DETROIT — MISO said its 2026 budget requires an increase of more than 11% over 2025’s.
MISO plans to allot itself $448.4 million in operating expenses and project investments in 2026, up 11.2% from 2025’s $403.3 million budget, CFO Melissa Brown told the Board of Directors’ Audit and Finance Committee on Oct. 29.
The RTO said it would increase its administrative fee from 51 cents/MWh in 2025 to 54 cents/MWh in 2026.
Brown told the committee that modern systems are more expensive to implement and maintain, and MISO needs to spend more to complete the switch from its legacy software to newer technology.
“That’s kind of the balancing act we’re in right now,” Brown said.
The committee voted unanimously to recommend the budget. The full board will vote on whether to approve the draft 2026 spending amounts at its year-end meeting Dec. 11 in Indianapolis.
Brown said the budget may be reduced by that time, with MISO shedding about $2 million to $3 million in project investments.
MISO now experiences more volatility in its financial estimates for its major projects, Brown said, including evolving design work on new initiatives such as planning for large loads, rolling out ambient-adjusted ratings for transmission lines, working on the interconnection queue fast lane and getting the regular queue down to a single-year process.
The RTO also plans to hire 28 staff members for new positions in 2026, spread across operations, planning and cybersecurity.
Brown said MISO’s capital investments will jump to $32.4 million in 2026 — up $2 million — mainly from an upgrade to its headquarters-based control room in Carmel, Ind. Brown said the control room hasn’t had an overhaul since its inception.
“To say that it is overdue is probably an understatement,” Brown said during MISO’s last Board Week in Detroit in September.
The stakeholder-led Finance Subcommittee has endorsed the budget.
“MISO has taken a conversative approach with the budget and not yet factored potential load growth from data centers and other new load activity, which could reduce MISO rates,” subcommittee Chair Mitch Myhre, of Alliant Energy, said of the RTO’s 2026 financial plans at the Advisory Committee’s meeting Oct. 28. If MISO collects more from members because of more load being served, it could lower the rate it charges members. But Myhre said the “dynamic environment” today means no one quite knows how much load upsurge to expect.
The U.S. has entered a strategic partnership to pursue construction of at least $80 billion worth of Westinghouse nuclear reactors nationwide.
Cameco Corp. and Brookfield Asset Management, the two owners of Westinghouse Electric Co., announced the agreement Oct. 28.
The company announcements were missing some specifics, and the Trump administration did not make its own announcement. But piecing together the information available, it appears the U.S. has agreed to use tools at its disposal to facilitate construction of reactors and then help pay for them, possibly with Japanese investments, in return for a share of profits and a potential ownership share.
The partnership provides for the U.S. government to arrange financing and facilitate the permitting and approvals for new Westinghouse reactors to be built in the U.S., including near-term financing of long lead-time items.
The 1.1-GW Westinghouse AP1000 reactor at the center of the Oct. 28 announcement would fit the bill, as it is a proven design intended for modular construction and is being used in multiple projects under way worldwide.
But the company announcement did not specifically say the $80 billion or more would be directed to AP1000 construction or say where the money would come from.
“The partnership contains profit sharing mechanisms that provide for all parties, including the American people, once certain thresholds are met, to participate in the long-term financial and strategic value that will be created within Westinghouse by the growth of nuclear energy and advancement of investment into AI capabilities in the United States.”
This sentence was omitted from the Cameco announcement, which contained much more specific information:
“Under the new strategic partnership, the U.S. government will be granted a participation interest which, once vested, will entitle it to receive 20% of any cash distributions in excess of $17.5 billion made by Westinghouse after the granting of the participation interest. For the participation interest to vest, the U.S. government must make a final investment decision and enter into definitive agreements to complete the construction of new Westinghouse nuclear reactors in the U.S. with an aggregate value of at least $80 billion.
“Additionally, in recognition of the anticipated acceleration of long-term value creation that the U.S. government is expected to help unlock by deploying its financial, regulatory, policy and diplomatic tools to support the objectives of the partnership, if, on or prior to January 2029 the participation interest has vested, and if the valuation in an initial public offering (IPO) of Westinghouse is expected to be $30 billion or more at that time, the U.S. government will be entitled to require an IPO.
“Immediately prior to, or in connection with the IPO, the participation interest will directly or indirectly convert into a warrant, with a five-year term, to purchase equity securities equivalent to 20% of the public value of the IPO entity at the time of exercise after deducting $17.5 billion from the public value.”
Support from Japan Investment
The details of the binding term sheet announced Oct. 28 are expected to be replaced with definitive agreements reached through negotiation, Cameco said.
The Brookfield announcement quoted U.S. Energy Secretary Chris Wright and U.S. Commerce Secretary Howard Lutnick cheering the strategic agreement. But neither Energy nor Commerce made any announcement or offered any detail about the agreement.
