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December 17, 2025

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FERC Approves Cost Allocation for Eddystone Emergency Order

FERC on Aug. 15 approved PJM’s proposal for allocating the costs for Constellation Energy to continue operating its Eddystone Generating Station near Philadelphia under an emergency order by the U.S. Department of Energy (ER25-2653).  

The cost would be spread across all PJM load, with charges determined by multiplying load-serving entities’ share of the RTO monthly unforced capacity obligation by the monthly credit paid to Constellation. The costs to be included in that credit are subject to review by the Independent Market Monitor. The actual costs will be determined through the deactivation avoidable cost credit (DACC), which was designed for resources whose deactivation is being voluntarily delayed while transmission upgrades are built to allow the resource to go offline without reliability issues. (See PJM Board Selects Cost Allocation for Eddystone.) 

The revisions to the Reliability Assurance Agreement (RAA) are only applicable to the Federal Power Act Section 202(c) order keeping Eddystone online from June 1 to Aug. 28. Any DOE orders pertaining to other resources or to further keep the plant online would require a separate cost allocation filing. 

Several public interest organizations protested allocating the Eddystone costs to all PJM load, arguing that the RTO’s capacity market procured sufficient capacity to cover the 90 days the emergency order is in effect. They wrote that the order itself stated that there is a shortage of capacity in pockets of PJM, quoting its finding that “an emergency exists in portions of the electricity grid operated by [PJM] due to a shortage of facilities for the generation of electric energy, resource adequacy concerns and other causes.” Without further clarification from DOE, they argued, any cost allocation would be arbitrary. 

The protest was signed onto by the Environmental Law and Policy Center, Natural Resources Defense Council, Sustainable FERC Project, Sierra Club, Public Citizen, Citizens Utility Board of Illinois and Environmental Defense Fund. They wrote that PJM continuing to export while operating Eddystone during the heat wave in late June shows that the plant is not needed to maintain reliability and the parties benefiting from its continued operation may not be PJM load. 

“In sum, PJM’s proposal asks ratepayers across PJM to pay for something — resource adequacy — they have already paid for once. PJM ratepayers have no need for, and will not materially benefit from, additional generating capacity. PJM’s dispatch of Eddystone during a recent summer heat wave only raises more questions about the beneficiaries of the unit’s retention,” the organizations wrote. 

PJM defended its RTO-wide cost allocation by stating that Eddystone is in the PECO zone, which saw no transmission constraints binding in the 2025/26 capacity auction, and arguing that Eddystone’s output is therefore considered deliverable across the RTO. Both Constellation and PJM said Eddystone’s operation during the heat wave corresponded to a maximum generation and load management alert, which is a NERC Energy Emergency Alert level 1 event. 

The organizations also focused on the notion that the agreement between Constellation and PJM to use the DACC to determine recoverable costs does not fall under FERC oversight, arguing the costs associated with Eddystone’s operation should be considered wholesale rates. They noted that PJM’s interpretation of which parties are affected by the emergency order and compensation agreement leaves out LSEs and consumers who may be allocated the resulting costs. 

“In PJM’s view, a Section 202(c) order constitutes a blank check to establish charges that may be passed on to other entities and customers with no opportunity for regulatory review. It ignores the fundamental purpose of the Federal Power Act: to provide a check on private utilities,” they wrote. 

The organizations also took issue with an operating memo in which PJM and Constellation agreed to allowing Eddystone to be dispatched for system restoration and for any costs to provide black start service to be recovered through the proposed structure. They argue that would saddle all PJM customers with the cost to provide a localized service, which itself already has a FERC-approved cost allocation. 

The PJM Industrial Customer Coalition submitted comments supporting the cost allocation proposal but argued that the RTO should be required to file the DACC compensation for FERC approval. 

PJM argued that Section 202(c) does not require commission involvement in determining compensation unless the parties involved cannot agree on a methodology. It pointed to San Diego Gas & Electric, in which DOE used Section 202(c) to order CAISO to purchase energy from the spot market; when CAISO sought refunds for the transactions, the commission found that it did not have oversight, as the parties to the sale had agreed to the price. 

FERC found that the cost allocation appropriately matches the scope of the emergency identified by DOE. The commission also determined that the emergency order does not require PJM to demonstrate that ratepayers will benefit from Eddystone’s operation and said that the compensation methodology itself is out of scope. 

“We agree with PJM that the proposed cost allocation recognizes that the emergency order is based on the overall resource adequacy need in the PJM footprint,” the commission wrote. “The emergency order describes an ‘emergency situation,’ referring to PJM’s own public statements and regulatory filings, which reflect a ‘growing resource adequacy concern’ for the entire PJM region. 

“The emergency order also states that the retirement of the Eddystone units would ‘further decrease available dispatchable generation within PJM’s service territory.’ These statements support a finding that the retention of the Eddystone units benefits the PJM region in general.” 

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NYISO OC Approves SIS for Micron Fab Interconnection

ALBANY — The NYISO Operating Committee on Aug. 14 approved the system impact study for the second of Micron Technology’s semiconductor chip manufacturing centers slated to begin construction later in 2025 in the town of Clay, N.Y.

Micron’s facilities, also known as fabricators (or “fabs”), are a major contributor to the forecasted load growth in New York state, according to NYISO. This facility, “Fab 2,” will draw 576 MW from the grid. When combined with another fabricator at the same site, the total load will be 1,056 MW. Two other fabricators are also planned at the site over the next 20 years.

