The Missouri Public Service Commission unanimously approved a settlement agreement on rates for Ameren’s large load customers that insulates ratepayers from most costs associated with supplying data centers’ electricity needs.
The plan defines large load customers as those requiring a maximum 75 MW or more in monthly demand. Supply contracts under the rate would have minimum 12-year terms, with an option for a five-year load ramp period, making for potential 17-year contracts. The PSC sanctioned the rate Nov. 24 (ET-2025-0184).
Agreements would automatically extend for five-year increments unless customers provide a 36-month written notice that they intend to end or reduce their service. Customers who elect not to extend their service must pay exit and early termination fees.
Large load facilities would be required to post collateral equal to two years of minimum monthly bills. Under the plan, they would be able to participate in Ameren’s nuclear and clean energy programs through an expanded clean energy choice rider.
The rate also stipulates that a percentage of excess revenues from large customers be dispersed to benefit ratepayers, with half of the revenues earmarked for low-income customers. Finally, Ameren must evaluate the cost allocations for large loads and ensure that existing customers aren’t paying for costs that should be paid by data centers and manufacturers.
The Missouri PSC said its approval of the agreement is “a significant step forward in implementing” 2025’s Senate Bill 4. The omnibus energy bill enacted by the state legislature prevents large customers’ “unjust or unreasonable” costs from bleeding into other customers’ bills, among other directives.
“Efforts were also made to design a plan that was similar to other tariffs throughout the country, and across Missouri, ensuring Missouri can properly compete for the economic development benefits that these loads represent,” the PSC said in a press release.
Several parties signed off on the settlement agreement, including Ameren, the PSC staff, Google, Sierra Club, Missouri Industrial Energy Consumers, Renew Missouri and Evergy.
The PSC’s vote enshrined more consumer protections than originally were drawn up in the large load rate; an earlier version applied the rate to customers of 100 MW and above and included a 10-year contract term.
Jenn DeRose, a strategist with the Sierra Club’s Beyond Coal Campaign in Missouri, said the rate plan is a “step in the right direction” to protect ratepayers from cost increases from data centers and discourage speculative moves from developers.
“Missourians are rightly concerned about the impacts of new data centers on their electric bills and communities, and they deserve protections,” DeRose said in a statement. “How will customers be protected after Ameren spends billions of dollars of our money on new gas-burning power plants if the AI bubble bursts, the utility overbuilds power plants due to AI speculation, or AI data centers become significantly more efficient?”
Senate Bill 4 also requires utilities to replace retiring plants with dispatchable resources and mandates that utilities source at least 80% of their capacity with dispatchable generation.
That means large loads in Missouri likely would take a lot of natural gas-fired power. Ameren Missouri is planning a significant gas expansion, including the Castle Bluff Energy Center anticipated in 2027 and the Big Hollow Energy Center in 2028. The utility’s 2025 preferred resource plan includes building 1.6 GW of new natural gas generation by 2030 and a total 6.1 GW by 2045. Ameren Missouri’s next integrated resource plan filing is due to the commission in 2026.
U.S. Secretary of Energy Chris Wright has extended the order under Section 202(c) of the Federal Power Act to keep Constellation Energy’s Eddystone Generating Station in Pennsylvania running through this winter.
“Thanks to President Trump’s leadership, the Department of Energy is using all tools available to keep the lights on and heat running for the American people,” Wright said in a statement. “This emergency order is needed to strengthen grid reliability and will help provide affordable, reliable and secure power when Americans need it most.”
The Campbell and Eddystone orders have been challenged in court by state authorities and environmental groups. The former case is further along, with the first substantive briefs due Dec. 19.
Eddystone was scheduled to retire before the summer. PJM dispatched the units during heat waves in June and July, DOE said. The current order will keep the plant running until Feb. 24, 2026. DOE noted the RTO set a winter peak in January 2025.
“Through 2030, PJM anticipates reliability risk from increasing electricity demand, generator retirement outpacing new resource construction and characteristics of resources in PJM’s interconnection queue,” DOE’s order said. “Upcoming retirements, including the planned retirement of the Eddystone units, would exacerbate these resource adequacy issues.”
In total, the two units subject to the order generated 26,434 MWh between June 2025 and September 2025, DOE said in the order.
PJM has been dealing with rising demand and retirements in recent years. DOE’s order said that “will continue in the near term and [is] also likely to continue in subsequent years.”
“This could lead to the loss of power to homes and local businesses in the areas affected by curtailments or outages, presenting a risk to public health and safety,” the order said.
A common theme across the deluge of comments on the Department of Energy’s Advance Notice of Proposed Rulemaking to FERC on large load interconnections was that parties welcomed the process as a vehicle for the commission to improve its rules to help with speed-to-market concerns (RM26-4).
But many of the comments warned FERC and DOE from going too far into jurisdictional issues that could wind up working at cross purposes with the ANOPR’s goal of speeding up interconnections. The first round of comments on the proposal was due Nov. 21. (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)
“Any commission action must recognize that large load customers are end-use retail customers, meaning the delivery service they receive necessarily includes an element of local distribution service,” the Edison Electric Institute told FERC. “Even in states that have elected to restructure their electric industry and implement retail choice, the states require that local utilities secure wholesale transmission service on behalf of all retail customers so that they can procure this competitive generation supply.”
