Competitive markets might not have the same level of support as they did early in Pat Wood’s career, but the former FERC chair believes the politics will swing back in their direction.
“Growing up in the Reagan era, you did have a big faith in free markets,” Wood told Yes Energy’s EMPOWER Conference on March 5 in Denver. “I know that’s a little bit under attack these days, but I think truth will prevail. We’ll get through this rough period here and get to the other side.”
Wood was a FERC staffer when the commission was opening up the interstate natural gas markets in the 1980s. The markets worked well and opened new supply, so that by the 1990s, industry and regulators moved onto tackling electricity, recalled Wood, who is now CEO of Hunt Energy Network.
“FERC, at the same time, as we did in Texas in the mid-’90s, decided, ‘Let’s do the same magic trick on the power markets, because God knows, they could use it,’” Wood said.
Wood was the chair of the Texas Public Utility Commission under Gov. George W. Bush and was appointed chair of FERC after Bush was elected president. Texas had a law that required its industry to move at the same pace as the federal government, so Wood and other policymakers followed the Clinton administration’s work around Order 888 and the basic requirements for ISO/RTOs. That process gave Texas an example of what not to do in the form of California.
“We figured out what they did wrong, and we did it good,” Wood said. “So, we’ve been able to go to a deep, retail, deregulated market in Texas.”
Wood moved over to FERC in time to clean up the fallout from the Western Energy Crisis and to help set up the organized markets operating in interstate commerce.
“That was my job, my four years at FERC, to get all these markets set up into being RTOs and ISOs,” Wood said. “So, we pulled California back out of the ditch. You may argue it’s still there, but I think they’ve actually come a long way.”
Part of the lesson from California was that the markets needed to be monitored. FERC required RTOs to have market monitors and won new enforcement authority from Congress a few years after the crisis.
“We really just assumed that we could wave a magic wand and things would be competitive,” Wood said. “Folks, this industry was vertically integrated, regulated to the toenails for 100 years. So, you can’t just wave the wand overnight and say, ‘Oh, you’re competitive.’ We got to kind of undo the damage that’s done by the regulated enterprise. And so that took some time, and it still is, I guess, a project that’s not complete.”
Market power mitigation is important to that project, but as the markets mature with regional planning and resource adequacy constructs, that mitigation can be wound down, he added.
One of Wood’s biggest regrets was the failure of standard market design because that would have made it easier for competitors to get into the business all around the country. As the markets evolved, that happened naturally, but Wood said it was more like “Spanish and Portuguese” than dialects of the same language.
Now the growth of new technologies including intermittent renewables and storage, which Hunt helps develop, are leading to new realities on the grid.
“I do think that as grids move to more and more renewables, which is surprising to some, Texas is probably going to go ahead of California, and pretty much anywhere else in North America, and catching up with some of our people in the world,” Wood said. “We’re moving to a much more renewable-heavy grid, and so that world needs a different set of assets than we have had historically for those last 100 years.”
Hunt has rolled out storage around the Texas grid and has also started investing in small, dispatchable peaking generators that only run an average of 100 to 200 hours a year, as those growing intermittent resources need to be balanced, he added.
WALTHAM, Mass. — The uncertainty around federal funding, permitting approvals and tariffs on trade is creating major challenges for clean energy development in the Northeast, industry representatives said at the Northeast Commerce and Energy Association’s annual Renewable Energy Conference on March 5.
Turmoil in the federal government is creating “an atmosphere that is not good for business,” said Jeremy McDiarmid, managing director and general counsel at Advanced Energy United. “It’s been 44 days, and it seems like forever.”
Tariffs on Canadian imports threaten to add “hundreds of millions of dollars in potential costs for New England electric customers,” McDiarmid said, noting that this could be “extraordinarily damaging for the ratepayer at the end of the day.”
Patricia Tamez, senior adviser at Shell Energy, said the tariffs could be particularly damaging for clean energy technologies with nascent supply chains.
“Everybody needs investment certainty. … Supply chains for a new industry are difficult to set up,” Tamez said. “The starts and stops make it very hard to predict what’s going to happen.”
“There is conflicting information from the government agencies on whether a tariff can be collected on the provision of electricity,” Tamez said. “This conflict has been noted by many, but the government hasn’t yet announced a clear position.”
