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December 16, 2025

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States’ Interregional Transmission Efforts Examined

Advocates for interregional transmission should focus more on allocation of benefits than on allocation of costs, a researcher said during an ACORE webinar. 

This — along with identifying the constituency for a project and the regulatory gaps that would thwart it — would help advance the longstanding goal of building more wires to move electricity across state lines and RTO/ISO boundaries, said Abe Silverman, who is facilitating a nine-state collaborative to advance interregional transmission. 

The American Council on Renewable Energy hosted “Powering Progress: States Leading on Transmission Collaboration” on Aug. 19 to look at the outcome of past multistate collaborations and at the ongoing efforts toward further collaboration. 

ACORE’s Kevin O’Rourke was joined by Silverman, an assistant research scholar with the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University; Anya Poplavska, senior policy advocate at the Acadia Center; and Beth Soholt, executive director of the Clean Grid Alliance. 

Soholt spoke of CapX2020, the successful $2.1 billion effort by 11 utilities to build nearly 800 miles of 345- and 230-kV transmission lines across Minnesota and into three neighboring states. 

There was a long process of lining up internal and external support, financing, regulatory approval and community acceptance, she said, as well as the challenge of shaping a disparate group of cooperatives, municipal utilities and investor-owned utilities into a coalition of the willing with a consensus on a common goal. 

“It’s a lot easier to kill a project, it’s a lot more difficult to make it happen,” Soholt said. “And this group did come together and make it happen.” 

Poplavska spoke about the Northeast Grid Planning Forum, convened by the Acadia Center and Nergica to lay the groundwork for collaboration to meet what is projected to be a 100% increase in power demand over the next quarter century — and to loop in neighboring parts of Canada, which has a deep and longstanding infrastructure connection with the U.S. Northeast. (See New Initiative Focuses on Interregional Tx Coordination in the Northeast.) 

There is only piecemeal and fragmented decision-making now, she said. “And [the forum is] really born of the synergies between Canada and the Northeastern states. The whole point of it is to really create a framework across these different regions that facilitates planning, coordination and decision making.” 

Accentuate the Benefits

Poplavska identified three steps in the process: identification of needs; design and selection of projects; and, most difficult of all, allocation of costs. 

“How are costs going to be borne across different regions?” she said. “I don’t think it’s a stretch to say that this is a huge limitation and reason that interregional projects just don’t get pursued as much.” 

A potential best practice, Poplavska added, would be to move beyond a strict 1-1 benefit-cost ratio on cost allocation and allow states to voluntarily cover additional costs that contribute to meeting their policy goals. 

“Cost allocation is a bit of a red herring,” Silverman said. “Because what we really need to talk about is benefits allocation. Because all these projects have such enormous net benefits that if we really get hung up on how we’re allocating the costs without taking into consideration the benefits, we end up having sort of a circular conversation that we very rarely get anywhere.” 

It is a very different discussion, he added, to go to the governors of three states and say “We have a billion dollars of benefits we have to allocate between the states” rather than “We have $500 million of costs that we need to allocate.” 

Silverman is facilitator of the Northeast States Collaborative on Interregional Transmission — an effort that spans nine states from Maine to Maryland served by three grid operators. (See State Officials in the Northeast Discuss Interregional Transmission Plan.) The states entered a memorandum of understanding in 2024 to accelerate the siting and permitting of regional and interregional transmission.  

All signs point to the benefits of regionalization, Silverman said, and it serves the competing visions of decarbonization and fossil fuel-based energy dominance. 

“There’s probably 20 high-quality studies all showing enormous consumer benefits if we get interregional transmission right,” he said. “And that’s everything from faster deployment of data centers and clean energy and economic development in our states. It’s also often lowering costs for consumers, and it’s certainly improving reliability.” 

Silverman added: “But what we sort of have encountered is that there is a regulatory gap between the benefits and the people who see the benefits and the people doing the grid planning.” 

He said the value of the collaborative he is working with and the forum Poplavska is working with is that they create the constituency that can advocate for those gaps to be closed, and allow these types of projects to move forward. 

“If all we needed was another study talking about how beneficial interregional transmission was, we’ll just keep writing those studies forever,” Silverman said. 

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Texas RE Analyst Urges ‘Extravagant’ Utility Cyber Plans

Utilities should ensure their cybersecurity incident preparations are “as extravagant as possible,” so they are protected in the event of an attack from malicious entities, a manager with the Texas Reliability Entity told entities.

“Whether or not you think [a cyber incident is] actually going to happen, you want to make sure that your response plan is capable of withstanding any type of scenario that occurs,” Chris Mejia, Texas RE’s CIP cyber and physical security analyst, said in the regional entity’s regular Talk with Texas RE webinar Aug. 19.

Mejia was discussing the reliability standard CIP-003-8 (Cybersecurity — security management controls), which specifies requirements for entities to include in the security plans for their low-impact cyber assets. NERC defines low-impact systems as those not considered a significant risk to grid security.

