The Michigan Public Service Commission unanimously rejected requests from Attorney General Dana Nessel to reassess DTE Energy’s arrangement to provide 1.4 GW to an Oracle and OpenAI’s Stargate data center south of Ann Arbor.
Nessel, a Democrat, criticized a lack of discussion around the PSC’s March 27 vote that leaves DTE Energy’s agreement in place (U-21990). The attorney general filed a motion to reopen DTE’s application and a petition for rehearing in the docket, condemning “a secret review of the heavily redacted contracts with significant consequences for Michigan utility customers.”
The PSC also rejected Nessel’s request for a contested case proceeding to review six “heavily redacted contracts proposed by DTE for three battery storage facilities throughout the state meant to support the data center project.”
Oracle and OpenAI partnered with the newly formed Related Digital to propose a $7 billion Stargate AI data center in Saline Township in October 2025. It took the PSC less than two months to grant DTE Energy’s redacted large load supply agreement for the project.
“The Michigan Public Service Commission continues to perform a grave disservice to the state of Michigan and the utility customers of this state, to the only apparent benefit of the utility corporations and their new billion-dollar AI customers,” Nessel said in a statement. “Since these secret contracts were first filed in October, I have requested and demanded that my office and other consumer advocates be able to review these contracts and ensure adequate protections for existing utility customers. At every opportunity, the commissioners have shut out everybody, choosing instead to keep DTE’s contract terms top secret, fast track their approval and play fast and loose with the meager terms they claim to put in place.”
Nessel added she has never observed “a process so secretive, rushed and ripe for disaster as what the commission rammed through here.” She vowed her office will continue to explore remaining options to get insight into the agreements’ ratepayer ramifications.
Nessel said the PSC failed to address her contention that DTE wrote in weaker protections for its existing customers than the commission ordered in December.
According to Nessel, the commission instructed DTE to make representations that “payments made by Green Chile Ventures LLC under Rate Schedule D11 and the special contracts will cover the costs to serve Green Chile Ventures LLC such that the costs of serving Green Chile Ventures LLC (including generation, transmission, distribution, or other costs) are not covered by other customers.”
Green Chile Ventures is a subsidiary of Oracle and serves as a development vehicle for Stargate data centers.
Nessel said DTE altered the PSC’s ordered language and wrote that “aggregate revenues generated by the customer [Green Chile Ventures LLC] will cover the costs to serve them.”
Nessel said the rewrite didn’t offer a clear enough guarantee that DTE won’t place the near-term costs of the data center on existing customers. She said DTE dodged accepting the conditions ordered by the PSC.
The AG’s office said, “DTE has only represented that by the end of the 19-year contract that it expects the aggregate payments from the data center to have eventually risen to a sum greater than the company’s own costs to serve the data center.”
In shooting down a reopening of the case, the PSC said it “finds that the reference to aggregate revenues in the acceptance letter does not change or somehow endanger the cost allocations that were placed on the approval.”
The PSC authorized a $242.4 million annual rate increase for DTE in February 2026, which took effect in early March (U-21860). DTE originally requested a $574 million increase.
Five days after the approval, DTE said it would move to raise electric rates again, with a formal filing expected sometime in April and new increases to take effect in March 2027.
Nessel has said she plans to involve herself in the case.
“It’s astonishing that our current system allows DTE to announce their next rate hike case less than one week after locking in a $242 million rate hike, all while the utility projects record profits,” Nessel said. “How many times are Michigan families expected to reach deeper into their pockets to bankroll record profits and shareholder dividends for DTE and Consumers Energy’s Wall Street investors, while reliability and affordability remain out of reach?”
The AG’s office said since 2020, state regulators have greenlit more than $1 billion in annual revenue increases for DTE, “despite continued reliability and affordability concerns.”
DTE did not reply to a request for comment before publication time.
Port Canaveral commissioners voted unanimously not to sell land to Berkshire Hathaway and Chesapeake Utilities to build an LNG plant.
A 50-acre barge canal property on Merritt Island, part of the port authority’s property, was the target of an unsolicited offer by Berkshire, which wanted to purchase the land for an LNG liquefaction plant to help supply both the cruise and space industry.
Commissioners cited the land’s potential value and not having control of the land for 50 years as reasons for their rejection.
Kentucky Power filed an application with the Public Service Commission to build a new cooling tower at the Mitchell Generating Station.
The project would cost $191 million and comes after the PSC warned any additional investments at the facility would require separate review. The utility asked for a Certificate of Public Necessity to start work on building the new cooling tower, saying the project is necessary to preserve a significant source of electricity.
Gov. Mills Signs Bill to Prioritize Affordable Electric Rates
Gov. Janet Mills signed a bill that directs the Public Utilities Commission to consider the affordability of electricity for residential customers when setting new rates.
The PUC will develop an affordability metric to determine the impact of electric bills on the overall burden for households. It also will disclose the credit and collection activities of Central Maine Power and Versant Power.
Lawmakers Back off from Creating Climate Superfund
The Legislature has decided not to create a climate superfund program and instead wait for similar court battles in New York and Vermont to play out.
Instead of starting a program, the bill now directs the Department of Environmental Protection to calculate the dollar value of costs to Maine from greenhouse emissions over the past 20 years. The original bill would have set up a program to assess costs of climate harms and charged big oil companies for those damages, with the funds helping to prepare communities for sea level rise and extreme weather.
Sen. Stacy Brenner (D-Scarborough) told the Environmental and Natural Resources Committee that avoiding a potential lawsuit was the motivation for backing off from a full superfund program for now, but she said the new version of the bill is a step forward in the process.
