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December 14, 2025

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New Tech, Collaboration Key to Targeted PSPS, WECC Panelists Say

As large swaths of the West continue to explore ways to mitigate wildfire risk, utilities say information sharing and new technologies allow them to implement targeted public safety power shutoffs (PSPS).

Representatives from three utilities discussed PSPS during a webinar hosted by WECC on Aug. 6. A PSPS is when an electric utility temporarily shuts off power to reduce the risk of wildfire caused by the company’s equipment.

Southern California Edison, which serves about 15 million customers, has approximately 1,800 weather stations that are deployed across high-risk wildfire areas and provide real-time updates on conditions, said Kevin Alirez, a senior adviser with the utility.

But in an effort to avoid PSPS, SCE has “aggressively pursued grid-hardening efforts” around areas that are most prone to PSPS, including undergrounding of transmission lines and covering conductors, Alirez said.

“We’re installing more isolating devices as well across our distribution circuits so that we can be more surgical and more precise on those specific areas across our grid to do those de-energizations,” he added.

SCE also is looking at microgrids as a strategy for PSPS “where it makes sense,” according to Alirez.

“Battery energy is a big thing coming out too,” Alirez said. “So where can we potentially add battery energy storage units across our grid that would make most sense from a PSPS de-energization perspective?”

Carrie Laird, managing director of emergency management and meteorology at PacifiCorp, said PSPS is a last resort in wildfire mitigation.

In order to reduce the impact of PSPS, PacifiCorp focuses on sectionalizing its system “so that we can impact smaller subsets of customers with the introduction of … smart protective devices, early fault detecting devices,” Laird said.

The utility uses cameras powered by artificial intelligence, among other technologies, to detect wildfires faster, according to Laird.

Laird also noted that because of the challenging geography of PacifiCorp’s service area, the utility’s communications connections to its transmission and distribution system have been “pretty far behind the big California utilities … so that’s a huge area of focus.”

For the Public Service Company of New Mexico, PSPS is a great tool, but the goal is “to never have to do a PSPS,” according to Thad Petzold, associate director of wildfire risk and vegetation management.

“The first thing you do when you decide you’re going to have a PSPS policy is try to minimize the impact to your customers,” Petzold said. “And so you’re using sectionalizers, and you’re figuring out ways to really make those areas more granular … this isn’t something that we necessarily want to do, but it’s something that we will do for safety.”

An important part of ensuring that a PSPS has limited impact is collaborating with other utilities and states, he noted.

“Because … otherwise you’re stuck doing a lot of different trials and projects where you’re trying … that out and the data takes such a long time to really incorporate,” Petzold said. “So you look at what successful people do, you copy them, and you do it in, in our case, the most frugal way that we possibly can.”

Similarly, coordination and communication between utilities is important to avoid customer confusion, especially when the counterpart does not have the same type of PSPS planning, according to Laird.

Still, with the threat of wildfires growing and high fire-risk areas constantly changing and expanding, Laird said a PSPS “can happen anywhere if the combination of … the fuels and weather conditions are right.”

“It’s not just [a] California problem anymore, and it’s not just a … wild-urban land interface or rural problem either,” she added. “The topic of urban conflagration is a hot one right now. So the preparedness piece of this could happen anywhere, and helping our customers get to a space where they’re prepared should they be impacted is kind of an important area of focus.”

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MISO Requests Month to Respond to States’ Long-range Tx Complaint

MISO has asked FERC for a month to prepare a defense of its second long-range transmission portfolio, which is being challenged by five state commissions in the footprint.  

The grid operator said it needed an extension to respond to the 200-page complaint alleging that its $22 billion transmission package for the Midwest region isn’t as valuable as purported. As it stands, MISO is to respond to the complaint, filed July 30 by the public service commissions of North Dakota, Montana, Arkansas, Mississippi and Louisiana, by Aug. 19. The RTO asked for the deadline to be pushed to Sept. 19. (See Five Republican States File FERC Complaint to Undercut $22B MISO Long-range Tx Plan.)  

MISO said it didn’t receive notice from the commissions that they planned to dispute the transmission portfolio. It also said it needed time to review testimony, conduct analyses and prepare its own expert witness testimony in response to testimony from William Hogan, research director of the Harvard Electricity Policy Group and professor emeritus at the John F. Kennedy School of Government at Harvard University.  

Hogan testified that MISO’s assumptions and cost-benefit analysis “contain several significant defects,” including environmental benefits extended to states that don’t believe there is a social cost of carbon; reliability benefits premised on unlikely instances of load shedding as the alternative at a rate of $3,500-$10,000/MWh; and a distorted avoided capacity cost benefit that doesn’t imagine materially different and closer-to-load generation resources being built without the transmission projects. The criticisms track those that MISO’s Independent Market Monitor made in 2024. (See MISO Board Endorses $21.8B Long-range Transmission Plan.)  