Clay is a mostly residential suburb of Syracuse with a population of roughly 60,000, according to census data. Micron’s facility will be the largest electric customer in the town by far. When completed, the chip factory will be the largest manufacturing facility in Onondaga County.

The SIS found that the Micron facility will require upgrades to the local grid. Overloads would occur on several local 245-kV lines and substations, so a new substation will be needed. The study also found voltage transfer degradation, which would require upgrades to nearby interfaces.

National Grid estimated that $139.7 million in network upgrades are required, and the new substation will cost $122.2 million. Other upgrades to nearby transmission interfaces would total about $17 million.

The OC also approved eight SIS scopes, all for data centers spread out across the state. If completed, these data centers would collectively draw over 2,100 MW from the grid.

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Kairos Power, TVA Announce Nuclear PPA

The list of firsts for advanced nuclear power grew a little longer Aug. 18 with a power purchase agreement between Kairos Power and the Tennessee Valley Authority. 

The electricity — or more exactly, its clean energy attributes — would be assigned to Google data centers.  

The terms — only 50 MW, not until 2030, from a technology still being developed — are not by themselves a huge splash in a sector that is projecting a need for dozens of gigawatts of capacity in the next five years. 

But it is the first PPA signed by a U.S. utility for the output from an advanced GEN IV reactor, and it is the latest of many indications of the strong interest the tech sector has in next-generation nuclear power, with its promise of emissions-free baseload power and its potential for co-location. 

The PPA between Kairos and TVA would deliver up to 50 MW from Kairos’ planned Hermes 2 Plant to the TVA grid, which powers Google data centers in Tennessee and Alabama. 

It is the first step under Google’s October 2024 agreement with Kairos on a partnership to develop a 500-MW fleet of advanced nuclear reactors by 2035. (See Google, Kairos Sign 500-MW Nuclear PPA.) Kairos will boost Hermes 2’s output from 28 MW to 50 MW to reach the PPA’s terms. 

Kairos is designing a high-temperature small modular reactor fueled with pebble-form TRISO and cooled with low-pressure fluoride salt. 

Hermes 1 is a demonstration reactor under construction in Oak Ridge, Tenn., with an anticipated 2027 startup date. It is intended to produce only heat, not electricity. Lessons learned from Hermes 1 will shape the Hermes 2 demonstration reactor, to be built nearby. (See Kairos Power Cleared to Build Demonstration SMRs.) 

There are two more advanced-nuclear firsts: Hermes 1 was the first GEN IV reactor approved by the Nuclear Regulatory Commission and the first non-light water reactor permitted in the United States in more than half a century. 

Also in Oak Ridge, TVA in May became the first U.S. utility to request a construction permit for a small modular reactor — a GE Hitachi BWRX-300. (See TVA First U.S. Utility to Request SMR Construction Permit.)  

There are many other recent firsts in SMR and advanced nuclear development, but not the most important first: None in this part of the world has entered commercial operation. 

Ontario in May authorized construction for what could be the first commercial SMR in North America. (See Ontario Greenlights OPG to Build Small Modular Reactor.) But the target date for connection to the grid is not until late 2030. 

There is intense interest and effort focused on the development of SMRs, with their promise of faster, less expensive construction. The Nuclear Energy Agency is tracking more than six dozen designs at some stage of development; more than two dozen of the efforts are headquartered in the U.S. 

How many of those efforts obtain sufficient capital and overcome technical hurdles to reach commercial viability remains to be seen. 

The Trump administration is trying to expedite the process, but the 11 projects recently chosen for a fast-track pilot program will receive no financial assistance — only help cutting through regulatory red tape. (See Advanced Nuclear Fast-track Effort Gets First 11 Projects.) 

Nonetheless, advanced nuclear developers often speak with present-tense confidence about their business models and technologies. 

“We build mass-manufactured nuclear plants that will power anything from a data center to a city,” declares Aalo. In fact, Aalo’s liquid-metal reactor design is only in the non-nuclear prototype stage, and the company was a 10-person operation in a coworking space until recently. 

Some of the other companies in the SMR race are not as far along as Aalo. 

Others are steadily moving closer to splitting their first atoms, aided in some cases by the technical and financial resources of the U.S. government.  

In 2021, the U.S. Department of Energy Office of Nuclear Energy put Kairos’ Hermes project on its list of “5 Advanced Reactor Designs to Watch in 2030.” DOE already had begun assisting Hermes financially during the first Trump administration; in 2024 it committed up to $303 million in grants to the effort. 

The cost of developing a first-of-a-kind SMR and bringing a working copy online is considerable — $5.6 billion, in the case of the first Ontario reactor, plus a projected $9.6 billion for the three follow-up SMRs planned on the same site. 

Google, Kairos and TVA said the PPA announced Aug. 18 would help ease some of that first-mover cost and drive down the price tag for future reactors. 

“Google stepping in and helping shoulder the burden of the cost and risk for first-of-a-kind nuclear projects not only helps Google get to these solutions, but it keeps us from having to burden our customers with development of that technology,” said Don Moul, CEO of TVA. 

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FERC Partly Grants Complaint on PJM Opportunity Cost Adders

FERC partly granted a complaint from LS Power challenging the PJM calculation of opportunity cost adders (OCA), requiring operating agreement (OA) revisions to more thoroughly document the inputs and algorithms behind the OCA. 