The Maryland Supreme Court ruled against reviving climate lawsuits brought by Baltimore, Annapolis and Anne Arundel County that were struck down by lower courts.
The governments had sued 26 multinational oil and gas companies to recover damages caused by the effects of greenhouse gas emissions, accusing them of deceiving the public about the dangers of using their products. The Supreme Court ruled that federal law overrides state law on air pollution that crosses state lines, blocked such lawsuits from proceeding and accused the plaintiffs of trying to use litigation to regulate greenhouse gas emissions.
Two lower courts had dismissed the cases, which were filed in 2018 and 2021.
PSC Approves Largest Consumers Rate Increase in Decades
The Public Service Commission approved a $276.6 million rate increase for Consumers Energy – the largest rate hike approved in more than 20 years.
The PSC said it shaved more than $100 million off the original request since it was filed in June 2025. Regulators also said the increase will allow Consumers to continue reducing outages and improving historically bottom-tier reliability.
The increase, which will go into effect May 1, will add $6.46 to the average residential bill.
Gov. Kelly Ayotte issued an executive order directing the state Department of Energy to create a “nuclear roadmap.”
The order tasks the DOE with identifying a path toward implementing “advanced nuclear electric generation” and studying ways to insulate ratepayers from delays and cost overruns.
A preliminary roadmap is due within six months and a final report within two years.
Power Siting Board staff recommended the denial of the 180-MW Sloopy Solar facility in Clark County.
The project is partially grandfathered in, according to the PSB, because it received a system impact study and fees before October 2021. It already was in motion before the passage of Senate Bill 52, which allows a county board to prohibit the construction of utility-scale wind or solar facilities altogether or in certain designated zones in unincorporated areas.
Although the staff recommended denial, the board is not bound by the report and could still approve it.
Gov. Larry Rhoden signed a bill that will place new limits on large loads and data centers.
The law will apply to data centers 10 MW or greater. It requires data center companies to ensure their water use does not overburden local resources and to pay for electrical infrastructure costs. It also prohibits the state from overriding local ordinances limiting, prohibiting or regulating data centers.
Another bill will allow the Public Utilities Commission to assess data center companies the costs of regulatory reviews related to their projects.
El Paso Electric plans to have a $500 million, 366-MW natural gas plant built in 10 months to meet part of the power needs of Meta’s data center complex under construction in El Paso.
Meta announced the data center project is expanding to a $10 billion, 11-building complex. Meta will pay the costs of the plant, and it won’t affect EPE rates during the first five years of operation. The PUC still must approve the project.
Construction of the plant is scheduled to begin in August with an expected completion date of May 2027.
Study: U.S. has Caused $10T Worth of Climate Damage Since 1990
The U.S. has caused $10 trillion in global damages between 1990 and 2020 through its greenhouse emissions, with a quarter of the damages inflicted upon itself, according to a study published in Nature.
The study attempts to attach dollar amounts to “loss and damage” — a term used to account for the harm suffered by societies from rising temperatures. By being the largest carbon emitter in history, the U.S. ($10.18 trillion) has caused greater harm to worldwide economic growth than any other country, ahead of China ($8.7 trillion), according to the findings of the paper.
NRC Seeks Comments on Project Matador Environmental Review
Fermi America is working with the Nuclear Regulatory Commission on a pilot program to develop applicant-prepared Environmental Impact Statement documentation, an approach the NRC says will help improve regulatory efficiency.
This new approach — enabled by recent amendments to the National Environmental Policy Act — allows applicants, under NRC oversight, to develop a draft EIS. The change is expected to reduce review time by about 50%. Fermi America is the first private company to participate in the pilot.
Fermi America is planning what it calls the world’s largest energy-driven artificial intelligence complex, located in Amarillo, Texas. The HyperGrid campus aims to integrate large-scale nuclear power plants, small modular reactors and other power sources.
Entergy: Revised Meta Data Center Deal to Deliver Higher Savings
Entergy said Meta Platforms will pay its full cost of service for a planned hyperscale data center in northeast Louisiana under a revised agreement.
The agreement is expected to deliver nearly $2 billion in customer savings over 20 years, the company said, in addition to the $650 million announced in 2025.
Representatives of Florida Power & Light urged fellow SERC Reliability members to start using artificial intelligence tools, even in their own personal lives, warning that its use on the grid is spreading too rapidly to not understand how it works.
To that end, Robert Wargo, senior director of the utility’s Critical Infrastructure Protection program, and Robert Adams, senior director of compliance and regulatory affairs, briefed members at SERC’s annual meetings March 25 in Jupiter, Fla. on the many ways their utility is using AI to monitor its distribution grid, reduce outage times and avoid outages entirely.
Like virtually every state in the country, Florida is experiencing surging load growth that is expected to accelerate, driven primarily by the proliferation of data centers, and the Sunshine State is hurriedly building solar resources to meet it. “Think of a dispatcher in the future with all this volatile load out there,” Adams said. In the past, “generation was pretty stable. You had a defined number of generating plants, and nothing moved horribly quickly on the transmission grid.”
But “transmission is actually becoming a lot more distribution-like with that volatility, and that system operator is going to get absolutely overwhelmed with data inputs. … You go from roughly 20 generation plants to hundreds of generating plants and batteries. The number of contingencies that’s going to generate for a system operator is infinite.”
Wargo talked about NextEra Energy’s new NERC Information Command Center, which includes an Advanced Virtual Auditing (AVA) tool that constantly monitors compliance with the ERO’s Critical Infrastructure Protection. “Ava,” which Wargo referred to with she/her pronouns, can recognize voice commands and speak. “She is constantly in the background, checking our compliance. No longer do we have to say, ‘OK, we’re going spend six months with three people doing spot checks to see if we’re compliant.’ We have instant awareness of whether we are compliant.”
