Search
December 17, 2025

Posted on

NERC Offered to Help with Iberia Outage Investigation, Robb Says

NERC CEO Jim Robb told the ERO’s trustees the organization has offered to assist its European counterparts as they investigate the recent mass blackout in the Iberian peninsula, while warning that it is “way too early” to draw any conclusions about the cause of the issues. 

Robb’s comments at the May 8 meeting of NERC’s Board of Trustees in Washington, D.C., echoed those he made at a joint meeting of FERC and the National Association of Regulatory Utility Commissioners on April 30. (See FERC-NARUC Collaborative Examines Ongoing Issues with Gas-electric Coordination.)  

They were similar to the remarks of Teresa Ribera, European Commission executive vice president for a clean, just and competitive transition, who on May 5 criticized what she called a “trigger-happy attitude” blaming renewable energy for the outages.  

Nearly the entire population of Spain and Portugal, along with parts of France, lost power on the afternoon of April 28, with electricity restored for most of the peninsula only the following day. Spain’s grid operator said the same week that the outages began with two separate generation loss incidents in the country’s southwest, but it has not identified their exact location. 

Robb drew parallels between the Iberia outages and the Northeast blackout of August 2003, which “changed so much about how we approach reliability of the [power grid] here in North America.” He also compared the incident to “some of the things we’ve seen in West Texas, California and Utah,” an apparent reference to previous grid disturbances including the Odessa disturbances of 2021 and 2022 when multiple renewable generation resources tripped offline. (See NERC Repeats IBR Warnings After Second Odessa Event.) 

While Robb advised listeners that “it’s probably best to … let [investigators] do their work,” he named a few areas in which NERC is particularly interested, such as the relative lack of inertial generation on the peninsula and the “frequency loss and voltage control that comes along with that.” He also mentioned the use of natural gas to restart the Iberian grid, which touches on questions that NERC has been studying about the North American grid’s black start capability.  

In addition to offering to help the European Energy Information Sharing and Analysis Centre with its investigation, Robb said the ERO plans to give a full briefing at FERC’s open meeting in June about the Iberian outage and its implications for North American customers. 

FERC Chairman Mark Christie, who also attended the meeting, assured Robb he was looking forward to NERC’s report and urged the ERO to “keep telling the truth.” He also expressed his hope that FERC’s upcoming technical conference on resource adequacy June 4-5, which will feature presentations from Robb as well as CEOs of the RTOs, would be “critically important” and “a seminal moment in American energy policy.” 

Kim Shares Section 321 Analysis

The board meeting featured a presentation from Soo Jin Kim, NERC’s vice president of engineering and standards, on the ERO’s use of its special powers under Section 321 of NERC’s Rules of Procedure to streamline the standards development process. 

NERC’s board has invoked its Section 321 powers twice so far: in August 2024 to move forward with standards on inverter-based resources (IBRs), and in January 2025 for a proposed cold weather standard. In both cases the ERO was facing a FERC-imposed deadline that trustees feared they could not meet through the normal stakeholder process, with standards having failed to garner enough votes in formal ballot periods. 

Kim acknowledged that the Section 321 process had been “very time consuming” and “a strain on resources” for both industry and NERC, even though both uses resulted in standards being submitted to FERC. She said the ERO staff has been working to identify the contributing factors in the development of the cold weather standard that required the board to invoke the special authority. 

So far, NERC has identified several common elements, Kim said. First, many of the comments received during the ballot period were not helpful and in some cases “contradicting … the original FERC order and the directives that were issued,” leaving the standard development team unsure how they could address industry concerns while still satisfying the commission’s mandate.

“Process inefficiencies” also contributed to the ERO’s inability to finish the standard in time, Kim said, naming the difficulty of assembling a standards development team given the limited availability of industry stakeholders as an example. In addition, she said miscommunication between NERC and industry at key moments kept the project from meeting its goals. 

NERC staff members are working on recommendations for both the ERO and industry to address these issues, Kim said. For industry, these include working out ways for interested employees to participate in NERC’s drafting teams, work groups and task forces; improving metrics for measuring the progress of standards development projects; and revising the process and timing for FERC engagement.  

Recommendations for NERC include figuring out how new participants can get involved in the standards process and enhancing the process for holding technical conferences, which formed an important part of the Section 321 cycle for both the IBR and the cold weather standards. 

RDA Updates, IBR Alert Approved

Trustees also approved changes to NERC’s regional delegation agreements at the meeting, ahead of their expiration at the end of the year. The RDAs set out NERC’s relationships with the regional entities, including their authority to engage in compliance monitoring and perform reliability assessments. They now will be filed with FERC, to take effect Jan. 1, 2026. 