The adder is a component of the cost-based offers that resources submit in the energy market and aims to capture the revenues that may be missed out on if a resource with limited run hours is dispatched when prices are low (EL24-91). The commission wrote that market participants do not have adequate information to determine whether their OCAs are accurate and account for all factors that may limit when a resource can be operated. 

The order requires that market sellers have access to unit-specific inputs, assumptions and results — including intermediate results; a public posting describing the models and algorithms used in the calculator and hypothetical examples showing how they function; and that the Independent Market Monitor and PJM meet with market sellers on request to discuss assumptions built into the calculator and its results. A compliance filing is required within 45 days of the Aug. 14 order. 

“We find that the PJM operating agreement is unjust and unreasonable because it fails to provide market participants with a sufficient level of detail regarding the calculation of OCAs,” the commission wrote. “Inaccurate OCAs that are too low (i.e., do not fully reflect the market participant’s opportunity costs) could cause resources to prematurely use up their limited run hours when energy prices are lower and render them unable to operate in subsequent periods when prices are higher and they are most needed to provide energy and support the bulk electric system’s reliability.  As such, accurate OCAs are essential to help ensure the efficient use of energy-limited resources in PJM, support accurate price formation, and increase market participants’ confidence in and understanding of how market power mitigation provisions are being implemented.” 

The complaint, which was filed in March 2024, argued that the Monitor has not provided enough information on its OCA calculator and market participants are not able to replicate its results. In some cases, LS Power said it has identified issues that have led the Monitor to make changes in how it determines the OCA. Overall, however, it argues the Monitor has not engaged in adequate communication with market participants and has been unwilling to make changes when requested. The complaint also argued that PJM’s decision to eliminate its OCA calculator in June 2020 and instead rely on the Monitor’s calculator should have been brought to the commission as a change to the OA. 

LS Power wrote that only one pollutant was being modeled for its Chambersburg and Rockford generators, causing their adders to be significantly diminished and resulting in the units being prevented from operating during high pricing periods due to emissions limits on their air permits. It estimated the Rockford adder should have been 25 times higher than what the Monitor calculated. After reporting the issue to the Monitor, the company said it was referred to the Manual 15 language detailing the OCA calculation. 

The Monitor responded to the complaint stating that it’s the responsibility of market sellers to submit information about the pollutants that can limit a resource’s run hours and said it met with the company to discuss the adder several times in April, May and June 2022. After additional pollutant data was provided on July 26, 2022, the Monitor updated its modeling of LS Power’s resources. 

LS Power also argued the Monitor was calculating different OCAs for the six units at its Aurora Generating Station, despite each unit being identical. The complaint argued the Monitor has not transparently addressed the cause of the difference. 

While investigating volatility in the adder calculated for a different resource in June 2022, the Monitor said it identified an error in the calculator, where a flaw in the calculation of shadow prices reduced the output that resource was modeled as produced, causing its emissions to vary. The issue was resolved on June 23, 2022, and the Monitor stated there was minimal impact on LS Power’s units. 

In a separate issue, the Monitor said there was an error causing variable operating and maintenance costs (VOM) to be double counted for the Chambersburg generator. This was corrected the same day LS Power raised the issue. The primary issue leading Chambersburg to hit its emissions limit in the period discussed in the complaint was PJM dispatchers using the resource to resolve local constraints. 

The Monitor defended the transparency of the calculator, stating it is adequately detailed in Manual 15 and the only inputs that are not available to resource owners are locational marginal price (LMP) and gas futures, which are proprietary and confidential data provided by a vendor. It stated it has held multiple educational workshops for PJM stakeholders, with materials available online, and will continue to hold more sessions. It also argued PJM can empower third parties, such as the Monitor, to aid in the calculation of market parameters so long as the RTO is the entity implementing them, which the Monitor said is the case here. 

PJM also voiced transparency concerns in its response, stating it has requested access to the software behind the adder, which the Monitor has declined to provide. It supported the Monitor’s role in the OCA calculation, however, stating that PJM staff are the final arbiter of the adder to be included in cost-based offers. 

The RTO engages in annual reviews of the OCA to ensure the process outlined in the OA and Manual 15 is being followed, in addition to periodic review of adders calculated for individual resources to watch for trends and abnormal values. The RTO wrote it has identified instances where it sought further review and was able to request data and meet with the Monitor. 

Responding to LS Power’s request that FERC allow market sellers to propose their own adders, PJM said it already has a pathway for alternatives to be submitted so long as it can be demonstrated the default calculation is not representative of a unit’s opportunity costs. PJM stated it has approved alternative OCAs in the past. 

The commission wrote that more transparency could help identify and resolve the sort of errors the Monitor outlined. 

“The IMM acknowledges that some errors occurred in the calculation of some OCAs. While some of these errors may have been limited in scope, such errors nonetheless harm the efficient functioning of markets and undermine market participants’ confidence that the market rules are being implemented appropriately. There is also the possibility that there are additional issues with OCA calculations that LS Power and other market participants have not been able to identify due to the opaqueness of current OCA calculation process,” the order states. 