In between detailing AI’s uses for grid reliability, however, Wargo and Adams acknowledged a general hesitancy to use AI. They urged attendees to simply try using it in their personal lives first.
“We have to lead our teams through this transition,” Adams said. “All of the employees are afraid of AI, and if you’re not an AI user today, I strongly encourage you: Go plan a date with your significant other. Start with that. … ‘My wife does not like fish, but I want to take her out to dinner. Give me five recommendations for a great date night.’ I’m not kidding. Works like a champ.”
One attendee asked about the best way for smaller utilities to start using AI. After encouraging him to partner with larger entities, Adams noted that Microsoft’s programs — “some of the stuff that you use every day” — now have AI software embedded in them.
“AI is being integrated into all of our systems. … Every one of the Microsoft products you use has AI enabled in it, and it is transforming Word and Excel, especially. PowerPoint hasn’t quite caught up yet; I keep praying.
“Keep the human in the center,” he urged. “It is a very scary process for all of us. Embrace it.”
Dragos Warns About Iranian Cyber Group
Ben Miller, chief information security officer for Dragos, warned that one of the newly identified threat groups in its 2025 Year in Review report has shifted from cyber espionage and theft to actively seeking to disrupt operational technology.
Most of Miller’s presentation at the meeting reviewed the report, which was released in February, and the cyberattack on Poland’s grid, believed to be committed by a Russian-backed hacking group. (See Dragos: Cyber Threats Rose Worldwide in 2025.)
The report, however, was released before the U.S. and Israel began bombing Iran and assassinating its top leaders. With the start of the war, a group named by Dragos as “Pyroxene” has changed its modus operandi.
In 2025, Dragos observed that the group was using social media to trick users into giving up their credentials; for example, the hackers created fake LinkedIn profiles and posed as recruiters in the aerospace industry, sending potential “hires” to fake websites that infected their computers with malware. But aside from during the Twelve-Day War of June 2025 — in which Iran conducted cyberattacks against Israel after the latter bombed its nuclear facilities — the group has refrained from disruptive attacks.
But on March 11, hackers attacked Michigan-based medical device and equipment manufacturer Stryker, wiping 200,000 workstations; the company was still recovering, Miller said.
A group that claims to be made up of pro-Palestinian “hacktivists,” widely believed to be backed by the Iranian government, said it was responsible for the attack. Miller said the attack bore a strong resemblance to Shamoon, the attack on Saudi Aramco in 2012. The group also claimed responsibility for hacking FBI Director Kash Patel’s email March 27.
Board Nominees and Draft 2027 Budget Approved
SERC members approved without discussion the nominees to the Board of Directors for two-year terms to begin June 1.
Roger Clark of Associated Electric Cooperative Inc. (cooperative sector); Greg Henrich of the Tennessee Valley Authority (federal-state); Shawn Schukar of Ameren Services and Nelson Peeler of Duke Energy (investor-owned utilities); and Kent Cochran of Nashville Electric Service (municipal) were confirmed to replace Directors Denver York, Vicky Budreau, Lee Xanthakos and Beth McFarland, and Doug Lego, respectively. Directors Eric Laverty (marketer), Venona Greaff (merchant) and Lonni Dieck (independent) were re-elected.
The board and members also approved the regional entity’s draft budget of $40.5 million for 2027, a 7.9% increase over 2026, for posting and submission to NERC.
CFO George Krogstie said much of the increase comes from the addition of three full-time-equivalent employees, along with increases in merit pay and benefits.
“The accuracy of our work and the timeliness of our work is critical. We have to keep pace and remain a credible and trusted expert, not just for our entities, but also to be there for NERC, and to ensure that these studies of reliability and resource adequacy are done in an accurate methodology,” Krogstie said.
“We intentionally did not add FTEs in 2026. We wanted to allow our programs to mature and then see where the greatest needs would be in terms of the impacts from” the addition of inverter-based resources. “We’re confident in the efficiencies that we have gained over the last few years and have a clear picture … of what our resource needs are in the immediate future.”
The approval of the draft begins a lengthy process to gain approval from the NERC Board of Trustees and FERC, which should conclude in October.
IESO’s plan to change the initialization logic for non-quick-start (NQS) resources left some stakeholders wondering why during an engagement March 24.
NQS generators require a formal commitment through the day-ahead market (DAM) or pre-dispatch (PD) to manage their longer startup times — at least one hour — and multihour run requirements.
IESO says the DAM needs to know the physical status of NQS resources at the end of the previous operating day to ensure the transition from real-time operation at hour ending 24 to the next day’s DAM “reflect a realistic and physically accurate operating state.”
Currently, the initialization logic assumes that an NQS unit is “ON” only if it has a “commitment” in HE24 of the PD run. NQS resources without a commitment in HE24 of PD are assumed to have an online status of “OFF,” regardless of whether the resource has a PD “schedule” for HE24. A commitment is an instruction to come online and provides greater certainty than a schedule.
When an NQS resource has a schedule in HE24 of the PD initialization run, it is online about 95% of the time when HE24 arrives in real time, said Garth Nash, an adviser in the market development unit. As a result, relying solely on the PD HE24 commitment flag causes many NQS resources to be improperly initialized as “OFF” in the DA engine.
Starting in June, IESO will set the initialization status to “ON” if a non-quick-start resource has a schedule in Day 0 HE24, regardless of whether it has a commitment in the hour. | IESO
Starting in June, IESO says, it will set the initialization status to “ON” if a resource has a schedule in Day 0 HE24, regardless of whether it has a commitment in the hour. NQS generators will receive no additional start-up costs for HE1.
What’s the Problem?