The cybersecurity plan requirements, found in Attachment 1 of the standard, include the following five mandatory sections:

    • Cybersecurity awareness — “reinforce … cybersecurity practices” among staff, including physical security practices if applicable, at least once every 15 calendar months.
    • Physical security controls — restrict access to the cyber asset itself or the location of the low-impact system within the asset, as well as any cyber assets that provide electronic access controls over the system.
    • Electronic access controls — “permit only necessary inbound and outbound electronic access as determined by the responsible entity” and authenticate any dial-up connectivity that can provide access to low-impact cyber systems.
    • Cybersecurity incident response — develop incident response plans that provide for identification, classification and response to cybersecurity incidents; identify roles and responsibilities for incident response; and test response plans at least once every 36 months.
    • Transient cyber asset and removable media risk mitigation — address the risk of malicious code spreading from removable media and other transient cyber devices, whether managed by the entity or by a third party.

Mejia emphasized that while the standard specifies minimal targets for compliance, such as the 36-calendar-month timeline for testing cyber incident response plans, entities should be willing to go above and beyond those requirements to keep their systems safe.

For example, in the case of the cybersecurity awareness element, Mejia observed that entities have multiple options for informing their staff of best practices: direct communication between managers and employees, indirect communication such as posters in common areas and visible support for cybersecurity from management. A good plan will involve using all three while also ensuring they are used in the best way for the organization rather than just satisfying the minimum for compliance.

“Let’s say you’re putting up a poster. Are you leaving that poster up for the entirety of those 15 months, and only changing it once every 15 months?” Mejia said. “You’ve got to be careful with that, because a lot of times that poster does end up kind of blending into the wall. People have blinders on, and they don’t see it anymore. So maybe a best practice is that … you go ahead and do it a little bit more frequently than that.”

Regarding physical security controls, Mejia observed again that there are “many different ways you can do this,” with common approaches using fences or walls and gates. But just having these facilities in place may not provide the level of security that entities expect without continuous testing. Mejia also urged entities to make sure they implement a layered approach with multiple reinforcing security mechanisms.

Finally, Mejia reminded entities that CIP-003-9, the successor to CIP-003-8, will take effect April 1, 2026, after being approved by FERC in 2023. (See FERC Approves NERC Cyber Protection Expansion.) The new standard will add a new requirement for “vendor electronic remote access security controls” to entities’ cybersecurity plans for low-impact cyber systems.

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Black Hills-NorthWestern Merger Could Reshape Western Market Map

The proposed merger between Black Hills Corp. and NorthWestern Energy likely will reshape the map in the competition between CAISO’s Extended Day-Ahead Market and SPP’s Markets+ — but it’s still too early to know where new boundaries will be drawn. 

The two companies announced Aug. 19 that their respective boards of directors voted unanimously to approve an agreement to merge in an all-stock, tax-free merger that will incur no new debt.  

The deal, which is expected to close in 12 to 15 months pending federal and state approvals, would “create a premier regional regulated electric and natural gas utility company with a pro forma market capitalization of approximately $7.8 billion and a combined enterprise value of $15.4 billion,” according to a joint statement. 

“The combined company will have greater scale and financial strength to consistently deliver for customers across our service territories and invest at the pace and scale that today’s energy transformation demands,” Black Hills CEO Linn Evans said in the statement. “Our vision is to be the energy partner of choice for our customers, communities and investors, and this merger will accelerate our ability to achieve this goal.” 

“Our merger with Black Hills will create a premier regional regulated utility company with a larger, more resilient platform consistent with mid-cap peers,” NorthWestern CEO Brian Bird said. “Together, we will be better positioned to meet rising demand, accelerate investment in energy and grid infrastructure, and support customers and communities through a rapidly evolving energy landscape.”  

Upon closing of the deal, shareholders of Rapid City, S.D.-based Black Hills will own 56% of the combined company, with the remaining 44% owned by shareholders of Butte, Mont.-based NorthWestern, leaving the Black Hills as the greater among equals in the merger.  

The combined company — whose name has yet to be determined — will have its headquarters in Rapid City, and its board will include six representatives from Black Hills and five from NorthWestern. Bird will take the helm, with Evans retiring.  

Black Hills serves 1.35 million electricity and natural gas customers across eight states: Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. The company’s electricity operations are concentrated in the Western Interconnection and include its Black Hills Power and Cheyenne Light, Fuel and Power subsidiaries, which serve customers in southeastern Montana, western South Dakota and northeastern Wyoming, and its Black Hills Colorado subsidiary in the southern part of that state. 

NorthWestern serves about 800,000 electricity and natural gas customers in Montana, South Dakota and Nebraska and operates a balancing authority area that covers a large portion of Montana. 

The territories of the two Black Hills Energy utilities joining the Western Energy Imbalance Market are represented on this map by the orange areas in Montana, Wyoming and South Dakota. | Black Hills Energy

In their joint statement, the two companies said the combined electric utility will serve about 700,000 customers and operate roughly 38,000 miles of transmission and distribution lines and approximately 2.9 GW of owned generation capacity consisting of a mix of thermal, hydro and wind. The combined natural gas utility will serve about 1.4 million customers and operate 59,000 miles of natural gas lines.  

