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December 13, 2025

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SPP Regional State Committee Briefs: Aug. 4, 2025

KANSAS CITY — SPP state regulators have approved a policy that establishes criteria for developing joint transmission projects with other RTOs to cost-effectively address persistent market-to-market (M2M) congestion. 

SPP intends to use the targeted market efficiency projects (TMEPs) to resolve M2M congestion that has resulted in millions of dollars of charges on its seam with MISO. SPP’s neighbor already uses TMEPs on its PJM seam. 

The cost of each project would be allocated between SPP and MISO based on the ratio of historical congestion costs, adjusted for M2M settlement effects. The interregional cost allocation would be recovered through the regionwide annual transmission review requirements. 

Louisiana and Texas voted against the policy over cost-allocation concerns during the SPP Regional State Committee’s Aug. 4 meeting. Attorney Dana Shelton, proxy for Louisiana Public Service Commissioner Mike Francis, expressed concern about “the allocation on a regionwide basis in the absence of showing a regionwide benefit.” 

Minnesota Public Utilities Commissioner John Tuma questioned the reluctance to talk about market efficiencies, saying TMEPs will benefit only SPP’s ratepayers. 

“This concept is about creating market-to-market benefits for our ratepayers. I think exploring it is only in our best interest at this stage,” he said. “Minnesota has joined this organization because we are one of those seams organizations, and we do see the benefit of these [M2M] efforts. Is this a big one? No … but it’s the kind of thing that will help us out in the long run.” 

The TMEPs would apply only to M2M flowgates along the MISO seam with a minimum of at least $1 million in historical congestion costs. Staff are proposing a $20 million project cap with an in-service time frame of three years and a four-year payback of avoided congestion costs. 

SPP’s Clint Savoy told the RSC that RTO staff is trying to filter the list of constraints they want to fix as part of the biennial joint system study with MISO. He said staff will use historical market data to find operating days when constraints bound in the day-ahead market. They will calculate the production cost for the entire market, remove the constraint and rerun the production cost analysis. 

“The change in production cost is essentially the benefit that SPP receives, so it’s a reduction in the production cost for the market as a whole,” Savoy said. 

The committee agreed with staff’s recommendation to stop moving a tariff change (RR681) that allocates costs of seams projects outside the FERC Order 1000 interregional process. Instead, it remanded the issue back to the Cost Allocation Working Group to address stakeholder concerns and asked it to provide an update during the RSC’s November meeting.  

The Markets and Operations Policy Committee rejected the proposal during its July meeting with only 54.9% approval. Members were uncomfortable about whether the projects would be subject to the grid operator’s competitive process screening. (See “Seams Cost Allocation Rejected,” SPP MOPC Briefs: July 15-16, 2025.) 

The RSC also granted CAWG’s request to delay the annual stakeholder review of the Safe Harbor Limit, which sets designated resources’ eligibility for base-plan funding at costs less than or equal to $180,000/MW. The working group said the delay was necessary because of “significant changes in SPP processes.” 

Bylaw Change for Western RTO

The RSC approved an amendment to its bylaws that will allow western commissioners to join the committee upon the RTO’s expansion into the West in 2026. The expansion will make the Arizona, Colorado and Utah commissions eligible to add representatives to the committee. 

Commissioners will be able to vote on proposed policy or tariff changes and other matters only if the proposal applies to the interconnection where their state is located. As Nebraska, New Mexico and South Dakota straddle both interconnections, those states will be limited to one vote if the proposal applies to both regions. 

The Western commissioners will be eligible to join the RSC after April 1, 2026, when the RTO expansion goes live. Staff said vendors are successfully building and testing market systems, with member testing to begin in September. 

Three Western commissioners sat in on the meetings: Arizona’s Kevin Thompson, New Mexico’s Greg Nibert and Wyoming’s Mike Robinson. Missouri’s Glen Kolkmeyer also was a guest although his chair, Kayla Hahn, represents the state on the RSC. 

The committee also endorsed a three-person Nominating Committee consisting of RSC President Patrick O’Connell, South Dakota’s Kristie Fiegen and Tuma that will recommend the 2026 leadership during the November meeting. It also approved a 2026 budget that passes $1 million for the first time ($1.18 million) by including an extra $500,000 for consulting services and making allowances for increased membership.  