The White House offered the clearest insight into the finances later Oct. 28, with an announcement from Trump’s ongoing diplomatic tour of Asia, saying that as part of its July agreement to invest $550 billion in the U.S., Japan now has agreed to invest up to $332 billion in critical U.S. energy infrastructure, including Westinghouse AP1000 reactors, GE Vernova small modular reactors and several other types of equipment from other companies.
All of this would fit with Trump’s push for U.S. energy dominance, in part with a massive increase in nuclear generating capacity, and his vision of a revitalized U.S. industrial base.
Until recently, U.S. nuclear energy development had stalled because of the high cost and long timeline for construction. Part of the problem was there have been so many different designs in the U.S. and so few new plants were being built that economies of scale and institutional knowledge were not being developed for construction.
The Plant Vogtle units 3 and 4 expansion in Georgia, for example, was completed years behind schedule and vastly over-budget and helped run Westinghouse into bankruptcy court in 2017.
But Plant Vogtle was the first of its kind in a generation — subsequent efforts are expected to proceed more smoothly. Even Vogtle Unit 4 was faster to completion than Unit 3.
A U.S. Department of Energy report in June noted that the second series of AP1000 reactor construction in China is reaching milestones much more quickly than the first series and predicted that time and cost savings also would accrue in the U.S. if a steady stream of AP1000 reactors are built.
As the demand for nuclear power grows nationwide and worldwide, Westinghouse is presenting the AP1000 as the solution to these first-of-a-kind challenges, offering modular construction in a shorter time frame with simpler design, fewer components, smaller amounts of material and a compacted footprint.
Two AP1000s are in operation at Plant Vogtle and four in China, Westinghouse reports, and 32 are contracted or under construction worldwide.
The AP1000 is not one of the cutting-edge Gen IV reactors in the midst of intense research and design, but rather an advanced evolution of traditional models — a Gen III+, as Westinghouse calls it.
Electric utilities trying to use cloud services to enhance their business continue to face “challenges” complying with NERC’s Critical Infrastructure Protection (CIP) standards, FERC staff said in a report on the commission’s 2025 audits for CIP compliance.
The authors of the 2025 Lessons Learned from Commission-led CIP Reliability Audits report also highlighted issues arising from entities’ failure to ensure CIP compliance from third-party contractors and to consider distributed energy resources and distribution-connected generation when categorizing their control centers.
FERC has conducted CIP audits since 2016 for each fiscal year, which runs from Oct. 1 to Sept. 30 of the following year. During the fiscal year, staff from FERC, NERC and the regional entities conduct audits with select utilities, comprising “data requests and reviews, webinars and teleconferences, and virtual and on-site visits.” The visits include interviews with entities’ subject matter experts, employees and managers; demonstrations of operating practices and procedures; and field inspections of high-, medium- or low-impact cyber assets.
As in previous years, details of the audits, such as how many audits were performed and which utilities were visited, were not disclosed in the report. The authors wrote that “while most of the [entities’] cybersecurity protection processes and procedures … met the mandatory requirements of the [CIP] standards, potential noncompliance and security risks remained.”
The warnings about cloud services came in a discussion of two instances where entities used cloud services to perform the functions of electronic access control or monitoring systems (EACMS) and physical access control systems (PACS). FERC staff observed that the CIP standards were originally “developed prior to the advent of cloud services [when] registered entities housed their cyber assets and cyber systems on premises.”
While efforts are underway to incorporate cloud technology into the CIP standards through Project 2023-09 (Risk management for third-party cloud services), the standards as they currently stand “simply do not contemplate cloud services,” the authors wrote. This fact creates “challenges demonstrating CIP compliance” for entities trying to use such services.
For example, FERC staff observed that CIP-004-7 (Cybersecurity – personnel and training) requires entities to conduct and demonstrate personnel risk assessments, including identity verification and background checks, for all individuals with electronic or physical access to grid-connected cyber systems. However, if cloud services are used, then this category would include employees of the cloud service provider, and entities may not be able to conduct investigations into such people.
CIP-010-4 (Cybersecurity – configuration change management and vulnerability assessments) presents another challenge, the authors wrote, because it “requires the development, maintenance and documentation of a baseline [system] configuration,” including multiple levels of hardware and software. This would be difficult to produce in a cloud system, where hardware and system-level configurations are often abstracted, and the integrity and source of software can be hard to verify.
To address these risks, FERC staff said entities should ensure that their high- and medium-impact cyber systems do not use cloud services. Low-impact systems may use cloud services, but entities should monitor their status and be prepared to mitigate compliance risk associated with the cloud if the impact rating changes.
Third-party Compliance Outsourcing Risks
Third parties were also mentioned in another section of the report that discussed utilities’ use of outside entities to help meet their compliance duties. Staff wrote that auditors “observed several instances where registered entities did not perform due diligence when relying on third parties.”