The commission declined to require that PJM calculate the OCA, finding that it has remained in control of the implementation of the adders, and declined to require that PJM allow alternative OCAs to be provided by market sellers who cannot demonstrate that the default methodology does not account for some limit. The commission said the issue of PJM having access to the calculator is out of the complaint’s scope but encouraged PJM and the Monitor to collaborate on allowing access. 

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FERC Rules Costs of Mich. Coal Plant Extension Can be Split Among 11 States

FERC said MISO should spread the costs of keeping a Michigan coal plant running past its retirement date over the RTO’s entire Midwest region.

The commission issued an Aug. 15 decision on the cost allocation of the J.H. Campbell coal-fired power plant, which is slated to run through Aug. 21 on an order from the U.S. Department of Energy. The plant originally was scheduled to wind down operations May 31. (See DOE Orders Michigan Coal Plant to Reverse Retirement.)

FERC said it’s appropriate that MISO split the costs of running the plant on a load ratio share among local resource Zones 1-7, which includes Wisconsin, Minnesota, the Dakotas, a section of Montana, Iowa, parts of Missouri, downstate Illinois, Indiana and a slice of Kentucky in addition to Michigan (EL25-90).

FERC said the allocation design is in line with its cost causation principle, reasoning that the cost split would “allocate costs in accordance with the scope of the emergency as described by the DOE order.”

“We acknowledge that parties have presented different interpretations of how the DOE order defined the geographic scope of the emergency.  However, we find that the most reasonable reading of the DOE order’s intended scope is that the emergency necessitating the continued operation of the Campbell Plant is in the MISO North and MISO Central regions, i.e., local resource Zones 1-7,” FERC said.

Plant owner Consumers Energy asked the commission for a Zone 1-7 rate recovery, claiming beneficiaries could be found among all Midwestern zones. However, Great River Energy and various public interest organizations argued that load-serving entities in Zones 1-7 already met their resource adequacy requirements, as evidenced by MISO’s 2025/26 Planning Resource Auction and would not benefit from bonus capacity from the Campbell plant. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)

Great River Energy argued the DOE mandate focused on the local impacts of generation retirements, which should mean that costs of the plant fall to Michigan’s Zone 7 alone. It said, “allocating costs of complying with the DOE order beyond Consumers’ own load is not supported by the cost causation principle.”

Michigan Attorney General Dana Nessel contended that the DOE order applied to the whole footprint and FERC should order a cost allocation that includes MISO South.

But FERC said it relied on the DOE citing a MISO presentation of the 2025/26 PRA results, where MISO said that “new capacity additions were insufficient to offset the negative impacts of decreased accreditation, suspension/retirements and external resources” in MISO Midwest. The commission said it seemed resource adequacy concerns in the subregion drove the DOE to issue the order.

FERC directed MISO to draft a compliance filing within a month to enact the new allocation. It also told the RTO to define a load ratio share and how it plans to calculate each load-serving entities’ load ratio share.

According to a recent Securities and Exchange Commission filing from Consumers Energy, J.H. Campbell cost $29 million to run from May 23 to June 30. (See DOE Extension of Michigan Coal Plant Cost $29M in 1st Month.)

The commission declined to grant the Organization of MISO States, the Illinois Attorney General and the Illinois Commerce Commission’s request that it instruct MISO to initiate stakeholder discussions on who should foot the bill for the plant’s extension. FERC said further procedure was unnecessary.

FERC also rejected requests to delay its cost allocation decision until rehearing requests on the DOE’s mandate are resolved.

“We find that arguments against adoption of the proposed tariff provision, such as that imposing the costs of keeping the Campbell Plant in operation violates the tariff and the [Federal Power Act] if the DOE order is deemed unlawful are beyond the limited scope of this proceeding and were not referred to the commission by DOE,” FERC wrote.

FERC similarly refused to address the creation of a provision to refund upgrade costs recovered under the cost allocation should the Campbell plant be subject to another stay-open order beyond Aug. 21. It said any such potential procedure was outside the “limited” nature of the allocation docket.

FERC also appeared to cover its bases should the DOE’s order for the coal plant to keep operating not hold up in court.

“While this order approves the cost allocation methodology in the proposed tariff provision, it does not approve recovery of actual costs,” FERC said.

FERC said Consumers Energy needs to petition it in a separate proceeding “at a later date” for approval to recover costs associated with the DOE’s order “before ratepayers can be charged for such costs.”

“Parties may raise issues related to the scope of costs prudently incurred pursuant to the DOE order in that proceeding,” FERC said. It added that parties to the complaint could “take appropriate steps, such as requesting rehearing in this proceeding, to preserve arguments” that FERC should order refunds should the DOE order be modified, or “otherwise revisit its approach to matters that DOE referred to the commission in connection with the DOE order.”

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Arizona Renewable Standard on the Chopping Block

Arizona regulators are moving toward the repeal of the renewable energy standard for utilities, saying the mandate has cost ratepayers billions of dollars since it was adopted in 2006. 

The Arizona Corporation Commission voted 5-0 on Aug. 14 to start a rulemaking process to repeal the Renewable Energy Standard and Tariff (REST). 

REST requires 15% of regulated electric utilities’ retail sales to be from renewable resources by 2025. Utilities have met or exceeded the standard. 

Commissioners called REST an outdated mandate that has driven up customer costs. 

“If renewables are truly the most affordable and reliable option … the generational technology should be able to prevail on its own without the need for mandates that have added millions of dollars in extra costs for ratepayers each year,” Chair Kevin Thompson said. 