“Over time, this increased scale is expected to drive operating and cost efficiencies across the combined enterprise,” the companies said. 

‘Just too Soon’

With such a sprawling territory, the combined electric utility operations of the two companies could shape the footprints of the two competing Western day-ahead markets in key ways, and the stakes could be especially high for Markets+. 

NorthWestern, which has been participating in CAISO’s Western Energy Imbalance Market (WEIM) since 2021, has not committed to either EDAM or Markets+ or expressed a leaning in either direction. According to sources close to the market decision process, the utility’s decision still is very much in play. 

Bordering NorthWestern’s BAA to the west is the Bonneville Power Administration, which has committed to funding and participating in Markets+, although that decision is being contested in a suit filed in the 9th Circuit Court of Appeals. (See BPA Sued in 9th Circuit over Day-ahead Market Decision.)  

To NorthWestern’s southwest is Idaho Power, which has not committed to either market but is leaning heavily to EDAM, while to the south is the PacifiCorp-East BAA, which will become the first EDAM participant in spring 2026. To the east and southeast are Western Area Power Administration (WAPA) BAAs that plan to participate in SPP’s RTO West expansion.  

If NorthWestern were to commit to EDAM, the Northwest portion of the already-fractured Markets+ footprint would be further cut off from the islanded portion of that market represented by Public Service Company of Colorado’s (PSCo) BAA. Alternatively, NorthWestern’s participation in Markets+ would put connectivity between the Northwest and PSCo within closer reach. 

But at first glance, the union between NorthWestern and Black Hills suggests the former scenario is more likely.  

That’s because in August 2024, Black Hills Power and Cheyenne Light — both currently located in WAPA’s BAA — announced plans to exit SPP’s real-time Western Energy Imbalance Service (WEIS) and join CAISO’s WEIM in 2026. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.) 

Among the reasons the utilities gave for the move was the fact that, with the expansion of both Markets+ and RTO West, SPP will disband the WEIS. 

“The planned formation of the SPP RTO West required us to assess our future market path, as it did not appear that the WEIS market status quo would remain an option after RTO West is operational,” Black Hills told RTO Insider at the time. “We have found imbalance market participation to be beneficial for our customers, and the opportunity for our utilities to participate in the WEIM allows us to continue to optimize our generation operations while maintaining our high reliability and creating long-term value for the customers we are privileged to serve.” 

At the time, the move appeared to represent a geographically small but symbolically large victory for CAISO, since it would put the ISO’s presence as far east as South Dakota. Now it could translate into a significantly greater advantage for CAISO as it seeks to court NorthWestern. 

The WEIM implementation agreement signed between CAISO and Black Hills Energy stipulates that one of the company’s utilities will be required to register a new BAA to facilitate participation in the market. The merger could enable the Black Hills utilities to instead join NorthWestern’s BAA, but that would dictate that all three utilities participate in the same market, whether that be CAISO’s WEIM or EDAM, or SPP’s Markets+. 

When asked how the merger could affect NorthWestern’s decision to join a day-ahead market, and whether the two companies planned to consolidate BAAs in the West, utility spokesperson Jo Dee Black told RTO Insider: “NorthWestern and Black Hills will evaluate operational opportunities over the coming months and apply best practices where they are appropriate.” 

Black Hills spokesperson Theresa Donnelly offered a similar response to the same questions. 

“With the newness of today’s announcement, we’re not able to respond to your questions,” she said. “It’s just too soon.” 

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ISO-NE Proceeding with Shortfall Threshold After Positive Feedback

After receiving positive feedback from stakeholders, ISO-NE plans to proceed with its proposal for a quantitative threshold to determine an acceptable level of energy shortfall risk for the region.

The regional energy shortfall threshold (REST) project is one of the RTO’s key initiatives for 2025 and is intended to establish a threshold reflecting “the region’s level of risk tolerance with respect to energy shortfall during extreme conditions.”

The REST, which incorporates both shortfall magnitude and duration, would be used for seasonal assessments forecasting energy shortfall risks heading into each summer and winter period, along with long-term assessments looking at risks five and 10 years into the future.

When calculating the threshold, ISO-NE would consider the tail 0.25% of 21-day model cases with the most shortfall risk. The REST would be triggered if the average shortfall magnitude of these tail cases exceeds 3% and the shortfall duration exceeds 18 hours. (See “Regional Energy Shortfall Threshold,” NEPOOL Reliability/Transmission Committee Briefs: July 15-16, 2025.)

Jinye Zhao of ISO-NE said at the NEPOOL Reliability Committee (RC) meeting Aug. 19 that, on average, one of the extreme 21-day cases would occur “approximately once every 90 three-month periods.” Accepting this threshold means that “about once every 90 three-month periods, the region can tolerate up to 3% of unserved load on average across the 72 most severe hours.”