IESO officials did not cite any financial impact of the current assumptions or the proposed change.
“Can we … clarify what you’re trying to solve here?” asked Jennifer Jayapalan, of Workbench Energy.
“It’s just trying to better align what the status of a unit is and what is assumed to be,” Nash responded. “It’s just trying to have that alignment between what the DAM is assuming and what the physical reality is.”
“I just want to make sure that there has been significant … analysis that these hours aren’t going to be isolated, because the market participants are going to be financially bound to hours that potentially … they can’t operationally meet,” Jayapalan said.
“The problem I’m seeing here is now you have a DAM schedule that, in theory, you’re supposed to continue through,” she continued. “We know there’s an issue here right now, where, if the PD no longer wants a resource, it takes it offline even though it’s scheduled all day, and then it brings it back up. We already are not paying startup costs [for] the second start of the day if the PD does not want it.”
Karen Backman, supervisor of market development, said NQS operators who do not want a day-ahead schedule for the following day must “make sure that the 9 a.m. pre-dispatch does not show them in the hour ending 24 as being scheduled.”
Jayapalan acknowledged that IESO’s new market has seen “some extreme conditions where NQS resources have been scheduled day after day.”
“I understand that it probably is a high probability so far. But there’s going to be these cases in there where [NQS units] have isolated hours that … they operationally can’t meet. And there are going to be cases where the PD is going to change significantly,” she added. “It happens all the time now.”
Sean Vincent, of Greenfield South Power, echoed Jayapalan’s concerns over the ISO’s reliability and cost benefit analysis. “In the future, it would be really beneficial if these points were … something that you were able to provide for in these meetings — the actual benefit that’s being provided here, and the amount of people … or runs that are being impacted; how much this is actually changing things,” he said. “I think this is all extremely great information that should be publicly available here in these meetings.”
Demand-side resources that do not fully respond to RTO dispatch would be penalized at half the rate assessed during performance assessment intervals, which PJM’s Pete Langbein said recognizes the lower reliability risks associated with pre-emergency deployments. That comes out to about $1,150/MWh based on capacity prices for the 2027/28 delivery year. The penalties would count toward the annual stop loss limit for Capacity Performance penalties.
Revenues would flow into a pot to be split between overperforming curtailment service providers if the demand-side response met or exceeded the reduction PJM requested. If there was a shortfall, a pro-rated share of the revenues would be allocated to load-serving entities.
The revisions to the Reliability Assurance Agreement and tariff are set to be considered for endorsement from the MRC and Members Committee during their April 26 meetings. If approved, PJM expects to file the changes at FERC around April 30, with the aim of having the change effective before the 2028/29 Base Residual Auction opens on June 30.
PJM’s proposal was one of three considered by the Market Implementation Committee on March 11, with Voltus seeking a lower penalty rate with a similar overall formula structure, and the Independent Market Monitor proposing to require demand-side resources curtail according to PJM instructions or forfeit their daily capacity revenues.
Monitor Joe Bowring told the MRC that if stakeholders do not endorse the main motion in April, he may bring his proposal as an alternative.
Members Committee
PJM Selects ‘Expedited’ CIFP Process for Backstop
The Board of Managers has decided to use an “expedited” Critical Issue Fast Path (CIFP) process to gather stakeholder feedback and hold a vote on how PJM should implement a reliability backstop auction to be conducted later in 2026. (See PJM Plans to Release Reliability Backstop Design in April.)
PJM has held seven workshops since the start of the year on the idea of having an auction to procure multiyear commitments, resulting in several proposals and perspectives being presented. Staff plan to release the RTO’s initial backstop auction design April 10.
Senior Director of Stakeholder Affairs Dave Anders said the process would follow the same rules as past CIFPs, but with a truncated schedule to advance the board’s aim of conducting an auction in September. That date was laid out in the statement of principles signed by the White House’s National Energy Dominance Council (NEDC) and all of the state governors in PJM. The statement argued PJM would not need to conduct a CIFP process to design the auction rules, as those discussions had already been initiated in the 2025 CIFP focused on large load growth. (See White House and PJM Governors Call for Backstop Capacity Auction and PJM Stakeholders Reject All CIFP Proposals on Large Loads.)
The process would consist of five meetings where stakeholders and PJM would discuss their proposals, culminating in a meeting with the board at which final packages would be presented and the MC would hold an advisory vote. Two Stage 1 meetings will be held April 16 and 17, followed by a Stage 2 meeting May 4 and a Stage 3 meeting the following day. A FERC filing is targeted for June.
The board considered several stakeholder processes to proceed with the backstop discussions, including an “enhanced 9.2(b)” process, referring to the tariff provision requiring the board to consult with stakeholders before making a unilateral filing. The RTO would informally expand on the tariff rules to hold additional meetings to hear perspectives on its design.
Board of Managers Chair and interim CEO David Mills said he has been in communication with the NEDC regarding the White House’s expectations and noted the statement of principles specifically told PJM another CIFP would not be necessary. He said he believes the board made the best decision for the benefit of its members and the process.
PJM Presents Timeline on Resource Adequacy Processes
PJM presented a timeline on which it expects to administer six stakeholder processes centered on maintaining resource adequacy through a confluence of rising data center growth, sluggish capacity development and generation deactivations.
If FERC approves PJM’s backstop design, the RTO expects to begin implementation in July and conduct the auction by Sept. 30.
The MRC voted the same day to endorse two issue charges to create a Connect and Manage framework to curtail large loads not paired with capacity when there is insufficient capacity or transmission headroom. The Connect and Manage Senior Task Force is expected to run from April through June before handing the work off to the MRC and MC, which is expected to continue the effort through September. Implementation is targeted from November to December. (See PJM Forms Task Force to Explore Large Load Curtailment.)