In one case, auditors saw that a utility did not properly oversee a firewall update that it contracted to a third party, and that party did not complete the task. This left unnecessary inbound and outbound electronic access within the entity’s firewall, a violation of CIP-003-8 (Cybersecurity – security management controls).
Another entity contracted with a vendor to install, test and maintain a cloud-based PACS, including the recurring 24-month testing required by CIP-006-6 (Cybersecurity – physical security of BES cyber systems). However, the vendor did not conduct the testing, and the utility lacked oversight controls to tell whether the vendor had done so.
Finally, a utility hired a third party to conduct vulnerability scanning, review scanned results and prioritize mitigation plans as part of the vulnerability assessment required by CIP-010-4. However, the entity did not participate in all phases of these activities. FERC staff did not indicate whether the third party failed to perform these tasks but observed that by failing to participate, the entity was already in violation of the standard.
Staff said that entities could mitigate the risk posed by outsourcing compliance functions to third parties by implementing compensating controls such as contractual agreements, internal controls to provide oversight, and ensuring third-party staff, infrastructure and data are located within the continental U.S.
DER Classification Oversights
The last issue flagged in the report had to do with the impact rating assigned by utilities to control centers as required by CIP-002-5.1a (Cybersecurity – BES cyber system categorization). Auditors found that some entities “failed to consider DERs and distribution-connected generation in their calculations” of the impact rating of a control center performing generator operator functions.
This oversight meant that operators lacked insight into the true level of generation on their systems, FERC staff wrote, especially because in some cases DERs — though small individually — accounted for large amounts of generation in the aggregate. Failing to properly categorize these systems meant entities might not apply the proper controls.
FERC staff recommended that entities “assess and document generation resources holistically, including DERs,” and ensure that they are assigned the impact rating commensurate with their true capacity.
PacifiCorp and Portland General Electric remain on track to join CAISO’s Extended Day-Ahead Market (EDAM) on their planned entry dates, although the schedule remains “very tight and very aggressive,” CAISO executives said during a stakeholder meeting.
“Things are going very smoothly,” CAISO Chief Information and Technology Officer Khaled Abdul-Rahman said during the Oct. 27 Western Energy Markets Regional Issues Forum (RIF) meeting. “We are going to be in market simulation for [PacifiCorp] until mid-January 2026, and our go-live is scheduled for May 1, 2026.”
PacifiCorp’s systems are being tested in EDAM’s market simulation phase, which is a critical step to ensure market features, rule changes and system upgrades are working as designed, CAISO said in a document on the subject.
CAISO in 2025 has held workshops to show how more complicated parts of EDAM will work, such as scheduling at interties, Abdul-Rahman said, and the ISO plans to hold more elaborate workshops on the subject in November.
“We have to make sure our existing market participants are comfortable with the changes,” Abdul-Rahman said. “And in terms of post-market implementation, the main challenge is preparing settlement data … this is the area that we are focusing on a lot because there are a lot of changes.”
CAISO is working specifically on implementation challenges associated with congestion revenue allocation, although these challenges are “not impacting our plan” to begin EDAM in 2026, Abdul-Rahman said. (See CAISO’s EDAM Scores Simultaneous Wins at FERC.)
While EDAM’s market simulation phase continues, PacifiCorp is transitioning from a five-day per week operation to a seven-day per week operation, Paul Wood, PacifiCorp director of portfolio optimization, said at the meeting.
“The big thing to stress is that there has to be a lot of continuous training, testing and development,” Wood said. “Getting employees trained to participate in the EDAM market while continuing to perform daily jobs is [important]. There’s been a lot of training for employees to get their tools ready for a total change … on May 1.”
Ensuring vendors and consultants are involved early helps clear up assumptions before they become problems, Wood added. And flexibility through the transition to EDAM is key, since market rules and designs will shift, he said.
PGE is on track to begin its EDAM market simulation phase in March 2026, complete the phase by June 2026, and then enter the EDAM on Oct. 1, 2026.
RIF Transition Update
RIF committee members proposed to move forward with the transition of the RIF into the Stakeholder Representatives Committee (SRC) to be established for the Regional Organization for Western Energy being developed by the West-Wide Governance Pathways Initiative, which eventually will assume governance of the EDAM and Western Energy Imbalance Market (WEIM). (See Pathways Co-chair Maps out ‘Enhanced’ Stakeholder Process for Western Markets.)
One stakeholder asked the RIF committee to discuss the advantages of starting the SRC directly after ending the RIF, rather than including a transitional phase, so “folks can stand up and walk from one room to the other.”
Lindsey Schlekeway, NV Energy market policy manager and WEIM entity sector liaison, said many RIF stakeholders are the same stakeholders who will be in the SRC, so if “we can’t find a clear method for the transition, a lot of duplicative work would occur.”
“This is going to be a huge effort in order to stand up this new stakeholder committee, so we are just trying to find the most efficient and streamlined path,” Schlekeway said.