Employee No. 3 Speaks out

Bruce Rew, who recently announced his pending retirement from SPP as senior vice president of operations, was greeted with a round of applause before one of his last updates during the Joint Stakeholder Briefing following the RSC meeting. (See SPP’s Rew to Retire After 35 Years in Operations.) 

“Bruce reminds us he was Employee No. 3. I’m not sure 1 and 2 are still alive, but Bruce has had a remarkable career at SPP,” board Vice Chair Ray Hepper said, teasing the 35-year veteran. “So this may be among your last opportunities to really chew on Bruce in a board meeting.” 

Rew said SPP has issued only one resource advisory thus far in 2025, which lasted two days in April, compared with five in 2024. During that period, demand peaked for the year at 56.6 GW, about 1,500 MW below the all-time high. Despite the demand but with negative LMPs, staff were able to export almost 5 GW of energy to MISO and PJM June 25-26 when the RTOs’ solar power vanished during the evening hours. 

SPP’s Bruce Rew reacts to director Ray Hepper’s comments during his presentation. | © RTO Insider 

“As we gain more and more solar, that’s something that we’re going to continue to manage operationally to make sure that we’re prepared for that as well,” Rew said. “We potentially could have that same experience if we get 5 or 10,000 MW of solar.” 

It will be a while yet. The grid operator recently added its first gigawatt of solar capacity, complementing its 35.6 GW of wind capacity. It has added more than 3 GW of capacity in the past year, pushing its registered capacity past 100 GW. 

SPP has published a report on the April 26 load shed event near Shreveport, La., one of three in the footprint this year. The report analyzes the event, identifies the main causes, examines SPP’s response and provides recommendations and improvements to prevent similar incidents in the future. (See SPP Addresses 3rd Load Shed Since March 31.) 

SPP Lays out Market Principles

Carrie Simpson, SPP vice president of markets, followed Rew to the podium and discussed the priorities for market design changes set in a staff white paper that is circulating: price discovery and transparency, economic efficiency, reliability effectiveness and system performance. 

Referencing the 5 GW of exports to MISO and SPP, Simpson called it the result of a “healthy seam.” 

“It’s a good indication … that our pricing was supporting the rest of the interconnection, because people were able to buy from us and sell into MISO and PJM,” she said. “Had these exports not occurred, our LMPs would have been significantly even lower because we would have had to back down even more generation. And so just a good indication of the market working well and the signals being available to participants to take action and move power where it was needed or more efficiently needed in the interconnection.” 

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CPower Conference Highlights DR’s Opportunity from Data Centers

WASHINGTON — The growing number of data centers offers a major growth opportunity for demand response, as it can help get the energy-hungry facilities online quicker than new generation, executives and data center experts said at CPower Energy’s GridFuture 2025 conference Aug. 6. 

On top of that, renewables are growing, and their intermittency needs to be balanced, CPower CEO Michael Smith said at the event, held at the Omni Shoreham Hotel. 

“We’ve dispatched more than we ever have this year,” he said. “So, all of these things are conspiring to create a further need for flexible load on the system.” 

It takes a couple of years to build utility-scale solar and 15 years to build nuclear, he said. That does not factor how hard it is to get through the interconnection queues, or the relatively low forward prices in the markets compared to new-build costs that could rise further with the imposition of tariffs. 

Duke University has shown that demand response could help unlock new data centers by making more efficient use of the existing grid, Smith said. (See U.S. Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) 

Policymakers are starting to pay attention to that fact, with Senate Bill 6 in Texas requiring new loads at 75 MW or above to provide DR, ENP Consultants Director Jim McDonald said. 

“You’re going to see … a new version of Senate Bill 6” everywhere, McDonald said. “When AEP came out with their data center-only tariff a year and a half ago, that was a novel idea.” 

Many utilities now have adopted similar rules to AEP’s, which require more upfront deposits to secure a place on the grid. The same week as the conference, Google announced deals with AEP’s Indiana Michigan Power and the Tennessee Valley Authority to reduce power at its data centers when the grid is stressed in their territories. (See related story, Google Strikes Demand Response Deals with I&M, TVA.) 

Training artificial intelligence models has been driving demand growth from the sector, and while that is energy intensive, once those models are trained, they are going to be put to work, which will use more power, said Morgan Scott, vice president of global partnerships and outreach for the Electric Power Research Institute. 

