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November 18, 2024

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PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report

The PJM Independent Market Monitor released the second iteration of its report on the 2025/26 Base Residual Auction, digging deeper into the impact of excluding reliability-must-run (RMR) resources from the capacity market.

The report ran a sensitivity modeling the Brandon Shores and H.A. Wagner generators as offering capacity into PJM’s supply stack, along with including capacity offers from all intermittent and storage resources categorically exempt from the capacity must-offer requirement.

The report found that combining the two led to a 53.9% increase in total capacity costs, amounting to about $5.14 billion. The two generators, owned by Talen Energy, were not required to offer into the 2025/26 auction as they will be operating on an RMR contract. (See PJM Requests 2nd Talen Generator Delay Retirement.)

The second sensitivity analyzed the effect of limiting combustion turbines and combined cycle generators to their summer ratings when PJM’s risk modeling is concentrating risk in the winter, paired with modeling the expected output of the two RMR generators. The analysis estimated that the two led to a 77.6% increase in capacity costs, or about $6.42 billion.

Combining the three components — excluding the two RMR units, and categorically exempt resources from the capacity market and capping gas generation at summer ratings — corresponded with auction prices being 108.1% higher, or a $7.63 billion increase.

The Monitor argued that exempting resource classes from participating in the capacity market and not modeling RMR units allows generation owners to limit access to transmission that could be used by other resources to deliver capacity and create significant differences in the supply stack year-to-year. It argued that the risk of an intermittent capacity resource being subject to capacity performance (CP) penalties for being offline during an emergency at a time when it could not respond could be countered by accounting for availability when assessing performance.

“The inclusion of a must-offer obligation for categorically exempt intermittent and capacity storage resources should be coupled with the removal of (performance assessment interval) penalty liability for such resources when it is not physically possible to perform,” the Monitor wrote. “The capacity market has included balanced must-buy and must-sell obligations from its inception. The current rules can and should be changed to restore that balance.”

During the Organization of PJM States Inc. (OPSI) annual meeting Oct. 21, Monitor Joe Bowring said capacity interconnection rights (CIRs) are a scarce resource that control access to the grid for generators. He argued that those holding CIRs should be required to exercise them.

PJM Executive Vice President of Market Services and Strategy Stu Bresler responded that it would not make sense to count on resources that cannot perform when there’s an auction with an annual commitment to perform. Exempting intermittents from the CP construct would be trading one set of exemptions for another, he said. Instead, PJM is committed in the long term to designing a more granular, seasonal capacity market structure.

The Monitor’s report also recommended expanding the granularity of PJM’s effective load carrying capability (ELCC) accreditation to include hourly data, so that unit-specific accreditation can be implemented, replacing class accreditation with a system of paying resources to be available on an hourly basis, and untying accreditation and summer ratings to allow winter CIRs to determine capability when risk is concentrated in the winter.

“The need for the energy from capacity is not limited to one peak hour or five peak hours. Customers require energy from capacity resources all 8,760 hours per year,” the Monitor wrote. “Rather than develop a complicated seasonal capacity market based on an arbitrary definition of seasons, the hourly value of the energy from capacity should be explicitly recognized in the capacity market.”

The total impact the changes PJM made on the auction led prices to be around double what they would be based on supply and demand fundamentals alone, Bowring said.

PJM Defends Capacity Market Design in Response to Part A of IMM Report

In its Oct. 11 response to the initial portion of the Monitor’s report, PJM argued that while the underlying analysis in the report appeared to be largely correct, the Monitor drew incorrect conclusions and omitted necessary context in its recommendations.

“PJM also does not take exception to the results of the simulations the IMM conducted as they are summarized in the report. They are directionally consistent with those that would be expected given the inputs used,” PJM wrote. “However, the IMM presents an incomplete set of sensitivities, provides insufficient context, and draws several conclusions that either lack support or are incorrect.”

The Monitor’s analysis, released Sept. 20, modeled four sensitivities looking at the impacts of PJM’s marginal ELCC accreditation methodology, exempting generators operating on RMR agreements from being required to offer into the auction, capping accreditation at resources’ summer ratings, and not subjecting intermittent and storage resources to the must-offer requirement.