In addition, the board approved a Level 3 alert setting out essential actions for registered entities to take regarding IBR performance and modeling. These include enhancing the generator interconnection and planning policies, performing a review of IBRs currently on the system to determine the accuracy of their models, and implementing process to verify the accuracy of models used in the interconnection and planning processes. 

Posted on

SPP Approves 6th Competitive Transmission Project

OMAHA, Neb. — SPP has approved its sixth competitive project under FERC Order 1000, a 345-kV transmission line in Oklahoma bringing “needed congestion relief” north of Oklahoma City.

There’s more to come. SPP also said it has classified two more transmission projects as meeting the criteria for being considered competitive upgrades.

SPP’s Board of Directors on May 6 endorsed an industry expert panel’s (IEP) recommendation to select Transource Oklahoma, with Transource Energy, to build the proposed 38.4-mile, 345-kV transmission line. Transource expects the Mathewson-Redbud project to cost $72 million and plans to energize the line in 2027.

The board also approved a bid from incumbent transmission owner OG&E Transmission, with ITC Great Plains, as the alternate builder. Their bid, the only other one submitted, had an estimated cost of $84 million. That proved to be the deciding factor.

OG&E and ITC both voted against the recommendation in the Members Committee’s advisory vote to the board. Five other members abstained from the 12-2 vote.

The IEP, comprising industry experts independent from SPP, unanimously recommended the Transource proposal. It said that while both bids were “capable” of financing, constructing, operating and maintaining the project, Transource’s bid “presented an advantage primarily based on lower costs.”

“Because there were only two proposals, the determining factor was the cost of the project,” it said.

“We felt good with that result,” Steve Strickland, the IEP’s chair, told the board and members. “We believed either respondent was capable of producing the project.”

The panel determined the project’s lifetime cost, as measured by the present value revenue requirement, would provide more than $14 million in savings to SPP customers. It said the OG&E-ITC bid provided a “more robust” engineering design that added costs and risks that “negated most, if not all, of those benefits.”

The five-person IEP met virtually and in-person after the Mathewson-Redbud project reached the criteria to be classified as a competitive upgrade. The project first was identified in the 2023 Integrated Transmission Planning (ITP) assessment as an economic project with projected costs of $110 million; it was pulled from the portfolio because some of its upgrades would qualify as a competitive upgrade. (See “MEAN Appeal of ITP Fails,” SPP ‘All Over’ Addressing Resource Adequacy.)

Mathewson-Redbud transmission project | SPP

The panel evaluated the two bids through SPP’s competitive TO selection process, required under Order 1000. It scored the bids based on engineering design, project management, operations, rate analysis and finance.

SPP Director Irene Dimitry said OG&E, the incumbent TO, will handle the substation upgrades. That lowered the initial estimate.

Transource said it was “excited to get to work building this new transmission line” and support Oklahoma’s growing economy.

The developer is a partnership between American Electric Power and Evergy, focused on developing and investing in competitive projects nationwide. AEP owns 86.5% of the company.

SPP’s board annually forms a pool of industry experts that might be called upon to review, rank and score the competitive proposals. The grid operator already has solicited candidates for this year’s IEPs.

The panels will evaluate two projects that were part of the 2024 ITP:

  • the 345-kV Belfield-Maurine-Underwood-Laramie River project, a 438-mile line that runs from the Laramie River in Wyoming up into the Dakotas and has an estimated cost of $1.1 billion; and
  • the 345-kV Elm Creek-Tobias project on the western side of SPP’s footprint, an 85-mile segment valued at $887 million.

According to a report by consulting firm Concentric Energy Advisors critical of Order 1000’s success, MISO and CAISO have considered nearly 40 competitive projects between them. SPP has considered the third most (10) and approved of six:

  • North Liberal-Walkemeyer
  • Sooner-Wekiwa 345 kV
  • Wolf Creek-Blackberry 345 kV
  • Minco-Pleasant Valley-Draper 345 kV
  • Crossroads-Hobbs-Roadrunner 345 kV
  • Mathewson-Redbud 345 kV

The North Liberal-Walkemeyer project later was withdrawn.

The 2024 ITP was SPP’s largest portfolio in both size and value in its 20 years as a transmission planning coordinator. The plan includes 89 transmission projects, representing 2,333 miles of new transmission and 495 miles of rebuilds — including 1,900 miles of the RTO’s first 765-kV lines — to address increasing load growth and changes in the region’s generating fleet. SPP expects the portfolio’s benefits to exceed costs by a ratio of at least 8-to-1. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.)

Posted on

ISO-NE Discusses Details of New Prompt Capacity Market

ISO-NE and NEPOOL members discussed how to address market power, tie benefits and resource qualification in a prompt capacity market during a three-day meeting May 6 to 8.

The RTO is working to transition its Forward Capacity Market — which features auctions held three years prior to each capacity commitment period (CCP) — to a prompt market, with auctions held one month before each CCP.