The fair and rapid interconnection of large loads can be achieved without calling into question the way states and FERC traditionally have regulated bundled service, the organization said.
“States have successfully regulated retail interconnections for decades, including interconnections of large retail loads, and upsetting that paradigm here may have unintended consequences that could undermine the goals of both EEI members and the commission regarding developing methods to ensure rapid and reliable connection of large loads,” EEI said.
The ANOPR cites EPSA v. FERC as part of the justification for FERC to claim jurisdiction over large loads. In that case, the Supreme Court found that the commission could regulate areas that impact wholesale markets it oversees. But EEI said that decision left intact the Federal Power Act’s savings clause in Section 201, which reserves authorities for the states.
“A court may find an argument that retail customers affect wholesale prices simply because they interconnect to the grid as a clear overreach by the commission,” EEI said.
The National Rural Electric Cooperative Association filed similar comments, saying the ANOPR can help by focusing on issues firmly under FERC’s jurisdiction, but any rule changes should avoid a jurisdictional fight.
If FERC does decide to go forward with asserting jurisdiction, it needs to foreswear jurisdiction over retail sales — even for large loads that connect directly to the transmission system, NRECA argued. The proceeding cannot be a backdoor to impose retail competition on states that are vertically integrated, it said.
“In considering whether to act upon load interconnection processes, the commission should keep core federalism principles at the forefront of its decision-making,” the American Clean Power Association said in its comments. “Load interconnection has historically been a state-jurisdictional issue, and any federal action should be measured and carefully considered.”
FERC could set clear requirements for consistent, timely and transparent load and hybrid interconnections, and then trigger federal action only if and when states and transmission owners cannot keep up with the minimum standards, ACP said.
The Virginia State Corporation Commission, which regulates the largest data center market in the world, made similar comments.
“Under this paradigm, the transmission owners would file with the commission verification that a large load interconnection tariff meeting such requirements has been filed with their state regulatory authority,” the SCC said.
The SCC noted that the ANOPR’s claims about “connecting directly” to the transmission is questionable because almost all such loads have one or more substations on site to step down the voltage before the electricity can be used.
“The legal durability of any final rule in this proceeding will thus depend on the merit of these assertions,” the Virginia commission said. “The VSCC does not believe it is necessary for the commission to even reach these questions, however, as the best approach to these issues is a cooperative one, where the commission sets minimum standards for interconnecting utilities to meet, while leaving it to state commissions to regulate these retail tariffs as they have done for many years.”
The National Association of Regulatory Utility Commissioners argued that nothing in the ANOPR is intended to assert jurisdiction over distribution interconnections, generation facilities and retail sales, and the commission should state that explicitly in any final rule.
“As acknowledged in the ANOPR, FERC has never attempted to assert jurisdiction over end-user load interconnections,” NARUC said. “The reason for this fact is that FERC asserting jurisdiction over load interconnection is outside the boundaries imposed by the FPA.”
If FERC were to assert jurisdiction over the interconnection of a subset of retail customers, it would interfere with the balancing performed by state regulators in retail rate cases and would have significant impacts on all classes of customers.
“NARUC pledges to engage with regulated entities and other stakeholders to explore consensus solutions for FERC’s consideration that will help meet national goals for large load interconnection, while avoiding disputes over jurisdiction that would impede achieving our shared goals,” it told FERC. “Working together, under the concept of cooperative federalism, will lead to optimal solutions.”
FERC can and should regulate large loads’ interstate transmission and wholesale market aspects, the Pennsylvania Office of Consumer Advocate and the Delaware Division of the Public Advocate said in joint comments.
“Due to the resource adequacy and affordability crises that residential consumers face within PJM, the joint consumer advocates support all jurisdictional efforts to effectuate the FPA’s plain text and core purposes as well as cost-causation principles,” they said. “Primarily, the joint consumer advocates support the creation of an expedited large load interconnection queue that includes the large load through its interconnecting utility or electric distribution company, with a workable study time frame, that seriously accounts for participants’ costs to all other affected grid users within the wholesale market.”
Talen Energy’s Susquehanna Steam Electric Station located in Salem Township, Pa. | Talen Energy
The consumer advocates argued that the ANOPR ignores the fact that even very large customers often are connected through distribution facilities that are firmly under the states’ authority.
“FERC should avoid pre-empting existing state authority because courts no longer reflexively defer to agencies’ interpretations of ambiguous statutes, and Skidmore deference will not suffice here,” the advocates said. “A FERC final rule that includes federal pre-emption of any existing, traditional state authority will face an uphill battle under the U.S. Supreme Court’s new standard of review for agency statutory interpretation.”
The ANOPR compares large load interconnections to the process FERC has long overseen for generators, but the Maryland Public Service Commission argued that the two are far different in reality.
“FERC issued Orders 888 and 2003 to correct inefficiencies and discrimination by vertically integrated utilities favoring their own generation resources,” the PSC said. “However, utilities have no comparable incentive to discriminate against large load, as these customers represent valuable opportunities for new retail sales and investment. And unlike generators, end-use customers are retail customers — they do not participate in the wholesale markets.”
Still, like many commenters, the PSC said that FERC can help speed up data center interactions through a policy of cooperative federalism.
