The changes, approved by the IESO Board of Directors on Oct. 24 and effective Nov. 17, include a multistep tie-break process to optimize the capacity auction clearing process (MR-00488-R00) and an amendment to make it easier for participants to transfer capacity obligations and harder to buy them out (MR-00483-R00).
Resources selected in the annual capacity auction are expected to participate in the energy market unless they buy out or transfer their obligations. But some resources fail to fulfill their obligations because, for example, they did not complete the registration requirements. (See IESO Seeks to Shore up Capacity Market.)
Unfulfilled obligations reduce the capacity available and distort clearing price signals, the ISO says.
With the changes, suppliers who fail to complete the registration process no longer will have the option of simply forfeiting their deposits and will be required to buy out their obligations. In addition, the buyout charge is increasing from 33 to 50% of the obligation value.
The revisions also will remove the requirement that obligations can be transferred between resources only with the same attributes.
The board said the changes, recommended unanimously by the Technical Panel, will improve reliability.
Tie-break Methodology
A tie occurs when two or more participants offer the same price for the last available quantity of capacity in a zone.
Under the previous rules, the ISO used time stamps to select the bid submitted first to break the tie. The new rules created a three-step process to award an equal share in step 1 and apply a proportional allocation in step 2, based on what’s left over from step 1. Capacity remaining after step 2 will be allocated by time stamp rank.
In its approval, the board said the changes will result in a “more equitable” tie-break solution.
Auction
The Nov. 26-27 auction, which will seek capacity for the periods beginning May 1 and Nov. 1, 2026, is open to existing and non-committed demand response, generation, energy storage and import resources. Results will be posted Dec. 4.
The 2024 auction for summer 2025 (May 1-Oct. 31) procured 1,987.9 MW at $332.39/MW-day in all zones except the Northeast and Northwest, which priced at $195/MW-day. For the winter obligation period (Nov. 1, 2025, to April 30, 2026), IESO procured 1,478.4 MW at $139/MW-day in all zones.
The Organization of MISO States (OMS) estimates the RTO is up to approximately 16.6 GW of distributed energy resources across its footprint, up 3 GW from 2024.
That’s according to the 2025 OMS DER Survey, released before the Nov. 10 meeting of the MISO DER Task Force.
OMS Legal and Regulatory Director Brad Pope said the annual survey recorded a “big jump” in DER deployment from 2024 to 2025. In 2024, the survey uncovered nearly 13.6 GW of DERs. For the previous three years, OMS typically has tallied an approximate 1-GW increase in DERs year over year. (See OMS Survey: Another 1-GW Jump in DERs in MISO Footprint.)
Pope said solar generation continues to dominate among reported DERs. Erik Hanser, a staffer with the Michigan Public Service Commission, said 75% of the megawatts represented in the 2025 survey originate from either solar or demand response.
Pope said some increases this year probably are due to underreporting in previous years. He said OMS is looking to improve its data collection method to get the fullest picture it can of DERs in MISO.
MISO utilities responding to the survey “still see a need for regulatory direction” on DERs, from MISO and “especially from state commissions,” Pope said. He said respondents agreed that a “comprehensive and secure data registry of some form” would be useful to share DER data. Many utilities expect to encounter challenges around data sharing and secure communication when FERC Order 2222 — which will allow DER aggregators to compete in MISO’s wholesale markets — takes effect in 2030.
Hanser said that in this version of the survey, OMS logged “a lot more serious talk” about DER management systems, with more utilities considering them. But Hanser said survey responses indicated DERs are still too small in size and number to materially affect the MISO transmission system or inspire planning changes. Hanser said utilities in high DER penetration areas reported a small number of backflow issues on circuits or at substations, some of which were addressed by line upgrades.
Hanser said some utilities thought MISO should lead on creating protocols to set up communication between utilities and DER aggregators. Other utilities are in the early stages of addressing communication and awaiting more information from the RTO, he said.