The West-Wide Governance Pathways Initiative’s Launch Committee Co-Chair Pam Sporborg said the stakeholder process of the new regional organization that will oversee CAISO’s energy markets is an evolution of the ISO’s Regional Issues Forum (RIF).
The RIF is a space for the power industry to discuss issues related to the ISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). However, following the passage of AB 825 in California, CAISO will hand over responsibility for the markets to the independent Regional Organization for Western Energy (ROWE), which is being designed by the Pathways Initiative’s Launch Committee. The handover is scheduled for early 2028. (See Newsom Signs Calif. Pathways Bill into Law.)
Speaking at the RIF on Oct. 27, Sporborg, director of transmission and markets at Portland General Electric, said the Pathways Initiative’s Stakeholder Representatives Committee (SRC), which will provide advisory support to ROWE’s board, builds on the RIF’s success, praising the forum as enabling “more in-depth dialog on the stakeholder process and the evolution of the market.”
“We … see the Stakeholder Representatives Committee as this incremental evolution beyond the RIF sector liaison role with an expanded number of sectors that I think add some granularity and new voices into the process,” Sporborg said.
“We have more of an opportunity to really have additional engagement in each of the policy development processes,” Sporborg said. She added that there is an “opportunity to bring … members of each sector into that policy development process to ensure that as the market evolves, it’s really evolving at the direction of stakeholders.”
She noted the sectors will be involved in market development by providing SRC members with more say on proposals through an enhanced voting process, comment engagement, analysis and other opportunities.
Sporborg explained the enhanced voting approach, saying stakeholders will submit indicative votes throughout the policymaking process to ensure concerns are being addressed and to provide more analysis on proposals rather than SRC members simply voting “support, oppose or neutral.”
The Launch Committee is considering a remand process to allow entities to refine unpopular proposals. This would apply to final proposals prior to an initiative being sent to the ROWE board.
“We want to enhance the way these votes get shared with the board, so that there would be some opportunity to identify … more analytics behind that support, oppose or neutral vote to help the board understand if there’s opposition in a particular sector,” Sporborg said. “For example, do all small utilities oppose a proposal, or does this have significant opposition in the IPP sector? We want to be able to have that kind of analytic show through the tabulated voting.”
Non-IOU load-serving entities serving load from WEIM or EDAM
Public interest organizations
Independent power producers, independent transmission developers and marketers
Consumer advocates
Large commercial and industrial customers
Distributed energy resources
Sporborg said the Launch Committee envisions a “hybrid structure” that brings together staff expertise and stakeholder input, “where you get the ability to execute quickly and to drive forward through a staff-driven process. But by bringing more of the voice of the stakeholder into that process, we can have more of a stakeholder-driven policy evolution.”
Holistic reform to interconnection barriers is essential to meeting rapidly growing power demand across the country, experts emphasized at a recent webinar.
Panelists at the Resources for the Future webinar on Oct. 27 discussed underlying challenges of interconnection, along with reform efforts underway throughout the U.S.
As demand for new generation accelerates, “we need all hands on deck,” said Sarah Toth Kotwis, senior associate at the nonprofit think-tank RMI.
“We are in a really crucial time,” said Joe Rand, energy policy researcher at the Lawrence Berkeley National Laboratory. “If we don’t have transmission and headroom to connect that new supply, we’re simply not going to be able to do it.”
Rand said queue backlogs ballooned in recent years, though some declines in queue capacity occurred between 2023 and 2024. He noted that interconnection requests generally have low completion rates; Berkeley Lab data indicate that only about 13% of the capacity entering interconnection queues achieves commercial operation.
The core issues of interconnection are long wait times and high costs, Toth Kotwis said. To address these issues in the short-term, grid operators should focus on process changes to connect projects as quickly and cheaply as possible, while focusing long-term efforts on “proactive transmission planning that optimizes planning throughout the system.”
Aubrey Johnson, vice president of system planning and competitive transmission at MISO, said the RTO’s queue saw major growth starting in 2021. He said MISO has been actively pursuing interconnection improvements to keep up with increasing interconnection requests.
“A lot of what FERC Order 2023 has done, MISO had already been in the process of doing,” Johnson said. “We’ve been doing [cluster studies] since back in 2019.”
FERC Order 2023 directs grid operators to adopt first-ready, first-served cluster study processes and require generators to meet significant site control and financial requirements.
“What we’ve found out from the cluster study is: it has the ability for us to be faster, but it actually does not necessarily get us to be faster because of all the restudies that end up happening,” he noted.
More projects joining the queue has caused queue cycles to take longer, causing delays to the start of subsequent queue cycles, Johnson said. He added that MISO has struggled with high dropout rates, with only about 20% of the projects that enter MISO’s queue signing generator interconnection agreements.
“Time will tell” how the increased cost requirements and withdrawal penalties mandated by Order 2023 will affect completion rates, but these reforms should affect the volume of projects entering queues, Johnson said.