The move to a prompt market is intended to increase the accuracy of available information prior to each auction and eliminate the phenomenon of in-development resources receiving capacity supply obligations (CSOs) but not coming online quickly enough to meet them.

The RTO plans to file its prompt market proposal in late 2025. Once it completes the prompt market design, ISO-NE plans to begin working on the details of a separate proposal for seasonal capacity market changes, which would split CCPs into separate six-month winter and summer periods.

Market Power Mitigation and Resource Retirements

Responding to feedback from NEPOOL members at the Markets Committee in April, ISO-NE has walked back a proposal for a penalty to prevent the abuse of market power in the new auction format.

The market power charge would have applied to retiring resources that fail a pair of ISO-NE tests to determine whether the resource is economically viable and whether its retirement would provide net benefits to the resource owner’s generation portfolio. (See ISO-NE Outlines Market Power Mitigation Measures for CAR Project.)

“Multiple sectors shared concerns on potential issues associated with an imposition of the market power charge,” said Kevin Coopey, principal analyst at ISO-NE. He said the feedback included concerns about the “individualized nature” of market power penalties on participants found to be exercising market power, compared to the “potential regional harm.”

He said ISO-NE “continues to believe that there could be benefits to a [market power charge] and may further assess such a framework after CAR [the Capacity Auction Reform initiative] is completed.”

In place of a penalty, ISO-NE plans to adapt its existing process of proxy supply offers. Proxy offers would apply only to resources that fail both the conduct test and the net-portfolio benefits test and would last for one year after a resource’s retirement.

Stakeholders at the MC generally expressed appreciation for the elimination of the proposed market power charge, while some continued to advocate for more flexibility around retirement submissions. ISO-NE still proposes to require retirement notifications to be submitted two years in advance and would not allow participants to withdraw submissions.

ISO-NE also adopted a proposal made to the MC in April by LS Power to allow accelerated retirements for requests that pass reliability and market power tests. Once a resource is approved for accelerated retirement, it would be able to retire as soon as its first month without a CSO.

Buyer-side Market Power Mitigation

ISO-NE also plans to largely maintain its existing format for mitigating buyer-side market power, economist Andrew Copland said.

Buyer-side market power occurs “when a participant with a large load-side interest attempts to lower its total capacity market costs through the uneconomic entry of a resource,” he noted.

New passive demand response resources and resources smaller than 5 MW are exempt from buyer-side market power mitigation, along with new resources supported by federal or state governments to support decarbonization and resources “that do not receive out-of-market revenues from [a load-serving entity], state or political subdivision of a state.”

Resources also could avoid mitigation by passing a conduct test or providing evidence showing that their sponsoring LSE “is unlikely to realize a material net financial benefit.”

If a market entrant does not meet any of these criteria, it would be subject to an offer floor price imposed by the ISO-NE Internal Market Monitor.

Tie Benefits

Also at the MC, members debated how ISO-NE accounts for tie benefits in the capacity market.

Tie benefits describe the level of support the RTO expects to receive from neighboring control areas during grid emergencies. ISO-NE assumes about 2,000 MW of tie benefits, which reduces the amount of capacity it needs to procure in its capacity auction.

In recent months, New England generators have pushed back against this assumption and have argued the RTO should not treat tie benefits as equivalent to resources with CSOs.

Bruce Anderson, general counsel for the New England Power Generators Association (NEPGA), said that because tie benefits are not supported by CSOs or subject to Pay-for-Performance penalties, ISO-NE should not reduce its installed capacity requirement to account for them.

“Rather than reduce the capacity market demand quantity based on a probabilistic estimate of the amount of energy ISO-NE can rely on during capacity deficiencies, the value of import megawatts should be grounded in actual, firm offer and delivery requirements,” Anderson said.

He argued that the current approach “compromises system reliability” and “displaces resources willing to assume a capacity supply obligation, including those both within New England and in neighboring control areas.”

Ben Griffiths of LS Power expressed particular concern about Hydro-Quebec interconnection capability credits (HQICCs) on the Phase II transmission line between New England and Quebec. HQICCs reduce the capacity charges for interconnection rights holders that financially support the line.

Griffiths argued the current methodology gives HQICCs “preferential treatment compared to capacity,” while non-interconnection-rights-holding participants are effectively “compelled to purchase HQICCs at above-market rates even when true performance-backed capacity is available at the same price.”

He said ISO-NE should conform its treatment of HQICCs “with either PTF [pool transmission facilities] or capacity obligations” to boost market equity and improve reliability.

He also emphasized the uncertain emergency benefits associated with the lines, noting that Hydro-Quebec has not given emergency assistance to New England over at least the last seven years.

“We have no idea how much, if any, emergency assistance [Hydro-Quebec] could provide New England when needed,” Griffiths said.