“Stakeholders have generally expressed support for the ISO’s proposed tail α% of 0.25%, proposed shortfall magnitude threshold of 3%, and proposed shortfall duration threshold of 18 hours,” Zhao said. “As a result, the ISO has retained its REST proposal as introduced at the June RC.”

Zhao clarified that the duration metric will evaluate the cumulative shortfall hours within a 21-day period instead of the longest period of consecutive shortfall hours. She said focusing on consecutive shortfall hours would introduce significant noise to the data, as small gaps between shortfall periods could mask the length of shortfall events.

She noted that ISO-NE never has experienced load shed due to a lack of generation, so it is not possible to back-test these thresholds for accuracy. However, she stressed that the lack of energy shortfall events in the past does not guarantee a risk-free future, and the increasing uncertainties stemming from climate change and a shifting resource mix and load profile could increase risks.

ISO-NE has said the REST will be a key tool to help identify when solutions are needed, but it is “premature to calculate the value of lost load (VOLL)” associated with extreme shortfall periods, Zhao said.

“While there are methodologies available to calculate metrics like VOLL, applying them may be more appropriate if a specific system risk has been identified through the long-term or seasonal assessment process,” she said. “A cost/benefit analysis could be helpful at that time to evaluate whether potential risk mitigation options are economically justified once the nature and scale of tail risk are identified and better understood.”

Some stakeholders urged the RTO to start thinking about how to identify and pursue solutions if the REST is violated, noting that, if the region identifies significant risks in one of the initial REST analyses, it likely would take years to establish a process for selecting a solution, work through the process and ultimately develop the selected project.

ISO-NE plans to run the REST analysis in conjunction with its seasonal assessments and will report the summer results in June and the winter results in November. For annual long-term assessments, the RTO plans to begin work in February or March and produce a report in November, beginning in 2026.

Mike Knowland of ISO-NE said the RTO will allow stakeholders to suggest modeling sensitivities to include in REST analyses and that ISO-NE plans to include three to five stakeholder-requested sensitivities in each long-term REST assessment. The RC is scheduled to vote on the REST proposal in September.

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State Tx Entity, Regional Markets Feature in Ore. Energy Strategy

The Oregon Department of Energy’s new draft energy strategy points to the importance of new transmission development and expanding electricity markets for meeting the state’s energy goals.

ODOE’s draft Oregon Energy Strategy, released for public comment Aug. 14, sets out recommendations by which the state can meet its greenhouse gas emissions policy objectives, which call for fully decarbonizing investor-owned utility electricity deliveries by 2040 and, by 2050, reducing fuel emissions by 90% and economy-wide emissions by 80%.

“An energy strategy could help align policies and programs; it could help navigate hard decisions with a focus on how to maintain affordability and reliability, [and] keep an eye on economic growth, on advancing equity and maximizing benefits, while minimizing harms,” Edith Bayer, ODOE energy systems senior policy analyst, said during an Aug. 14 call to discuss the draft document.

The wide-ranging strategy document identifies five “pathways” for meeting state objectives, including improving energy efficiency, increasing electrification across the economy, investing in clean electricity infrastructure, using low-carbon fuels in hard-to-decarbonize sectors and strengthening “resilience” throughout the energy system.

A section describing the clean electricity pathway warns that the state presently lacks the infrastructure needed to meet its energy transition goals.

“There is not currently sufficient transmission capacity, generating resources or storage to reliably power Oregon’s future electricity needs, particularly if new data centers come online as quickly as forecasted,” ODOE writes, pointing to the need to prioritize construction of new utility-scale resources, which often take years to site, plan, permit, build and interconnect with the grid.

“Failure to develop sufficient resources will not only threaten system reliability and hinder progress toward Oregon’s clean energy objectives, but will inhibit economic development and discourage new businesses from entering the state,” the report says.

ODOE’s top recommendation for addressing the challenge: establish a state “transmission entity” — one that appears to be modeled on New Mexico’s Renewable Energy Transmission Authority and the Colorado Electric Transmission Authority.

The department says the Oregon entity should be given authority to “identify and designate transmission corridors,” undertake “partial siting and permitting approvals” for projects in the corridors and offer direct financial support “through state bonds for projects that are determined to benefit the public interest.”

“Across the Pacific Northwest, transmission constraints hinder access to least-cost generation and contribute to reliability concerns,” the agency wrote. “Line expansions and additions are not proceeding at the pace or scale necessary to meet Oregon’s policy objectives.”

ODOE said the new entity could help simplify the process of siting and permitting transmission lines that traverse both state and federal jurisdictions, a key challenge in a region in which the Bonneville Power Administration controls more than 70% of the transmission network.

“To reduce this barrier, a new state entity could establish designated corridors for transmission development and obtain limited siting approval for development within the corridor, including development of enhanced, expanded or new transmission facilities but also of storage and electric generating resources,” the report notes. “Having a new state entity pursue limited siting approval for an entire corridor would retain Oregon’s historic focus on robust siting and permitting processes, while enabling individual projects within a given sited corridor to proceed more rapidly than is currently possible.”