Hogan also said he took issue with the 29.8 GW of high-accreditation “flex capacity” MISO assumed would be built by 2042 to meet resource adequacy requirements despite no concrete plans from members. Hogan said if members built the nearly 30 GW in highly available capacity, it would obviate the need for scores of wind and solar generation projects MISO also assumed in its modeling.  

MISO has said repeatedly that its second long-range portfolio is founded on the generation plans that its members have communicated to it. The RTO also noted that 75% of the footprint’s load is served by members with ambitious decarbonization or renewable energy goals.  

The five state commissions asked FERC to deny MISO’s request for extension. They argued that MISO’s subject matter experts are in-house and “MISO should have on hand all the materials to support its case, primarily the package of information it presented to receive the board’s approval.”  

They also said the filing should come as no surprise, because every concern they outlined with the transmission portfolio was raised multiple times by stakeholders, some state commission staff and MISO’s own Independent Market Monitor as the portfolio was being drawn up.  

“MISO had ample time to respond to those concerns but failed to substantively address them,” the five state commissions said.  

The states added that should FERC decide to grant an extension, it should be limited to two weeks beyond Aug. 19.  

The North Dakota Public Service Commission — one of only two state commissions that joined the complaint that are expected to fund some of the long-range transmission — circulated a press release explaining that ballooning transmission costs drove their decision to draft the complaint.  

“Transmission costs are rapidly becoming a large portion of utility customer bills, and their costs need to be carefully scrutinized,” Commissioner Jill Kringstad said. “I recognize the importance of transmission infrastructure, but it must be a prudent investment that balances affordability with the long-term needs of the grid.” 

Commission Chair Randy Christmann said MISO gave a “weak justification” for the projects and that they will lead to “massive cost increases for residents.”  

“Overturning MISO’s decision will protect North Dakotan consumers from this egregious maneuver,” he said.  

Commissioner Sheri Haugen-Hoffart said she opposes “any cost allocation framework that compels states to subsidize transmission projects driven by other states’ public policy goals.”  

“If a state chooses to pursue ambitious decarbonization targets, it should also bear the financial responsibility for the infrastructure required to meet those goals. Anything less undermines the principle of just and reasonable rates and imposes unfair financial burdens on ratepayers in states that have not adopted such policies,” Haugen-Hoffart said. 

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Stakeholder Forum: Will Christie’s FERC Tenure End in a Bang or a Whimper?

By Paul Cicio

FERC Chair Mark Christie’s five-year term officially expired June 30, yet Senate gridlock over unrelated issues means President Trump’s nominee, Laura Swett, is unlikely to be confirmed any time soon. 

Christie, a vocal critic of high transmission costs and transmission incentives “candy” that impact every consumer in the nation, has only a couple of weeks to act to reduce consumer costs. The question is, will his tenure end in a bang or a whimper? He has the desire and intent, but will Commissioners Rosner, See and Chang follow his lead?  

In his July 24 monthly meeting press conference, Christie said transmission costs are responsible for increasing electric rates being imposed on every consumer in the nation. Electricity prices are escalating nationwide despite the fact that until recently, demand has been flat. Each year for the past 10 years or so, monopoly utilities have spent billions of dollars per year on transmission and less than 10 percent of these transmission projects were competitively bid, which would have reduced consumer costs. 

Paul Cicio

Economists frequently comment on rising inflation but miss the fact that electricity prices, which typically are stripped out of core inflation measurements, have consistently exceeded the consumer price index. The consistency of these price increases goes back longer than the AI-driven data center boom, and other inflationary factors. It is a price response to a policy problem: a lack of competition. 

PJM, the largest RTO in the country, is a cautionary tale. In 2014, transmission charges were 6.8% of the PJM wholesale price. A decade later, they are over 32%, even though demand has barely moved. 

Where projects have been competitively bid, consumers have seen cost reductions of up to 40%. More than $100 billion in new transmission projects are in the planning stage or in implementation, which should give FERC impetus to act to reduce costs.    

Failures by FERC, RTOs and states to embrace and enforce competition are at the heart of high transmission costs. Electric utilities spend tens of millions of dollars per year lobbying to protect their monopoly and have largely succeeded. Homeowners have no idea that their utility is putting profit over the interests of their customers. Utility actions to prevent competitive bidding of transmission lines is anti-consumer, anti-competitive, anti-market and anti-American.  

PJM Transmission Owners’ annual transmission formula rate informational filings | PJM Transmission Owners

Consumers support competition, as does President Trump. One of his executive orders calls for each federal agency to root out regulations that are harmful to competition. Trump has pledged to reduce the cost of energy, and this is a good example of regulations that are anti-competitive and drive up the price of electricity for decades to come.    