The R Street Institute generally supports the expansion of wholesale and retail competition, but it said the fast-paced ANOPR process was not the right venue.
“FERC should narrowly address large load interconnections in ways that hew to the commission’s well supported implementation of generation interconnection planning and that limit regulatory creep,” R Street said. “FERC should further leverage the commission’s competencies and expertise and prioritize litigation risk and implementation concerns.”
What should FERC do in response to the ANOPR?
PJM said a federally regulated large load interconnection process warrants more study, but it urged FERC to move forward on areas where it has firmer jurisdictional footing, such as resource adequacy, ancillary services, interconnection and transmission planning, and NERC reliability requirements.
“Such a construct would have potential benefits including centralization and the promotion of uniform policies and practices,” PJM said. “But, as with the existing generator interconnection process, there will undoubtedly also be costs, claimed delays (many of which will be outside the control of the RTO/ISO), and other complexities that will have to be addressed and that are likely to frustrate the ANOPR’s ‘speed to market’ objective — especially given potential impacts to the existing generator interconnection process.”
The RTO asked FERC to move forward on the pending co-location proceeding that has held up large load issues in its footprint, as did other commenters who do business in its territory (EL25-49).
MISO supports rule changes to help speed up interconnections, but it argued that FERC should respect regional differences.
“MISO’s existing processes effectively reflect unique facts and circumstances of MISO’s system, its states and members,” the RTO said. “Importantly, states and load-serving entities are primarily vertically integrated and responsible for resource adequacy within the MISO footprint. As a result, many states and utilities within MISO have processes which enable them to review and pare through speculative load requests to determine projects with more certainty, allowing MISO processes to enable speed to power for more certain large load interconnections, including determining the associated transmission required to facilitate the required generation interconnections.”
Making large load use the same or a similar process to the generation queue, which has had its own well documented issues with delays, is questionable, the RTO said.
“MISO questions whether standardized large load interconnection procedures will result in the ‘speed to power’ that is necessary to allow the United States to effectively compete in the global competition for economic development, such as in artificial intelligence and creating manufacturing and industrial jobs,” it told FERC.
Meta, the parent company of Facebook and a major player in building data centers, cautioned FERC against a one-size-fits-all approach, even though large load interconnections could benefit from some standardization.
“Some regions of the country are just beginning to bring data centers online, while others have already interconnected substantial large data center loads and are working quickly to add more,” Meta said. “Keeping this momentum going is imperative. Issuing a detailed, standard rule that fails to account for the diversity in the economic landscape could slow down successful interconnection processes and undermine the commission’s goal of bringing more data centers online faster and in a more orderly manner.”
Amazon Energy — Amazon’s energy trading subsidiary — supports FERC action, but whatever the commission does should not upset the planning around data centers that is underway.
“Amazon Energy respectfully urges the commission to apply any new rules or policy changes adopted in this proceeding prospectively, and not to large load interconnection requests currently in progress under existing interconnection procedures,” it said. “Specifically, Amazon Energy proposes any new rules apply only to large load interconnection requests that, as of the effective date of the new rules, have not executed agreements that include a significant financial commitment to the interconnecting utility.”
Google filed comments arguing FERC should work to build out the grid so the growing demand from data centers can be met in a timely and reliable way.
“Now is the moment to right the ship and build out the transmission grid needed to support our nation’s ambitious AI goals,” Google said. “And we must do this with a commitment to affordability: The goal is not to spend more, but to plan better in order to develop a transmission grid that can support the nation’s digital infrastructure needs. Ultimately, a modern, robust transmission grid is the essential platform for delivering affordable, reliable energy to all customers, unlocking transformative dividends across the American economy — from AI leadership to a revitalized domestic manufacturing base.”
The grid needs a holistic planning process, and grid planners need an accurate sense of how much new demand from large loads they will have to meet. Google endorsed SPP’s Consolidated Planning Process, in which generator interconnection and long-term transmission planning are combined.
“The commission should also focus its near-term efforts on identifying pathways to expediting other transmission-level load interconnections that benefit the grid, such as loads that voluntarily offer flexibility via demand reduction or agree to take curtailable transmission service,” Google said. “As with co-located or electrically proximate pairs of load and generation, Google believes that the commission should consider prioritizing reforms to expedite the study of loads that can themselves minimize or help manage the strain on the transmission system.”
Flexibility’s Role
Emerald AI, which works with data centers to make their operations more flexible, endorsed the ANOPR’s idea to create a “Flexible Load Fast Track” for projects that can curtail demand when needed.
“The greatest opportunity in this rulemaking is not merely streamlining the administrative study process but enabling large loads to actively avoid or defer massive grid and energy infrastructure upgrades,” the company said.
The traditional model in which new customers’ load is measured at its maximum and coincident with system peaks requires major investment in new wires and generation and is fundamentally incompatible with the exponential growth and unique physical characteristics of data center demand, Emerald said.
“Delays in interconnection, driven by study processes that do not allow for flexibility — including software-defined flexibility — threaten to stall this economic engine,” Emerald said. “By adopting a technology-neutral, performance-based definition of flexibility and curtailable load, the commission can unlock tens of gigawatts of capacity, ensuring that the U.S. maintains its competitive edge in AI while protecting ratepayers from the costs of unnecessary transmission buildout.”