“As we become more mature in the way that we use AI, it will continue to use more energy,” Scott said. “Will we find efficiencies? Yes. Are these numbers wrong? Yes. But the point is, they are directionally correct and give you conceptually an understanding that this is going to continue to grow because of the way that we are going to use AI and what we are asking these models to do.” 

The hardware side also is changing quickly, with the lifespans of the equipment in data centers getting shorter and shorter. Microchips degrade in one to three years now and innovations are rolling quickly, she added. 

“We’re seeing massive jumps in terms of what that electricity draw is, and so you can see we actually have a forecast of 1.2 MW per rack in a data center because of those changes within Nvidia chips,” Scott said. 

The business opportunity for CPower and the DR industry in general is huge when it comes to the growing demand from AI, Smith said in an interview after the event. 

“Those activities can stress the grid because they can come on fast and they can consume a lot of electricity very quickly,” Smith said. “So, that’s exactly what we do. We’re that shock absorber that monetizes or optimizes the value of the flexibility that’s inherent in those machines.” 

CPower and other DR companies are able to provide them a channel to monetize the flexibility that is possible in their operations, Smith said. 

Data centers can offer flexible load either by curtailing their operations, including by shifting them to other sites, or using on-site resources such as backup generators or, as Duke explored in its study, batteries. 

“We give the market operator access to those assets, and the market operator then can dispatch effectively those assets when needed,” Smith said. “And it really is a dispatch protocol. … A market operator can and should be able to dispatch a 500-MW peaking plant or a 500-MW data center equally.” 

AI Opportunities and Risks

CPower is looking into AI to help improve its operations. Smith said his sales team uses it to take notes in meetings, but eventually it should help with the software the company uses to manage aggregations of DR customers. 

“It will help that software make better decisions about where to put various customer assets, in what programs [and] at what times,” Smith said. “We do develop our own software. We have to be pretty cognizant of the tools that are available to us and use them appropriately. I’m not super comfortable just turning AI loose for the sake of turning AI loose, but I think our IT organization has done a really nice job of allowing AI to be used in the organization.” 

While the demand growth from AI and other sources presents opportunities for the entire power industry, it is not without its risks, CPower Chief Legal and Regulatory Officer Ken Schisler said in a separate interview. 

“If we’re not careful, what could be voluntary DR participation becomes power rationing, and that’s going to be rejected by the public,” Schisler said. 

From left: CPower’s David Chernis, Emerald AI CEO Varun Sivaram, Bentaus CEO Bob Davidoff, ENP Consultants Founder Jim McDonald and Mercury Computing Co-Founder Monty Prekeris at the GridFuture 2025 conference | © RTO Insider LLC

Conscripting demand flexibility like in Texas Senate Bill 6 could prove politically unsustainable as well, he said. 

“People are going to want to see the transmission built or the power stations built so that they can use power when and where they want it, and if they have flexibility, they want to be able to make it available to the grid on their terms, rather than have it conscripted and rationed for them,” Schisler said. “So … unless you have those flexibility opportunities widely available, you’re left with no choice but to sort of simply ration power.” 

Rising prices have led to political pushback, with states in PJM looking for reforms to cushion their consumers. Schisler said he is familiar with that dynamic from his time on the Maryland Public Service Commission. When the state restructured, it placed temporary caps on the price of electricity. Some utilities’ caps expired in 2004 — just before natural gas prices spiked in response to two historic hurricanes, leading to much higher bills for customers. 

“It happened right before Katrina and Rita” in 2005, Schisler said. “You wouldn’t want to be me back in those times, and we’re in one of those phases now.” 

States have been updating their policies and working to get reforms through at PJM in response to the situation, but one area Schisler said could help is improving access to data from customers to help enroll even residential customers into DR to save them money. 

Data access varies by state. Schisler said ERCOT’s market, wholly within Texas, is one of the best examples of making it easy and New York is working on reforms to do the same thing. But in multistate RTOs like PJM, it has proven much more difficult. 

“I can go anywhere in the world, and I have a safe, secure banking system that I can get money out of an ATM, check my balance, etc., and know that that system is secure,” Schisler said. “But we’re still at a place where, at scale, interacting with utilities to get data is still a patchwork.” 