When a new transmission line is put into the rate base, consumers will pay for it over the next 40 years or more. Added to the cost of the transmission line is a rich ROE and financing costs that can increase the total cost by seven to eight times.   

Building transmission lines is a lucrative business for utilities, which is why they fight against competitive bidding of transmission lines at FERC, at RTOs and in their states. In 2024, utilities pushed legislation in Oklahoma, Wisconsin, Indiana, Missouri, Illinois and Kansas that that instituted rights of first refusal, preventing transmission lines in their territory from being competitively bid. 

The Industrial Energy Consumers of America has filed several legal complaints and motions for rehearing that have been sitting at FERC, some for months and others for years. Those filings would be a good place to start and also eliminate the “candy,” as Christie calls it. The candy is transmission economic incentives that are not needed, inflate costs and are inconsistent with “just and reasonable” rates.         

Chairman Christie, the moment is now: Finish what you began and break the grip of monopoly transmission and escalating electricity prices. Let your tenure end with a bang. 

Paul Cicio is president of Industrial Energy Consumers of America and is a consumer advocate. 

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Constellation Optimistic About Nuclear-friendly Federal Policies

Constellation Energy said it is riding high on policy and market support for nuclear energy as it announced its second-quarter results.

“The passage of One Big Beautiful Bill [Act] was an undisputed win for nuclear power,” CEO Joe Dominguez said during an earnings call with analysts Aug. 7.

More than that, the passage of OBBBA was a demonstration of bipartisan support for a power-generation technology that for many years was out of favor with many Americans. Dominguez noted the bill, which passed with only Republican votes, expands tax credits created by the Inflation Reduction Act, which was passed with only Democratic votes.

“It’s one of the only things the two bills have in common, is that it supports existing and new nuclear plants,” he said.

He added that negotiations have reached late stages with one potential power customer and middle stages with others interested in clean, reliable electricity.

“But most importantly, from my perspective, we’re seeing a continued acceleration of interest from a growing number of entities,” Dominguez said.

An analyst asked if Constellation’s nuclear strategy has changed in light of OBBBA.

Evolution seems likely, Dominguez said, rather than abrupt and sharp changes — particularly with small modular reactors, a potential game changer for the industry. Not all of the dozens of SMR designs being advanced will work or be commercially viable, he said.

Constellation’s R.E. Ginna nuclear power plant in Ontario, N.Y., houses the nation’s smallest and second-oldest operating commercial reactor. | Constellation Energy

“But we’ve got a pretty good bead on who we think the winners are going to be,” he said. “I feel better with the passage of each week in terms of better understanding the cost structures and the time to complete the work. And so I would say that our confidence is growing, but it’s growing incrementally, not in terms of major step changes.”

Dominguez said co-location of new SMRs with Constellation’s existing fleet of large reactors just makes sense — the sites have suitable land, an experienced workforce and a supportive community.

He singled out New York for its recent policy moves to support existing and new nuclear generation — announcing plans to develop at least 1 GW of new advanced nuclear capacity, moving toward a decision to extend to 2049 the zero-emissions credits that subsidize Constellation’s four in-state reactors and collaborating with the company to seek federal funding for advanced nuclear development at the Nine Mile Point plant, which has two older-generation reactors. (See N.Y. Makes Case for Extending Nuclear Subsidies to 2049 and N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility.)

“It’s early innings on this work, but I think it is going to be a signpost for other states, and I’m excited for the opportunities to expand nuclear in places like Maryland, Illinois, Texas and Pennsylvania,” Dominguez said.

In other updates:

    • Constellation’s acquisition of natural gas power generator Calpine has cleared most of its key regulatory reviews and is targeted for closure before the end of this year.
    • Big Tech is not the only sector seeking clean energy. Many customers other than data centers are interested in nuclear power.
    • Comcast is among the newest of these customers and has committed to a significant energy transaction that will help support a nuclear reactor uprate.
    • The engineering process is complete on potential uprates of other reactors, and Constellation says it hopes to partner with customers on these projects as well.
    • Constellation and GridBeyond are collaborating on an AI-powered demand-response program in the PJM grid that will allow customers to cut their peak energy costs while helping the market maintain system reliability.

Constellation reported second-quarter 2025 income of $833 million ($2.67/share) on revenue of $6.1 billion, which compares with $809 million ($2.58/share) on $5.48 billion a year earlier.

Its stock price closed 0.6% lower Aug. 7.

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Clean Energy Groups Seek Rehearing on DOE Resource Adequacy Report

Three clean energy trade groups have asked the Department of Energy to reconsider its recent report on resource adequacy, which they contend uses a deterministic approach to stake out a position for not retiring any more power plants in the face of rising electricity demand.  