Improvements to PJM’s forecasting of large load additions already are being developed, with staff internally drafting revisions to Manual 19: Load Forecasting and Analysis, and a third-party consultant is being brought in to develop an independent forecast from April to December. A FERC filing is targeted for early June, with an order anticipated by the end of 2026.
Manual language to effectuate the implementation of the Expedited Interconnection Track is being drafted by PJM staff, with stakeholder endorsement to be sought in June and July. PJM is aiming for a go-live date in August. (See PJM Consults MC on Price Collar Extension, Expedited Interconnection Track.)
The RTO also is continuing to prepare its filings responding to a FERC investigation into how it offers transmission service for co-located configurations between large loads and generation. The final filing is expected in April, and workshops are set to continue through the following month. If PJM’s proposal is approved, implementation could begin in June and would likely extend into 2027. (See PJM Presents 1st Look at Co-located Load Compliance Filings.)
And the RTO plans to publish a paper on its market incentives in May, to be followed by a stakeholder process through November, when a FERC filing is anticipated. A broad examination of how each of PJM’s markets contributes to the incentives required to bring on sufficient capacity to serve rising data center demand was one of several items the board requested at the conclusion of the 2025 CIFP process. (See PJM Board of Managers Selects CIFP Proposal to Address Large Load Growth.)
OPSI Announces New Executive Director
The Organization of PJM States Inc. (OPSI) has selected Ben Sloan, director of legal and regulatory affairs, to serve as its executive director following the retirement of Gregory Carmean, who has led the organization since 2012.
“We are very excited to welcome Ben into the executive director role,” OPSI President Dennis Deters said in a statement. “He brings deep expertise in PJM process and substance and a demonstrated commitment to advancing the public interest. His experience navigating complex proceedings at PJM and before FERC and leading coalitions of diverse state commissions across all 14 PJM jurisdictions makes him exceptionally well suited for this position.”
Sloan told RTO Insider he will take over on April 1 and Carmean will remain with the organization through April 17 to aid in the transition. Along with filling his prior position, one of Sloan’s first priorities will be adding a new staffer dedicated to expanding OPSI’s engagement in the stakeholder process.
PJM Considering Requesting Rehearing on DFAX Order
General Counsel Chris O’Hara said PJM is considering requesting a rehearing on the order, the scope of the amount to be refunded and the possibility of interest. The order requires PJM to recalculate transmission rates determined through the solution-based distribution factor (DFAX) methodology going back to June 2015 wherever the de minimis exception was used. The practice removed zones from the cost allocation formula if they were responsible for less than 1% of the flow modeled on a transmission upgrade.
PJM also is weighing a motion for clarification on what it is required to do and asking for an extension of the 90-day deadline in the March 6 order, O’Hara said. The RTO’s preference would be to stagger the recalculation of cost assignments to complete a few years every few months, with the full decade to take over a year.
O’Hara said more information on the scale of the rebilling may be available at the Planning Committee’s meeting April 7.
Solution-based DFAX is used to determine the entirety of the cost for projects less than $5 million and under 500 kV, while for higher cost and voltage projects, the calculation is split evenly between the load-ratio share basis and solution-based DFAX. Different methods are used if a project is needed to resolve stability violations.
In addition to rejecting a settlement on the de minimis exception that carried the support of PJM and several transmission owners, the order established a paper hearing evaluating whether solution-based DFAX should be applied to projects required to resolve short-circuit violations. O’Hara said more cost reallocations could be down the road depending on the outcome of that proceeding.
Board of Managers Discusses Streamlining Stakeholder Process
Mills opened a discussion on how PJM can streamline its decision-making processes as the RTO seeks to navigate data center load growth, tightening reserve margins, affordability, and balancing over- and under-procurement. Issues are coming at PJM faster than stakeholders can respond, and Mills said he does not want to see the board put in positions where it must act unilaterally.
“Are there ways we can streamline the process or communications without compromising the [Consensus Based Issue Resolution] process we desperately needed?” he asked.
He noted there were hours of discussions on a pair of issue charges framing how PJM would proceed on frameworks for curtailing large loads that might compromise resource adequacy or transmission security, adding he’s not sure there’s time for lengthy debates on process.
Each of the four areas the RTO is navigating will require states taking on new responsibilities, and Mills said he intends to be firmer with pushing ownership of items outside of PJM’s authority back to the proper forums.
Manager Matthew Nelson said the board read every proposal in the 2025 CIFP process and came ready with questions about them during the final meeting. The process for the backstop auction, however, is likely to be on a much tighter time frame — meaning there might not be the same opportunity for the board to present stakeholders with feedback. He expressed commitment to showing the membership PJM leadership is engaged and listening to their perspectives.
Several stakeholders said their efforts to draft proposals would be aided by PJM making its thinking or stance clear early when considering rule changes.
Clara Summers, of the Illinois Citizens Utility Board, said the Deactivation Enhancements Senior Task Force has been working since October to develop alternatives to costly reliability-must-run agreements for resources which cannot deactivate due to transmission violations. However, stakeholders’ efforts have been challenged by PJM significantly changing its proposal late into that process. She said stakeholders look to PJM to a sense of what is needed and workable.
Constellation Energy’s Erik Heinle said when stakeholders are developing proposals, they are expected to have the design matrix filled out for each element under consideration, which can complicate voting on proposals focused on just a few elements. He suggested that voting on design components instead of packages could simplify package formation and understanding stakeholders’ priorities. Nelson and Manager Vickie VanZandt said they liked the concept.