Johnson added that forward-looking transmission planning efforts, such as MISO’s Long-Range Transmission Planning initiative and MISO and SPP’s Joint Targeted Interconnection Queue process, should help lower interconnection costs and increase project viability.
Rand of the Berkeley Lab said the requirements of Order 2023 should reduce the number of speculative projects in the queue.
“In 2024, we did see just unprecedented levels of withdrawals,” Rand said. “I think a lot of older, nonviable projects are really starting to pull the plug as they see these reforms being implemented.”
While reducing the number of nonviable projects should help, developers have a different perspective on so-called speculative projects, Rand said.
“I think they would say that none of their projects are speculative per se; they would happily build any of these if the interconnection costs were reasonable to them, and, of course, if the other factors like permitting and offtake agreements lined up,” he said.
Rand said the Order 2023 reforms have not solved the fundamental issue of price transparency that motivates developers to submit a high volume of requests.
“From a developer standpoint, they don’t have another way to identify what the interconnection cost requirements are going to be for that particular project until they get in the queue,” he said.
In PJM, projects with network upgrade costs higher than $100,000/MW “are over 50% more likely to drop out before the third study than projects that don’t have that,” said Sarah Johnston, associate professor at the University of Calgary.
“Presumably this is new information, because otherwise they wouldn’t want to plan the project and go through the process,” Johnston said. “And so, it does speak to how having this up-front certainty could help in getting some generators out of the queue.”
Speakers emphasized that resource development challenges are not limited to interconnection barriers, and noted that permitting, supply chain and contracting issues frequently prevent development after resources sign interconnection agreements.
Toth Kotwis said some of the issues projects face after achieving an interconnection agreement can be attributed to how long the study process takes.
“Projects that are connecting now, in 2025, to PJM’s grid have been waiting in the queues for eight years on average,” Toth Kotwis said. “So much has changed in the last eight years … of course it’s a struggle to get built, because we’re in a new reality of supply chain constraints and global geopolitics making everything more difficult.”
Johnson of MISO said he’s confident RTOs across the country are making significant progress toward addressing interconnection barriers, but that the industry should “be giving the same level of attention” to helping projects with signed interconnection agreements reach commercial operation.
He said there are more than 60 GW of projects with signed agreements in MISO alone, more than half of which have been delayed beyond their planned in-service date.
“Across the organized markets, there’s over 260 GW of signed [generator interconnection agreements] today that know what their upgrade costs are, that supposedly would be viable projects, but most often are not getting built,” Johnson said.
WASHINGTON — Uncertainty in load forecasts presents competitive firms and regulated utilities with polar opposite incentives, NRG Vice President of Regulatory Affairs Travis Kavulla said at S&P Global’s Nodal Trader Conference on Oct. 24.
“Data centers and the consequences of unbelievable load forecasts are really not good,” Kavulla said. “On the power generation side, it could actually, paradoxically, lead to underinvestment in power generation that relies on market forwards. Investors and companies like mine might just throw up their hands and say, ‘This is so unbelievable. We’re standing pat. We don’t want to overbuild.’”
While companies that operate purely in the markets might wait to see how much demand actually shows up — which could prove overly cautious — utilities have different incentives, he said.
“It might induce overspending and overbuild because of the moral hazards and financial incentives that are present on that side of the industry,” Kavulla said. For “people who, unlike merchant generation, don’t have to wear the risk of the spending that they include in rate base and have a captured base of customers, there will always be someone there to pay for it, even if data center growth doesn’t materialize.”
The situation also can induce a crisis for politicians, which risks laws being passed that compound the problems facing the industry, he added.
“What PJM is really asking the community for generation to do is to add more than the amount of generation — about 40,000 MW — that was added during the entire turnover of the shale revolution, of coal to gas, in a shorter period of time than that generation got online when supply chains were less challenged,” Kavulla said.
Other markets like ERCOT also have huge projections for future demand, but forward prices remain low. Forward prices in PJM shot up right after the RTO released its first load forecasts that included booming demand from data centers and other large loads, but they fell shortly after.
Capacity prices have shot up in PJM over the past two auctions, but the price impact of new load coming onto the system is absent in energy forwards, Kavulla said.
“We also have ERCOT, which shows similar activities,” Kavulla said. “No capacity market here to remove some of the pressure of trading off load growth. Instead, you would expect, certainly, given what we saw in the previous projection of demand growth well exceeding supply additions, for the market to be significantly impacted, and that’s just not the case.”
The situation has many explanations, but three of them stand out for Kavulla, including that load growth is fake. But even a fraction of the projections becoming a reality should push forward prices up given how tight many markets are and the well documented issues getting new supply on the grid.
Another option is expecting politics to intervene rather than letting prices rise enough to incent a market response to add more supplies, he said.