One way some companies have gotten around this is to install their own meters so they can help customers manage their loads, but that is economically wasteful, Schisler argued. The issue for data access has been around for years; President Barack Obama tried to address it with the Green Button Initiative, which Schisler called “an anti-standard.” 

“We’re still acquiring data through lots of different channels now; Green Button didn’t make that go away,” he added. “The other challenge with it is it’s largely an issue that is under the domain of state commissioners, yet the [reason] for accessing this data is for participation in wholesale markets, and we haven’t bridged that need with state regulators and with utilities.” 

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RF Speaker Promotes AI in Corporate Communications

Utility managers should not be afraid to explore the benefits that recent advances in artificial intelligence can bring to their frontline employees, a tech company leader told attendees of ReliabilityFirst’s annual Human Performance Workshop.

RF holds the Human Performance Workshop each year to share insights into factors affecting employee performance and suggestions for improving efficiency.

In his introductory presentation, Johnny Gest, RF’s manager of engineering and system performance, noted a phenomenon — what he called “performance drift” — that can develop in complicated organizations. Poor communication from managers, personal health and stress, organizational changes and overly harsh policies can all make it difficult for employees to understand their responsibilities within the system.

Barry Nelson, CEO of FactorLab, a developer of AI systems aimed at workplace improvement, picked up this theme in his own presentation, emphasizing the need for clear communication of expectations in the business world.

“The question is, what can we do to drive consistency [and] predictability with such a complex and dynamic environment?” Nelson said. “And in this particular case, can AI play a role — and not a role like writing an email, but a real role to help you, as leaders, maybe frame the problem or look at the problem in different ways to reduce drift?”

Nelson said AI can give managers a fresh look at their own systems, identify areas of improvement and set targets and benchmarks for success. For instance, an electric utility based in the southeastern U.S. used an AI product developed by FactorLab to improve communication in its safety meetings, leading to a double-digit reduction in the severity and frequency of serious injuries over two years.

Managers can use AI tools to examine their organizations’ communication from various angles, Nelson said. One product can score conversations on a range of factors, such as engagement of participants, level of detail on various topics and the quality of questions. With this information, organizations can work to improve the efficiency of their communication.

He also discussed the role AI can play in improving workplace communications by assisting with the editing of presentations and documents. Nelson gave the example of a daily briefing for frontline workers, in which managers have to keep the attention of employees who may feel bored or preoccupied with preparing for the day, and may zone out without catching important information.

“Technology can play a role in helping us find these pockets [of friction] and then understanding the system and cultural problems in order to fix the pockets,” Nelson said. He mentioned that AI can also help address language barriers, showing a video of a Spanish-language briefing translated into English in real time.

Nelson emphasized that the proper use of AI is not to replace human engagement but to improve efficiency within an organization so employees do not feel overlooked or undervalued.

“We find that the feedback has been incredibly positive from those in the field, because they know someone’s listening. They get the sense that … we care about these conversations, and that we’re trying to help them get better,” Nelson said. “Obviously, that’s not everyone’s cup of tea, but you would be surprised how many people in your organization are really looking for some feedback that we simply don’t have the human capacity to give at the moment.”

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BPA’s Proposed Tx Access Changes Prompt Questions of Industry Readiness

The Bonneville Power Administration’s proposed changes to its grid access process have prompted questions about how new readiness criteria will affect established industry practices and financing of new projects. 

In February, BPA paused certain transmission planning processes to consider changes in light of significant growth of transmission service requests. The federal power agency’s 2025 transmission cluster study includes more than 65 GW of requests, compared with 5.9 GW in 2021. The requests exceed the total regional load predicted for the Pacific Northwest in 2034, according to the agency. (See BPA Halts Some Tx Planning Processes Amid Service Requests and Industry Sees Challenges as BPA Considers ‘Radical’ Updates to Tx Planning.) 

On July 9, BPA outlined its proposed plan to tackle the queue during a workshop. The agency has developed a two-part approach: a transitional phase to get off the pause and a longer-term “future state” that will include more substantial reforms to BPA’s existing transmission processes. (See BPA Outlines Proposed Transmission Planning Reforms.) 