The American Clean Power Association (ACP), American Council on Renewable Energy (ACORE) and Advanced Energy United (AEU) filed a request for rehearing Aug. 6, saying DOE should rework the report to offer a more clear-eyed view of the risks the industry faces with exploding demand stemming from the growth of data centers and other large energy customers. (See DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030.) 

“As demand for energy surges, grid reliability must rely on sound modeling, reasonable forecasts and unbiased analysis of all technologies,” the groups said in a statement. “Instead, DOE’s protocol relies on inaccurate and inconsistent assumptions that undercut the credibility of certain technologies in favor of others.” 

The report uses forecasts for high demand coupled with projections for limited new supply that include only NERC Tier 1 planned generation — resources already under construction or with firm in-service dates. That means DOE effectively assumes no new generation will go online after 2026 in a report that extends to 2030, John Hensley, ACP senior vice president of markets and policy analysis, said on a call with reporters. 

“We are all kind of cognizant of the challenges facing us over the next 10 years as energy demand is starting to skyrocket, at the same time that there are very active debates going on right now, thinking about taking a lot of resources off the table that could help to meet that demand going forward,” Hensley said. 

A recent RTO Insider story cited industry experts who raised similar concerns about the report, prompting DOE to defend its methodology. (See Industry Experts Find Fault in DOE’s Resource Adequacy Analysis.) 

The agency said its future data center demand estimate represented a midpoint from 2024 studies by the Electric Power Research Institute and the Lawrence Berkeley National Laboratory and acknowledged the report’s “conservative yet realistic baseline” for new generation, but pointed also to supply change challenges the electric sector faces, which could lead to major construction delays.  

Former Kentucky Public Service Commission Chair Kent Chandler said the report relies on one scenario with limited supply growth to push the argument for no retirements. While that could offer evidence of how the industry and its regulators are falling short, it is not enough, he said. 

“It is certainly not, in my opinion, sort of my former regulator hat, useful for the singular purpose of saying all power plants need to stay on at all cost, or build all new power plants at all costs,” Chandler, now a senior fellow with R Street, said in an interview. 

Most studies assessing future resource adequacy would use various scenarios and rank the probabilities of occurring, but by its own admission DOE’s report does not do that, Chandler said.  

A ‘Protocol’ for Retirements

Some industry observers have argued DOE could use the report’s findings to issue more orders under the Federal Power Act to keep plants from retiring, as it did with the Campbell plant in Michigan and the Eddystone plant in Pennsylvania. 

“It’s directly tied to that,” AEU Managing Director Caitlin Maquis said on the call with reporters. “DOE’s analysis came out of Executive Order 1462 back in April that directed DOE to put this analysis together, and then, as part of that same executive order, directs DOE to use all mechanisms available, including FPA Section 202 (c) to retain resources it deems necessary in regions it’s identified as having inadequate reserve margins.” 

A rehearing request for a DOE report is rare, but the groups call the document a “protocol” that will be used to keep more power plants open under the FPA. 

The rehearing request argues the report amounts to “an effective amendment to DOE’s existing regulation governing 202 (c).” 

“In the rehearing request, we go through pretty extensively the reasons that this protocol from DOE may be styled as a report but really looks like agency action that is intended to have real world effects,” Gabe Tabak, ACP general counsel, told reporters. “It is not, as folks sometimes call government reports, a piece of shelf art that is just going to sit there. So, even though it is labeled as a report, in our view, it clears the bar as agency action and therefore qualifies as a type of action where hearing is appropriate to seek.” 

Although preventing retirements in the face of rising demand can be prudent, maintaining all plants that were on the path to closure absent that growth doesn’t make sense, Hensley said. 

“Deferring that decision making to the utilities themselves and their PUCs is the right course of action,” he added. “They understand what their fleet looks like. They understand the available options set in front of them and can make the best decision on what retirements to delay or new resources to bring online to meet that in a most economic way for ratepayers and to balance supply and demand.” 

Taking Politics out of the Picture

Chandler said Kentucky, a coal-friendly state, established a board to review all proposed plant retirements and make recommendations to the PSC regarding approval. He noted the board recently made no filing after a co-op asked to retire a small, broken combustion turbine plant that would have cost more to repair than build new. 

“This body, who basically was put together for the purpose of keeping thermal fossil fuel-fired generation from retiring, was like, ‘We take no position on the retirement either way,’” Chandler said. “They were never going to be for it, but they just couldn’t come up with a reason to say, ‘Yeah, let’s keep it on.’” 

“So, that’s a long way of saying even those folks that are super interested in resource adequacy, or have a bias towards legacy, fossil fuel-fired generation — there are going to be many instances where it just does not make any sense at all for reliability or economic purposes to try to keep some of these plants on way past their economic life,” he said. 