“Overall, we got the sense that it’s too early. … Utilities are waiting for guidance both from MISO and their state regulators,” Hanser said. “Utilities are wary [of acting] before fully understanding how DERs will eventually operate in MISO. Utilities want to build systems they believe will interact easily with MISO rules.”
During the OMS Annual Meeting in October, Executive Director Tricia DeBleeckere urged MISO and members to do more to prepare for the 2029 deadline for the RTO to comply with Order 2222.
For the first year of the survey’s history, utilities reported electric vehicles as DERs, Pope said, with slightly more than 1 GW hailing mostly from Michigan’s Zone 7. Pope said OMS is investigating how utilities quantify the resource capability of EVs and if the ones that showed up in the survey are capable of bidirectional services. Hanser said OMS must examine if the reported EVs are in fact being used as distributed resources and aiding the grid.
Overall, Zone 7 contains the most DERs, at a little more than 4 GW. The zone is home to a few large, behind-the-meter generators that put it beyond other MISO zones. Minnesota, Wisconsin and the Dakotas’ Zone 1 holds the second-most DERs, at nearly 3.4 GW.
OMS gathers data on DER assets both registered and unregistered with MISO. Pope noted that the organization collects information only on DERs connected at the distribution level and therefore doesn’t include all of MISO’s load-modifying resources in its survey.
After seven months of operations under its Market Renewal Program, IESO is doing some housekeeping, implementing “non-substantive” changes that it said will “improve clarity” and “better align the market rules with the correct functioning” of the nodal market.
The changes, approved by the IESO Board of Directors on Oct. 24, are effective Dec. 3.
The Renewed Market, which launched May 1, created a financially binding day-ahead market (DAM) and about 1,000 generation, load and intertie pricing nodes to replace its provincewide price. (See Ontario Nodal Market Nearing ‘Steady State’ After Nearly 4 Months.)
Some of the changes remove transitory provisions that allowed both the Renewed Market rules and the legacy market rules to be in effect concurrently. “They do not reflect changes in design principles and are limited to typographical, cleanup, clarifications or computational corrections,” IESO said.
In addition to general cleanup items, the changes affect sections on settlements, market power mitigation, and market and system operations.
Market Power Mitigation
The changes (MR-00484-R00) reduce the default value for maximum starts per day from 10,000 to one; remove the “unnecessary administrative burden” on market participants to disclose affiliated entities that have limited or no ability to control or influence a market participant; and codify IESO’s obligation to publish potential constrained areas.
Market and System Operations
The changes to Chapter 7 of the market rules (MR-00484-R01):
prohibit generator offer guarantee-eligible resources from increasing offer prices for energy and operating reserves (OR) during the first 30 minutes of a dispatch hour of the real-time market unrestricted window;
require market participants to revise single-cycle mode status to align with the requirements and duration of commitments that span across midnight; and
add a limit for electricity storage resources offering OR in the opposite direction of OR supply during the subsequent dispatch hour in the energy market. The limit was inadvertently omitted.
Settlements
Settlement provisions of the market rules were revised (MR-00484-R02) to:
amend the hourly operating reserve settlement amount by dividing the quantities by 12;
clarify the eligibility for the DAM balancing credit based on day-ahead schedules;
delete the offer/bid substitution for DAM make-whole payments (MWPs), which is not applicable;
modify the language of the DAM MWP ineligibility for called capacity exports with the same language in the real-time MWP provisions;
insert the “dispatchable load” resource type within a provision for the real-time MWP reversal charge;
amend the formula for the hourly uplift settlement amount to add a missing variable; and
amend the formula for the DAM reliability scheduling uplift by inserting brackets to clarify the summation function.
Miscellaneous Cleanup Items
MR-00484-R03 deletes the obligation for IESO to review the capacity prudential requirements at least once every three years.
MR-00484-R04 corrects typographical and grammatical errors, adds cross-references and italicizes defined terms.