Bayer noted the recommendation might resemble an Oregon House of Representatives bill (HB 3628) to establish a state transmission authority that failed to emerge from committee during the 2025 session.

“We hope that the text in the draft report captures the potential value that such an entity could provide, as well as the potential risks,” she said. “There’s near universal agreement in all of our engagement and everything that we heard that transmission is one of the most critical areas to meet our goals of clean, reliable and affordable energy.”

Coordination Through Markets

The strategy document also urges Oregon to step up collaboration with its neighbors, specifically through increased engagement with regional markets and other grid efforts.

ODOE calls out the “billions of dollars” the West has saved through expanded participation in CAISO’s real-time Western Energy Imbalance Market since 2014 and notes the development of the region’s two competing day-ahead markets: the ISO’s Extended Day-Ahead Market and SPP’s Markets+.

“Utilities in the region are moving toward more organized power markets to reduce costs and improve reliability. This is essential to more efficiently utilize existing infrastructure and to benefit from geographic and resource diversity across the region,” the agency wrote.

It said regional diversity will become “increasingly important” as states decarbonize, with a more diversified supply mix allowing load-serving entities to “take advantage of different weather patterns, resource mixes and time zones to integrate more renewable generation while mitigating risks from weather changes, including extreme weather events and wildfires.”

ODOE said movement toward an RTO would be “an important step to improve West-wide coordination and reduce costs for consumers.”

The document mentions also the two efforts managed by the Western Power Pool: the Western Resource Adequacy Program to develop regionwide RA requirements, and the Western Transmission Expansion Coalition to identify cost-effective interregional transmission projects.

“It is important that the state of Oregon engage in these activities to advance state energy policy objectives, ensure that regional activities are consistent with state policy and strengthen Oregon’s cooperation on vital areas including market development, resource adequacy, emissions accounting and transmission planning,” the report says.

The comprehensive strategy document recommends a wide range of additional energy-related actions, including those dealing with the electrification of buildings, transportation and industry; energy efficiency and conservation improvements; developing and expanding adoption of low-carbon fuels; and reducing vulnerabilities in the state’s energy system. It also explores equity issues stemming from the transition to cleaner sources of energy, including jobs impacts.

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Calif. Utilities Move Cautiously on Dynamic Pricing

Despite a state mandate to implement dynamic pricing, two of California’s publicly owned utilities told regulators they’re not ready to make the leap to rates that change hourly or more often. 

The two utilities — Sacramento Municipal Utility District (SMUD) and the Los Angeles Department of Water and Power (LADWP) — outlined the challenges of dynamic pricing in reports submitted to the California Energy Commission. 

The reports are intended to show utilities’ compliance with the CEC’s load management standards, which include a requirement to offer customer rates that can respond to hourly or sub-hourly price signals. 

The commission on Aug. 13 approved compliance plans from SMUD and LADWP, as well as from two community choice aggregators: the Clean Power Alliance of Southern California and Ava Community Energy Authority, which serves the East Bay. 

The dynamic pricing requirement is based on the idea that electricity customers can use smart devices, such as thermostats, water heaters and EV chargers, to reduce or shift their electric loads in response to price or other signals. 

In addition to saving money for customers, the rates may encourage the use of energy at off-peak hours, improve grid reliability, decrease the need for new electrical capacity, and reduce fossil fuel consumption and greenhouse gas emissions. 

SMUD, which was the first utility in California to implement time-of-day pricing, said in its plan that it is “fully supportive of the goals of the LMS regulations.” 

“We are focused on scaling up programs, including programs that can help reduce the need to purchase costly resource adequacy and to avoid the need to upgrade neighborhood transformers as EV charging loads grow,” Katharine Larson, SMUD’s regulatory program manager, told the commission. 

But with projected net annual costs of $2.4 million to $3.7 million to implement hourly or sub-hourly pricing, dynamic pricing wouldn’t be cost-effective, SMUD said.  

Customer Interest Uncertain

SMUD was also concerned about a potential lack of interest in such a program. The utility cited its experience with its critical peak pricing (CPP) plan, in which customers agree to pay a higher rate when the utility calls a “peak event” in exchange for discounted rates at other times. 

The peak events can occur at any time of day during the summer and can last from one to four hours. Program participants must allow automatic adjustments of smart devices enrolled with SMUD. 

After two years of active recruitment for CPP, fewer than 700 customers have signed up for the program. 

The commission approved SMUD’s compliance plan with the condition that the utility provides an updated cost-effectiveness analysis for dynamic pricing by August 2028. 

In its compliance plan, LADWP said implementing dynamic rates by the load management standard’s April 1, 2026, deadline wouldn’t be feasible and would cause an “extreme hardship” for the utility. 

LADWP doesn’t have advanced metering infrastructure needed to implement dynamic rates, but its plan includes other programs to encourage customers to shift their loads. Those include an electric vehicle managed-charging program. 

