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December 16, 2025

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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. 

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IRS Guidance on Wind and Solar Credits Not as Bad as Feared

The Trump administration is tightening the rules on qualifying for tax credits on new wind and solar construction, but not as much as some feared it would.

IRS Notice 2025-42 released Aug. 15 indicates the Five Percent Safe Harbor provision for the clean energy production and investment credits will be eliminated for new solar facilities larger than 1.5 MW and new wind facilities that start work after Sept. 2, 2025.

It is being replaced with a protocol to establish that significant physical construction has been started before July 5, 2026; proceeded continuously; and was completed within four calendar years to establish eligibility for the tax credits.

This is not as harsh as it could have been, or as some in the clean energy industry had feared — some companies in the sector saw their stock prices soar later Aug. 15 as the guidance was digested.

As the S&P 500 and Nasdaq closed fractionally lower, NextEra Energy closed 4.4% higher, Enphase Energy 8.1%, First Solar 11.1%, Nextracker 12.2% and Sunrun 32.8%.

Research and strategy firm Jefferies called it a win for utility-scale renewables and a huge win for residential solar, saying the guidance was “significantly better than expected.”

The sector’s trade organization, the American Clean Power Association, was critical of the guidance but struck a more measured tone than it has with some of the many setbacks President Donald Trump and his cabinet agencies have dealt to renewable energy in his second term.

CEO Jason Grumet said: “The Treasury Department’s decision to accelerate the phaseout of clean energy tax credits undermines the integrity of our energy grid and our legislative process. In the One Big Beautiful Bill Act, Congress explicitly chose to provide energy companies with one year to phase out tax credits to keep energy prices low while meeting growing power demand.”

But he continued: “We acknowledge and appreciate the hard work of senators who led the effort to elevate pragmatism over partisanship in the legislative process. Their continued advocacy to protect this legislative agreement was instrumental in avoiding greater impediments to energy deployment.”

On July 4, Trump signed the bill, which contained provisions accelerating the phaseout of the Clean Electricity Production Tax Credit and Investment Tax Credit — 45Y and 48E, respectively.

Some Republicans in Congress wanted the credits eliminated immediately, and Trump was widely reported to have won their support for OBBBA and its slower phaseout by promising a firm hand carrying out OBBBA’s provisions.

Trump followed up on July 7 with an executive order directing Treasury to issue new guidance on 45Y and 48E and directing the Department of the Interior to review and revise all policies deemed preferential to wind and solar facilities within 45 days of OBBBA’s enactment. (See U.S. Clean Energy Sector Faces Cuts and Limitations and Trump Executive Order Targets Renewable Energy Tax Credits.)

Interior already has issued a series of policy changes to comply with the order that most observers would characterize as harsh. (See Dept. of Interior Launches Overhaul of OSW Regs and Feds Pile on More Barriers to Wind and Solar.)

Treasury dropped the next shoe on Aug. 15. More is to come, however, including guidance on the safeguards Trump ordered against foreign entities of concern.

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Duke Energy Says Combining Carolina Utilities Would Save Billions

Duke Energy has asked state and federal regulators to combine its two electric utilities that serve the Carolinas in a move it said would result in billions of dollars of customer savings.

Duke Energy Carolinas and Duke Energy Progress have operated as separate utilities since the 2012 merger of Duke and Progress Energy. The two subsidiaries’ combination is legally classified as a merger, but it is more like reorganizing two corporate divisions into one. If approved, the effective date for the combination would be Jan. 1, 2027.

“Combining our two utilities reduces customer costs, simplifies operations, supports economic growth and promotes regulatory efficiencies, all of which will create value for customers in both states,” Duke Energy Carolinas CEO Kodwo Ghartey-Tagoe said in a statement. “There will be no immediate changes to retail customer rates or services. We look forward to sharing more details with our customers on how rates will evolve over time if the combination is approved by regulators.”

Operating as a single utility in the Carolinas would let Duke meet the growing needs for power there at a lower cost due to more efficient planning and an improved ability to avoid redundant investments. The combination would let Duke build fewer assets to meet the combined systems’ needs, and spreading infrastructure across the larger customer base would moderate impact on rates.

The combined utilities would be able to run fewer and less expensive units, use less fuel and cut down on units cycling on and off, thus saving maintenance costs.

The combination needs to be approved by the North Carolina Utilities Commission, the South Carolina PSC and FERC.

The combination is expected to save about $1 billion between 2027 and 2038, which is the close of the planning horizon for the 2023 Carolinas Resource Plan. Retail rates would start changing as the combined firm goes before North Carolina and South Carolina regulators in 2027 and later.