Non-firm Interconnection Service
American Electric Power commended DOE for launching the rulemaking and said FERC needed to ensure that generation can come online in a timely fashion to serve new large loads. It endorsed the connect-and-manage approach used in ERCOT.
“Under this approach, all generators pay an entry fee and can rapidly connect to the grid, subject to curtailment until supporting network transmission is planned and constructed,” AEP said. “Generators may start as energy resources for some portion of their capacity but are on a pathway to full recognition as capacity resources until supporting network transmission is built.”
The Data Center Coalition also endorsed a change to interconnection service, arguing FERC should regulate energy resource interconnection service more like ERCOT does with connect and manage. Too often, the organization argued, the commission has stringent requirements that are more in line with network resource interconnection service, which is meant to ensure resources can deliver power even during peak hours.
“The stakes are clear: If the United States is to maintain resource adequacy, economic competitiveness and technological leadership, the grid must be capable of interconnecting both load and supply at the pace required by today’s economy,” the coalition said.
NRG Energy urged an even bigger change: using open seasons to help large loads connect to the grid much more quickly.
“A more efficient, market-based approach employing open seasons would provide much needed certainty around the amount and location of large loads, which would benefit regional transmission system operators/independent system operators, transmission owners, generators and consumers alike by facilitating more orderly planning and capital investment,” it told FERC.
Such processes have been used by natural gas pipelines to help raise capital and get customers, NRG said. The Alberta Electric System Operator recently used the concept to allocate open headroom on its system to data center customers.
“AESO began by establishing an interim, reliability-based megawatt limit (1,200 MW) on large load interconnections with its grid and then assigning that capacity to large loads ready to advance in the interconnection process in ‘a fair, efficient and openly competitive manner’ based, in part, on each large load’s ‘willingness to commit’ through the posting of financial security,” NRG said.
Open seasons will require a more proactive role from grid planners, but that should benefit the interconnection and transmission planning processes, NRG said.
“Such an approach is geared toward speed-to-market, getting the most megawatts online at the lowest overall cost, and ensuring a direct allocation of incremental costs to new large users of the grid,” the company added.
What to do about reliability rules?
NERC intervened in the case to ask whether it should consider new rules to deal with issues caused by new large loads and whether the large load customers should have to follow them.
So far customers have not had to follow NERC’s mandatory standards, but the FPA does say they can apply to “users” of the bulk power system and that could cover large customers.
“NERC plans to coordinate with stakeholders over the following year to explore potential revisions to the registry criteria and reliability standards that would incorporate large loads impacting the reliable operation of the BPS,” the ERO told FERC.
The Large Loads Task Force is working on those issues now. NERC laid out a timeline that runs through 2028 to address any needed changes to its mandatory reliability standards in response to the proliferation of large customers.
“Depending on the outcome of these activities, next steps may include NERC registry criteria updates that help mitigate risk associated with emerging large loads,” it said. “As discussed at the commission-led 2025 Reliability Technical Conference, any updates to registry criteria would be dependent upon whether relevant users, owners and operators of the BPS could materially impact, either individually or in aggregate, the reliability of the BPS.”
The U.S. Department of Energy now has some feedback to consider as it pursues its Speed to Power initiative.
DOE announced the program Sept. 18 as a means to expedite development of the gigawatt-scale generation, transmission and grid infrastructure needed to support large-scale data centers and accelerate the artificial intelligence development those facilities would enable. (See DOE Launches Speed to Power, Eyes Multi-GW Projects.)
DOE launched the initiative by asking stakeholders for their input. The window for the request for information closed Nov. 21. Numerous entities submitted comments, and some shared them publicly.
The American Public Power Association said public power utilities face significant constraints as they try to expand their capacity for new loads while protecting their existing customers from risks and costs. So, APPA welcomed an expanded federal role in accelerating critical projects, and suggested some focus points for DOE, including:
ensuring financial and technical assistance are available for public utilities and streamlining the application process;
enabling joint action on projects that individual utilities could not undertake alone; and
coordinating federal agencies’ efforts.
APPA also said public-private joint ownership of transmission is an important tool with a track record of success. APPA flagged supply chain constraints, federal permitting delays and regulatory uncertainty as major barriers to success.
The Software & Information Industry Association raised a central concern: The U.S. lacks a cohesive national framework to ensure sufficient and reliable energy supply for data centers — permitting processes often are fragmented across local, state and federal jurisdictions, creating delays and uncertainty.
SIIA called for streamlining the permitting for AI infrastructure projects and for incentivizing nuclear energy to power AI; strengthening federal authority over transmission development and limiting discriminatory state-level practices; and reforming forecasting processes to include new large loads only when backed by significant upfront investments and financial commitments.
SIIA also suggested DOE use tools such as the Defense Production Act to accelerate American manufacturing of critical grid equipment.
The federal government could assume a key role in identifying which large load additions directly support national security and therefore should be prioritized.
DOE could designate National Interest Electric Transmission Corridors, and if it did, it should use grid operators’ regional and interregional planning processes.
DOE should convene transmission planners nationwide to discuss greater standardization and uniformity for large load forecasting.
DOE could request that FERC direct NERC to ensure to ensure a proper system of registration of large loads, and potentially to submit reliability standards.