“There will be some deus ex machina of policy that could either be ‘bring your own generation’ that causes entry to happen outside of the energy price fundamentals,” Kavulla said. “There could just be a price cap on energy. There could be government funding or rate-regulated entry of generation. Something will happen that causes the energy markets not to be doing the lift associated with the load growth projections.”
The other issue is that the markets themselves do not lead to deals that far in the future with competitive retail contracts lasting one to five years.
“There might be a lot of people wanting to sell you something on a longer daily basis, but not a lot of people willing to buy something on a longer daily basis,” Kavulla said. “All things being equal, that ends up working to the counter effect of incremental demand outpacing incremental supply.”
All three can be true at the same time, and Kavulla argued the situation can be fixed with more of a top-down approach to large loads.
Data center developers and others currently bring plans to utilities, which collect them and are aggregated across ISO/RTO markets. But Kavulla said it would work better for markets to publicly announce available headroom and then request large loads apply to use it. The Alberta Electric System Operator has put that idea into practice.
“We are going to say we have X megawatts of capacity available in the Alberta market today, and we are going to tender that out and have data centers who are interested in developing quickly in this province subscribe it,” Kavulla said. “In a series of literally three stakeholder meetings in the Alberta regulatory process, they kind of rolled out this design.”
The approach is similar to how the natural gas industry gets customers to sign up for new pipelines, which shows FERC in its regulatory process that there is a need for new capacity, he added.
Capacity markets worked reasonably well at incenting new generation in the past, but they need some reforms to deal with the current paradigm, Concentric Energy Advisors CEO Danielle Powers said during a panel Oct. 23.
“When we deregulated, we lacked the planning function — period,” Powers said. “It used to be that the utilities plan, and they planned for the right mix at the right time, and that was all left to market forces, largely. And so, I think you can have both.”
Regulators and ISO/RTOs instead have focused on “nibbling around the edges.” While resource accreditation is important, it is vital that the grid get the right mix of resources online so it can operate reliably, she said.
The markets have been adding supply but not enough generation that also can provide key grid balancing services, said NERC Senior Vice President Mark Lauby.
“We have solar panels, but they don’t always provide the kind of meat and potatoes of frequency and mass that we expect,” Lauby said. “So how are we going to supplement that?”
NERC has been studying large loads for 18 months, and their proliferation has major implications for how the grid will be operated in the future, Lauby said. The grid always has been operated so it can absorb losing a large generator and, in some cases, large loads going offline instantly.
“Now we’re talking about losing the city of San Francisco at one time,” Lauby said. “So how do we manage that? What are some of the adjustments we need to make in the system? What are the interconnection requirements so we can make sure that the system remains reliable?”
NERC is considering new standards to ensure the system can be operated reliably, and in its stakeholder-driven mandatory standards process, that could involve the large loads helping to develop new rules.
Part of the issue is misaligned timing: If a regulated utility had gone to a state commission and asked to build a couple of gigawatts on speculation just two and a half years ago, they would have been laughed out of the room, said Abram Klein, managing partner at Appian Way.
“We’re at a little intermediate period where the markets have gotten a little bit tighter,” Klein said. “But there’s a lot of positive sides. I mean, the solar plus wind plus batteries is working much better than expected.”
One area that could stand improvement is the demand side, with studies from Duke University’s Tyler Norris and Goldman Sachs saying that could help the grid meet rising demand from large loads. But that needs to be priced into the market, as opposed to the DR in PJM that suppresses energy prices whenever it is called on, Klein said.
Traditional DR will not work with data centers because of the “rebound event,” where if 4 GW of data center load is asked to go offline peak, it will just create a new net peak whenever it is allowed back on the grid, said Arcus Power’s Wish Bakshi, lead data and AI consultant.
Data centers can offer flexibility, but it would work better to “underclock” chips, which Bakshi compared to operating a V12 like a much less powerful V4 engine.
“You turn it down, so it keeps running and training, and at 8 p.m. or 9 p.m., they basically kick back up, so you don’t have that crazy spike, and you’re basically ramping up very slowly,” Bakshi said. “That’s kind of how you do it with these AI data centers.”
The other option is just to pay high power prices to keep the data center running, which can make economic sense given that its owners invested tens of billions of dollars just in the high-end Nvidia chips that make it work, Bakshi said.
Another option is shifting compute load to another data center, but that comes with its own limits.
“There’s only so much fiber optic cable that go across the country that can actually do that,” Bakshi said. “Is it possible? Yes. But only the big shops can do that. Google’s already working on it.”
FERC has rejected Tri-State Generation and Transmission’s proposed tariff designed to manage the projected massive growth in data center load confronting its Mountain West member utilities over the next decade (ER25-3316).
The commission’s Oct. 27 decision could call into question a growing push among utilities to develop such rulesets to insulate ratepayers from the financial and reliability risks stemming from the heavy energy demands of new data centers. (See Large-load Tariffs Touted as Alternative to ‘Side Deals’.)