MR-00484-R05 removes transitory provisions to reflect the switch from the legacy market to the Renewed Market, including:
“Section A” rules at the beginning of each chapter, which allowed both the renewed market rules and the legacy market rules to be in effect concurrently;
sections A.1 and B.1.1 in each chapter of the market rules (where applicable); and
the defined term “market transition error,” which is no longer required.
It also modified the definitions of the terms “market transition,” “market transition completion” and “Renewed Market rules.”
The PJM Independent Market Monitor found that modeling issues were the largest cause of synchronized reserve underperformance during a July 22 spin event, in which about 80% of assigned reserves responded.
The Monitor has been reaching out to resource owners whose units underperform during reserve deployments, focusing on events longer than 10 minutes. It also has inquired with the owners of overperforming resources, but the small sample size limited the amount that could be shared.
The effort has become more important since PJM instituted a 30% adder on the synchronized and primary reserve requirement in May 2023 to counteract a low response rate.
The 10-minute-32-second event had 2,764 MW of generation and 548 MW of demand response assigned, with a 78.8% response rate. (See “July Operating Metrics,” July Heat Wave Update, PJM OC Briefs: Aug. 7, 2025.)
Joel Romero Luna, a market analyst with the Monitor, said PJM’s modeling of the amount of time needed to bring equipment into service or change output is accounting for a rising share of reserve underperformance. That constituted the largest cause July 22, at 178.8 MW of the 523 MW for which a cause was attributed.
Issues with software and hardware, such as mechanical failures or errors in programs that dispatch units, were the second-highest rationale for underperformance, followed by outdated or inaccurate resource parameters.
Luna told the Operating Committee on Nov. 3 that communication between PJM and resource operators has improved significantly. However, operators sometimes still do not know what is required of them during a spin event.
Personnel error and communications issues accounted for 12% of the shortfall for which a cause could be attributed. PJM has reworked how reserve deployments are sent to resource operators to convey instructions through unit basepoints. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
October Operating Metrics
PJM’s load forecast accuracy improved for a fourth consecutive month, PJM’s Marcus Smith said while presenting the monthly operating metrics. The average hourly forecast error was 1.02%, while the rate for peak hours was 1.30%.
Three days exceeded the RTO’s 3% peak-hour error benchmark due to unpredicted weather conditions. The peak Oct. 4 was 3.05% under forecast due to high temperatures in the east causing increased load. Oct. 7 was over forecast by 3.12% due to storms across the footprint pushing temperatures down, and Oct. 8 was over forecast by 3.59% due to lower temperatures and variations in cloud coverage.
There was one shared reserve event and one geomagnetic disturbance warning, and there were 24 post-contingency local load relief warnings. Two shortage cases were approved Oct. 3 due to low generation during the afternoon ramp; another was issued Oct. 17 at 10:20 a.m. due to a unit tripping offline.
A spin event was declared Oct. 15 at 4:52 p.m.; it lasted 5 minutes and 21 seconds. There was 2,804 MW of generation assigned, of which 57% responded.
Another event Oct. 17 was initiated at 8:13 p.m. and lasted 11 minutes and 7 seconds. There was 1,743 MW of generation assigned, of which 74% responded, and 644 MW of demand response assigned, of which 92% responded.
The Oct. 17 deployment is the second in PJM’s three-event rolling average used to determine whether it will reduce a 30% adder on the synchronized and primary reserve requirement. Paired with an event Sept. 25 with 77% performance, the average is 78%. Performance across three consecutive events must be above 75% for the adder to be reduced by 10%, and a larger reduction is possible if performance is higher. (See PJM OC Briefs: March 6, 2025.)
A third October spin event was declared Oct. 28, but the data had not been processed before the Operating Committee meeting.
Manual 14D Revisions Endorsed
Stakeholders endorsed by acclamation a slate of revisions to Manual 14D: Generation Operational Requirements drafted through the document’s periodic review.