Meanwhile, Hydro-Quebec has considered cutting off exports to the U.S., according to reporting by The Globe and Mail. The company already faces extremely low reservoir levels because of an extended drought, putting it in “an excellent negotiating position” to potentially pause exports as it recharges its reservoirs, Robert McCullough of McCullough Research noted in an email.
Imports from Quebec have met about 11% of demand in ISO-NE over the past five years, and the RTO has said cutting them off could create “precipitous, adverse consequences” for grid reliability.
Regarding federal funding, Tamez said it appears unlikely that Republicans will fully repeal the Inflation Reduction Act, noting the large amounts of funding that have gone to Republican congressional districts and the “very large coalition that’s developed across energy sources to protect the IRA.”
McDiarmid said there is “a lot that states can do” to fill the gaps left by the federal government, but he acknowledged that the states lack the “the financial prowess to replace the finances that these federal tax credits can provide.”
Speakers said the challenges to clean energy development come at a difficult time for the region, which is preparing for an exponential increase in demand growth over the next couple decades. ISO-NE projects its peak demand to grow from about 25 GW in 2024 to about 57 GW in 2050.
The New England states will need to keep pace with load growth while simultaneously reducing fossil generation, which accounted for the majority of generation in the region in 2024. (See New England Gas Generation Hit a Record High in 2024.)
“We’re definitely moving to a world where both the supply and demand both are going to be highly variable and dependent on the weather,” said Marianne Perben, director of planning services at ISO-NE.
Michael Judge, undersecretary of energy at the Massachusetts Executive Office of Energy and Environmental Affairs, noted that the state will need to deploy about 24 times more wind and six times more solar than current levels to meet its climate mandates.
“We need to build a lot, and we need to do it really quickly,” Judge said. He highlighted the changes to permitting and siting processes enacted by the state in 2024, which are intended to streamline and expedite clean energy infrastructure approvals. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track.)
For the storage industry, “federal policy uncertainty right now is obviously a huge challenge,” said Sean Burke, director of policy at BlueWave Energy. He said the tariffs have created complications for state procurements and power purchase agreements.
New England states are aiming to massively scale up the region’s storage capacity in the coming years. The Connecticut legislature has established a storage development goal of 1,000 MW by 2030; Rhode Island has a goal of installing 600 MW by the end of 2033; and Massachusetts plans to procure 5,000 MW over the next five years.
Hans Detweiler, senior director of development at Jupiter Power, emphasized the importance of soliciting “apples to apples bids” to enable state agencies to see how the bids are priced and potentially adjust the pricing to account for major changes in federal policy.
Detweiler said he remains optimistic about the “long-term opportunity” of storage in the Boston area, adding that “within the Boston load pocket, our view is the volatility is going to come,” which will create the demand for storage resources.
MISO plans to file with FERC by mid-March a proposal to implement a fast-tracked interconnection queue lane for select generation projects.
The grid operator gathered stakeholders for a final workshop March 7 before advancing its proposal to introduce an “expedited resource addition study” in its queue. Its plan would have the RTO processing projects designated as essential by regulators through a separate queue equipped with specialized, dedicated studies instead of the cluster-style studies it uses in the regular queue.
MISO has notified FERC staff of its intention to file. The grid operator hopes to oversee its first applicants at the beginning of June.
“We’ve heard from FERC staff that it’s one of the most talked-about changes in the industry right now,” Director of Resource Utilization Andy Witmeier said. He said several in MISO’s stakeholder community want the fast track to help resolve imminent resource inadequacy. (See Generation Developers Ask for Scoring System on MISO Queue Fast Track.)
Witmeier said MISO’s current queue is not up to the challenge of processing new projects in a timely manner because of a pileup of study delays. As of Feb. 6, the queue contains about 308 GW across 1,695 projects, according to the RTO.
MISO Executive Director of Resource Adequacy Scott Wright has said the RTO wants to conduct the serial, expedited studies to “fill the gap for a few years” until the normal queue improves so that routine processing of projects can be completed within the span of a year.
But for now, Witmeier said it is important for necessary generation projects to get the benefit of standalone studies that clearly show estimated network upgrade costs without the numerous project dropouts of the regular queue muddying study results.
Witmeier said projects “must be tied to some reliability or RA need” to enter the express lane. Developers submitting applications would need to submit a new form and documentation from their applicable regulators demonstrating a project’s importance.
MISO would not independently evaluate the need for projects, explaining that would trample on states and load-serving entities’ role as resource planners, Witmeier said. “We are not the ones to decide what generation should serve load. We study what reliability impacts occur because of generation additions, load additions,” he said.