That decision might have been different with a larger 650-MW power plant, which would be a major resource to take offline in one area, he added. 

DOE historically has used Section 202 (c) for limited circumstances when the grid is stressed and a power plant is running up against emissions limits from environmental rules, ensuring it will not be fined for exceeding air permits to maintain reliability — including this summer. 

Chandler said one way to take the politics out of the retirement issue would be broadening how RTOs and ISOs employ reliability must-run (RMR) contracts. While most grid operators use RMRs as a stopgap to prevent grid problems as they address the consequences of removing a retiring plant from the system, ERCOT is one market that relies on the tool for resource adequacy after making a clear case, he said.  

Chandler thinks Congress — or possibly FERC — could change rules to allow RTOs/ISOs to review the impact of retirements on resource adequacy and offer RMRs when needed. 

“That removes a lot of the politics around depending on DOE to do 202 (c) orders, and it frankly makes it probably a more sustainable practice and limits its application to just those instances where it’s most necessary,” he said. 

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NERC Plans to Register 720 IBRs by May 2026

NERC has finished identifying owners of inverter-based resources that will need to register with the ERO and is ready to move on to the final stage of the work plan FERC approved in May 2023, the organization said in a quarterly update filed Aug. 4 (RD22-4).

According to the filing, NERC and the regional entities identified 720 IBRs qualifying for registration that either are or plan to be connected by the registration deadline of May 15, 2026, with a total nameplate capacity of over 32,000 MVA. They were distributed among the regional entities as follows:

    • MRO: 110 IBRs with a total nameplate capacity of 4,454 MVA;
    • NPCC: 50 at 1,752 MVA;
    • ReliabilityFirst: 73 at 3,572 MVA;
    • SERC: 171 at 9,881 MVA;
    • Texas RE: 34 at 1,792 MVA; and
    • WECC: 282 at 10,725 MVA.

The ERO Enterprise arrived at these numbers by revising their initial estimate of 863 IBRs with nameplate capacity of 38,785 MVA, derived from surveys of balancing authorities and transmission owners and submitted to FERC in February. (See NERC Updates FERC on IBR Registration Progress.) NERC refined the estimate by reaching out to generator owners and operators identified as candidates in the initial survey to confirm that their facilities qualify for registration.

GOs and GOPs with facilities requiring registration will be classified as Category 2, a label created by NERC in changes to its Rules of Procedure filed with FERC in 2024. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) Category 2 GOs are entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of [at least] 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage [of at least] 60 kV.” Category 2 GOPs operate such equipment.

NERC emphasized in the filing that these numbers are subject to change. Facilities under development may be canceled or have their expected operational date delayed past the registration deadline. Registered entities also may determine their facilities were inaccurately reported, in which case they will be removed from the list.

The identification of qualifying facilities completes Phase 2 of NERC’s IBR registration work plan, developed in response to a 2022 FERC order to identify and register IBRs that currently are not required to register but, “in the aggregate, have a material impact” on reliable operation. Phase 1 was the creation of the Category 2 designation.

Phase 3, comprising registration of GOs and GOPs, will begin “in the upcoming months,” NERC said. Entities will register through the Centralized Organization Registration ERO System, the common registration portal for all utilities.

The ERO will continue to file quarterly updates on the percentage of registrations completed within each RE’s footprint, with the final update to be filed within a few days of the deadline. NERC also will update its quick reference guide on the registration initiative with links to frequently asked questions and recordings of webinars for candidates.

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SPP Celebrates Novel Consolidated Planning Process

KANSAS CITY — SPP’s Board of Directors has approved a tariff change establishing an integrated, three-year transmission planning cycle that represents a “watershed” moment and a “first-in-the-country” mechanism, RTO officials said. 

The board endorsed the proposal during its quarterly meeting Aug. 5 following a unanimous advisory vote by the Members Committee. The vote added to previous unanimous endorsements from state regulators, the Markets and Operations Policy Committee and five other stakeholder groups. 

The Consolidated Planning Process (CPP) replaces SPP’s current sequential planning and generator interconnection studies that have resulted in clogged queues and an average of six-year wait times before resources go into service. (See SPP ‘Blazes Trail’ with Consolidated Planning Process.) 

The new process comprises a long-term 20-year study and an annual 10-year assessment, aligning system modeling, planning assumptions and cost allocation across load and generation needs. The CPP-10 includes a GI capability study, a GI decision point and a regional transmission assessment that recommends projects for construction. The CPP-20 establishes a 20-year regional vision. 

The CPP also establishes a general contribution funding mechanism, called GRID-C, for upgrades that serve both load and generation, enabling shared cost responsibilities and fewer restudies. 