Duke Energy Carolinas owns 20.8 GW of generation and supplies power to 2.9 million customers across 24,000 square miles in the Carolinas. Duke Energy Progress owns 13.8 GW and supplies power to 1.8 million customers across 28,000 square miles.

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MISO States Split on FERC Complaint to Unwind $22B Long-range Tx Plan

Members of the Organization of MISO States are divided on whether the organization should register comments in a FERC complaint that could fundamentally change the way MISO can plan its long-view transmission.

The rift among the states shows how contentious the late July complaint is.

The public service commissions of North Dakota, Montana, Mississippi, Louisiana and Arkansas have sought reclassification of MISO’s $22 billion, mostly 765-kV second long-range transmission portfolio and have contested the RTO’s business case for the lines through a FERC complaint. The complaint could have FERC halting a regional cost-sharing of the lines across MISO Midwest and could upend MISO’s long-range planning process. (See Five Republican States File FERC Complaint to Undercut $22B MISO Long-range Tx Plan.)

FERC has allowed MISO until Sept. 9 to respond to the complaint, 10 days shorter than the monthlong extension MISO originally requested. (See MISO Requests Month to Respond to States’ Long-range Tx Complaint.)

Organization of MISO States Executive Director Tricia DeBleeckere said the complaint positions OMS in a tough spot because five OMS members lodged the complaint in the first place.

DeBleeckere suggested that OMS refrain from filing comments in the docket but said she would defer to what a majority of members want.

OMS President Asks States to Back MISO Planning

Joseph Sullivan, president of the Organization of MISO States and vice chair of the Minnesota Public Utilities Commission, said he’d like to see OMS membership who didn’t bring the complaint file comments defending MISO’s planning process.

“I would like to see if we can get to a majority to file comments in support of the process. Now, there are different ways to do cost-benefit calculations. But this is coming nine months after MISO approved the lines in December 2024 and more than a year and a half after it was clear that this would be the approach,” Sullivan told other regulators at an Aug. 14 OMS Board of Directors meeting.

Sullivan said regulators should remember that the lines are meant to accommodate load growth and economic development while modernizing the MISO system. He said even if the ensuing portfolio isn’t exactly what some states had in mind, MISO states agreed to the MISO process. He added that MISO is an outlier among other RTOs for successfully planning long-range transmission.

“We are the only region that succeeds at this, and that’s because we are working together. [That’s] in no small part because of OMS,” he said.

Sullivan pointed out that OMS in 2019 adopted principles on how MISO should approach long-range transmission planning and followed up in 2021 with a cost-allocation principles document and a filing in support of MISO’s postage-stamp-to-load allocation design. He said MISO’s resulting, second long-range portfolio is “consistent” with the OMS principles.

Sullivan said the five states’ request that MISO going forward submit future long-range transmission business cases to FERC for approval would be “a pretty significant federal takeover of state resource adequacy and utility planning in the modern age.”

“A purist may say ‘not so,’ but in the age of RTOs, that is exactly what this is. We all rely on each other and having the FERC say yes or no is something we should push back vigorously on. Fundamentally, this process is the culmination of the MISO stakeholder process and the aggregation of state and utility resource plans,” he said.

Sullivan said he hoped the remaining OMS members could band together in opposition against the complaint. He said OMS members should all be thinking about the “practical knock-on-effects” should FERC grant the complaint.

The second long-range portfolio already is included in all MISO modeling, Sullivan said, including expedited transmission project review, the 2022 cycle of generator interconnection requests and the interconnection queue fast lane.

“So, there will be major upheavals impacting potentially hundreds of projects, many already approved by our commissions. … Because this filing was so late in the process, it will have massive effects on everything we have already done — much of it to meet the moment on artificial intelligence, data centers, load growth and re-industrialization,” Sullivan warned.

Wisconsin Public Service Commissioner Marcus Hawkins said he would support a majority OMS filing on the complaint, or a filing from a subset of MISO states.

States that brought the complaint forward opposed a majority filing from OMS in the docket.

Barton Norfleet, counsel for the Mississippi Public Service Commission, said he thought OMS should sit this docket out. Noel Darce, counsel for the Louisiana Public Service Commission, also agreed that comments should come from individual states, not the organization itself.

South Dakota Public Utilities Commissioner Chris Nelson said his commission is holding off on communicating a position on the complaint and would weigh making a filing once MISO has responded.

“This is a really divisive issue,” Nelson said.

North Dakota Public Service Commissioner Jill Kringstad said North Dakota has long communicated its disillusionment with the MISO portfolio. She said North Dakota is exercising its right to have FERC take an “objective” view at the long-range transmission.

Sullivan said he thought states and OMS board members should “find the common denominator over the next couple of weeks and develop a set of baseline comments defending the process.”