Projects that take advantage of the express lane would be expected to be in operation no later than 2032. In the first two years of the express lane, projects would enjoy MISO’s usual three-year grace period of commercial operation dates beyond its three-year in-service expectation. Projects that enter the fast track in 2027 and 2028, however, would be limited to a single three-year period from developer submission to produce power.
The RTO intends to retire the fast track after a few years.
Witmeier said the elimination of the additional three-year extension for projects entering in later years tries to recognize the current, frazzled state of the industry’s supply chain and the hope that it can be repaired within a few years.
But Wisconsin Public Service Commissioner Marcus Hawkins said he thought the structure could open MISO to “bottlenecks” where developers rush to enter projects.
“It’s weird, and it’s hard to explain, and it’s something I think FERC would find problematic,” Hawkins said of the split deadline structure during an Organization of MISO States meeting in late February.
Warren Hess of Central Municipal Power Agency/Services asked how the RTO would ensure it was not overbuilding transmission by maintaining separate queue processes.
“There are multiple parallel processes going on all the time at MISO,” Witmeier said, adding that the Business Practices Manuals mandate double-checking the necessity of transmission projects before they are finalized.
“The one, new wrinkle — and it’s not new — is you can change the flows and have a new constraint show up,” Witmeier explained of the simultaneous queue studies.
He said that while the new process could introduce the “slight chance of over-allocating transmission capacity,” MISO is on the lookout for such constraints through its annual transmission planning.
SPP says it has named Carrie Simpson, a key figure in its expansion efforts in the Western Interconnection, as its vice president of markets, effective April 1.
Currently the RTO’s senior director of seams and Western services, Simpson will replace Antoine Lucas, who was recently promoted to COO.
Simpson will be responsible for overseeing the development, design and delivery of all SPP market-based services and will serve as the executive sponsor of the Markets+ effort, a regional day-ahead wholesale market that is in its second stage of development.
Simpson helped develop SPP’s Integrated Marketplace — a next-day market that serves as the foundation of the RTO’s Western market offerings — before taking a position as Western markets director with Xcel Energy subsidiary Southwestern Public Service in Colorado in 2015. She rejoined the RTO in 2022. (See SPP Brings Back Ex-staffer to Develop Western Services.)
Simpson has more than 20 years of industry experience. She holds an undergraduate degree from Harvard University and a law degree from the University of Denver’s Sturm College of Law. She is licensed to practice law in Colorado.
stood up the Western Energy Imbalance Service market;
operated the Western Power Pool’s Western Resource Adequacy Program;
attracted seven members as part of its RTO expansion into the West, scheduled to go live in 2026; and
begun development of Markets+.
SPP would not be the first grid operator with satellite offices: Neighboring MISO has offices in Eagan, Minn., and Little Rock, Ark., in addition to its corporate headquarters in Carmel, Ind.
The Seams Advisory Group inaugurated the office’s conference room with a meeting March 7. SPP’s Jena Arnold told stakeholders the RTO expansion effort is in a holding pattern while waiting on FERC approval of its filed tariff before it can begin collaborating with other planning regions. The RTO expects to set up joint operating agreements with at least nine other utilities in the West.
New Winter Peak Set
C.J. Brown, SPP’s director of system operations, told the Resource and Energy Adequacy Leadership (REAL) Team on March 3 that the RTO set a new winter peak of 48.14 GW in its balancing authority area Feb. 20.
“It was very, very tight,” Brown said. He noted that SPP relied on 3 GW of imports to make up for a loss of wind production that was down that day as compared to Feb. 19. He promised a full presentation before the Markets and Operations Policy Committee with “plenty of graphics and details.”
The REAL Team did not take up any voting items during its short meeting before SPP’s Energy Synergy Summit.
The Bonneville Power Administration announced March 6 that it intends to join SPP’s Markets+, saying in its highly anticipated draft policy that the day-ahead market “is the best long-term strategic direction for Bonneville, its customers and the Northwest.”
The purpose of the draft policy is to clarify which day-ahead market offering BPA will pursue and to continue to support the development of Western energy markets, the agency said. Following a 30-day public comment period, BPA expects to issue a final record of decision in May, according to a news release.