SPP says the streamlined framework improves cost certainty for stakeholders and promotes equitable cost sharing. Casey Cathey, the grid operator’s vice president of engineering, said the CPP will lead to faster integration of generation and remove “huge challenges” from the current three-phase study process. 

“If you show up and you pay your GRID-C, you’re committed,” Cathey said. “Within seven months on an annual basis, we’ll get to a [generator interconnection agreement], and you may move forward with your build. This is a critical area for modernizing the grid. This is quite innovative across the nation, if not the entire world. We’re blending generator interconnection processes and transmission planning processes in a very elegant solution for providing cost certainty.” 

Cathey may not be wrong about the “elegant solution.” 

“This will be the only RTO that can really offer upfront cost certainty to interconnection customers, which is so incredible for those in the development of assets,” Pine Gate Renewables’ Brett White said. 

The cost-sharing framework assigns GI costs based on transmission usage, projected accreditation needs, the CPP-20 portfolio and future generation.  

The CPP effort grew out of the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT) formed in the last decade to improve SPP’s transmission planning. That led to a task force that continued the work, meeting more than 200 times over three and half years to put together the process. 

Independent Director Steve Wright recalled that the project already was under way when he joined the board in 2023. 

“It is a really big national problem that people new to the industry look at what’s going on here and how long it takes us to figure out interconnections,” he said. “This process is Byzantine and not meeting the moment, because we need electricity. … [The board] was seeing all things going on across the country and saying, ‘What’s going on here is truly creative and can be a national model.’ And here we are at this moment, when it’s actually happened … it’s going to create a model that people can either use or measure against in terms of what are they doing to be able to make this work.” 

Vice Chair Ray Hepper, a Maine resident, said the CPP was a “first-in-the-country” innovation, one that has attracted notice in various corners of the country. 

“I know a lot of people in New England, and they’ll call me and ask, ‘What’s going on?’” he said. “Everybody else is watching. This is a really remarkable feat.” 

EDP Renewables’ David Mindham, apologizing for his “fluffy comments,” added his kudos for CPP. He said it is unlike anything EDP has found in the other RTOs it participates in. 

“It’s very seldom that a process truly comes together, where every interested party sits in a room for years at a time and works through everybody’s issues and … comes to consensus on something. That just doesn’t happen,” Mindham said. “This is probably the first example of a process that I can really think of that was consensus-driven that really balanced stakeholder interests. I think we got an amazing product. I think there could be challenges in implementation. … But if we keep up the same sort of collaboration and atmosphere with that creating this, I think we’ll move through those equally as well.” 

David Mindham, EDP Renewables | © RTO Insider LLC

SPP plans to file the tariff change with FERC by October and will request an effective date of March 1, 2026. Full implementation will begin in 2027, with the first CPP portfolios studied being delivered in 2028. Transitional work will bridge the gap between the CPP framework and the current study process for the 2026 and 2027 assessments. 

“We still have a lot of work to do,” Cathey said. “We have to clean up the backlog. We have to get through and complete the next [study cluster]. We have a lot of individual processes and tools.” 

At the same time, SPP staff are staging internal software to be ready to implement CPP and as part of a recently announced partnership with digital provider Hitachi. The companies have agreed to develop an AI-based solution that the grid operator says will reduce processing times in the GI study process by at least 80%. (See SPP, Hitachi Partner to Use AI in Clearing GI Queue.) 

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NRG Energy Secures $216M Loan from TEF

NRG Energy has closed on a $216 million loan from the Texas Energy Fund that will help it build 456 MW of gas-fired capacity at an existing power plant, the company said in a press release.

The funding will go toward the construction of two new natural gas units at NRG’s TH Wharton power plant in the Houston area, the fifth-largest metropolitan area in the U.S. The company said the units will deliver power to the constrained load zone by summer 2026.

“Demand for electricity across Texas is surging and we’re working quickly to supply new dispatchable natural gas generation to the grid,” said Robert Gaudette, president of NRG Business and Wholesale Operations, in an Aug. 4 statement.

The loan is just the second issued by the Public Utility Commission since the fund’s inception in 2024. The first went to the Kerrville Public Utility Board earlier in 2025. (See First Texas Energy Fund Loan Goes to Kerrville Utility.)

The 20-year loan, executed with the Public Utility Commission, will cover up to 60% of the projected $360 million cost, not to exceed $216 million, at a 3% interest rate through July 2045. The project must meet minimum performance standards, as outlined in the program’s rules.

The two units already are under construction.

NRG has two more projects with another 1 GW of capacity that are progressing through the TEF’s due diligence process. The PUC is reviewing 15 other applications for the TEF’s in-ERCOT program, representing an additional 8.4 GW of capacity. The program, designed to add about 10 GW of gas-fired generation to the Texas grid, was approved by voters in 2023.