Commissioner Rachel Walden said the all-source request for proposals process that utilities are required to follow is the best way to select resources. Renewables will continue to be an option, she said. 

“I want to reiterate that if solar and wind is the cheapest generation, and can be balanced out with the reliable baseload, that it will be selected,” Walden said. “I have not heard or seen evidence that there needs to be a mandate.” 

The commission’s action follows a vote in February 2024 to start laying the groundwork for the repeal. (See Tug-of-war Developing over Ariz. Clean Energy Rules.) 

Commission staff will file a notice of rulemaking, and the commission will hold three public comment sessions in November. 

APS’ Clean Energy Goals

The action comes as one major utility, Arizona Public Service, has backed away from its commitment to 100% clean and carbon-free energy by 2050. 

APS also had an interim target of 65% clean resources and 45% renewable energy by 2030. 

During an Aug. 6 quarterly earnings call, officials with APS parent Pinnacle West Capital said the company has updated its clean energy goals to an “aspirational carbon-neutral approach” by 2050. 

The company also is canceling its interim targets “to better reflect APS’ near-term need to ensure reliability and affordability,” Pinnacle West said in a release. The integrated resource planning process will be used “to help determine the most responsible path forward.” 

The company attributed the change to the need for reliable electricity as the state’s population and economy grow at “unprecedented levels.” 

“Our mission is to reliably serve customers at the lowest cost possible,” Pinnacle West CEO Ted Geisler said in a statement. “To do that, we need to integrate the most reliable and cost-effective resources available to us to meet Arizona’s fast-growing energy needs.” 

At the Aug. 14 commission meeting, several speakers said the REST rules should be retained and modernized rather than repealed. 

Autumn Johnson, executive director of the Arizona Solar Energy Industries Association (AriSEIA), said that just because investor-owned utilities have met the 15% renewable energy requirement of REST doesn’t mean they will continue to do so. 

“Given the load growth projected by the IOUs, the plans to spend approximately $5.3 billion on a new gas pipeline and APS’ recent announcement that they are reneging on all of their clean energy goals, there is absolutely no certainty that the utilities will remain at 15%,” Johnson told the commission. 

In an Aug. 7 announcement, the ACC praised the state’s three largest electric utilities for their commitment to Transwestern Pipeline’s Desert Southwest expansion project. The new pipeline will transport natural gas from the Permian Basin in West Texas to Arizona and New Mexico. 

Steven Zylstra, president and CEO of the Arizona Technology Council, said the REST rules have created a predictable framework for private investment in the state’s clean energy economy. 

“With federal renewable and clean energy tax credits already eliminated, now is the worst possible time to undermine an industry that has delivered so much progress for our state,” Zylstra said in comments filed with the commission opposing the repeal. 

REST Costs Disputed

According to the ACC, renewable resources accounted for about 19% of APS’ energy portfolio in 2024, up from 13% in 2023. For Tucson Electric Power, about 29% of its energy portfolio consisted of renewables in 2024, compared to 27% in 2023. 

The ACC estimates the REST rules have resulted in about $2.3 billion in surcharges to Arizona ratepayers since 2006. REST supporters dispute that figure. 

When evaluating costs and benefits, one must consider the cost of non-renewable resources that would have been built without the REST rules, according to comments filed jointly by AriSEIA, Vote Solar and Solar United Neighbors. 

In addition, renewable resources save ratepayers money because they have no ongoing fuel costs, the groups said. 

They noted that 36 states have standards or goals for clean and renewable energy and 21 states have set target dates for achieving 100% clean energy. 

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PJM MRC/MC Preview: Aug. 20, 2025

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Aug. 20. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will cover the discussions and votes.

Markets and Reliability Committee

Consent Agenda (9:20-9:25)

The committee will be asked to endorse as part of its consent agenda:

C. proposed changes to Manual 11: Energy & Ancillary Services Market Operations, Manual 12: Balancing Operations, Manual 15: Cost Development Guidelines and Manual 28: Operating Agreement Accounting codifying the first phase of PJM’s regulation market redesign. The market would use a single price signal to dispatch regulation units up and down, replacing a model with separate long-deployment and fast-response products. (See “Regulation Market Redesign Endorsed,” PJM MIC Briefs: Aug. 6, 2025.)

Same-day endorsement will be sought at the MC for the revisions to Manual 15.

Issue Tracking: Regulation Market Design

Endorsements (9:25-10:45)

1. RPM Seller Credit (9:25-9:40)

PJM’s Gwen Kelly will present a proposal to add a creditworthiness review in the granting of seller credit in the Reliability Pricing Model. The committee will be asked to endorse the proposed solution and corresponding tariff revisions at this meeting.

Issue Tracking: Review of RPM Seller Credit Provision for Market Participants

2. Elimination of First Usage (9:40-9:55)

PJM’s Thomas DeVita will present a solution to rework how PJM determines whether a wholesale resource interconnecting to a distribution asset falls under federal or state jurisdiction. The “bright-line” test would consider any points of interconnection below 69 kV to be under state or local jurisdiction, whereas higher-voltage facilities would fall under federal jurisdiction, unless FERC and the transmission owner have classified it as a transmission or distribution asset for cost recovery purposes. (See PJM Proposes Changes to Determination of Jurisdiction over Generation.)