“In general, our current model will not work to effectively evaluate and respond to the massive amount of requests and megawatts in the BPA transmission service queue,” BPA spokesperson Doug Johnson told  RTO Insider. “The framework of our proposal revolves around instituting more rigorous requirements for transmission service requests. The goal is to process the queue as quickly as we can to advance our efforts to identify, plan and build the projects our customers need to do business as well as to provide interim service to those parties who have clarity about the service they need now.” 

As part of this effort, BPA has proposed implementing readiness criteria to weed out speculative requests from commercially ready projects. 

“The current practice in the Northwest is for load-serving entities to require developers who are bidding into their request for proposals to provide their own transmission,” Henry Tilghman, a consultant whose clients include Renewable Northwest and the Northwest & Intermountain Power Producers Coalition, told RTO Insider. (Tilghman spoke on his own behalf, not that of his clients.) 

The load looking to purchase the output of a project doesn’t provide the transmission — the project provides it, Tilghman explained. 

“So that puts the burden on the developer to get into the queue and obtain transmission service,” he noted. 

Financing at Risk?

However, under BPA’s new proposal, the agency would require evidence of security or a power purchase agreement or bilateral transaction between a load and resource to establish commercial readiness, Tilghman said. 

“You would not be allowed to even request transmission service until you have an agreement in place or provide security,” Tilghman said. “So that completely disrupts the existing model where the bidder into the [request for proposal] has to have transmission service placed in order to be eligible to bid.” 

This could affect financing of new projects, Tilghman contended. He said lenders have conducted risk assessments based on criteria that have been in place for decades. 

“One of those criteria is having transmission service in place with enough certainty that the project will be able to deliver … its output to its customer,” he added. “Now you’re going to have to do development without that … transmission as you bring your project through the development process.” 

The Pacific Northwest Renewable Interconnection & Transmission Customer Advocates (PRITCA), a coalition whose members constitute more than 25% of the current BPA interconnection queue, has expressed similar concerns over BPA’s plans to apply commercial readiness criteria. 

“Developers in the queue have generally sunk millions of dollars into developing their projects,” Eric Christensen, an attorney with Beveridge & Diamond PC, which represents PRITCA, told RTO Insider. “The fact that developers are willing to put their own money on the line demonstrates that projects are commercially viable,” Christensen said. 

A more appropriate way to deal with the queue would be to study transmission requests in batches based on existing queue order, Christensen argued. He said this approach would allow viable projects to have a path forward to firm transmission while allowing unserious requests to exit on their own accord. 

Because the proposals are new, it’s unclear whether lenders have had time to analyze how they could impact investments, Christensen said. 

“We talk with financiers regularly, and one of the big variables in financing decisions is a certain path to [long-term firm] transmission,” Christensen added. “If BPA goes forward with the current proposal, we expect to see large financing cost increases or an unwillingness to provide financing, due to the uncertainty these changes create.” 

PUD Support

However, in public comments submitted to BPA, public utility districts have supported readiness criteria. 

For example, Mason PUD said it “generally supports the addition of readiness criteria, so encumbrances are not provided for requests that will likely not convert to service. This will create an actionable queue [that] only includes mature long-term transmission service requests.” 

Grant County PUD said it “supports the development of additional and clarified readiness criteria in order for TSRs to remain in the queue.” 

“Unknown and New-Point [Points of Receipt/Points of Delivery] should be deemed speculative and removed from the queue until and unless new procedures are developed to accommodate such PORs/PODs in a realistic and timely manner,” Grant argued. 

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Tri-State Plan Includes Renewables, Batteries and Gas

Colorado regulators have approved Tri-State Generation and Transmission Association’s plan to add 1,657 MW of new resources from 2026 to 2031, despite objections about the inclusion of a new natural gas plant.

The Colorado Public Utilities Commission voted 3-0 on Aug. 1 to approve the plan.

New resources in the plan include 400 MW of wind, 300 MW of solar and 650 MW of battery storage, along with 307 MW from a new natural gas plant in Moffat County in northwestern Colorado. The battery resources will be Tri-State’s first experience with battery storage systems.

In addition, Tri-State plans to replace turbines at the J.M. Shafer gas-fired plant to boost capacity.

The 1,657 MW of resources were included in Tri-State’s preferred portfolio, one of six analyzed in the implementation report for its 2023 electric resource plan (ERP). The report follows commission approval for Phase 1 of the ERP and a competitive bid process.