The changes require that generation owners notify PJM of start-up issues that may affect their units during a cold weather advisory and added sections detailing cold weather operating limit data requests and the cold weather advisory drill. They also detail how data about resources is used in PJM’s Gen Model to produce load flow, short circuit and dynamics modeling for planning staff.
Industry stakeholders will have a chance to weigh in on the proposals of NERC’s Modernization of Standards Processes and Procedures Task Force in the coming weeks, task force leaders said at the Nov. 10 meeting of the Member Representatives Committee.
NERC has been seeking comments on the MSPPTF’s draft recommendations since Oct. 21, task force Chair Greg Ford reminded attendees, observing that the comment period actually closed earlier that day. (See NERC Seeks Feedback on Standards Modernization Recommendations.) The ERO’s Board of Trustees created the MSPPTF in February in light of the rapidly evolving risk environment, which has made it increasingly difficult to keep up with new threats to reliability.
While the online comment submissions are closed, Ford said stakeholders can share their views on the recommendations at two upcoming stakeholder forums, to be held Nov. 13 in Salt Lake City and Nov. 19 in Atlanta. These forums were intended to be to be held in person, but because of uncertainties around flight availability arising from the ongoing federal government shutdown, Ford reminded listeners that an online option is available.
“We really encourage everyone to come participate in this,” Ford said. “This is where we, as the task force, can learn a little bit more about what your comments were intended to address, but it’s also more for you to hear from the task force members on where our recommendations were headed. We’ll take all of that input and get ready for our December workshop.”
The MSPPTF’s recommendations apply across the standards development process. They include organizing a biannual period for requesting, reviewing and initiating new standards projects; implementing a subcommittee under the Reliability Issues Steering Committee to drive standards drafting; and revamping the standards balloting process to provide more accountability and encourage stakeholder participation.
The task force will revise its proposals based on feedback submitted online and at the forums, and present its final recommendations to the board at its February 2026 meeting in Savannah, Ga.
Leadership Elections and Plan Update
Ford took over running the MRC meeting briefly while Chair John Haarlow, CEO of Snohomish County Public Utility District, and Vice Chair Matt Fischesser, of ACES Power, excused themselves so members could vote on a proposal to grant them another term in their positions.
Haarlow and Fischesser were the only nominees received during the nomination period, which lasted from Sept. 11 to Oct. 9, and as a result were unanimously confirmed to remain.
Camilo Serna, NERC’s senior vice president for strategy and external engagement, then gave members an overview of the ERO’s progress on its next three-year strategic plan. NERC’s current three-year plan will conclude at the end of 2025; the organization had planned to create a new plan to begin in 2026 but concluded earlier this year that long-term planning would be a “fool’s errand” because of the uncertainty introduced since President Donald Trump’s return to office. Instead, 2026 will be treated as a “bridge year” before the new plan begins in 2027.
Serna said NERC is defining the priorities, goals and initiatives to be addressed in the plan and how it will measure progress. The organization will provide a draft of the priorities to the MRC in January so that members can provide feedback ahead of the February board and MRC meetings; this list will be finalized by March.
LITTLE ROCK, Ark. — SPP state regulators have approved several motions related to FERC Order 1920’s mandate for long-term, scenario-based planning to ensure the system can meet future needs and be fairly compensated.
The Regional State Committee endorsed the continued use of SPP’s highway/byway cost allocation for long-term regional projects during its Nov. 3 quarterly meeting. It also approved the Cost Allocation Working Group’s recommendation to allocate long-term projects with public policy benefits to the state they benefit.
Under the grid operator’s highway/byway methodology, one-third of the cost of byway projects — lines rated at 100 to 300 kV — are allocated to the RTO’s full footprint, with customers in the transmission pricing zone in which the project is built being allocated the rest. “Highway” projects, those larger than 300 kV, are allocated RTO-wide.
The RSC offered several amendments to the motions brought forward by a CAWG sub-group, but both failed. Both would have established a $150 million threshold for projects to be cost allocated, provided that a simple majority of affected committee members vote to initiate the process.