Among the CCAs, Ava said it doesn’t yet have enough information to know whether dynamic rates would be cost-effective or benefit customers.  

Ava said “significant uncertainties exist” regarding the potential for load-shift under dynamic pricing, customer acceptance of a complex new rate and administrative costs of the program. To help answer those questions, Ava is participating in a dynamic pricing pilot program with PG&E. 

Similarly, the Clean Power Alliance plans to participate in Southern California Edison’s expanded dynamic rate pilot through 2027. 

Customizing Compliance

The commission’s vote Aug. 13 follows compliance plan approval for six other utilities in May. The commission will consider plans from another nine CCAs at a future meeting. 

Commissioner Andrew McAllister said CEC staff had done a good job in “almost customizing” the implementation of the load-management standards for each utility, “responding to the realities on the ground.” 

“We have a big, diverse state,” McAllister said. “We’re doing something new; we’re sort of creating a new playing field.” 

The CEC approved an update to its load management standards in October 2022. (See California Moving to Dynamic Pricing for Retail Customers.) 

In addition to requiring dynamic pricing, the update directs utilities to maintain up-to-date rates in a database called the Market Informed Demand Automation Server (MIDAS).  

Utilities also must develop a standard tool to support third-party services’ access to rate information for their customers. The commission voted to extend the deadline for submitting the tool to May 8, 2026. 

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NYISO BIC Dissects Power Prices During June Heat Wave

NYISO shared a detailed analysis of New York’s late June heat wave, in which significant operating reserve shortages elevated energy prices.

“We had committed mostly everything that was available on the system, as well as the fact that we went short on reserves throughout the [state] for the peak hour,” Nate Gilbraith, manager of energy market design for NYISO, told the Business Issues Committee on Aug. 13. “That means the day-ahead market did not procure the full 2,620-MW reserve requirement.”

NYISO was short about 300 MW of reserves. The real-time market scheduled energy that did not have a corresponding day-ahead energy schedule to meet the needs because the day-ahead market did not “foresee” scheduling needs, Gilbraith said.

Real-time load exceeded the day-ahead forecast and market expectations. Imports from other regions, also affected by the heat wave, were much lower. Some generators experienced outages and derates, with some of those because of the heat wave. Actual load increased real-time market needs by over 900 MW. (See NYISO Issues Energy Warning as Heat Wave Boils New York.)

“What I am hearing you say is, as a consequence of having a tighter system, [reserves] aren’t there anymore as something that can be grabbed when you need them,” said Doreen Saia, chair of Greenberg Traurig’s energy and natural resources practice. “So we need to be much more purposeful when we’re looking at the day-ahead forecast.”

“I’ll say it back to you in another way: I think we need to make sure our operators have the tools to ensure reliability in real time,” Gilbraith said. “The fact we came out of the day-ahead market a bit short raises some questions … with how we set our market rules.”

In some areas, transmission flows met or exceeded facility ratings, causing transmission shortage pricing to occur. This was particularly acute on Long Island, where congestion exacerbated already high statewide prices. On June 24, during the peak evening hours, statewide prices were $2,000 to $3,000/MWh. On Long Island, prices exceeded $7,000/MWh.

A stakeholder asked whether there was more information on how much behind-the-meter solar and special-case resources contributed to load reduction. Gilbraith said that beginning at 6 p.m., BTM solar dropped off very rapidly and so did not contribute as much. Additional analysis of SCRs will be forthcoming, he said.

Stakeholders also asked why neighboring regions did not provide imports as expected. This was in part because the weather was much hotter than forecasted across multiple footprints.

“What we saw on this day was really across the entire Eastern Seaboard,” Gilbraith said. “So everyone is now in a situation where they do not have their reliability reserve requirements. … It was one of those emergency drills that we run through that you don’t ever want to actually be in.”

July Market Performance

NYISO also presented its July market performance report to the committee. The locational-based marginal price for July was $78.89/MWh, higher than the $58.96/MWh seen in June and far higher than the $47.42/MWh seen in July 2024.

Natural gas prices and distillate prices were both higher than in June. This was the largest driver of price increases in New York, according to the ISO.

NYISO noted that for the past couple of months, there have been overestimations in BTM solar forecasts relative to the actual power they provided. Some of this is because of smoke from the Canadian wildfires. The ISO is working on figuring out how much of the overestimation is from the smoke compared to forecasting issues.

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FERC Approves Cost Allocation for Eddystone Emergency Order

FERC on Aug. 15 approved PJM’s proposal for allocating the costs for Constellation Energy to continue operating its Eddystone Generating Station near Philadelphia under an emergency order by the U.S. Department of Energy (ER25-2653).  

The cost would be spread across all PJM load, with charges determined by multiplying load-serving entities’ share of the RTO monthly unforced capacity obligation by the monthly credit paid to Constellation. The costs to be included in that credit are subject to review by the Independent Market Monitor. The actual costs will be determined through the deactivation avoidable cost credit (DACC), which was designed for resources whose deactivation is being voluntarily delayed while transmission upgrades are built to allow the resource to go offline without reliability issues. (See PJM Board Selects Cost Allocation for Eddystone.) 