The committee will be asked to endorse the proposed solution and corresponding tariff revisions at this meeting.

Issue Tracking: Eliminating “First Use” for Interconnections to Distribution Facilities in PJM

3. ELCC Accreditation Methodology (9:55-10:45)

A. PJM’s Michele Greening will present the results of a poll conducted by the Effective Load Carrying Capability Senior Task Force on changes to the effective load-carrying capability (ELCC) calculation and how the ratings it produces factor into resource accreditation.

B. PJM’s Pat Bruno will review the RTO’s Package C, which would add winter deliverability tests and winter installed capacity values to the ELCC analysis and apply weighting to historic performance in favor of more recent events. PJM’s proposal will be voted on first as the main motion.

C. Michael Cocco, of Old Dominion Electric Cooperative, will present an alternative proposal, Package F, that would reduce the probability of the ELCC modeling drawing resource performance data from the 2014 polar vortex and December 2022’s Winter Storm Elliott by 33%.

D. Independent Market Monitor Joe Bowring will present another alternative proposal, Package B1, that would shift to unit-specific accreditation, use winter ratings in the ELCC calculation and remove the polar vortex and Elliott performance data on the grounds that PJM has made operational changes that make historic performance unlikely to reoccur. The Monitor will seek an RTO member to move and second the proposal.

The committee will be asked to endorse a proposed solution at this meeting. Same-day MC endorsement may be sought.

Issue Tracking: Capacity Market Enhancements – ELCC Accreditation Methodology

Members Committee

Consent Agenda (2:20-2:25)

The committee will be asked to endorse as part of its consent agenda:

B. proposed tariff and Operating Agreement revisions intended to make balancing operating reserve credit and deviation charges more accurately reflect whether a resource has followed PJM dispatch. The addition of a tracking ramp limited desired (TRLD) metric would compare resource output over time to dispatch instructions to determine how a resource is responding, while changes to the balancing operating reserve credit calculation would aim to simplify the formula.

Issue Tracking: Operating Reserve Clarification for Resources Operating as Requested by PJM

C. proposed Reliability Assurance Agreement revisions to revise the definition of dual-fuel capacity resources to include those that have dedicated fuel sources that are not stored on-site.

Issue Tracking: Dual Fuel Capacity Definitions

Endorsements (2:25-3:25)

1. Election (9:25-9:40)

PJM’s Greening will present a proposal to nominate Constellation Energy’s Juliet Anderson to serve as 2025 Generation Owner sector whip. The committee will be asked to vote on the nomination upon first read.

2. Regulation Market Manual 15 Revisions (2:35-2:45)

PJM’s Ilyana Dropkin will present revisions to Manual 15: Cost Development Guidelines to codify PJM’s regulation market redesign (see above). The committee will be asked to endorse the proposed manual revisions at this meeting.

Issue Tracking: Regulation Market Design

3. ELCC Accreditation Methodology (2:45-3:25)

PJM’s Bruno, ODEC’s Cocco and Monitor Bowring will present each of their proposals to rework the ELCC methodology (see above). The committee will be asked to endorse a proposed solution at this meeting.

Issue Tracking: Capacity Market Enhancements – ELCC Accreditation Methodology

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NEPOOL Nears Vote on 1st Phase of ISO-NE Capacity Auction Reforms

ISO-NE presented some of the final design details and tariff changes for the first phase of its Capacity Auction Reforms (CAR) project at the summer meeting of the NEPOOL Markets Committee on Aug. 12-14 in preparation for a stakeholder vote in October. 

The first phase of CAR is centered around transitioning ISO-NE’s Forward Capacity Market to a prompt design, with auctions held less than one month before the start of each annual capacity commitment period (CCP). It includes significant changes for resource deactivation and wide-ranging conforming changes to prepare for the new auction format. The RTO aims to file the proposal with FERC before the end of the year. 

After completing the first phase of work, ISO-NE plans to ramp up stakeholder discussions on the second phase of the CAR project, which will focus on resource accreditation and dividing CCPs into distinct seasonal periods. 

As stakeholders near a vote on the first CAR filing, the Massachusetts Attorney General’s Office has called for more quantitative analysis of the impact of the changes. 

In a memo published prior to the MC meeting, the AGO asked ISO-NE to provide “whatever qualitative or quantitative information it can on the impact of the [prompt market proposal] as a standalone market design.” 

The office noted that developing the seasonal and accreditation changes “involves significant design, regulatory and implementation risks, which could potentially delay or otherwise derail” the implementation of the second phase of the CAR project and “leave the auction for capacity commitment period 2028/29 to be conducted under the [prompt] design only.” 

ISO-NE commissioned a preliminary impact analysis in late 2023, which projected a prompt and seasonal capacity market to reduce capacity market costs by about 12% compared to the FCM. The study estimated that a prompt-annual design would reduce costs by 10 to 11% relative to the existing design. (See NEPOOL Markets Committee Briefs: Jan. 11, 2024.) 

Responding to the request, the RTO has said it will wait to conduct a more comprehensive impact assessment once it has completed the bulk of the work on both phases of the project. 

ISO-NE spokesperson Matt Kakley noted that the 2023 analysis “showed numerous benefits to consumers and suppliers, as well as market efficiency gains” and said the RTO “has worked closely with stakeholders to provide additional information about the impacts and efficiency gains associated with the move to a prompt auction.” 