The Monitor wrote that shifting generation accreditation from equivalent demand forced outage rate (EFORd) to marginal ELCC led to a 49.1% increase in total capacity costs, a finding PJM said conflates the changes made to accreditation and risk modeling. PJM said its revised risk modeling approach accounted for the bulk of the increased capacity costs associated with a market redesign approved by FERC in January 2024 following the Critical Issue Fast Path (CIFP) process conducted last year. (See FERC Approves 1st PJM Proposal out of CIFP.)

“The IMM does not estimate sensitivities capable of differentiating the impacts of these distinct market rule changes, but nevertheless attributes the impact to ‘PJM’s ELCC approach’ and ‘the ELCC availability metric,’” PJM wrote.

PJM went on to defend the marginal ELCC approach, stating that the probabilistic modeling at its core is becoming industry standard, with variants approved by FERC for implementation in MISO and NYISO, with ISO-NE considering similar changes. It argued the EFORd approach of using average availability to determine accreditation predominantly incentivizes performance throughout the year without sufficient focus on high-risk periods.

“Under the tight supply-demand conditions that materialized for the 2025/26 BRA, even relatively small impacts to the supply-demand balance can have outsized impacts on clearing prices because of the inelasticity of both supply and demand,” PJM wrote. “PJM believes that the nearly 2.7 GW impact of the enhanced risk modeling and concordant accreditation changes were appropriate and necessary to reflect emerging patterns of risk and lower-than-expected generator performance during such risk events.”

While the Monitor argued that PJM’s practice of modeling the expected output of RMR units when determining capacity transfer between zones is inconsistent with not including those resources in the supply stack, PJM stated that it views the issue as secondary to recognizing the disparities between capacity resource obligations and RMR agreements. Those contracts require units to operate during limited operational events and carry different obligations from capacity that are incomparable to capacity obligations, PJM said.

The response said more analysis is needed to determine the impact of using winter ratings for gas resources. Adding capacity to high-risk winter hours could shift ELCC weighting toward the summer, where high loads are a greater driver than forced outage rates. That could have the effect of pushing the reliability requirement higher.

PJM said the Monitor’s allegation that intermittent resources could be engaged in market manipulation by withholding their capacity is unsupported and misses valid reasons generation owners may not exercise the must-offer exception.

“The report fails to consider legitimate reasons why exempt resources may not have been offered into the capacity market. … Specifically, PJM believes that the IMM must assess the portfolio profitability impacts of the purported ‘withholding’ in order to determine whether the action could plausibly be connected to the exertion of market power. Additionally, the IMM should request information from market sellers in cases where the IMM suspects exercise of market power to consider whether there were other factors that explain the market sellers’ decisions,” PJM wrote.

PJM said the Monitor had not included an additional sensitivity the RTO had required be included in the report: the cumulative impact four recommendations the Monitor had made in its report on the 2024/25 BRA would have had if implemented in the 2025/26 auction. Those recommendations were establishing a sharper variable resource rate (VRR) curve, extending the must-offer requirement to intermittent resources, and excluding capacity offers from demand response (DR) and external resources.

Excluding DR from the auction would have reduced the excess unforced capacity (UCAP) by 8,769 MW, while doing so for external generation would have removed an additional 1,410 MW of excess UCAP. Combining the two would have left the RTO 6,983 MW short of the reliability requirement, pushing the clearing price to the $375.91/MW-day cap and resulting in a total capacity cost 42% higher than the actual results.

PJM said that gap would not have been made up for by other recommendations the Monitor made to increase available supply, such as requiring intermittent and storage resources to offer. That would have added 2,800 MW of available capacity, leaving a shortfall of 4,183 MW.

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Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation

Stakeholders reacted sharply to additional detail presented on PJM’s straw proposal to create a one-off expedited application window for high-capacity-factor generation interconnection requests. (See PJM Proposes Expedited Interconnection Studies for High-capacity Factor Generation.) 