Another plan, referred to as Portfolio 6, excludes the new gas plant but increases battery storage to 1,175 MW, for a portfolio total of 1,900 MW. That plan also includes new turbines at Shafer.

Tri-State chose its preferred portfolio “as a result of the portfolio’s overall performance across the reliability, environmental and financial categories,” the Colorado-based power cooperative said in its implementation report.

The preferred portfolio was the least-cost option based on the present value of revenue requirements (PVRR), not including the social cost of emissions. The PVRR of the preferred portfolio would be about $88 million less than that of Portfolio 6.

Like all the portfolios analyzed in the implementation report, the preferred portfolio meets reliability targets. It achieves an 80% reduction in greenhouse gas emissions in Colorado in 2030 relative to 2005 levels.

“However, the other portfolios analyzed result in significant, unnecessary financial burdens by aggressively pursuing resources with high transmission interconnection upgrade costs” not needed to achieve the same benefits, Tri-State said.

The new resources are needed in part due to the retirements of the Craig and Springerville coal-fired power plants, slated for 2028 and 2031, respectively.

“Retirement of dispatchable coal resources cannot be affordably or reliably replaced solely with semi-dispatchable resources,” Tri-State said.

Commission Chair Eric Blank said he understood the resource diversity benefit of natural gas.

“For me, given our lack of rate regulation over Tri-State, I don’t think we should be substituting our judgment for that of the utility when there’s a tough choice to be made between competing portfolios where either could be deemed reasonable,” Blank said.

Commissioners also agreed with Tri-State that “time is of the essence” for procuring new resources due to a “volatile” market for renewable energy equipment and recent federal tax and trade actions.

Non-gas Portfolio

Other parties had urged Tri-State to choose Portfolio 6, which excludes the new gas-fueled power plant.

The Natural Resources Defense Council and the Sierra Club, filing together as “the conservation coalition,” said the present value of revenue requirements for Portfolio 6 was similar to that of the preferred portfolio when considered over the 19-year analysis period. Portfolio 6 had the lowest PVRR when the social cost of emissions was included, they said.

Portfolio 6 would result in lower GHG emissions for Tri-State “for little to no incremental cost,” the coalition said in a filing. The groups noted that Tri-State must eliminate its Colorado GHG emissions by 2050.

The groups also questioned the excess capacity resulting from the new gas plant and the “explicit assumption that Tri-State will overbuild capacity in order to sell into the market.”

“The commission’s rules, and prudent utility planning, simply do not countenance a regulated utility operating like a merchant generator in the way Tri-State proposes,” the coalition said.

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Dept. of Interior Launches Overhaul of OSW Regs

Another day, another swipe at wind power: The Department of the Interior has launched an overhaul of all regulations pertaining to wind generation in U.S. waters. 

Whether this affects just the increasingly remote prospect of future wind power development or also the few projects under construction and in operation is not immediately clear from Interior’s Aug. 7 announcement. 

The agency’s public affairs office did not provide clarity when asked later in the day. The industry’s trade organization, Oceantic Network, said it still was trying to digest the announcement. 

“We’re taking a results-driven approach that prioritizes reliability, strengthens national security and upholds both scientific integrity and responsible environmental stewardship,” Interior Secretary Doug Burgum said in a news release. 

Interior’s Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement will lead the review for potential update of Parts 285, 585 and 586 of Title 30 of the Code of Federal Regulations. 

President Donald Trump switched from campaign trail rhetoric against offshore wind to tangible action a few hours after his inauguration Jan. 20, ordering a halt to all new offshore wind leasing, permitting and loans, as well as directing an ominous-sounding review of existing leases for potential modification or termination.  

In the wake of that memorandum, federal regulatory work essential to advancing an offshore wind proposal slowed or halted. Some companies in the already-struggling sector paused or ended their efforts as well. 

More recently, Interior has swung into action to thwart placement of offshore wind turbines and their smaller onshore cousins, as well as solar panels. 