Seller-side Market Power

Also at the MC, ISO-NE economist Andrew Copland provided an update on the RTO’s proposal for mitigating seller-side market power. 

Similar to the current mitigation rules in the FCM, ISO-NE would require capacity resources to submit a cost workbook to the Internal Market Monitor if they offer above a price threshold, which the RTO defines as “the average of two prices: (i) the previous capacity clearing price and (ii) the price on the upcoming auction’s [marginal reliability impact] demand curve corresponding with the previous auction’s total cleared” capacity supply obligation (CSO). 

Resources bidding above this threshold that fail both an IMM pivotal-supplier test and a contact test are subject to a binding price determined by the Monitor. 

Copland said ISO-NE does not plan to change the “underlying cost review threshold methodology” for the threshold but will propose to change the name of the threshold from the “dynamic de-list bid threshold” to the “capacity offer price threshold.” 

Andrew Gillespie, director of governmental and regulatory affairs at Calpine, pushed ISO-NE to update its methodology for calculating the cost review threshold. He said the existing method is “somewhat backward-looking as it relates to changing market conditions” and could lead to the threshold being set at an artificially low level in future auctions. 

Gillespie noted that ISO-NE would determine the threshold for its first prompt auction about five years after the most recent Forward Capacity Auction. He pointed to the multiple significant capacity scarcity events that have occurred since this auction and said high-performance penalty costs incurred during them could put significant upward pressure on capacity prices in future auctions. 

Instead of relying on past auction results, Gillespie recommended that ISO-NE base the threshold on the “common value component,” which is calculated by multiplying the expected number of hours with capacity conditions by the expected balancing ratio and the performance payment rate. 

“The common value component is the lowest competitive bid, and hence the threshold should be no lower than that,” Gillespie said. 

He said this methodology would be more forward looking and would avoid issues associated with adapting historical data to the new prompt-seasonal format. 

The proposal was well received by multiple stakeholders at the meeting, while ISO-NE expressed concern about challenges and complications related to relying on expectations for capacity scarcity hours and the balancing ratio. The RTO reiterated that it does not plan to overhaul the threshold methodology as a part of the CAR project but said more discussion on the threshold will be needed during the second phase of the project to prepare for a seasonal auction design. 

Noncommercial Capacity

Under the new capacity market format, ISO-NE would not differentiate between new and existing capacity resources, and all new resources would have to demonstrate they have reached commercial operations to participate in capacity auctions. 

The RTO previously has allowed noncommercial resources to participate in FCAs, which were held over three years prior to each CCP. Under the FCM rules, new resources are subject to critical path schedule (CPS) monitoring, allowing the RTO to track their progress toward reaching commercial operations. 

At the MC meeting in July, ISO-NE said it plans to continue CPS monitoring until mid-2028 for noncommercial resources that received CSOs in past FCAs. (See NEPOOL Markets Committee Briefs: July 8-9, 2025.) 

The RTO changed its proposal at the MC meeting in August and now plans to continue CPS monitoring “until all projects on monitoring are either completed, withdrawn or terminated,” said Matt Brewster, senior manager of capacity requirement and qualification at ISO-NE. 

Brewster said the approach “seeks to accommodate decisions made by participants under the current rules and facilitate the move to commercial-only participation in the prompt market.” 

He noted that, starting with the 2028/29 period, “capacity on CPS monitoring cannot acquire CSO for any additional CCP until it is commercial.” 

Also at the MC, Brewster discussed ISO-NE’s planned approach toward resource repowering and material modifications. He said qualified capacity would generally be based on a resource’s performance from the past five years, and ISO-NE plans to largely maintain existing processes for “reflecting measurable increases or decreases in capability and changes to technology, characteristics or composition.” 

For resources that can demonstrate increased or decreased capacity compared to the historical data prior to each annual auction, ISO-NE will update the lookback period “to exclude data for periods preceding the change,” he noted. 

In cases of modifications to a resource’s technical characteristics, such as a change to its intermittency, ISO-NE would require resources to submit data on the modification “for the next annual or monthly qualification process,” Brewster said. 

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BPA Preparing to Deliver Power Under New Multiyear Contracts

The Bonneville Power Administration will begin to issue long-term contract offers under its Provider of Choice (POC) initiative after finalizing the set of policies and decisions that will guide the 20-year contracts. 

On Aug. 14, BPA released several documents under its POC policy: POC Contract Record of Decision, Contract High Water Mark Implementation (CHWM) Policy and accompanying Record of Decision, New Resource Rate Block Policy and final POC CHWM contract templates. (See BPA Issues Final Long-term Power Contract, Updates Strategic Plan.) 

With the documents finalized, BPA can begin to issue contract offers to customers. The goal is to complete all contract offers by Sept. 30 and for customers to return signed contracts by Dec. 5, allowing the administration to execute them by the end of the year. BPA will focus on implementation and preparation for power deliveries under the new contracts, which are set to begin Oct. 1, 2028, according to a news release. 

“While this multiyear effort will not be complete until signed contracts are in hand, the contracts, policies and records of decision released this summer are a significant culmination of work,” said Kim Thompson, BPA vice president for Northwest Requirements Marketing. “Thanks to the significant time, thought, leadership and attention to detail from power, legal and other supporting staff, BPA will have policies and contracts that serve BPA and its customers for decades to come.” 