Two companies recently withdrew their projects from consideration by the fund, which is administered by the PUC.

LS Power said in June that it pulled a 527-MW project out of due diligence “due to numerous factors” and is no longer pursuing funds from the TEF program. In July, Hunt Energy Network told the PUC that it was withdrawing another due-diligence project because it “does not align with the requirements and conditions of the TEF loan in a cost-effective manner.”

Six projects have been withdrawn by applicants or rejected by the PUC in 2025. (See 2 More Projects Fall out of TEF Loan Program.)

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Interior Reverses Approval of Lava Ridge Wind Project

The Department of the Interior is moving to cancel the Lava Ridge Wind Project, a gigawatt-scale wind farm proposed on thousands of acres of federal land in Idaho. 

The proposal had long been the target of criticism within the state. President Donald Trump ordered all development halted in a Day One memorandum Jan. 20 so Interior could review the record of decision issued six weeks earlier.  

On Aug. 6, Interior announced the review had uncovered crucial legal deficiencies in the “reckless” and “thoughtless” approval issued under lame-duck President Joe Biden. 

“This decisive action defends the American taxpayer, safeguards our land and averts what would have been one of the largest, most irresponsible wind projects in the nation,” Interior Secretary Doug Burgum said. 

Lava Ridge developer Magic Valley Wind and its corporate parent, LS Power, did not respond to requests for comment for this report. 

Interior’s decision is the latest in a series of directives and policy actions by Trump and his cabinet agencies to thwart renewable energy development, one of Biden’s signature initiatives. (See Feds Pile on More Barriers to Wind and Solar and Trump Administration Takes Another Swing at Wind Power.) 

Trump instead is seeking to maximize fossil fuel use. A reminder of this came later Aug. 6, when Interior announced it had advanced the first expedited coal lease under provisions of the One Big Beautiful Bill Act. A day earlier, Interior announced it had approved the second-largest coal mine expansion since Trump returned to office — a move intended to enable extraction of 33 million tons of coal at a Montana mine. 

Lava Ridge was proposed in 2021 with up to 400 wind turbines disturbing 9,114 acres. During the Bureau of Land Management review process, it was reduced to 231 turbines and 992 acres disturbed, with the overall footprint reduced to 38,535 acres. BLM issued a favorable record of decision Dec. 5, 2024. 

Nameplate capacity was to be at least 1,000 MW, which would nearly double the roughly 1,100 MW of wind power installed statewide in 2024. Idaho’s largest existing wind farm in 2024 was rated at only 160 MW, according to the U.S. Energy Information Administration. 

Residents and elected leaders of the solidly Republican state mounted a vocal campaign against the plan on the grounds that it would be ugly; would be too close to the Minidoka National Historic Site, where civilian Americans of Japanese descent were held during World War II; and would send its electricity to California. 

Idaho’s congressional delegation and governor, Republicans all, had fought the Lava Ridge proposal all the way through to BLM approval and then continued after. On Aug. 6, they took a victory lap. 

“I made a promise to Idahoans that I would not rest until the Lava Ridge Wind Energy Project was terminated,” U.S. Sen. Jim Risch said. “Today, President Trump and I delivered on that promise.” 

On X, Gov. Brad Little praised Trump and Burgum: “On behalf of all Idahoans — thank you for your leadership.” 

BLM said in December it had worked to reduce the impacts of the original proposal on wildlife, cultural resources, local aviation, ranchers who use public land and adjacent private landowners.  

Minidoka, where more than 13,000 Japanese Americans were interned, had become a bit of a rallying point for opponents, as alternate iterations of the Lava Ridge plan would have put turbines much closer than the nine miles in the final version. 

Turbines already spin southeast and southwest of the concentration camp site — most of Idaho’s existing wind energy generation is in the Snake River Valley. 

California Impact?

It is unclear what impact the cancellation of Lava Ridge will have on California’s ambitious plans to reduce its electricity emissions, which include extensively tapping output from wind resources in the inland West. As part of that effort, the California Public Utilities Commission’s (CPUC) integrated resource planning portfolio calls for the state to procure more than 1,000 MW of wind generation from Idaho. 

Unclear also is the effect on another LS Power project, the Southwest Intertie Project-North (SWIP-North), a 285-mile, 500-kV transmission line being developed in northern Nevada by the company’s Great Basin Transmission subsidiary. 

Last year, the CAISO Board of Governors finalized approval of a proposal to include SWIP-North as a CAISO participating transmission owner (PTO) after ISO planners determined the project would be the only line completed in time to help deliver Idaho wind to California’s load-serving entities by 2027. 