However, separate votes to require alternative ex post cost allocation methodology be approved by either a two-thirds or simple majority both failed with deadlocked ballots.
John Krajewski, a consultant for the Nebraska Power Review Board who led the CAWG sub-group, said SPP has never identified a project or issued a notification to construct (NTC) out of a 20-year study.
“So, in some respects, this was an academic exercise,” he said, “but I also think it was important because we’re required to do it under Order 1920, and it’s possible in the future this may be an issue.”
Order 1920 requires transmission providers to plan for at least 20 years, create at least three different long-term scenarios to identify future needs and evaluate potential solutions for cost-effectiveness. The order also incorporates a landowner bill of rights, tribal impact reports and engagement plans with environmental justice communities. The compliance filing is due in June.
Nickell Recaps ‘Transformational’ Year
SPP CEO Lanny Nickell thanked the RSC for the “key role” it played in helping the grid operator move initiatives related to resource adequacy and cost allocation that made 2025 a “transformational” year.
Nickell name-checked the one-time expedited resource adequacy study (ERAS) to fast-track qualified projects and a provisional load process, both approved recently by FERC. He also mentioned the Consolidated Planning Process that would combine transmission planning and generator interconnection studies; it was filed with FERC on Nov. 3.
“That, in and of itself, is going to be revolutionary,” he said of the CPP.
Nickell said SPP received 36 submissions as part of the ERAS process, totaling 13.2 GW of capacity. About 73% of that is gas generation, with solar and batteries accounting for the rest. Generator interconnection agreements will be made during the first quarter of 2026, he said.
“That’s the kind of generation we’re going to need to help us with our accreditation and to help load-serving entities meet their requirements,” he said.
The RTO expansion into the Western Interconnection remains on track, Nickell said, with a Dec. 2 go/no go date fast approaching to determine whether to open the transmission congestion rights market in the West on Jan. 1, 2026. The next key decision comes Feb. 2, he said, when SPP will decide whether or not to stick with the April 1 go-live date.
The grid operator’s other Western market, Markets+, has 41 entities that have committed to fund the development of the market’s systems development and hardware. SPP is targeting a go-live date in late 2027.
“We’re in a time of change, and I think it’s just important to realize and to show and to demonstrate what can be done when you put your heart to it and put your mind to it,” Nickell said.
JTIQ Funds Remain in Limbo
General Counsel Paul Suskie told the committee that SPP has yet to receive “official word” about the status of the U.S. Department of Energy’s $464 million grant for the grid operator’s Joint Targeted Interconnection Queue initiative with MISO.
“Fingers are crossed that the funds will still be there,” Suskie said. “I’m personally an optimistic person. I’m optimistic the current administration will see the value that JTIQ will have for the region to get new generation online.”
The DOE loan under its Grid Resilience and Innovation Partnerships (GRIP) program would account for more than 27% of the $1.7 billion portfolio, comprising five 345-kV projects along SPP’s northern seam with MISO. Each grid operator is responsible for two projects in its footprint, and they share the fifth.
The funds were awarded in 2023 to the Minnesota Department of Commerce, the lead applicant in the JTIQ initiative that also involves the Great Plains Institute and the two RTOs. However, the department in early October included the $464 million grant on a list of projects that it intended to terminate. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)
Suskie said conversations continue between DOE and parties to the initiative. NTCs have been awarded to Omaha Public Power District and Evergy for the JITQ projects, he said, giving them the obligation to move forward with their portions of the projects and making them eligible for cost recovery.
FERC has approved the RTOs’ request to allocate the portfolio’s costs 100% to interconnecting generation assessed on a per-megawatt basis. In doing so, it cited the GRIP funding as one of the “unique set of facts and circumstances of the proposed JTIQ framework.” (See FERC Upholds MISO and SPP’s JTIQ Cost Allocation over Criticism.)