BPA choosing Markets+ over CAISO’s Extended Day-Ahead Market (EDAM) is perhaps unsurprising given an agency staff report published in April 2024 recommending that it join SPP’s offering. Still, the draft policy follows months of discussions and debates about the impact of BPA’s choice on Western electricity markets and customers. Even United States senators have weighed in. (See BPA Staff Recommends Markets+ over EDAM and BPA Has not Made ‘Business Case’ for Markets+, NW Senators Say.)
BPA said it landed on Markets+ based on “overall market design features, including an independent governance model, uniform resource adequacy requirements, superior GHG design and congestion revenue design that incentivizes transmission investments.”
Independent governance has been a key consideration for BPA. Staff have argued that Markets+ provides greater independence from California state influence compared with the EDAM option. The draft policy reiterates this point, saying that “independent market governance continues to be paramount to Bonneville’s policy direction towards participation in Markets+.” It notes that Markets+ will be governed by an independent panel whose members “must be independent of market participants.”
By contrast, efforts launched by the West-Wide Governance Pathways Initiative to ensure independent governance of CAISO’s EDAM and Western Energy Imbalance Market (WEIM) have not gone far enough, it says.
A proposal under Step 1 of the Pathways Initiative to elevate the Western Energy Markets Governing Body’s authority over CAISO energy markets was approved unanimously by the body and ISO’s Board of Governors in 2024. (See CAISO, WEM Approve Pathways ‘Step 1’ Tariff Amendments.)
Still, the board will continue to exercise some influence, and “critically, the day-to-day management of policy development and market operations remains with CAISO management, who ultimately report to the” board, the policy states.
California lawmakers recently introduced SB 540, or the Pathways Bill, setting conditions under which CAISO and Golden State utilities can participate in energy markets governed by an independent regional organization. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.)
However, passage of the bill is not guaranteed, and though BPA supports the effort, “the current Pathways proposal does not go far enough to meet … what our expectations are of an independent governance model,” Rachel Dibble, BPA vice president of bulk marketing, told reporters.
Dibble added that BPA believes the ideal governance model already exists within the Markets+ framework, saying “it’s there for us right now. [With] the California model, the changes are still just speculative.”
Jayme Ackemann, CAISO’s head of communications, told RTO Insider that the ISO appreciates BPA’s contributions to the development of regional markets in the West. She noted that BPA and other utilities have benefited from the WEIM, saying the real-time market has “has delivered substantial reliability benefits and cost savings of nearly $7B to consumers.”
“BPA’s final market decision will have major impacts on reliability and affordability for electricity customers in the Northwest and across the West,” Ackemann said. “We encourage BPA to continue to evaluate EDAM and engage in the Pathways Initiative as governance reform legislation works its way through the California legislature.”
Antoine Lucas, SPP’s vice president of markets and incoming COO, also offered his thoughts, saying SPP is encouraged by BPA’s draft policy.
“From the outset, our goal has been to provide a competitive market option that could earn the participation of Western stakeholders,” Lucas said. “Through its detailed analysis of day-ahead market choices, BPA has concluded in its draft policy paper that Markets+ will provide the most benefits for their customers.”
Reaction Through the West
Scott Simms, executive director of the Portland, Ore.-based Public Power Council (PPC), said “BPA’s decision to move forward with Markets+ underscores the strength of the SPP Markets+ option, which was designed by diverse stakeholders across the West.”
“With many utilities across the Northwest and Southwest already supporting Markets+, this decision signals even greater momentum toward a broad and well-structured market that delivers reliability and cost benefits,” Simms added. “We encourage additional utilities to consider joining this effort to further enhance regional coordination and market efficiencies.”
The PPC, which represents the Northwest’s extensive network of publicly owned utilities that make up BPA’s base of “preference” customers, began actively urging BPA to choose Markets+ over EDAM even before the agency’s staff issued its “leaning” in favor of the SPP market last spring. (See Northwest Public Power Group Endorses Markets+ over EDAM.)
In its statement, the PPC pointed to the SPP market’s “well-defined, inclusive and transparent decision-making process that ensures public power’s interests — along with those interests of other stakeholders and participants — are represented and protected over the long term.”
PPC Chair Chris Robinson, general manager of Tacoma Power, said the group appreciated “BPA’s thoughtful approach and transparent process used to reach this decision.”
Meanwhile, Seattle City Light expressed disappointment with the decision.
“Having two markets in the region is inefficient [and] will negatively affect consumer rates and potentially cause adverse effects on regional greenhouse gas emissions reductions and reliability, especially during extreme weather events,” said City Light CEO Dawn Lindell. “We remain steadfast in our position that our customers are best served with an efficient, well-connected and integrated market.”