The revisions to the Reliability Assurance Agreement (RAA) are only applicable to the Federal Power Act Section 202(c) order keeping Eddystone online from June 1 to Aug. 28. Any DOE orders pertaining to other resources or to further keep the plant online would require a separate cost allocation filing. 

Several public interest organizations protested allocating the Eddystone costs to all PJM load, arguing that the RTO’s capacity market procured sufficient capacity to cover the 90 days the emergency order is in effect. They wrote that the order itself stated that there is a shortage of capacity in pockets of PJM, quoting its finding that “an emergency exists in portions of the electricity grid operated by [PJM] due to a shortage of facilities for the generation of electric energy, resource adequacy concerns and other causes.” Without further clarification from DOE, they argued, any cost allocation would be arbitrary. 

The protest was signed onto by the Environmental Law and Policy Center, Natural Resources Defense Council, Sustainable FERC Project, Sierra Club, Public Citizen, Citizens Utility Board of Illinois and Environmental Defense Fund. They wrote that PJM continuing to export while operating Eddystone during the heat wave in late June shows that the plant is not needed to maintain reliability and the parties benefiting from its continued operation may not be PJM load. 

“In sum, PJM’s proposal asks ratepayers across PJM to pay for something — resource adequacy — they have already paid for once. PJM ratepayers have no need for, and will not materially benefit from, additional generating capacity. PJM’s dispatch of Eddystone during a recent summer heat wave only raises more questions about the beneficiaries of the unit’s retention,” the organizations wrote. 

PJM defended its RTO-wide cost allocation by stating that Eddystone is in the PECO zone, which saw no transmission constraints binding in the 2025/26 capacity auction, and arguing that Eddystone’s output is therefore considered deliverable across the RTO. Both Constellation and PJM said Eddystone’s operation during the heat wave corresponded to a maximum generation and load management alert, which is a NERC Energy Emergency Alert level 1 event. 

The organizations also focused on the notion that the agreement between Constellation and PJM to use the DACC to determine recoverable costs does not fall under FERC oversight, arguing the costs associated with Eddystone’s operation should be considered wholesale rates. They noted that PJM’s interpretation of which parties are affected by the emergency order and compensation agreement leaves out LSEs and consumers who may be allocated the resulting costs. 

“In PJM’s view, a Section 202(c) order constitutes a blank check to establish charges that may be passed on to other entities and customers with no opportunity for regulatory review. It ignores the fundamental purpose of the Federal Power Act: to provide a check on private utilities,” they wrote. 

The organizations also took issue with an operating memo in which PJM and Constellation agreed to allowing Eddystone to be dispatched for system restoration and for any costs to provide black start service to be recovered through the proposed structure. They argue that would saddle all PJM customers with the cost to provide a localized service, which itself already has a FERC-approved cost allocation. 

The PJM Industrial Customer Coalition submitted comments supporting the cost allocation proposal but argued that the RTO should be required to file the DACC compensation for FERC approval. 

PJM argued that Section 202(c) does not require commission involvement in determining compensation unless the parties involved cannot agree on a methodology. It pointed to San Diego Gas & Electric, in which DOE used Section 202(c) to order CAISO to purchase energy from the spot market; when CAISO sought refunds for the transactions, the commission found that it did not have oversight, as the parties to the sale had agreed to the price. 

FERC found that the cost allocation appropriately matches the scope of the emergency identified by DOE. The commission also determined that the emergency order does not require PJM to demonstrate that ratepayers will benefit from Eddystone’s operation and said that the compensation methodology itself is out of scope. 

“We agree with PJM that the proposed cost allocation recognizes that the emergency order is based on the overall resource adequacy need in the PJM footprint,” the commission wrote. “The emergency order describes an ‘emergency situation,’ referring to PJM’s own public statements and regulatory filings, which reflect a ‘growing resource adequacy concern’ for the entire PJM region. 

“The emergency order also states that the retirement of the Eddystone units would ‘further decrease available dispatchable generation within PJM’s service territory.’ These statements support a finding that the retention of the Eddystone units benefits the PJM region in general.” 

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NYISO OC Approves SIS for Micron Fab Interconnection

ALBANY — The NYISO Operating Committee on Aug. 14 approved the system impact study for the second of Micron Technology’s semiconductor chip manufacturing centers slated to begin construction later in 2025 in the town of Clay, N.Y.

Micron’s facilities, also known as fabricators (or “fabs”), are a major contributor to the forecasted load growth in New York state, according to NYISO. This facility, “Fab 2,” will draw 576 MW from the grid. When combined with another fabricator at the same site, the total load will be 1,056 MW. Two other fabricators are also planned at the site over the next 20 years.