DOE should update its regulations to clarify the role of state and local authorities and grid operations in implementing any future orders under the Defense Production Act.
MISO’s comments focused on how it is addressing the issue now, saying it has “updated and enhanced its processes across the transmission and resource planning horizons to efficiently support large load additions and improve the integration of large loads.” And MISO also is working on several efforts to potentially enhance its existing processes.
MISO said supply chain frictions pose a significant threat to constructing the infrastructure needed to meet regional projected load growth. DOE could help the power industry by better understanding these frictions and helping address them.
NRG Energy said DOE is best suited to a role in which it assists in creating a market for supply and flexible demand rather than directly subsidizing individual projects.
It said capital formation in the generation sector is lagging projected AI demand for three reasons: uncertainty of demand, high fixed costs throughout the supply chain and forward energy markets not signaling future demand sufficient to justify the level of investment needed to meet projections.
On this last point, NRG says: “The current situation of seeming underinvestment likely results from some combination of … overstated demand, few long-term buyers for supply relative to those seeking to sell long-term supply, and a tacit understanding that the market one would hope to do the lifting on capital formation is not the venue where this action necessarily takes place.”
The Electric Power Supply Association emphasized the value of competitive wholesale electricity markets, accurate demand forecasting and regulatory and trade reforms.
Understanding the future demand — how much, when and where — is foundational, EPSA said: “We should not rush headlong into potentially trillions of dollars of energy infrastructure investments without a calculated and realistic projection for what infrastructure is needed.”
EPSA also said DOE should encourage voluntary partnerships between generators and large energy users to accelerate development while shielding ratepayers from financial risk; NEPA, the Clean Air Act and similar laws could be updated; and an independent bipartisan FERC would provide essential predictability for investors.
DOE should focus on facilitating transmission development that bridges interconnections and regions.
DOE should expand the Transmission Facilitation Program for interregional transmission to address capital availability concerns.
Congress should establish a siting and permitting framework for certain high-capacity interstate transmission lines similar to the Natural Gas Act for interstate pipelines; DOE should strengthen its Coordinated Interagency Transmission Authorizations and Permits Program; and the Trump administration should reduce environmental review bottlenecks.
Congress and the administration should enact tax credits for high-capacity transmission; address supply chain constraints; cap wildfire liability; and maintain an agency workforce sufficient to support transmission siting and permitting.
The Institute for Policy Integrity at New York University School of Law said DOE should support NERC in development of a robust energy adequacy planning standard; initiate a nationwide study of interstate gas capacity; develop a rule to improve interregional transmission planning; assist development of a co-optimized transmission planning model; prioritize its funding decisions with a cost-benefit framework; and prioritize existing programs that incentivize grid expansion and innovation.
Americans for Prosperity urged consideration of generation, transmission and distribution occurring outside of the traditional grid, such as with microgrids, co-located generators and consumer-regulated electricity.
Secure The Grid Coalition offered a lengthy call for the DOE to protect the grid against geomagnetically induced currents, such as from solar storms or high-altitude nuclear warhead detonation.
DOE’s National Renewable Energy Laboratory has created a data viewer in support of the Speed to Power initiative, with an interactive U.S. map showing some of the information developers need as they conduct site assessments, including: power demand from data centers that are planned, under construction or in operation; fiber-optic cable networks; transmission lines; power plants; substations; natural gas pipelines; day and night population; NERC reserve margins; FEMA risk indexes; and railroads.
Citing “concerning [unmanned aircraft system] activity over sensitive critical infrastructure sites,” the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency has published multiple guides to help critical infrastructure operators address the security risks posed to their systems by drones.
CISA released the guidance as part of its Be Air Aware initiative, aimed at promoting awareness of drone risks. The agency wrote in a blog post that drones “are affordable, easy to modify and have advanced capabilities, making them a unique and multifaceted threat to critical infrastructure.”
“The new risks and challenges from UAS activity demonstrate that the threat environment is always changing, which means our defenses must improve as well,” CISA Acting Director Madhu Gottumukkala wrote in a separate press release. “CISA’s Be Air Aware resources are designed to empower critical infrastructure owners and operators with the information they need to better safeguard their systems and assets.”
To illustrate the risk, CISA pointed to the case of Skyler Philippi, arrested by the FBI in November 2024 for plotting to rig a drone with explosives and fly it into an electric substation near Nashville in furtherance of a “violent white supremacist ideology,” according to then-Attorney General Merrick Garland. (See Feds Accuse Tenn. Man of Substation Attack Plot.) Philippi pleaded guilty to the charges in September.
Each of CISA’s three guides, released Nov. 19, covered a specific aspect of drone risks. In the Unmanned Aircraft System Detection Technology Guidance, the agency reviewed systems for identifying and tracking nearby drone activity, grouped into three key steps: establishing capability requirements for UAS detection systems, determining the most appropriate technology for the site and integrating drone detection technology into existing security plans.
The Suspicious Unmanned Aircraft System Activity Guidance was created for critical infrastructure operators who have detected drone activity near their facilities and need to determine their risk level. CISA emphasized in the guidance that “most UAS activity is likely non-threatening to critical infrastructure operations and compliant with Federal Aviation Administration … regulations,” but encouraged organizations to develop procedures for distinguishing between safe and suspicious activity.