Bonneville delivers power to regional public power customers under contracts executed in 2008. The agreements provided approximately 76% of BPA’s power services’ revenue requirement in 2022, according to a concept paper. (See BPA Close to Issuing New Long-term Power Contract.) 

The long-term contracts by statute cannot exceed 20 years, and BPA launched the POC initiative to begin contract discussions with stakeholders before the current agreements expire in 2028, according to the paper. 

BPA also must offer contracts to investor-owned utilities under the Pacific Northwest Electric Power Planning and Conservation Act. However, no IOU has requested a new contract. Instead of drafting new contract language for IOUs, BPA developed the NR Block Policy, outlining how the agency would establish contracts and product offerings if IOUs should request them, according to a news release. 

Another new feature relates to the CHWM. 

CHWM determines how much power a customer can buy at the Priority Firm Tier 1 rate, which represents most of BPA’s power sales. Under the new contracts, BPA will calculate CHWMs once in 2026, and those will be fixed for the duration of the contract to reduce the Tier 1 load service uncertainty for customers. (See BPA Customers to See Increased Power, Transmission Rates.) 

“CHWMs were a significant focus during the policy development and remain a focal point of customers,” Sarah Burczak, policy lead for Provider of Choice, said in a statement. “CHWMs set customer-specific limits for buying power at what is typically BPA’s lowest rate. The CHWM Implementation Policy addresses specific eligibility, calculation, process and adjustment details. The policy establishes clear expectations for how CHWMs will be established and provides assurances for how BPA will conduct ongoing related processes.” 

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Stakeholder Forum: Recent MISO Complaint Undermines Regional Transmission Planning Framework

By Ted Thomas

A new attack on regional transmission planning threatens to unravel a decade of progress toward a more reliable, affordable and interconnected electric grid. 

Ted Thomas

A group of state utility commissioners recently filed a complaint with FERC opposing the cost allocation for a new set of regional transmission projects known as Tranche 2.1 in the MISO region. This 3,631-mile 765-kV backbone portfolio of projects is expected to deliver up to $72 billion in net benefits across the system. 

Their argument? That these projects don’t serve the broader region and should be funded only by the states they physically pass through. It’s an appealing message — no one wants to pay for something they can’t see. But it’s also oversimplified and short-sighted, and it risks undermining the premise of regional planning and cost sharing that keeps the grid reliable and affordable. 

At its core, the complaint misunderstands how regional transmission works. High-voltage transmission lines are not local infrastructure, they are the backbone of the electric grid. They enable power to flow across hundreds of miles, balancing supply and demand in real time and delivering affordable electricity to customers even when local conditions falter. Transmission lines provide shared benefits far beyond state borders. 

This is why MISO — a region with a history of collaboration — created the Multi-Value Project (MVP) framework. When the first round of multi-value transmission projects was approved over a decade ago, they weren’t built just to serve one state or one utility, but to address regional reliability needs, reduce congestion and provide access to low-cost generation across MISO’s 15-state footprint. 

Independent studies later showed those projects will return up to $52.6 billion in benefits over the next 20 to 40 years — benefits that are shared by customers throughout the region and a 20% increase from the original estimate. 

Tranche 2.1 projects follow the same planning logic. Though individual lines may be in specific states, MISO plans them as part of a broader portfolio designed to work together to ease systemwide transmission bottlenecks, enabling cheaper and more reliable electricity to flow across MISO. These projects were approved through a rigorous, transparent regional planning process that evaluated systemwide impacts, not just local needs, and conservatively estimated the benefits of the projects. That’s why MISO’s board agreed these projects should be treated as MVPs and funded accordingly. 

To argue now that these projects should be paid for only by the states in which they’re located is to undermine the premise of regional collaboration. If every state were allowed to pick and choose which projects they want to fund, the grid would be more fragmented and inefficient and less resilient than it already is. Regional transmission planning works only when everyone contributes to — and benefits from — the shared infrastructure we all rely on. 

Moreover, refusing to share costs for regionally beneficial projects will hurt customers in the long run. Without large-scale transmission, we’ll be forced to rely on more expensive local generation, endure greater price volatility and face more frequent reliability challenges as demand grows and extreme weather becomes more common. That’s a cost nobody wants to bear, especially when the alternative is a well-planned, cost-effective solution that has already proved its worth.  

Arkansas is a prime example of how regional planning delivers value. We benefit when low-cost power from elsewhere can flow into Arkansas during times of high demand or generation shortfalls — and vice versa. Regional planning has brought long-term stability to power prices and improved reliability, especially in rural areas that often are more vulnerable to outages and price spikes.  

Despite this, the complaint threatens to erode the regional planning framework, and to do so in the context of a transmission plan that does not even allocate costs to three of the states that filed the complaint, including Arkansas.  

Rather than obstructing new energy infrastructure, we must recognize the urgent need to build for the future and meet demand. FERC should reject this complaint and reaffirm the principles that have made MVPs successful. Tranche 2.1 projects are part of a broader strategy to modernize the grid, reduce costs and ensure a reliable electricity system across the region.  

If we want a grid that works for everyone, we need to keep investing in shared solutions. Transmission isn’t local. Neither are its benefits. Let’s not let short-sighted politics get in the way of smart regional planning. 

Ted Thomas is the founder of Energize Strategies and a former chairman of the Arkansas Public Service Commission.