Heinle pointed to the 2025 CIFP process focused on resource adequacy, which yielded a dozen proposals all in agreement that load forecasting should be improved. Despite that agreement, each package sponsor had to articulate their support for ongoing efforts to rework how PJM forecasts large load additions.
EDF North America Director of Transmission Policy Emma Nix Simon questioned whether dividing PJM’s membership into five sectors continues to make sense as the number of members has grown to more than 1,000. She also suggested a larger set of meetings could be recorded to allow stakeholders to engage with meetings they were not able to attend or rewind to better understand a technical subject.
LS Power Senior Vice President of Wholesale Market Policy Marji Philips said PJM can improve on listening to its members when there is broad opposition to changes it is considering. She pointed to efforts to establish a seasonal capacity market during the 2023 CIFP process focused on resource adequacy, a proposal she said the RTO continued to advocate for despite opposition across the member sectors. The number of proposals also has become unmanageable in some processes — both the 2023 and 2025 CIFPs had more than 10 proposals — leading her to suggest limiting the number of proposals by sector. (See PJM Files Capacity Market Revamp with FERC.)
VALLEY FORGE, Pa. — PJM is forming a task force to explore how new data centers can be required to curtail if they interconnect before there is sufficient capacity and transmission capability.
The Markets and Reliability Committee endorsed PJM’s Connect and Manage issue charge, which would identify circumstances under which large loads would be required to curtail because of a lack of generation capability, and an Exelon issue charge addressing interconnections that would cause transmission violations that cannot be resolved before the load’s in-service date.
Both issue charges were approved during the committee’s March 25 meeting and assigned to the newly formed Connect and Manage Senior Task Force (CAMSTF), which is holding its first meeting March 31.
Exelon Vice President Transmission Strategy David Weaver said the transmission side should be addressed in its own process because it would require a focus on the development of software tools needed to model available transmission headroom in each hour. If headroom is available for part of a year, that would provide a starting point for determining when a large load would need to be curtailed.
PJM Board of Managers Chair and interim CEO David Mills said a Connect and Manage framework would be a stopgap to mitigate falling reserve margins while other solutions with longer lead times are rolled out. Even with the implementation of programs intended to speed resource development — such as the proposed Expedited Interconnection Track and bring-your-own-generation systems — it will take years for new capacity to begin coming online.
“What we have here is a collision course of time versus shortfall,” he said.
The Connect and Manage issue charge scope begins with education on jurisdictional boundaries and moves on to defining which large loads would be subject; curtailment triggers and where they fit into the emergency procedure stack; how curtailment quantities would be assigned to utilities; and exceptions for large loads that bring their own new generation (BYONG) or enter into other supply arrangements.
The document precludes discussion on the amount procured in the capacity market, PJM’s authority in determining which customers must curtail during load shed and “overall load shed allocation” as being out of scope.
Data Center Coalition Issue Charge Merged with PJM Language
PJM and the Data Center Coalition workshopped the issue charge to incorporate elements of one the coalition and Google were slated to present a first read on later in the meeting that would open a separate conversation on a BYONG framework.
Language was added to the key work activities to “define supply-load linkages for the purposes of Connect and Manage exemption,” and the scope was widened to include evaluation of the system conditions that might trigger curtailment.
GQS New Energy Strategies Principal Pamela Quinlan, representing the DCC, said there seemed to be an oversimplification of how BYONG would be harmonized with Connect and Manage and the reliability backstop procurement also under consideration. There’s a desire to unlock the capital needed to construct resources to serve data centers, but this confusion is putting that investment on ice.
She argued PJM’s issue charge could result in a framework that requires data centers to buy capacity they cannot use, as they would be curtailed before capacity resources are deployed.
PJM’s Chris Pilong said there’s a difference between including load in capacity auctions and how the resulting costs are allocated to customers, which gets into state retail ratemaking.
Quinlan responded that these are wholesale costs that should be addressed at the wholesale level.
Presenting the DCC issue charge, Google’s Brian George said a BYONG framework limited to new generation would be overly limited. The coalition’s issue charge would have expanded the definition to allow large loads to bring, build or buy technology-agnostic resources to cover their consumption.
Constellation Energy’s Erik Heinle argued the issue charge should allow consideration of more than just new generation, which would be discriminatory against existing resources.
“We need to be very careful that we choose options that will survive FERC and accomplish those goals” of maintaining reliability, certainty and new development, he said.
Pennsylvania Bill Would Require Data Center Curtailment
Implementing a system to curtail specific customers likely would require buy-in from the PJM member states, as the RTO has held that it can require electric distribution companies to curtail only by specific megawatt amounts. Allocating that curtailment to a customer class would require coordination between utilities and state regulators.
The Pennsylvania House of Representatives approved a bill that would require new or expanding data centers to take interruptible service from EDCs and curtail during regional supply shortages. The bill also would require data centers to pay for their interconnection costs and source a percentage of their consumption from clean energy sources. The bill cleared the House along party lines March 24 and faces an uphill battle in the Republican-controlled Senate.
The DCC submitted testimony opposing the legislation, arguing data centers provide essential services that first responders rely on and must remain online during emergencies. It advocated for expanding voluntary demand response programs with “clear incentives and compensation.”
“Due to the essential nature of their operations, data centers must maintain uninterrupted operations in order to provide essential connectivity and data flow to their customers and to the many end users who rely on constant, seamless access to data and underlying applications,” the coalition wrote. “Some reliability risks, including sudden utility power outages due to storms, natural disasters and other causes, are inherently outside data center companies’ control. Data centers need to remain operational during emergencies to ensure that access to essential data and services continues uninterrupted for clients, end users and the general population.”
