’s transmission and distribution system, speakers said. That includes the well known delays with PJM’s generator interconnection queues.
In addition, all of the state’s four utilities, to varying degrees, have areas where projects cannot be connected because the infrastructure cannot accept them, said Lyle Rawlings, president of the Mid-Atlantic Solar & Storage Industries Association (MSSIA).
“That’s the big bad problem that we’re facing. It’s already putting tremendous downward pressure on our ability to deliver solar in this state,” he said.
The issue was a major factor in the drop in installed solar capacity in 2024, he said. BPU figures show installations were 40% below the 2023 level even as the state reached a milestone of 5 GW of installed projects.
Still, Rawlings said, the state is “on track” to reach its goal of 17 GW of installed solar power by 2035, and MSSIA modeling shows that by then it could account for 24.5% of New Jersey’s electricity, with nuclear contributing 34%. (See Struggling NJ Solar Sector Evaluates Net-metering Reform.)
Former Commissioner Gordon suggested that part of supply could be swiftly increased by connecting grid-scale battery storage through the infrastructure left behind by now closed generating facilities.
“The task of getting the PJM approval for a battery storage facility located at an old fossil fuel generating plant could take much less time than a brand new project,” he said. “I mean, maybe 90% of the analysis has already been done, and you’re not likely to encounter the political pushback from building something new in an area that might affect the neighbors, because people been living with this generating plant for decades.”
PJM’s Haque said the RTO is awaiting the result of an application to FERC to grant approval in such a situation. He said PJM also has sought permission to grant accelerated approval to projects that pair a generating facility that already has been approved with a battery storage project.
“It’s about trying to expedite resources,” he said. So an approved solar project could be paired with storage, enabling the batteries to “produce during periods where that solar unit can’t produce” and without forcing the storage operator to “go through the queue.”
Leveraging the Footprint
A similar strategy of harnessing “surplus interconnection opportunity” could be adopted by upgrading the state’s existing solar projects, said Lawrence Barth, director of corporate strategy at NJR Clean Energy Ventures, an energy project developer and operator.
“We ought to be thinking about how do we leverage that footprint now that we’ve got panels that produce two to three times that amount than when they were originally installed, at lower cost,” he said.
Several speakers suggested the state consider boosting generation by adding to the nuclear fleet in South Jersey, the Salem 1 and 2 plants and Hope Creek, which are operated by Public Service Enterprise Group and generate about 40% of the state’s electricity. They cited the example of Plant Vogtle — one of the first nuclear reactors built in the U.S. in nearly a decade — that came online in Atlanta in 2024.
But they also noted the extensive permitting bureaucracy, massive investment and lengthy construction timeline needed; Vogtle took 15 years to build. More feasible would be a small nuclear reactor, which could be built in five or six years, said Erick Ford, president of the New Jersey Energy Coalition.
“If they’re going to start the process now, [by] 2030 they should be able to have it online,” he said.