Other stakeholders pushed back on NEPGA and LS Power’s arguments, saying that tie benefits are an important input into the ICR and are supported by agreements between neighboring regions.

At the April MC meeting, Matthew Ide, of the Massachusetts Municipal Wholesale Electric Co., said that “network load customers pay for all the tie benefits that come from the PTF ties through regional transmission rates. In return, load receives the benefit of a lower ICR and less need to procure capacity to meet the ICR.” (See NEPOOL Markets Committee Briefs: April 8-9, 2025.)

Resource Qualification

Jennifer Engelson, supervisor of resource qualification at ISO-NE, detailed the RTO’s current thinking on resource qualification in a prompt auction.

New resources that have not achieved commercial operations will be allowed to participate in auction qualification activities but must come online prior to a “capacity demonstration deadline” in early April prior to the auction in May, she said. ISO-NE plans to issue preliminary qualified capacity (QC) values in February but would not finalize these values until after the demonstration deadline and a period for participants to challenge their QC values.

For intermittent resources, QC will be based on “the average of the median of the resource’s net output in reliability hours for the most recent five seasonal periods,” Engelson said.

For non-intermittent resources, QC will be based on the median seasonal claimed capability for the past five years. QC for non-intermittent imports and distributed energy capacity resources will be based on seasonal audit values.

Posted on

Panel Explores How Western Markets Have ‘Played off’ Each Other

SACRAMENTO — In the competition between two Western day-ahead markets — CAISO’s Extended Day Ahead Market (EDAM) and SPP’s Markets+ — the two market operators have “sort of played off one another,” an industry observer said. 

Kris Raper, vice president of strategic engagement and external affairs at WECC, offered her views on the developing Western markets May 6 during a California Energy Transition Summit hosted by Infocast. 

For a while, it seemed like CAISO’s Western Energy Imbalance Market (WEIM) and EDAM “were really the only game,” Raper said during a panel discussion on Western markets. 

But then “SPP sort of came in the room and they had to create a space for themselves,” Raper said. 

“My personal observation is that SPP has sort of stood back a bit and seen within … CAISO, within the EIM and the EDAM formation, what has worked for them and what has not,” Raper said. “And they have taken a script from that.” 

“It’s a good thing, right?” she added. “If it makes them all better and utilizes more stakeholder input.” 

Raper’s comments came in response to an audience member question on what California can learn from SPP’s Western market expansion. 

Another panelist, Western Freedom Executive Director Kathleen Staks, also responded. 

“California has learned that … the hatred for California is real,” Staks said. “That is part of why SPP saw that moment. California was not responding to the needs of the West in an adequate way.” 

Staks is Launch Committee co-chair for the West-Wide Governance Pathways Initiative, which is developing a new independent Western “regional organization” (RO) to oversee CAISO’s WEIM and EDAM. Some potential market participants are uncomfortable with markets led by CAISO, whose Board of Governors members are appointed by the California governor. 

The Pathways effort now hinges on Senate Bill 540 in the California legislature, which would allow an independent RO to oversee CAISO energy markets. (See California Lawmakers Seek to Trump-proof Pathways Initiative Bill.) 

Affordability, Reliability

Raper described many of her comments as “personal observations” and noted that WECC has a neutral view on energy markets.  

“If it adds to reliability, then that’s something we would support,” Raper said. 

The market developments are occurring as lawmakers in several states are responding to constituent concerns by taking back power that was delegated to utility commissions, Raper said. That means a new group of stakeholders who must be educated on the issues. 

“A lot of the reason that legislators are hearing from their constituents is because costs are so high,” Staks said. 

If SB 540 doesn’t pass, Staks said, utilities that haven’t yet committed to a day-ahead market may choose a non-CAISO option and leave CAISO’s WEIM. 

“That is not good from an affordability standpoint for California,” Staks said. “It is not good from a reliability standpoint, because it makes it harder to trade with our neighbors, and it’s not as good from an emissions standpoint.” 

Posted on

California, Other States Sue Trump Administration over Halting EV Charger Funds

A coalition of 17 states has filed a federal suit contending that President Donald Trump’s administration is unlawfully withholding billions of dollars in congressionally approved funds meant for the expansion of electric vehicle charging infrastructure. 

Led by attorneys general from California, Washington and Colorado, the states claim the U.S. Department of Transportation’s Federal Highway Administration (FHWA) — acting under an executive order issued by Trump on his first day in office — is withholding $5 billion in funding for EV charging infrastructure “in diametric opposition to statutory mandate,” according to the complaint filed with the U.S. District Court in Seattle. 

The states seek a preliminary injunction to stop FHWA from withholding the funds and a court order declaring their actions unlawful. 