Exelon Issue Charge Focuses on Managing Transmission Violations
The Exelon issue charge seeks to develop tools to allow utilities to offer non-firm service to large loads while transmission upgrades required for them to receive reliable service are being constructed.
Its scope includes identification and curtailment of eligible large loads and a recognition that customer-level curtailments fall within the domain of retail rates.
The document envisions a solution in which PJM and transmission owners would model the amount of curtailment required under specific system conditions so utilities could establish “specific customer contractual curtailment guarantees.”
Options for the temporary transmission service large loads could receive include:
Fully matched, in which all the load is served by co-located generation and only ancillary transmission services are provided.
Partly matched, in which some energy is provided by onsite generation and withdrawal from the grid is limited to the net studied value.
Storage matched, pairing the load with onsite batteries, which can allow operations to continue during curtailment.
Connect and Manage, allowing the TO to interrupt the load to mitigate transmission violations.
Responding to questions on how the issue charge is different from FERC’s ongoing investigation into PJM’s rules for co-located load, Pilong said Exelon is seeking to establish broader rules for configurations in which the large load is not necessarily paired with onsite resources. (See PJM Presents 1st Look at Co-located Load Compliance Filings.)
Several stakeholders questioned why the PJM and Exelon issue charges could not be merged. Pilong said both parties spoke extensively about that possibility but determined they are trying to solve separate, though related, issues. He noted PJM does not have a load interconnection queue, and the determination of network upgrades is a TO responsibility.
Exelon Director of RTO Relations Alex Stern said the CAMSTF would first focus on the PJM/DCC issue charge and shift to the transmission-side afterward.
IESO’s Long Lead-Time (LLT) procurement may be delayed beyond its planned April launch because the ISO still is awaiting a directive from the Ontario Ministry of Energy and Mines.
ISO officials announced the potential delay in an engagement session March 26, where they also shared refinements to their buy-local incentives.
The LLT procurement is intended for resources that require longer planning cycles than the four-year lead times in the pending Long-Term 2 (LT2) procurement. IESO plans to seek 600 to 800 MW of capacity from storage resources and up to 1 TWh of energy from hydro resources requiring at least five years of lead time.
“While we were expecting to get our directive to launch the LLT [request for proposals] by the end of this month, we no longer expect that to be the case,” IESO’s Ben Weir said. “Government is continuing to take some time to finalize the [supply chain] policy that’s going to be applicable to this procurement. … There is still hope that the end of April launch timeline does not get impacted by this … but that timeline has been put into question.”
At issue are the government’s rules for incentivizing respondents to use Canadian construction materials and labor. The ISO previously said developers who commit to sourcing 75% of materials and construction services from Canadian suppliers would receive a 2% reduction in their “evaluated” price. (See IESO Expands Hydro Eligibility in Long Lead-Time Procurement.)
But in its March 26 presentation, IESO revised the incentive to a sliding scale, ranging from a 1% price reduction for using 60 to 70% Canadian supplies, to a 3% reduction for a 100% Canadian commitment.
If a supplier cannot prove they met their committed percentage, they will be subject to up to $5 million in liquidated damages, with higher damages for those falling more than 5 percentage points below their commitment.
Michael Killeavy of Power Advisory questioned the rationale behind the damages, asking, “If there’s a shortfall in Canadian content, how is the ISO actually damaged?”
Weir said the ISO wants a disincentive for suppliers who fail to honor their pledge to use a high percentage of Canadian supplies. “They shouldn’t have been awarded [a reduction in their evaluated price],” he said.
Reserve Price
IESO’s Jasdeep Kahlon again defended the ISO’s plan to use Window 1 of the LT2 procurement as the baseline for the LLT reserve price — a confidential price threshold to ensure the ISO doesn’t pay too much.
The price will be adjusted for inflation to account for the later commercial operation dates for long lead-time projects. IESO also will consider the cost of new entry at Year 21 of the 40-year contract term.
Kahlon said some stakeholders are concerned that the resources procured through LT2 are not comparable to those in the LLT procurement.
“While the ISO is taking this into consideration, I do want to clarify that the reserve price is intended to be … a price ceiling and reflect the ISO’s willingness to pay for LLT energy and capacity resources,” he said. “The ISO is not attempting to set a target or a forecasted price.”
Suppliers who promise a high percentage of Canadian labor and supplies will receive a reduction in their “evaluated” price, ranging from 1% for using 60 to 70% Canadian supplies to a 3% reduction for a 100% Canadian commitment. | IESO
In addition to the CONE baseline cost at Year 21, Kahlon said the ISO will consider the value of other attributes, “including supply diversity and system reliability benefits, longer asset lifetimes, the duration and flexibility that these projects bring” in addition to the domestic sourcing considerations that weren’t required for LT2 Window 1.
“I think a lot of the [stakeholder] concern may stem from maybe a lack of confidence that the ISO is going to correctly value these additional attributes,” he said. “So, this is where I’m … strongly encouraging stakeholders to submit any supporting materials, reports, modeling, analysis — whatever stakeholders believe would help the ISO correctly value these attributes.”
Early Delivery Concession
In response to stakeholder concerns, IESO agreed to relax conditions for its consent for a COD earlier than specified in the contract.
Stakeholders expressed concern that IESO’s veto power over an early COD could undermine the ability to finance projects, saying a project that is financially viable with a six-year lead time may not remain viable with a seven-year lead time.
IESO said it will update the LLT contracts to specify that consent for an early COD “shall not unreasonably be withheld.”
Timelines
The ISO also agreed to extend the RFP’s proposal submission deadline to Nov. 26. Some stakeholders had requested a deadline at the end of December.
Patrick Gillette, of consulting firm CRD Energy, said the November deadline “is somewhat problematic, especially for the greenfield sites that the Ministry of Natural Resources is going to be releasing.”