Operators should determine the normal level of drone activity in the area and communicate that information to security staff, CISA wrote. This can be done by contacting the FAA, government and community stakeholders and local hobbyist groups and asking where drone activity is permitted and when special events may include drones. Operators may survey the surrounding areas to identify locations that might attract drone users.
They should monitor for indications of suspicious drone activity, such as hovering near sensitive locations, flying in patterns and carrying observable payloads such as sprayers or dangling wires. If these are detected, organizations should engage with the operator if possible to learn the purpose of the flight and negotiate adjustments to avoid the facility. If this effort is unsuccessful and the activity poses a security or safety risk, law enforcement may need to be contacted along with the FAA.
Finally, in the Safe Handling Considerations for Downed Unmanned Aircraft Systems document, CISA advised critical infrastructure operators on preparing for and responding to grounded drones from unknown sources on their property. The agency said that while crashed drones often result from nothing more than “a reckless or inexperienced operator,” organizations must consider the possibility of “something more nefarious, including criminals conducting surveillance or weaponizing the UAS with explosives or cyberattack capabilities.”
Steps to respond to downed drones include securing the area by restricting access to authorized personnel and recording incident details for first responders and investigators. Organizations should consult with law enforcement on issues such as determining the owner of the drone and whether to return it if the drone was crashed accidentally.
FERC approved MISO’s proposal to increase the number of generation projects it may study under its expedited interconnection queue lane from 10 to 15 per quarter.
The commission in a Nov. 25 order found that the increased quarterly project limit appears to be fair and aligns with its previous orders to speed up interconnection timelines reliably and transparently (ER25-3543).
FERC said it agreed with MISO that increasing project counts would help projects reach generation interconnection agreements faster and meet resource adequacy needs quicker. It said faster processing wouldn’t “adversely affect” MISO’s normal generator interconnection queue. (See MISO Moves to Increase Quarterly Project Count in Queue Express Lane.)
The change becomes effective Nov. 26, days before MISO kicks off acceptance of a second cycle of expedited generation requests.
The grid operator in late September filed with FERC to raise the quarterly rate, saying it could handle 15 project slots per quarter and potentially could close the temporary queue process earlier than the originally planned Aug. 31, 2027, retirement date.
MISO has to date received 49 project applications for its expedited queue, with most of the megawatts coming from gas-fired generators.
Kyle Trotter told stakeholders the RTO discovered it could process the generation projects faster than it previously anticipated.
“We didn’t see a reason not to try to go faster and expedite them even more. It doesn’t go deeper than that,” Trotter said at an October Interconnection Process Working Group meeting.
MISO Vice President of System Planning Aubrey Johnson told the Entergy Regional State Committee on Nov. 11 that the RTO believes the fast lane has met its objectives to accelerate resource additions.
However, environmental groups have challenged MISO’s and SPP’s queue fast tracks at the D.C. Circuit Court of Appeals, arguing the processes are unduly preferential, allowing primarily fossil fuel generation to skip queue lines while ratepayers fund the grid upgrades needed to accommodate them. (See Enviros Challenge MISO, SPP Queue Express Lanes.)
Altogether, MISO’s temporary process would accommodate 68 projects, with 10 reserved for submissions form independent power producers and eight from entities serving its retail choice load in downstate Illinois and a percentage of Michigan.
MISO is to roll out a new transmission warning declaration to give its members advanced notice when scarce transmission capacity is raising the risk of load shed.
Speaking at a Nov. 20 MISO Reliability Subcommittee meeting, Clayton Umlor, a MISO manager of reliability coordination, said a transmission emergency warning would establish “more transparency around transmission risk,” especially when load loss is imminent.
The RTO wants to put the new system in place sometime in the first quarter of 2026.
Umlor said MISO would institute the warning only after it has exhausted all normal congestion management procedures without relief, including generation redispatch, transmission loading relief and reconfiguration plans. The RTO alo would try deploying units’ emergency ranges and calling on its emergency-only units and load-modifying resources before sounding the alarm, he said.
MISO intends to use the warning when 100 MW or more of load is at risk after those actions, or when it finds transmission facilities rated above 100 kV have post-contingent flow greater than or equal to 115%.
Umlor said MISO would issue warnings when a reliability coordinator believes “system conditions warrant heightened awareness of potential transmission risk,” such as when load is being served radially due to a forced transmission outage or when a real-time flow of a transmission facility rated more than 100 kV is expected to exceed 100% of transfer capability.
The RTO would call off warnings once risk recedes.
Umlor said the new warnings would require software changes for its operator interface and some stakeholder training. “We want this to be a meaningful communication tool,” Umlor said, adding that MISO doesn’t want to issue the warnings so frequently that it becomes a “boy who cried wolf” situation.
He asked stakeholders to provide opinions on MISO’s proposed 100-MW threshold.
‘A Lot of Stakeholder Confusion’
The new warning category is the latest change MISO is pursuing after a May 2025 load-shedding event in New Orleans in which 600 MW was forced offline abruptly to avoid exceeding an interconnection reliability operating limit (IROL) on Entergy’s transmission system. (See MISO Mulling New Way to Convey Spate of Advisories in South.)