“When America retreats, China wins. President Trump’s illegal action withholding funds for electric vehicle infrastructure is yet another Trump gift to China — ceding American innovation and killing thousands of jobs,” California Gov. Gavin Newsom said in a statement announcing the suit. “Instead of hawking Teslas on the White House lawn, President Trump could actually help Elon — and the nation — by following the law and releasing this bipartisan funding.”  

Congress approved the funding under the bipartisan Infrastructure Investment and Jobs Act of 2021. But following Trump’s Jan. 20 executive order called Unleashing American Energy, the FHWA has refused to comply with its obligations to distribute the money to states and has instead withheld the money, the complaint alleges. (See Trump Will Need More than Orders to Meet Rising Demand.) 

The states argue the federal government’s actions hinder their EV efforts, saying, “The harms to plaintiff states will continue and become increasingly damaging if unabated.” 

“Plaintiff states each have invested in programs to encourage adoption of EVs as a means of reducing smog, air toxics and other harmful pollution from combustion engine vehicle emissions, which cause grave health problems such as cancer and asthma and [contribute] to the devastating effects of climate change in these states,” the suit states. 

California accounts for more than 30% of all zero-emission vehicles sold in the U.S., and the FHWA’s actions could cost the state more than $300 million, risk thousands of jobs and thwart the tech industry, according to a statement. 

Under the executive order, Trump directed all agencies to pause funding appropriated through the Infrastructure Investment and Jobs Act, including money for EV infrastructure. Specifically, the order aims to eliminate the EV “mandate” and the “Green New Deal” in an effort to “promote true consumer choice” and get rid of “unfair subsidies and other ill-conceived government-imposed market distortions that favor EVs over other technologies and effectively mandate their purchase by individuals,” the order states. 

However, the states claim in the suit that “agencies have no authority to rescind or revise statutes, or to withhold funds duly appropriated by Congress based on the president’s disagreement with the policies and priorities of Congress.” 

The directive was one of several Trump issued on his first day in office this January, which also included one addressing an “energy emergency.” 

The suit follows a similar complaint filed May 5 by a group of 18 Democratic state attorneys over Trump’s decision to halt wind energy projects’ federal approvals. (See State Attorneys General Sue Trump for Halting Wind Approvals.) 

The complainants in that lawsuit include states that were allegedly banking on major offshore wind projects that have been interrupted, such as New Jersey and New York, as well as many impacted by the order’s impact on onshore wind, such as California and New Mexico. 

Posted on

DOJ Seeks PJM Market Data for Review of Constellation-Calpine Merger

The U.S. Department of Justice’s Antitrust Division is looking into Constellation Energy’s proposed purchase of Calpine, sending an information request to PJM for market data by May 30 as part of its review.

“The Department of Justice request of PJM is not unusual for a transaction like Constellation’s acquisition of Calpine,” Constellation said in a statement. “We proposed a robust plan for satisfying the Department of Justice’s review of the transaction, and we are confident that our filing will be approved in a timely manner. Once approved, Constellation will be even better positioned to deliver reliable and affordable energy to our customers from coast to coast.”

The proposed merger is the largest in years among independent power producers, and while the two firms have operations across the country, they overlap most in PJM, where potential market power issues have dominated the debate in FERC’s docket for the deal (EC25-43). (See Constellation-Calpine Merger Draws Protests over Market Power Concerns in PJM.)

FERC filed a notice on April 14 seeking comment from parties in the docket on proposed communications between its staff and DOJ’s Antitrust Division while its own review is pending. That was not opposed by either side, though a group of protesters asked FERC to file reports on any communications, while Constellation responded that it has asked for confidential treatment of the commercially sensitive information in the docket.

“The applicants support any interagency communication that will lead to a more efficient review and approval of the application,” Constellation told FERC.

DOJ’s request to PJM seeks a broad range of market data since Jan. 1, 2023, including details on every generator in the market and all of the participants in auctions for energy, capacity and financial transmission rights. It asks for details on all generators’ bids into PJM markets, any outages and the resulting locational marginal prices.

The request also seeks information on net flows over transmission lines for the real-time and day-ahead markets and the transfer capabilities of the lines PJM manages, including warning levels and transfer limits.

DOJ also wants details on all imports and exports, including the entities behind them and their contract path. It also asked for transfer capabilities between PJM and its neighboring systems on an hourly basis.

The request asks for every time the three-pivotal-supplier test was applied and led to mitigation of generators in the energy markets. It seeks breakdowns by year for how many hours specific generators had their offers mitigated.

DOJ also wants information on the capacity market dating back to the 2024/25 auction, held in 2022, including every local delivery area’s demand curves, details on every generator’s offer into the market and details on generators using the fixed resource requirement alternative.

Finally, the department is seeking details on the entire market’s portfolio of FTRs and auction revenue rights since Jan 1, 2023.