Modeled on similar tariffs filed by other U.S. utilities, Tri-State’s High Impact Load Tariff would have established a biennial planning cycle for customer loads rated at 45 MW or higher, with the aim of weeding out speculative projects.
In its filing, the Colorado-based cooperative wrote that a “separate HIL planning cycle process is necessary because HILs are of a size that require significant generation capacity additions or procurement of long-term [power purchase agreements], which necessitates proper planning” to prevent ratepayers from bearing the financial burden of grid projects being completed “only for a HIL to not materialize.”
The proposed rules would have required Tri-State members and developers of HIL projects to undergo an evaluation process that included providing evidence that a developer had 90% site control of its project location and submitting an executed member-customer high-impact load (MCHIL) agreement and high-impact load agreement (HILA) to be executed between the utility member and Tri-State.
Developers of projects under 80 MW would also have been required to pay an evaluation fee starting at $35,000 plus $1,000/MW, with the fee increasing to $150,000 for projects between 80 and 200 MW and $250,000 for projects above 200 MW — levels Tri-Sate said were consistent with deposit thresholds under its large generator interconnection process.
The HILA also would have required a HIL customer to provide a minimum security deposit of $2.7 million/MW to offset the risk that the customer “begins commercial operations late [or] ceases operations before the expiration of the HILA term or the HIL does not operate at the expected level (or at all).”
‘A Job for the States Alone’
In rejecting the proposed rules, the commission largely agreed with protests by Data Center Coalition and infrastructure developer Eolian Energy, finding that “certain aspects” of Tri-State’s proposed tariff “appear to present an impermissible intrusion on retail rate regulation,” which falls under the purview of states and is not subject to FERC’s jurisdictional authority under the Federal Power Act.
“We find that several provisions of the HIL Tariff require specific terms and conditions of service by a utility member to an end-use HIL customer (i.e., a retail service) and make the MCHIL a condition of Tri-State’s agreement to provide wholesale service to its utility members to facilitate their retail service of large loads,” the commission wrote.
The commission noted the protesters’ argument that Tri-State was proposing to use a FERC-jurisdictional tariff to set the terms of retail sales by “dictating” the minimum amount of energy a large load customer must purchase at retail.
“For example, Data Center Coalition argues that mandating HIL customers enter into contracts with utility members that contain minimum monthly demand and energy requirements are terms of retail service that are beyond the commission’s authority to regulate. Eolian argues that the MCHIL is a retail agreement, and Tri-State’s failure to explain how the commission can approve a tariff provision that dictates the terms of retail service is a deficiency in Tri-State’s filing,” the commission wrote.
Tri-State did not provide “a sufficient basis” for FERC finding the proposal did not regulate the terms and conditions of a HIL customer’s retail service “in ways that are beyond the commission’s authority,” it said, pointing specifically to the HILA provision that requires a Tri-State utility member to enter into an MCHIL that sets the terms for energy sales from the member to its retail customer.
The commission also disagreed with Tri-State’s contention that FERC has authority to assert jurisdiction over the proposed HILT and HILA, “which condition Tri-State’s service to its utility members on those utility members’ HIL customers complying with certain terms and conditions of retail service.”
“We note that the plain language of the FPA bars the commission from regulating retail sales, and the Supreme Court has been clear: Specification of terms of sale at retail ‘is a job for the states alone.’”
The commission also rejected Tri-State’s argument that it should accept the HIL program because it is similar to the co-op’s FERC-approved demand response program in laying out key terms for utility member participation.
“We disagree because Tri-State’s demand response program does not place the terms and conditions on the retail sale of electricity; instead, it sets forth the technical requirements that a utility member’s demand response resources must meet in order for the utility member to qualify for incentive payments from Tri-State’s demand response programs,” the commission wrote.
Guidance for 2nd Attempt
But the commission left open the door for Tri-State to file a modified version of the HILT that does not infringe on retail rate regulation, outlining a handful of “concerns” about the tariff the co-op should address, including:
insufficient evidence that the proposed security deposits are “appropriately sized to mitigate the risks Tri-State identifies”;
insufficient explanation justifying why Tri-State should be able to terminate a utility member’s HILA for reasons beyond the member’s control, potentially after the member has already incurred construction costs to help serve the new load; and
lack of justification for the “degree of discretion” Tri-State proposed to give itself in implementing various parts of the HILT, such as the evaluation criteria.
The commission also found that the tariff did not provide sufficient detail about the “interactions” between the proposed reliability and transmission criteria in the evaluation.
“We also note that Tri-State’s metrics for assessing the reliability criteria lack the necessary details for the commission to evaluate their effectiveness and whether they ensure not unduly discriminatory treatment across projects,” it wrote.