MISO has said an IROL “is the point when operational congestion becomes a reliability risk; crossing it isn’t just a violation — it’s a systemwide emergency.”
An Entergy representative at the RSC meeting said MISO’s designated actions during close calls aren’t always consistent.
Entergy associate general counsel Matt Brown said one shift of MISO operators could make one decision on a transmission plan of action while another shift could revoke that decision, even though criteria and conditions are unchanged.
“What it leads to is a lot of stakeholder confusion about what the risk level might be,” Brown said.
Brown said he understood MISO operators are under “tremendous pressure,” but added they sometimes make ambiguous declarations or split-second decisions the RTO struggles to explain afterward.
Umlor reiterated that the warning system is a “tool for communication that should be used infrequently enough that it is meaningful.” He said the set of criteria should be clear enough that the warning conveys real and present danger. MISO must be “vigilant to make this calibrated properly,” Umlor said.
Bill Booth, a consultant to the Mississippi Public Service Commission, asked if the warnings would come with any corrective actions for members.
“What’s the value of this warning if it doesn’t come with a directive?” Booth asked. He said when MISO delivers a capacity advisory, for instance, it comes with zero instructions.
Umlor said requests for action would come separately from MISO and not be tied to the warnings themselves.
John Harmon, MISO senior operations director of reliability, said the grid operator isn’t looking to change the existing action plans that it and utilities have in place — or their approach to public appeals for conservation.
Harmon said the intent is to “create an additional risk trigger instead of going straight to an emergency.”
Because transmission emergencies can involve shedding load, he said, it’s useful to add a layer of communication before outages that other MISO members can see. He added that MISO communicates directly in real time with utilities directly tied to the risk.
MISO has been declaring transmission and capacity advisories — mainly for its South region — since the springtime load shed.
Shedding Timed IROL Analyses
Relatedly, MISO plans to expand its IROL study timeline so it isn’t pressed to evaluate potential transmission emergencies in 15 minutes or less.
Harmon said the RTO would remove a 15-minute time limit to conduct cascade analyses from its emergency transmission procedures.
The grid operator’s current rules require it to complete an analysis on the possibility of cascading outages within 15 minutes before declaring a temporary IROL.
Harmon said MISO would be removing “an artificial time limit” and that additional minutes would allow it and its transmission owners to study, agree on and implement mitigation strategies before declaring a temporary IROL.
MISO said it’s “overly prescriptive” to assign a specific time limit on conducting studies. While the limit is “well intentioned,” it could rush decision-making and cause it to declare an IROL too quickly, especially in situations where load shed is pre-contingent, the RTO said.
Given PJM’s distinction of being both the nation’s largest wholesale electricity market and the epicenter of the data center boom, many hoped the grid operator would move closer to approving reforms governing large loads after a full day of committee proposals on Nov. 19. However, none of the dozen proposals considered were approved. (See: PJM Stakeholders Reject All CIFP Proposals on Large Loads.)
The voting results suggest that an approach similar to PJM’s proposal may be on the horizon. As a demand response aggregator and virtual power plant platform, CPower would be supportive, assuming certain provisions from PJM’s proposal were to be implemented.
Regardless, we’d prefer PJM take the time to get large loads right rather than push through changes that could do more harm than good. PJM needs every megawatt of supply it can secure, and the last thing it should do is inadvertently force existing supply out of the market. With roughly 8 GW of DR in PJM, a poorly executed policy shift risks undermining a critical source of capacity.
Michael Smith
As it stands now, with new large loads coming online, commercial and industrial customers are likely to be dispatched more frequently, meaning manual load shedding is likely to become more common. In time, this could discourage the largest customers from providing the greatest load relief through DR participation, which has proven to be instrumental in maintaining system reliability during peak events and preventing deeper emergency actions in PJM.
If new large loads do not bring their own capacity, be it generation or demand flexibility at their site or elsewhere, the number of potential or actual reserve shortage hours over the next few years will rise to the point that PJM may routinely have hundreds of hours of DR calls.
With this in mind, we encourage the PJM Board of Managers to respect the following principles as it further deliberates reforms:
“Non-Firm Goes First.” New large loads that are not backed by DR or generator capacity have not purchased firm service and should be dispatched off the grid before pre-emergency DR providers.
DR is DR. New large loads participating in load management programs should be dispatched at the same time as pre-emergency and emergency DR and price responsive demand, not after.
DR Loads are DR Loads. Any new DR programs should be available to all customers, not just new large loads.
Capacity is Capacity. If data centers can buy capacity from a generator to meet a requirement, they should be able to purchase DR capacity for the same purpose.
Whatever path PJM chooses, other markets may follow. That makes this decision especially consequential, as it could set a precedent for future policies and shape how DR is used nationwide.
Getting it right and expanding the use of DR is essential, as it’s the most immediately available, affordable and reliable way to support rapid load growth and enable the innovative energy economy.
Michael D. Smith is CEO of CPower, a virtual power plant platform with 6.7 GW of customer capacity at more than 23,000 sites.
Industry stakeholders and the ERO Enterprise generally expressed support for FERC’s proposal to approve 11 proposed reliability standards intended to allow utilities to use virtualization technology, particularly calling on the commission to leave intact language in the standards that could allow exceptions to the new standards to be granted more easily (RM24-8).