RSC Selects New Leadership
The RSC approved the Nominating Committee’s slate of officers for the 2026 term, with Nebraska’s Chuck Hutchinson succeeding New Mexico’s Patrick O’Connell as president.
Oklahoma’s Kim David will serve as the RSC’s vice president, while Arkansas’ Justin Tate and Missouri’s Kayla Hahn will take the secretary and treasurer positions, respectively.
O’Connell said it was an honor to have led the committee and its differing points of view.
“We work together to try to get to consensus and focus on the region first,” he said. “That’s not always true in daily life in general, especially these days. This isn’t just professionally a great experience; it’s also kind of a respite from the real world sometimes. I really, on a personal level, really appreciate how the RSC works together, and then I appreciate that SPP allows us to work together in that way.
“So, thank you all for that,” O’Connell said. “Dry your eyes, OK?”
The RSC’s roster grew to 13 with the addition of Montana’s Randy Pinocci. Observing from the audience were Wyoming Public Service Commission Chair Mike Robinson, another potential new member, and New Mexico’s Greg Nibert, who will replace O’Connell on the RSC in 2026.
VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed by acclamation revisions to Manual 18 to define how distributed energy resources will participate in the 2028/29 capacity auction in accordance with PJM’s Order 2222 compliance filing.
The Independent Market Monitor had proposed revising the language to address a possible issue where resources could bypass market power mitigation by offering into an auction as an aggregation of demand response resources, which are not subject to market power mitigation rules, but then include generation during the delivery year by classifying the resource as heterogeneous.
The recommended language would have sorted DERs into either homogenous distributed generation, homogeneous demand response or heterogeneous resources. If a resource failed to abide by its classification in the delivery year it would fail to meet its capacity commitment. It was not included as an amendment to PJM’s language.
Deputy Monitor Catherine Tyler said a resource with a DER plan should be required to supply the same type of aggregation that it offered into a Base Residual Auction. An aggregation composed of a combination of generation and DR that changed the concentration of one or the other would not be affected by the proposal, she said.
Questioned how PJM would handle such an issue today, PJM’s Pete Langbein said the information collected about market participants would make it clear how a resource is being offered into the market. If there appears to be an effort to exercise market power, PJM would reach out to the participant and potentially refer them to the Monitor or FERC’s Office of Enforcement. He said it likely would be rare for a DER to solely be composed of DR, but if such a resource was offered into an auction and then installed a significant amount of generation, that would raise red flags to PJM staff.
Aaron Breidenbaugh, senior director of regulatory affairs at CPower Energy Management, said it can be difficult to anticipate the future three years in advance. A DR participant might decide to install storage or solar and then be unable to do so, which could create compliance risks for customers interested in aggregation. Adding onerous limitations would discourage participants and possibly punish participants who had no adverse impact on market power.
“It’s a harsh solution in search of a potential problem,” he said.
Monitor Joe Bowring responded that if an entity believes they may participate in the capacity auction as a more advanced resource, they should offer as such.
“It is ineffective to substitute red flags and potential referrals for good market rules. Good market rules are not punishment unless participants attempt to exercise market power,” Bowring said.
The Manual 18 revisions also reflect changes to how DR is offered into the market, removing the availability window to model DR as being dispatchable in all hours and changing the calculation of participants’ winter peak load to be based on the 9 a.m. coincident peak, rather than each DR site’s individual peak. (See PJM Stakeholders Endorse More Detailed Demand Response Modeling.)
PJM Update on Regulation Market Redesign
PJM’s Michael Olaleye presented an update on the implementation of PJM’s redesign of the regulation market, which went live Oct. 1. The changes shifted the market from two bidirectional signals to one, shortened clearing and commitment to 30 minutes, and established the tracking ramp limited desired parameter. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.)
Since the go-live date, there have been more days with high clearing prices, with Oct. 3 seeing two intervals at $33,897/MWh and $29,636/MWh. There were 11 intervals where the clearing price exceeded $5,000/MWh. Despite performance scoring being tightened to consider only the precision of a resource’s response — accuracy and delay were eliminated as criteria — Olaleye said average scores have remained largely the same.
