RTO Insider

March 6, 2025

BPA Selects SPP Markets+ in Draft Policy

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 Jenn Strang, media relations manager at City Light. “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.”

The NW Energy Coalition noted that studies, including one commissioned by the agency itself, found that BPA would realize significant benefits by joining EDAM instead of Markets+. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits and Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)

“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.”

March 6, 2025

BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms

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.”

March 6, 2025

Republicans, Oil and Gas Ready to ‘Drill, Baby, Drill’ for Geothermal

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, he 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.

Energy Secretary Chris Wright delivers the closing keynote at the Geothermal House conference on March 4. | © RTO Insider LLC

“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.)

Rep. Randy Weber (R-Texas) | © RTO Insider LLC

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.

State of Play

In February 2024, the Department of Energy awarded $60 million in funding from the Infrastructure Investment and Jobs Act for three pilot projects, each using different enhanced geothermal technologies. A second round of funding for $14.2 million was announced in June. (See DOE to Fund Enhanced Geothermal Demo on Oregon Volcano.)

Sen. John Curtis (R-Utah) | © RTO Insider LLC

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.”

March 6, 2025

Texas Stakeholders Grappling with Tsunami of Large Loads

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.

The Sierra Club’s Cyrus Reed (right) listens to NRG Energy’s Travis Kavulla. | © RTO Insider LLC

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.

Katie Coleman, TIEC | © RTO Insider LLC

“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.

Judd Musser, APA | © RTO Insider LLC

“I’m going to do my best to be diplomatic here,” said the Advanced Power Alliance’s Judd Musser, who was anything but. 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.”

March 6, 2025

RMI Argues Regionally Planned Transmission Leads to Unexpected Benefits

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.”

March 6, 2025

New England Energy Market Costs Grew by over $2B in 2024/25 Winter

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.

In a change from ISO-NE’s initial proposal, the RTO will still allow compensation for reactive power outside the standard range. (See NEPOOL Transmission Committee Briefs: Feb. 27, 2025.)

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.)

March 6, 2025

Minn. PUC to Amazon: Prove Need for 250 Backup Diesel Generators

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.

March 6, 2025

MISO Annual Value Proposition Tops $5B for 1st Time

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.”

March 5, 2025

Parties Point to Each Other’s Policies as Drags on Meeting Demand Growth

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.”

Co-location is a major issue in PJM, where Haque said the RTO would have more to say in 30 or 60 days, as it is currently working to implement a recent FERC order. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.)

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.”

March 5, 2025

ACP Tallies US Clean Energy Surge in 2024

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.