Clay is a mostly residential suburb of Syracuse with a population of roughly 60,000, according to census data. Micron’s facility will be the largest electric customer in the town by far. When completed, the chip factory will be the largest manufacturing facility in Onondaga County.

The SIS found that the Micron facility will require upgrades to the local grid. Overloads would occur on several local 245-kV lines and substations, so a new substation will be needed. The study also found voltage transfer degradation, which would require upgrades to nearby interfaces.

National Grid estimated that $139.7 million in network upgrades are required, and the new substation will cost $122.2 million. Other upgrades to nearby transmission interfaces would total about $17 million.

The OC also approved eight SIS scopes, all for data centers spread out across the state. If completed, these data centers would collectively draw over 2,100 MW from the grid.

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Kairos Power, TVA Announce Nuclear PPA

The list of firsts for advanced nuclear power grew a little longer Aug. 18 with a power purchase agreement between Kairos Power and the Tennessee Valley Authority. 

The electricity — or more exactly, its clean energy attributes — would be assigned to Google data centers.  

The terms — only 50 MW, not until 2030, from a technology still being developed — are not by themselves a huge splash in a sector that is projecting a need for dozens of gigawatts of capacity in the next five years. 

But it is the first PPA signed by a U.S. utility for the output from an advanced GEN IV reactor, and it is the latest of many indications of the strong interest the tech sector has in next-generation nuclear power, with its promise of emissions-free baseload power and its potential for co-location. 

The PPA between Kairos and TVA would deliver up to 50 MW from Kairos’ planned Hermes 2 Plant to the TVA grid, which powers Google data centers in Tennessee and Alabama. 

It is the first step under Google’s October 2024 agreement with Kairos on a partnership to develop a 500-MW fleet of advanced nuclear reactors by 2035. (See Google, Kairos Sign 500-MW Nuclear PPA.) Kairos will boost Hermes 2’s output from 28 MW to 50 MW to reach the PPA’s terms. 

Kairos is designing a high-temperature small modular reactor fueled with pebble-form TRISO and cooled with low-pressure fluoride salt. 

Hermes 1 is a demonstration reactor under construction in Oak Ridge, Tenn., with an anticipated 2027 startup date. It is intended to produce only heat, not electricity. Lessons learned from Hermes 1 will shape the Hermes 2 demonstration reactor, to be built nearby. (See Kairos Power Cleared to Build Demonstration SMRs.) 

There are two more advanced-nuclear firsts: Hermes 1 was the first GEN IV reactor approved by the Nuclear Regulatory Commission and the first non-light water reactor permitted in the United States in more than half a century. 

Also in Oak Ridge, TVA in May became the first U.S. utility to request a construction permit for a small modular reactor — a GE Hitachi BWRX-300. (See TVA First U.S. Utility to Request SMR Construction Permit.)  

There are many other recent firsts in SMR and advanced nuclear development, but not the most important first: None in this part of the world has entered commercial operation. 

Ontario in May authorized construction for what could be the first commercial SMR in North America. (See Ontario Greenlights OPG to Build Small Modular Reactor.) But the target date for connection to the grid is not until late 2030. 

There is intense interest and effort focused on the development of SMRs, with their promise of faster, less expensive construction. The Nuclear Energy Agency is tracking more than six dozen designs at some stage of development; more than two dozen of the efforts are headquartered in the U.S. 

How many of those efforts obtain sufficient capital and overcome technical hurdles to reach commercial viability remains to be seen. 

The Trump administration is trying to expedite the process, but the 11 projects recently chosen for a fast-track pilot program will receive no financial assistance — only help cutting through regulatory red tape. (See Advanced Nuclear Fast-track Effort Gets First 11 Projects.) 

Nonetheless, advanced nuclear developers often speak with present-tense confidence about their business models and technologies. 

“We build mass-manufactured nuclear plants that will power anything from a data center to a city,” declares Aalo. In fact, Aalo’s liquid-metal reactor design is only in the non-nuclear prototype stage, and the company was a 10-person operation in a coworking space until recently. 

Some of the other companies in the SMR race are not as far along as Aalo. 

Others are steadily moving closer to splitting their first atoms, aided in some cases by the technical and financial resources of the U.S. government.  

In 2021, the U.S. Department of Energy Office of Nuclear Energy put Kairos’ Hermes project on its list of “5 Advanced Reactor Designs to Watch in 2030.” DOE already had begun assisting Hermes financially during the first Trump administration; in 2024 it committed up to $303 million in grants to the effort. 

The cost of developing a first-of-a-kind SMR and bringing a working copy online is considerable — $5.6 billion, in the case of the first Ontario reactor, plus a projected $9.6 billion for the three follow-up SMRs planned on the same site. 

Google, Kairos and TVA said the PPA announced Aug. 18 would help ease some of that first-mover cost and drive down the price tag for future reactors. 

“Google stepping in and helping shoulder the burden of the cost and risk for first-of-a-kind nuclear projects not only helps Google get to these solutions, but it keeps us from having to burden our customers with development of that technology,” said Don Moul, CEO of TVA.