A handful of market participants said the lost opportunity costs seen during October were shocking and questioned whether this is likely to be the norm.
Rebecca Stadelmeyer, Gabel Associates vice president of wholesale power and market services, said it was not expected that clearing prices would be in the thousands and that participants are working to figure out how to price load deals for auctions in deregulated states and ensure customers are protected. She suggested PJM hold education sessions on the results of the market changes, adding that past discussions relied on theory about how the redesign might play out.
NYISO presented the results of Phase 1 of the 2024 Cluster Study process at a special Operating Committee meeting Nov. 4.
The vast majority of the projects in the study are energy storage systems throughout New York. Of the 202 projects in the study, only three were found to be physically infeasible and barred from transitioning to Phase 2 of the cluster study process.
Three projects were examined for the 2025 Expedited Deliverability Study. Only one project, Empire Generating Units 1 and 2, was found to be able to satisfy the NYISO Deliverability Interconnection Standard at its requested capacity resource interconnection service level without system upgrades.
The committee unanimously approved both studies, with one abstention.
ICAP Working Group
The Installed Capacity Working Group received a presentation on the impact on consumers from NYISO’s planned implementation of FERC Order 2222.
NYISO found that reliability would improve from more participation of suppliers in the operating reserves program and that ancillary services prices for 30-minute reserves would increase slightly. No measurable impact was found on the capacity market. The order was also found to increase the price signals of new technologies.
The ISO also presented an update on the Improved Duct Firing Model project. It has identified elements of the model’s design that are incompatible with its current software. The ISO is exploring options, including possible tariff revisions, to implement the FERC-approved model design.
FERCrejected a complaint that the Kentucky Public Service Commission and attorney general filed against American Electric Power over a cost-allocation dispute involving the AEP East Operating Cos.’ transmission agreement (EL25-67).
AEP East provides transmission service to its utilities in PJM and some transmission-only affiliates in the region in an arrangement that started in 1984, predating the utility’s membership in the RTO, which began in 2004. The allocation of transmission costs for lines of 69 kV and above is shared among its utilities in Kentucky, Indiana, Michigan, Ohio, Virginia and West Virginia under a deal approved by FERC in 2010.
The deal covers all PJM projects, even “supplemental” transmission that transmission owners use to plan for their own, local needs. Under its Attachment M-3, PJM allocates the cost of supplemental projects only to the utilities that build them, but the 2010 Transmission Agreement allocates them across AEP’s utilities in the region.
Kentucky complained that setup is not fair because its residents do not benefit from supplemental transmission investments made in other states.
“Since 2019, AEP East has added $3.4 billion in AEP East Attachment M-3 Projects to rate base, of which more than $75 million has been allocated to Kentucky electricity consumers,” the order said. “Complainants aver that few, if any, of those AEP East Attachment M-3 Projects have any relationship to serving Kentucky Power retail or wholesale customers.”
The transmission agreement has been around since 1984 and in addition to joining the RTO, AEP stopped centrally planning its generation, the latter of which was a key part of FERC’s reasoning for approving the arrangement in the first place.
AEP argued that Kentucky consumers still use all of the AEP East transmission system and the benefits they get are roughly commensurate with the costs they paid. The utility holding company approaches local planning as if the AEP East utilities were a fully integrated system.
“AEP East states that this means making transmission investments at the local level with the purpose and effect of benefiting the entire AEP East transmission system, as reflected in AEP East’s transmission planning guidelines, and asserts that the AEP East transmission system was developed to be, and remains, a system within a system,” the order said.
FERC found that the complaint failed to prove the 2010 Transmission Agreement’s rules for allocating supplemental projects were unjust and unreasonable. Commission rules require that consumers pay for transmission that benefits them and allocations are done in way “at least roughly commensurate with benefits.”