Posted on

MISO Prepping for Likely 123-GW Summer 2025 Peak

MISO cautioned it likely is in for heat waves and drought this summer with a slight chance it navigates a 130-GW peak in July.

The RTO expects a coincident summertime peak of 122.6 GW, exactly the same as for July 2024. However, based on its load-serving entities’ noncoincident peak forecasts, MISO reported load could drift up to 130 GW in July, a high never seen in the footprint.

In MISO, noncoincident peak forecasts represent the monthly peak load submitted by LSEs; coincident peak forecasts, on the other hand, are adjusted relative to the RTO’s seasonal peaks.

According to LSEs’ noncoincident peak forecasts, MISO could contend with a 127.6-GW peak even in August.

MISO’s all-time summer peak of 127 GW occurred July 20, 2011. Last summer, it also warned it might eclipse that record but rounded out the season with a 122-GW peak in late August. (See MISO: Hurricanes, Heat Wave Noteworthy Against Relatively Peaceful Summer and MISO Braces for Hot Summer, Potential 130-GW Peak.)

During a May 8 summer readiness workshop with stakeholders, MISO noted it will have more capacity than absolutely necessary when its planning year begins June 1.

The grid operator set an initial planning reserve margin requirement of 135.2 GW for summer and ended up clearing slightly over 137.5 GW because of its sloped demand curve in April’s capacity auction, the first time the curve was used. It is meant to procure more capacity than strictly necessary to meet MISO’s one-day-in-10-years loss-of-load standard. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)

MISO’s total cleared capacity includes 124.2 GW of traditional generation and 13.3 GW of load-modifying resources, which include demand response, behind-the-meter generation and energy efficiency. The RTO must declare an emergency to access its LMRs. Even if MISO realizes its most likely outcome of a 123-GW peak, the demand will require nearly all of its nonemergency resources.

When asked by stakeholders whether MISO could place a probability on entering emergency procedures, resource adequacy engineer John DiBasilio pointed out that it “cleared more resources than usual” for the 2025/26 planning year and said those resources are under an obligation to offer.

“You are gaining a mandate on some additional resources to be available in the market,” DiBasilio told stakeholders. He declined to guess the likelihood of MISO declaring an emergency.

The RTO said its 13-GW solar fleet, which has more than doubled in size since last summer, also should help. MISO meteorologist Adam Simkowski said it expects to have nearly 15 GW in solar capacity by July, which will translate to an average 9-GW daytime high. However, Simkowski warned that solar output is more challenging to forecast minutes ahead in the real-time market than wind generation, which has more predictable forecasts.

A hypothetical August evening peak transformed by 15 GW of solar generation | MISO

Simkowski said by August, solar contributions should be consequential enough to shave evening peaks and delay usual net peak loads by two to three hours. Because solar output tapers in the evening, MISO will have greater ramping needs, “a relatively new phenomenon” it must contend with, Simkowski said. The RTO said it plans to introduce dynamic reserve requirements that can be set to high, medium or low based on forecasts and weekday versus weekend use patterns.

MISO previously said it hopes to use dynamic reserves by the beginning of 2026. The Independent Market Monitor has warned that ramping needs beyond 10 GW are becoming increasingly common in the footprint and presenting challenges in the control room. (See MISO IMM Warns of Operational Difficulties with Growing Solar Fleet.)

Heat and Drought

Simkowski and fellow meteorologist Brett Edwards said they expect temperatures to trend above normal in summer, with the potential for drought over the Central U.S. to exacerbate heat waves in MISO.

They said MISO South, especially areas along the Gulf Coast, should experience more normal precipitation patterns.

The RTO said five historical years (2012, 2017, 2018, 2021 and 2022) provide the best reference for what is likely to happen. It said all analog years had summers in which load topped 115 GW systemwide, with 2012’s persistent heat and extreme drought delivering load that exceeded 120 GW for multiple days.

Edwards said the footprint might be in for a repeat of summer 2012, where load and heat were high.

MISO said over summer 2024, temperatures lined up with historical averages, and only two days in late August exceeded a 90-degree Fahrenheit systemwide temperature. The RTO is not expecting such tame temperatures this year.

The 2025 outlook lines up with the National Oceanic and Atmospheric Administration, which has called for above-normal temperatures over the whole of the continental U.S. and below-normal rainfall across most of the MISO footprint.

Finally, MISO said it anticipates a normal to slightly busier-than-usual hurricane season in the Atlantic Ocean, with an early start time similar to 2024 because of warm ocean waters in the Caribbean.

Posted on

BPA’s Tx Planning Pause Prompts Talk of New RTO, Stricter TSR Requirements

Following the Bonneville Power Administration’s pause on certain transmission planning processes, the agency’s customers say it might be time to consider creating a regional transmission organization or imposing stricter requirements to tackle the “exponential growth” of transmission service requests.