Brian Turner, Western regulatory director at Advanced Energy United, shared City Light’s sentiment. Turner said in a statement that BPA failed to consider the many stakeholders who urged it to pause its market decision.
“Joining a smaller, more balkanized market undermines the very affordability and reliability of clean energy resources that the region depends on,” Turner said. “By rushing into this decision, BPA risks hitching its wagon to the wrong horse. With this decision, we are now heading toward a bifurcated West that will be intermeshed with costly seams running all over the region. Working together in a larger, more unified market, the West could be an energy powerhouse for the nation, but this decision threatens to put that vision out of reach.”
“In the coming weeks, we will further analyze this proposal and work to align BPA’s final decision with the best interest of all regional stakeholders,” NWEC Executive Director Nancy Hirsh said.
However, BPA has argued that the studies show a wide range of outcomes and cannot capture the full economic picture.
“In addition, this has never been a purely quantitative decision,” BPA’s Dibble told reporters. “We have really significant beliefs about the importance of governance, the importance of an open stakeholder process, and while those cannot be quantified, those are qualitative elements that we hold as very high priorities.”
She said those qualitative factors will, in the long run, lead to “positive quantitative benefits” because of Markets+’s “equitable” governance framework.
Asked whether BPA is concerned about the lack of transmission connectivity among entities that have committed to Markets+, and whether those entities are seeking to take steps to ensure the ability to trade, Dibble said the agency’s policy paper acknowledges the “limited connectivity between regions that we do hope, over time, will become more robust,” but she acknowledged that no plans for new transmission are in place.
“However, recognize that the final footprints are not solidified at this point,” she added. “There are still several entities who may have leaned in one direction that could rethink their decision because they have not signed agreements at this point. There are some that have been silent who could now step up with a decision and join either footprint. So I think it is premature to believe we know exactly what the footprints are going to be.”
The U.S. Department of Energy will allow the Bonneville Power Administration to reinstate 89 “probationary” employees and could provide the federal power agency exemptions from the Office of Personnel Management’s reductions in force (RIF) order, a BPA representative has confirmed to RTO Insider.
“We are working to get more exemptions from the RIF,” the representative said March 6.
The representative said they believed the 89 reinstatements would be in addition to the 40 probationary staffers already restored to their positions.
The move comes after OPM updated its guidance to department heads, saying that it was up to them whether to fire such workers.
Despite BPA’s status as a self-funding federal agency, its staff in January received the same “deferred resignation” buyout offer from President Donald Trump’s unofficial Department of Government Efficiency, immediately setting off alarms in the electricity sector about the impact on the region’s grid reliability. (See BPA Employees Confront Trump’s ‘Fork in the Road’.)
During a quarterly business review call Feb. 13, BPA Administrator John Hairston said about 200 agency employees — or 6% of the workforce — had accepted the Trump administration’s buyout offer, while 90 job offers had been rescinded following a federal hiring freeze announced Jan. 20.
Last month, Sens. Jeff Merkley and Ron Wyden, both Democrats of Oregon, called on the Trump administration to justify what they called “reckless” and “financially ludicrous” cutbacks that could compromise BPA’s ability to maintain grid reliability. (See Ore. Senators Ask Trump to Justify ‘Reckless’ Job Cuts at BPA.)
Scott Simms, executive director of the Portland, Ore.-based Public Power Council, previously told RTO Insider that he estimated BPA faced a loss of about 400 staff, which included resignations and the firing of probationary employees. Simms also warned about massive cutbacks of vital technical positions at the U.S. Army Corps of Engineers, the agency that physically operates most of the hydroelectric dams in the Northwest. (See 2 Top BPA Execs to Depart; Army Corps of Engineers also Faces Massive Cutbacks.)
Asked what might have turned the tide for BPA, Simms said: “While I have no direct knowledge of how a potential RIF may or not be considered for BPA, I am certain that the extensive industry and congressional outreach about the critical nature of the work BPA does — and the fact that it is a ratepayer-funded and not taxpayer-funded federal agency — really moved the needle on the probationary employee reinstatement.”
Simms added that the PPC is “incredibly grateful to DOE for hearing that message and for taking action to restore these critical workers to their jobs, and we are hopeful that as government-wide RIFs are considered, BPA and its federal generating agency partners can be exempted because of their important missions.”
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.)