    • On July 15, Interior told its staff that all decisions, actions, consultations and anything else pertaining to wind and solar would need separate review and approval by two high-level subordinates and then Burgum himself.
    • On July 29, Burgum ordered a series of steps to halt “preferential treatment” of wind and solar; give greater voice in offshore wind regulatory review to stakeholder groups that have opposed offshore wind; and review the effect of wind turbines on migratory birds. 
    • On July 30, BOEM rescinded all designated wind energy areas on the Outer Continental Shelf — over 3.5 million acres on the East, West and Gulf coasts. 
    • On Aug. 1, Interior said it would consider the energy density of generation when assessing the benefits of a project proposed on federal land or seabed, to make the most efficient use of space — setting up sprawling wind and solar farms for an unwinnable comparison with compact fossil or nuclear plants. 
    • On Aug. 4, BOEM rescinded its offshore renewable energy leasing schedule. 
    • On Aug. 6, Interior moved to cancel the gigawatt-scale Lava Ridge Wind Project on federal land in Idaho, which Trump had paused in his Day One memorandum. 

The series of actions is redundant in some ways, but if one is stalled or rejected in a court proceeding, the others still may accomplish the Trump administration’s goals. 

There is one small offshore wind farm in operation in federal waters, and five larger ones are in some stage of construction. 

Between the financial assault launched by the reconciliation bill Trump signed into law July 4 and the policy changes his administration has been making since January, it is unclear if any other offshore projects will proceed to construction before the 2028 presidential election and how long the industry would take to recover lost momentum after 2028. 

The Trump administration has moved to block the one remaining New Jersey offshore wind project from starting construction and has indicated it will do the same with the only Maryland project. 

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ISO-NE: Resources Overperformed During June Capacity Scarcity Event

Pay-for-Performance (PFP) credits accumulated during the capacity scarcity conditions June 24 totaled about $114 million, a major boost in revenue for resources that performed during the event, ISO-NE COO Vamsi Chadalavada told the NEPOOL Participants Committee on Aug. 7.

The event was caused by the highest demand ISO-NE has experienced since 2013 and about 2,560 MW of generator outages and reductions. (See Extreme Heat Triggers Capacity Deficiency in New England.)

ISO-NE’s PFP construct is intended to incentivize resource performance during capacity scarcity events. Resources earn credits by providing more power than their obligations, while resources that provide less power than their obligations face charges. Resources without capacity supply obligations (CSOs) also can earn credits by performing during shortfall events. On June 24, capacity resources earned about $67 million, while non-capacity resources earned about $47 million.

Credits and charges are intended to equal out, which is designed to protect ratepayers from the cost of incentives. However, ISO-NE has imposed a cap on the total monthly PFP charges a resource can accumulate, which caused a $26 million under-collection of PFP penalties on June 25. Under ISO-NE rules, the deficit between PFP credits and penalties is charged to capacity resources that have not hit the stop-loss cap.

In the wake of the scarcity event, the New England Power Generators Association (NEPGA) filed a complaint with FERC contesting ISO-NE’s rules on PFP charges, arguing the allocation method unfairly penalizes capacity resources that are below the stop-loss cap. (See related story, NEPGA Seeks Relief for ‘Improper’ Pay-for-performance Costs in ISO-NE.)

NEPGA also wrote that ISO-NE should cap its balancing ratio at 1.0, noting that the ratio exceeded that during the June 24 event, requiring capacity resources to provide more power than their capacity obligations. The balancing ratio determines the portion of each CSO that capacity resources are required to provide.

PFP charges and credits can have a major impact on each resource’s overall capacity revenue. The overall capacity market value in June was about $88 million, $26 million less than the credits awarded during the three-hour scarcity event.

Interregional imports earned the majority of PFP credits, taking in $70 million. The total imports across ties with New York and Canada surpassed 4,300 MW around the peak period of the event.

In-region generation resources earned about $36 million but racked up $99 million in charges. This calculation includes the reallocation of the deficit of funds caused by the stop-loss cap.

Monthly Operations Report

Energy market revenue totaled about $1 billion in July, compared to $672 million in July 2024, Chadalavada noted in his monthly report on system operations.

Chadalavada said the significant load fluctuations experienced in New England over the spring and summer demonstrate the increasing demand volatility challenges in ISO-NE. The RTO experienced its lowest recorded demand in April, more than 20,000 MW below the 26,000-MW system peak experienced on June 24. (See Growth of BTM Solar Drives Record-low Demand in ISO-NE.)

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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.