Cost allocations do not have to be done with “exacting provision,” but FERC needs a plausible reason for why they are roughly commensurate with assigned costs. The commission previously explained it has a strong policy of requiring rolled-in costs when any degree of integration has been shown.
“Complainants point to a selection of 26 AEP East Attachment M-3 Projects that they argue do not provide benefits to Kentucky customers that are commensurate with the approximately $15 million per year in costs allocated to Kentucky customers for those projects,” FERC said. “As discussed above, providing a selection of projects as evidence that a cost-allocation framework is no longer just and reasonable is not sufficient to overturn a cost-allocation framework approved by the commission.”
It still makes sense to allocate supplemental projects across all of AEP’s operating companies in PJM because while different utilities might have created the need for the upgrades, to the extent another firm benefits from them — it can be said to have “caused” part of the costs.
“Complainants focus on which entities drive the initial need for a transmission project, but that is not the end of the cost-causation analysis — rather, the cost-causation principle requires that the costs for a transmission project be allocated to those who benefit from the project,” FERC said.
“As discussed above, the commission has rejected challenges to cost allocations for specific transmission facilities where those facilities formed part of the integrated transmission system. Kentucky Power’s system is part of AEP East’s integrated transmission network. Thus, it is reasonable to conclude that Kentucky Power’s customers benefit from the AEP East Attachment M-3 Projects that become a part of that transmission network.”
Duke Energy reported third-quarter earnings of $1.4 billion ($1.81/share), up from a year earlier on higher retail sales volume and new rates.
“We approach 2026 with momentum as our company converts large load economic development prospects into tangible projects with signed electric service agreements, and we are already turning dirt on projects to meet this load and grow,” CEO Harry Sideris said on an earnings call Nov. 7. “We’re carrying out an ambitious generation bill that will add more than 13 GW of capacity to our system in the next five years.”
Duke expects its new five-year capital plan for 2026 to 2030 to be between $95 billion and $105 billion, up from the $87 billion that was planned for 2025 to 2029. The spending will help Duke modernize its system and bring new large load customers like data centers online, Sideris said.
“The step up is primarily related to investments in new generation that will drive earnings-based growth of more than 8.5% through 2030,” Sideris said.
While investments are accelerating, Sideris said Duke is keeping affordability in mind for its customers, both large industrials competing in global markets and households trying to manage their budgets.
“We continue to leverage AI and pursue a technology-enabled industry leading cost structure as we invest in our system,” Sideris said. “Other tools we are utilizing to keep rates as low as possible include the combination of the Duke Energy Carolinas and Duke Energy Progress utilities, which, if approved, would save retail customers more than $1 billion through 2038.”
Other activities on affordability include storm cost securitization, which Sideris said would cut the impact to bills by 18% compared to traditional mechanisms, and new tariffs and contract provisions for large load customers looking to take service from its utilities, he added.
“These are just a few of the many solutions we use to ensure our 10 million customers receive the service they count on at a fair price,” Sideris said. “We recognize that our work to provide affordable energy for customers is never done, but we are proud that average rate changes have paced below the rate of inflation over the last decade, and that our rates are well below the national average.”
Duke is building 8.5 GW of new dispatchable generation across its footprint over the next five years, which includes 1 GW of uprates. The rest is new natural gas plants.
The company is considering new nuclear plants, both small modular reactors and, after a request from the North Carolina Utilities Commission, traditional nuclear.
“We feel nuclear is a very important part of the future,” Sideris said. “With that said, there’s a lot of things that we have to determine and figure out before we move forward. We’re encouraged to see the government and some of the partnerships with Westinghouse that were recently announced leaning into this and addressing supply chain concerns, which is one of the items that we have on our list.
“We still need to figure out what we’re going to do with cost overrun protection and how we’re going to protect our investors and our customers from overruns on those projects, as well as how we’re going to protect the balance sheet if we move forward with nuclear, so we’re working to resolve those working with government officials as well as some of the tech customers.”