While development of SWIP-North has not been tied to any single generation project, most of Lava Ridge’s output was expected to be exported on the southbound segment of the line. In response to past stakeholder concerns about the line’s dependence on Lava Ridge, CAISO pointed out that “CPUC portfolios for out-of-state wind resources in Idaho are based upon generic wind resources and not specific to any one specific facility such as Lava Ridge.” 

Sources have told RTO Insider that the CAISO PTO designation for SWIP-North likely influenced Idaho Power’s leaning in favor of joining the CAISO Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+. But even with the Lava Ridge cancellation, Idaho Power’s interest in SWIP-N would appear to be secure, given that the utility plans to use the line to import power from the Southwest and not for exports. 

“The SWIP-North project is the final segment of the larger SWIP project, which began decades ago. The urgency of completing the project has grown as growing energy demand across the Western United States strains the grid,” Idaho Power said on its website. 

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MISO, SPP Still on Hunt for Joint Transmission Under CSP

MISO and SPP appear undaunted in their pursuit of a beneficial interregional project after FERC’s rejection of exemptions to their joint study rules. 

The grid operators announced they still are in search of projects that improve resilience, reliability and transfer capability under their joint Coordinated System Plan (CSP) study process. They also said they are weighing proposing more benefit metrics to FERC to justify projects. 

The RTOs originally set out to perform a different type of CSP this year with more in-depth modeling on a 10-year horizon and a wider variety of benefits they said would have cast a wider net for projects. However, FERC in July denied their requested temporary exemptions. The commission said a limited waiver of requirements was not the best vehicle for changes to the study. (See FERC Denies MISO, SPP Waiver of Joint Study Process.)  

Now the RTOs say they are considering submitting a filing to FERC under Federal Power Act Section 205 to include more types of benefits in business cases for joint projects. They said drawing on more and different benefits is in line with FERC Order 1920, which laid out seven categories of transmission benefits. 

MISO and SPP’s joint operating agreement currently limits them to using only the value of avoided regional projects to measure the reliability and public policy benefits of interregional projects stemming from the CSP. 

The two grid operators have said measuring the reliability value of a project solely on its ability to avoid regional projects constricts their planners from analyzing projects’ usefulness in other areas, like expanded interregional transfer capability or fortification against weather extremes. 

During an interregional planning meeting Aug. 6, SPP Manager of Interregional Strategy and Engagement Clint Savoy said the RTOs would have more details on how the two might expand their benefit definitions under the CSP during the next joint meeting Oct. 24. 

“It’s something that we’re constantly talking about … how to approach changes we want to make to the process itself,” Savoy told MISO and SPP stakeholders. 

The RTOs also said that because FERC rejected the waiver, they will add 15-year-out modeling scenarios to this year’s CSP.

The JOA requires MISO and SPP, when conducting a CSP, to use multiyear modeling, which the RTOs interpret to mean using multiple model years, such as five, 10 or 15 years out. They initially wanted to model several different 2034 scenarios to land on transmission needs instead of studying the system at different points in time. 

MISO Interregional Planning Adviser Ashleigh Moore said 15-year models are in progress and would be complete in October or November. 

Moore said that if transmission needs prove to be “drastically different” with the addition of the 15-year-out modeling, the RTOs might open a second window for stakeholders to propose transmission solutions. MISO and SPP are accepting transmission project ideas for the CSP through Sept. 5 under their first submission window. 

The RTOs still are aiming for a “robust and comprehensive interregional planning process,” she said.  

SPP engineer Spencer Magby said the RTOs will model an extreme temperature scenario that will serve as a sensitivity to the study. However, the modeling would extend only to extremely low winter temperatures, not blistering high summer temperatures. 

Southern Renewable Energy Association Transmission Director Andy Kowalczyk said MISO and SPP probably should model systems stressed by summertime, especially given the springtime instances of load shedding in Louisiana for both RTOs. (See MISO Says Public Communication Needs Work After NOLA Load Shed.) 

MISO and SPP planning engineers said they might consider hot weather modeling additions. 

Missouri Public Service Commission Chief Utility Economist Adam McKinnie asked MISO and SPP to share data on their existing transfer limits so stakeholders can have a better idea of how projects could expand transfer capability. Engineers said they would consider the request. 

MISO and SPP said they would share draft transmission projects in October and prepare to make project recommendations in December. As for cost allocations of the projects, the RTOs plan to hold discussions on a cost-sharing design late in 2025 and over 2026. 

MISO and SPP’s CSP process never has produced a viable interregional project. Their Joint Targeted Interconnection Queue study, on the other hand, has culminated in $1.7 billion in projects to be funded by the interconnecting generation that benefit from the lines. 

MISO and SPP also aim to submit a proposal to FERC in 2026 to institute the smaller, congestion-relieving Targeted Market Efficiency Projects, with a similar process to MISO and PJM’s TMEP studies.