Reached for comment, a Tri-State spokesperson told RTO Insider: “While this is a disappointing result, FERC provided guidance to Tri-State that we can use to move forward toward our goal of creating a repeatable and fair process to bring high-impact loads to Tri-State and our members, while providing data centers and other large loads a transparent and fair process.
“We still are reviewing the order and determining our next steps, but there may be an opportunity to modify the tariff to address FERC’s comments and deliver the consistency our members seek, in responding to requests for service from heavy energy-users.”
NextEra Energy plans to restart the 50-year-old Iowa nuclear power plant it shut down in 2020 and sell some of its output to Google for data center operations.
The target date for resumed operation of the 615-MW Duane Arnold Energy Center is the first quarter of 2029.
Central Iowa Power Cooperative and Corn Belt Power Cooperative will surrender their 30% ownership stake in the facility to NextEra in return for NextEra assuming their liability for decommissioning.
Central Iowa and Google will purchase the full output of the plant on equal terms, which were not disclosed but which are expected to contribute annually an adjusted 16 cents on average to NextEra’s earnings per share for the first 10 years of the agreement.
NextEra CEO John Ketchum said the company is not ready to disclose the expected cost of recommissioning.
For comparison, Constellation estimates a $1.6 billion price tag to restart the former Three Mile Island Unit 1, a pressurized-water reactor commissioned and retired at roughly the same time as the Duane Arnold reactor, which is smaller and uses the less-complex boiling water design.
Ketchum said the same team that has been doing the decommissioning will bring the facility back to operational status, and some of the employees who formerly operated Duane Arnold are expected to be rehired.
NextEra announced plans to shut down the facility in 2018, in an era when multiple U.S. nuclear plants had become uneconomical due to their high cost of operation and were being retired.
Duane Arnold ceased operation even sooner than planned when an August 2020 windstorm damaged its cooling towers.
Not even five years later, the nuclear power landscape began to change dramatically as demand for power — particularly the emissions-free baseload power provided by atomic fission — began to rise.
The very small number of retired but not disassembled U.S. nuclear plants have become a potentially valuable commodity, able to come back online at a fraction of the cost in time and money of a comparable new facility.
Two other retired nuclear power plants have begun recommissioning processes; the operational lives of existing reactors are being extended rather than cut short; construction may resume on a half-built, two-reactor facility mothballed eight years ago; uprating is planned for existing plants; and corporate offtake agreements are being signed for existing reactors as well as for advanced nuclear technologies that have not even reached prototype testing.
“Because we carefully and methodically went through the decommissioning process, we have confidence in the investment required to restart it,” Ketchum said. NextEra expects the recommissioned facility to qualify for the full range of available federal tax credits, he said.
The first quarter of 2029 is the latest the restart would be expected, Ketchum said. It could be as soon as the fourth quarter of 2028.
NextEra and Google also announced an agreement to explore development of new nuclear generation across the United States.
Counting Duane Arnold, the two companies have executed more than 3.5 GW of energy projects nationwide.
NextEra Energy reported GAAP earnings of $2.44 billion or $1.18/share on revenue of $7.97 billion in the third quarter of 2025, up from $1.85 billion, $0.90/share and $7.57 billion in the same quarter a year earlier.
MISO’s Advisory Committee will continue to be led by its vice chair through the end of 2025 after the departure of Sarah Freeman from Indiana’s regulatory agency.
At an Oct. 28 meeting, acting chair and vice chair Brian Drumm, of ITC, agreed to helm the Advisory Committee’s remaining meeting during MISO’s quarterly Board Week in early December in Indianapolis.
Former Advisory Committee chair Freeman exited the Indiana Utility Regulatory Commission — and thus MISO — Oct. 10 to join the Regulatory Assistance Project (RAP), a global non-governmental organization that helps policymakers tackle the clean energy transition. Freeman concluded 28 years of service to the state of Indiana to become a principal with RAP.
Chris Norton, of MISO’s Transmission-Dependent Utilities sector, proposed Drumm’s extension as acting chair. No committee member objected. Drumm previously led the Sept. 17 Advisory Committee meeting in Detroit as part of MISO Board Week.
At the Organization of MISO States’ annual meeting Oct. 21, OMS President and Minnesota Public Utilities Commissioner Joseph Sullivan said he would miss Freeman and her ability to work toward a goal and “ride over” noise in the industry. He said Freeman was one of the most active listeners he’s ever encountered and that he viewed her as a mentor through her demeanor and conduct.
MISO’s Advisory Committee is pulling together a committee of its members to consider nominations and select new leadership in 2026.
OMS intends to nominate Michigan Public Service Commission Chair Dan Scripps for committee consideration as the next Advisory Committee chair. Sullivan said Scripps is “well-suited to be a neutral voice” and potentially replace Freeman’s leadership on the Advisory Committee.
Separately, IURC Chairman Jim Huston took over Freeman’s representation on OMS until his retirement in early 2026. Huston plans to step down from the commission sometime in January, retiring after more than a decade on the job.