BPA heard from several customers and industry stakeholders during a May 6 workshop, including Seattle City Light, NewSun Energy, Portland General Electric (PGE), Northwest & Intermountain Power Producers Coalition (NIPPC), Renewable Northwest, Northwest Requirements Utilities and Western Public Agencies Group.

The agency hosted the workshop after it issued a pause in February to consider new “reforms” in light of “exponential growth” of transmission service requests (TSRs). BPA’s 2025 transmission cluster study includes over 65 GW of TSRs, compared with 5.9 GW in the 2021 study. The requests exceed the total regional load projected for the Pacific Northwest in 2034, according to the agency. (See BPA Halts Some Tx Planning Processes Amid Service Requests.)

After it issued the pause, BPA started soliciting stakeholder comments on how the agency can improve the transmission queue and deliver on its goal to go from transmission customer request to service in five to six years.

To meet that goal, BPA and power entities in the West must explore a range of possible approaches, even some controversial ones like creating an RTO, Michael Watkins, policy adviser at Seattle City Light, said during the workshop.

“Is it time for the West to finally wrap their hands around and accept that maybe we should form a regional transmission organization to bring us all together under one umbrella and actually serve our transmission needs?” Watkins said. “And it might be time to do that, and maybe it’s not, but we should talk about it as part of this process. That’s what we’re suggesting. I know that’s contentious, but I think that ought to be part of the discussion.”

Watkins also said it might be time for the West to consider solutions implemented in the East, like power transfer distribution factor scheduling and compensation change.

Speaking on behalf of NIPPC, Henry Tilghman said he agrees the West should consider an RTO.

“We should also consider moving to a congestion rights or a financial transmission rights model for transmission service,” Tilghman added.

Given BPA’s upcoming decision on whether to join a day-ahead market, “I think considering how we can move to a congestion rights model might be something we want to put into the hopper,” Tilghman said.

Other NIPPC recommendations include identifying reforms that don’t need a tariff change, ensuring interconnection and transmission service requirements are consistent and prioritizing the transition process.

Meanwhile, Laura Green of PGE said the utility supports imposing stricter data exhibit requirements to ensure only feasible TSRs move forward and clear the queue of requests that aren’t ready.

“You need to identify your [point of receipt] and your [point of delivery] and upstream generation resources, which I think we already do today. I think that’s part of the requirements,” Green said. “So it will be interesting to see what additional requirements might be put on customers.”

Jake Stephens, CEO at NewSun Energy, said BPA should think about interim solutions and study “the lower hanging fruit” like already planned upgrades or “simple redirects.”

While BPA’s efforts to address the growth of TSRs are good, the pause has impacted the market and companies that invested in resources in the belief their transmission requests would be studied, Stephens noted.

“Bonneville coming up with an interim way to keep working through that queue, I think is important,” Stephens said. “I think it’s necessary one way or another, because at the end of the day, if everything is studied, the results from all of that are going to be so staggering as to almost be undigestible.”

Posted on

E-ISAC Reports on Cyber, Physical Threats

The cyber and physical threat landscape facing electric utilities remains “as dynamic and complex as ever,” especially in light of recent “geopolitical and economic developments,” officials from the Electricity Information Sharing and Analysis Center (E-ISAC) told members of NERC’s Board of Trustees. 

Speaking at the quarterly open meeting of the board’s Technology and Security Committee on May 7, E-ISAC Vice President of Security Operations and Intelligence Matt Duncan cited recent threat assessments from the U.S. and Canadian governments that found “a growing cast of malicious and unpredictable actors” posing potential dangers to electric reliability. China, Russia, Iran and North Korea continue to represent major cyber threats, with more concern arising from criminals, political activist groups and other non-state actors. 

China’s cyber warfare group “remains the dominant threat,” Duncan said, pointing to an assessment from security vendor CrowdStrike that espionage and reconnaissance activities against U.S. financial services, media, manufacturing and industrial organizations by Chinese actors increased 300% in 2024 from the previous year. This indicates that “all of the naming and shaming that has gone on with … U.S. foreign policy has not deterred the adversary from continuing to scan and … preposition in [U.S.] networks.” 

Recent years also have seen a rise in malicious cyber activity by “hacktivists,” which Duncan described as a catch-all term for activity by groups not officially affiliated with state actors but associated with various causes, including conflicts between Russia and Ukraine, Israel and Palestine, and India and Pakistan. The last of these conflicts erupted the same week as the TSC meeting and already has seen Pakistani cyber criminals claim to have breached Indian defense systems. 

“While they are not as sophisticated or as capable as a nation-state actor or even a criminal gang, they employ a lot of the same tactics and can impact folks’ reputation and cause disturbances to business operations,” Duncan said. “No electric outages have been caused by these groups, but they certainly have caused some website outages and some other, higher-profile events related to websites facing the electricity industry.” 