Commenters on a second Notice of Proposed Rulemaking also supported a further modification to one of those standards that would improve cybersecurity at low-impact grid-connected cyber systems (RM25-8).
FERC issued both NOPRs in September along with a final rule directing NERC to develop standards addressing supply chain risk management and an order approving the ERO’s most recent cold weather standard. (See FERC Tackles Cybersecurity in Multiple Orders.) The virtualization updates touched almost every entry in the library of Critical Infrastructure Protection (CIP) standards:
CIP-002-7 (Cybersecurity — BES cyber system categorization)
Commissioners wrote that they supported NERC’s efforts to integrate virtualization and other new technologies into the grid but questioned the ERO’s proposal to replace the phrase “where technically feasible” in some standards with “per system capability” when granting exceptions to the new requirements. FERC asked stakeholders whether there is still a need for a technical feasibility exception (TFE) program, whether the proposed changes would result in entities seeking new exceptions and alternate approaches that would meet the ERO’s goals while allowing effective oversight.
In its response, NERC wrote that the “per system capability” language provides enough flexibility “to ensure the proposed … standards are forward-looking and enable responsible entities to adopt new technologies securely” but “does not absolve an entity from implementing methods to achieve the security objective.” The ERO observed that entities would be generally expected to “achieve the objective [of a given standard] by other means” if unable to implement the technology mentioned in the standard.
Compliance monitoring and enforcement engagements can also give the ERO insight into “how a responsible entity is mitigating risk unique to its environment,” not just its compliance with the letter of the standards, NERC wrote. The ERO wrote that under the existing standards, it collects data on technical feasibility exceptions each year, entities’ engagement with this program “has remained relatively stable over the past three years,” and entities are already required to explain how they are addressing the risks identified in the standards.
“NERC does not anticipate this trend shifting much with the transition to ‘per system capability’ language,” NERC wrote. “Responsible entities are likely to continue to use the mitigating approaches they are already implementing, and the TFE program has given NERC and the regional entities experience into what to expect as mitigating measures for ‘legacy’ systems.”
MRO’s NERC Standards Review Forum (NSRF) also wrote in support of the new language, explaining that the change “is designed to accommodate long-term situations” because the annual TFE reports require “administrative work that provides no benefit to the reliability of the grid [and] also have not proven to be beneficial.” The NSRF observed that “per system capability” or “per device capability” language “has been part of the CIP standards since 2016” and predicted that the proposed changes “should not impact the need for exception.”
The Bonneville Power Administration wrote that “exceptions to the CIP … standards are still necessary” because otherwise, “many utilities would be forced to immediately replace functional equipment at great cost and risk to reliability.” BPA added that it expected NERC and the REs to apply the same expectations to “per system capability” exceptions that it does to the TFE program, which REs can review through audits rather than requiring a separate process for approval.
NERC Argues Against Low-impact Study
In its other NOPR, FERC sought comment on its proposal to approve CIP-003-11 (Cybersecurity — security management controls), intended to address the risk of a coordinated attack using low-impact cyber systems.
Citing the China-linked Volt Typhoon group, which has been accused of embedding itself in the information technology networks of U.S. critical infrastructure organizations, the commission asked whether such actors could pose a threat to grid reliability and whether FERC should direct NERC to perform a study or develop a white paper on the issue.
NERC wrote against this suggestion, arguing that the organization is already studying relevant topics and that an order to conduct another study would be unnecessary. The ERO cited a 2023 data request that collected information from utilities on remote access incidents, along with a nonpublic Level 2 alert issued earlier in 2025 providing recommendations on remote access. Responses from industry “enabled NERC to further analyze the risks associated with cross-border remote access” to grid elements, the organization wrote.
ERO staff are “in the final stages … of developing recommendations” on the risk of remote access that will be published in a report by the end of the year, NERC continued. This report “will include detailed recommendations and next steps … that will inform NERC CIP reliability standards priorities over a multiyear horizon starting in 2026.” Because of this and other ongoing projects, NERC asked that FERC refrain from requiring further studies at least until the ERO has identified its next steps.
PJMpresented its Markets and Reliability Committee with a first read on a proposal to increase the minimum capitalization requirements to participate in its markets.
It was supported by 84% of stakeholders in the RTO’s Risk Management Committee in an October poll.
Under existing policy, entities participating in financial transmission rights markets must have either $1 million in tangible net worth (TNW) or $10 million in tangible assets. For those not involved in FTRs, the requirement is $500,000 in TNW or $5 million for tangible assets.
The proposal would increase the TNW threshold to $2 million for all participants with a 3% fixed rate escalation annually. It includes a transition period in which the TNW for non-FTR participants would first increase to $1 million and double over five years.
The TNW and tangible asset minimums have not been changed since they were instituted in 2011. PJM’s Ryan Jones said minimum capitalization requirements are meant to ensure that market participants can handle the risk associated with their activities and reduce the risk of default shifting costs to others.
An earlier version of the proposal would have required $5 million in TNW, but PJM decreased that after stakeholders voiced concern that it would create too big a barrier to participation, increase market concentration and reduce competition.
Independent Market Monitor Joe Bowring said he views the proposal as a modest requirement which would protect members against defaults by market participants who cannot meet their obligations.