Gillette said the extended deadline will be helpful for “more mature sites,” but “it’s going [to be] very difficult to convince anybody to put any money into a process where you have the risk of the Ministry of Natural Resources needing to confirm the site is going to be put out there; that you’ve got to do a bunch of technical work in the field, and you’re working on something that normally takes a year, and the timelines have been shrunk down to seven eight months,” he said. “The risk you’re running here is that the really good sites that don’t have as much work done on them won’t be submitted.”
Weir said the deadline could be delayed if the procurement is not launched by the end of April, but he added, “You’re not going to get a year.
“We are balancing here a number of different procurements that have different timelines; that … need resources to be in service to meet needs that show up at different times,” he said. “And there is … only so long that we can push back an LLT proposal submission and still get contracts awarded.”
Next Steps
The ISO plans to post updated drafts of the RFPs, contracts and pre-deliverability test intake forms on April 1, and the deliverability testing methodology by mid-April.
It asked for feedback on the latest engagement by April 15 at engagement@ieso.ca.
TORONTO — Generating power flow analyses in minutes that formerly took weeks. Using high-resolution weather data to create probabilistic operational plans. Running a million Monte Carlo scenarios to compare potential grid upgrades.
All that is now possible with artificial intelligence, and it will replace most traditional utility planning and operational processes within a decade, says Josh Wong, CEO of ThinkLabs AI.
With aging infrastructure and increasing congestion, AI is needed to solve problems that are “orders of magnitude more complex” than what the grid faced 20 years ago, Wong told the Ontario Electricity Distributors Association’s ENERCOM 2026 conference March 23.
“For the past decade, we have been looking at just a corner, a small subset of the [grid], and trying to solve it with, I would say, brute force,” Wong said, citing transmission cluster studies that can cost $250,000 each and take six to 10 months to complete. “We always run studies independently, ad hoc, reactively and repeatedly, and it takes months, and it takes a lot of time, resources, and manpower and budget.”
When Wong was at Toronto Hydro, the utility studied each distribution feeder once every three years. In contrast, AI can continuously update its analysis of the grid the way Google Maps updates travel directions in response to changing traffic patterns.
“So now we have a real-time … copilot sitting in your control room, analyzing every feeder, every single few seconds to look at issues” and recommend fixes, Wong said. “Should you expand this line? Should you add a battery? Should you switch? Should you put a demand response or flexibility contract?”
Wong’s goal: AI running grid operations on “autopilot” with human override.
Wong said his company is working with MISO on how to introduce AI into the control room. “We are teaching AI agents to actually become training simulators to train generation operators,” he said.
The grid is so complex that the “human loop” will always be needed, Wong acknowledged. “But we are fundamentally up-leveling the job of the planner [and] the operator from really mundane tasks by giving solutions.”
AI ‘Skunkworks’
Wong turned to AI after founding Opus One, which became a leading distributed energy resource management system, during the first generation of smart grid and smart metering. “I realized that the core of the smart grid, or grid intelligence, is the intelligence piece,” he explained. “It’s not the next gadget, the widget, the piece of hardware, meter, battery, etc.”
After selling Opus One to GE — now GE Vernova — Wong became restless to start something new. He began an AI skunkworks within GE, which in 2024 spun out ThinkLabs.
Last year, ThinkLabs teamed with Southern California Edison to build “physics-informed” AI digital twins to address SCE’s load growth, which the utility says will require it to add seven new distribution circuits each year for the next decade.
“They need to process up to 10,000 energization requests each month. Currently … each interconnection and load request takes 30 to 45 days,” he said. “How many … resources and planners do you need to make that happen?”
To help utilities maximize their existing infrastructure, Wong said, AI can enable a shift from worst-case scenario analyses to time series analyses of all 8,760 hours in a year.
Using Microsoft Azure AI Foundry, “we trained sub-transmission AI models. We trained distribution AI models. We had them co-simulate [transmission] and [distribution],” Wong said. “We added all the interconnections. We played it out based on their [interconnection] queue. We found all the thermal violations [and] voltage violations.”
It did not take 30 to 45 days. “We did it for the entire system in two-and-a-quarter minutes,” he said. “So now the joke is: Grab coffee, come back and you can connect.”
The output “doesn’t give you one future, it gives you a probability of futures,” he said. “Now, with the right horsepower and the AI models, we can finally get into probabilistic operational planning” that ensures operators are making the right decisions.
“Now, when I do that switching, when I dispatch that battery, I have confidence whether I’m actually solving the problem or not,” he said. “So, this is what high-performance compute gives you: really going from worst-case analysis and hope for the best — ‘spray and pray,’ overbuild — to really be very surgical in how we analyze the system and be very confident in our actions.”
Capital Planning, Power Restoration
ThinkLabs is feeding AI decades of log data from advanced meters and SCADA systems to allow it to help with root cause analyses.
Wong also sees AI taking a major role in capital budgets, allowing planners to run Monte Carlo simulations of alternative grid upgrades.
“I can run … a million scenarios in 10 minutes,” he said. “So can we go to a regulator and say, … ‘We have studied a million scenarios and … the data shows us that this is the most prudent investment.’”
Wong said AI also can help utilities recover from storm-related outages by matching equipment and crews with tasks and developing key performance indicators affecting estimated time to restoration. “ETRs are a very wild guess these days,” he said.
Moore’s Law — the observation that the number of transistors on an integrated circuit will double every two years with minimal cost increase — applies to grid AI, Wong said. That means that costs will drop and AI insights will be available to small local distribution companies, not just large utilities.
“This is no longer a pipe dream,” he said. “The future is now.”