Duncan devoted a significant part of his presentation to reviewing physical threats and the E-ISAC’s response to them. He noted that information sharing across the industry improved significantly in 2024, with utilities voluntarily sharing 45% more physical security incident data with the E-ISAC than in the previous year. 

Despite the greater information volume, Duncan emphasized that the number of incidents that affected the grid remained low in 2024. The E-ISAC uses a four-level system for assessing security threat levels: level 0 indicates non-criminal activity; level 1 is criminal activity resulting in no outages; level 2 is criminal activity that results in outages for fewer than 10,000 customers; and level 3 is criminal activity resulting in at least outages for at least 10,000 customers. 

The last two categories comprised around 3% of the physical incidents recorded for the entire year, around the average for the past five years. Of these incidents, the four most common types were theft, vandalism, ballistic damage and intrusion, representing 35, 27, 25 and 12%, respectively. 

While theft of copper wire is a longstanding problem for electrical facilities, Duncan said the E-ISAC has also seen significant reports of optical fiber being cut. He called this phenomenon “a very concerning development” for both the energy and the telecommunication sectors, because it could lead to loss of communication with control centers. 

He added that perpetrators may be motivated not by sabotage but simple greed, because “the coating [on the fiber optic cables] looks very similar to the untrained eye” to that on copper cables. Nevertheless, the E-ISAC continues “to ring the bell with government and our telecommunications partners.” 

Duncan also pointed out the significant number of incidents in which the apparent motive was to cause damage, noting that “those are the types of attacks you want to focus a little bit more on, because … somebody was actually trying to cause an impact, and it wasn’t an accident.” He noted that a large amount of violent rhetoric online discusses sabotaging the grid to achieve political gains. 

Bluma Sussman, the E-ISAC’s vice president of stakeholder engagement, hinted at the “challenging times” facing U.S.-Canada relations while promising that nothing would change the organization’s engagement with its Canadian partners. 

“Our ISAC is not just here for U.S. utilities, but for all of the North American electricity industry, and our partnership with Canadian utility members and government partners is a critical one,” Sussman said. “Our shared commitment to the reliability and security of the North American power grid is paramount, and its foundation lies in these strong relationships.” 

Posted on

Duke Earnings Report Highlights Huge Investments to Meet Load Growth

Duke Energy is seeing demand growth at a level its new CEO, Harry Sideris, has not seen in his 30-year career, and that is leading to massive investments across its utilities over the next decade. 

“We are ready to meet the moment with a renewed focus on speed and agility and supported by the same spirit of innovation that has been at the heart of this company for over a century,” Sideris said during a first-quarter earnings call May 6. “As I assume the CEO role during this pivotal point for our company and industry, Duke Energy’s mission remains unchanged: delivering long-term value for shareholders and superior service to our customers and communities by building a smarter energy future.” 

To support that new demand, Duke plans to invest $83 billion through 2029 and up to $200 billion cumulatively through 2034. 

That spending includes new generation and transmission and increased spending on its existing generation. The utility recently won 20-year license extensions from the Nuclear Regulatory Commission to keep its Oconee Nuclear Station in South Carolina running until midcentury. Sideris said Duke plans to do the same for the rest of its nuclear fleet. 

The firm also is investing in uprates at its other generators, which are small at the individual level but add up to 1 GW of new supply across its utilities, Sideris said. 

That 1 GW of new supply across its fleet is equal to the amount of load to be served under new contracts it signed with just two large users in April, Sideris said. 

The company plans to merge its Duke Energy Carolinas and Duke Energy Progress utilities, which have maintained some corporate separation since it bought Progress Energy in 2012. The firm plans to file applications with North Carolina and South Carolina regulators and FERC in 2025 and hopes to complete the merger by January 2027. 

“The proposed merger would create significant customer savings, simplify operations and regulatory processes, and add operational flexibility to our system,” Sideris said. 

Duke is seeing growth now, especially in its Southeast utilities and Indiana, but it expects the rate will pick up this decade, CFO Brian Savoy said. 

“We continue to expect load growth to accelerate, beginning in 2027 as economic development projects come online. Our economic development pipeline continues to grow and includes advanced manufacturing projects across multiple sectors, as well as data centers,” Savoy said on the earnings call. “We’re streamlining processes across the organization to accelerate projects through the pipeline, which is yielding results.” 

Duke is trying to figure out how its plans will be impacted by President Donald Trump’s tariffs, Savoy said. 

“It’s important to remember that tariffs primarily affect capital, and the majority of our capital spend is American labor, which is not subject to tariffs,” Savoy said. “We currently estimate the impact of tariffs to be about 1 to 3% of our five-year capital plan, and we are confident in our ability to further minimize the impact, leveraging our size and scale to work with suppliers across our diverse supply chain.”