The proposal would allow a limited number of projects to be added to the initial clusters of Transitional Cycle 2 (TC2) to meet growing resource adequacy concerns staff have identified in the 2029/30 delivery year. The cycle currently includes only projects submitted between October 2020 and September 2021. More details on PJM’s proposal will be presented at the Oct. 30 Markets and Reliability Committee meeting. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

These approaches to determining eligibility were presented: allowing only projects with an effective load carrying capability (ELCC) class rating of 45% or higher or a formula with weighted factors such as ELCC rating; whether a project is an uprate or greenfield; expected commercial operation date; MW output and permitting required. 

The options would limit the number of projects being expedited to 100, which Director of Interconnection Planning Donnie Bielak said is the approximate number of projects staff believe can be analyzed without significant disruption to the milestones of other projects in the queue. If more than 100 projects are submitted, PJM would prioritize them on the amount of accredited capacity they could deliver. 

The 45% ELCC rating approach would categorically prohibit the participation of onshore wind, intermittent hydroelectric, and fixed and tracking solar, as well as projects being built as part of a state agreement approach (SAA) project. The in-service date would need to be June 1, 2029, or earlier. 

Speaking during the Organization of PJM States Inc. (OPSI) annual meeting Oct. 21, Ohio Lt. Gov. Jon Husted (R) said state leaders had met with PJM and requested the RTO create an expedited process for interconnecting resources that could be available any time of day. 

“Thank you and let’s go, that’s how we feel about it. We appreciate PJM’s responsiveness to our request,” Husted said. 

Speaking at OPSI, PJM’s Executive Vice President of Market Services and Strategy Stu Bresler said the initiative is meant to ensure that capacity market price signals can be acted on by generation developers. He said there are investors who want to act on high price signals sent in the 2025/26 Base Residual Auction but can’t do so while PJM progresses through its transitional approach to studying interconnection requests. 

PJM CEO Manu Asthana echoed that sentiment, saying load growth is accelerating at the same time generation deactivations are outpacing new entry. The Reliability Resource Initiative (RRI) would allow resources to respond to market signals quickly enough to address reliability concerns. 

“I think it’s important to create an onramp for additional resources that want to participate and provide that reliability,” he said. 

Several stakeholders at the Oct. 18 PC meeting said the proposal would amount to queue jumping, allowing preferred categories of generation to skip a line of mostly renewable resources that has spanned years. 

The projected reliability gap also was called into question, with stakeholders arguing that the markets are functioning to procure sufficient capacity and ancillary services. More data was requested around load forecasting and operational needs PJM expects. 

E-Cubed Policy Associates President Paul Sotkiewicz said PJM has not articulated a need to disrupt the rules generation owners have relied on to bring their units to those markets. 

“There’s nothing, absolutely nothing that tells me that we have to move quickly at this point,” he said. 

PJM Senior Director of Market Design and Economics Becky Caroll said the RTO’s Energy Transition in a series of PJM reports have documented the resource adequacy needs and the reliability services that intermittent resources in the interconnection queue are not expected to provide. 

On the other hand, stakeholders said it could create a pathway for adding storage to existing resources or unlock potential for existing generation to make upgrades to increase total capacity. 

Bielak said the proposal is one of three avenues PJM is investigating for addressing its reliability concerns, pointing to rule changes on capacity interconnection rights (CIRs) transfers to allow deactivating generation to be more easily replaced with new resources. The Planning Committee endorsed one of three proposals during its Oct. 8 meeting. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.) 

PJM also is open to re-evaluating its surplus interconnection service (SIS) rules, which allow new resources to be co-located with existing generation so long as there are no material adverse impacts and the combined output does not exceed the original resource’s CIRs. 

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PSEG Announces Route for Piedmont Reliability Project Tx Line

PSEG has announced its proposed route for the Maryland Piedmont Reliability Project (MPRP), a core component of the $5 billion in grid reinforcements the PJM Board of Managers approved in December 2022. (See PJM Board Approves $5 Billion Transmission Expansion.)

The 70-mile, 500-kV line would run from an existing right of way in northern Baltimore County, Md., passing through Carroll County to the Doubs 500-kV substation in Frederick County. The line is expected to cost $424 million to build with an in-service date in June 2027.

The utility said the line would address reliability needs prompted by generator deactivations and support energy affordability.

“Due to significant generation retirements that have occurred in recent years without replacement resources, the energy deficit in Maryland is projected to grow unless additional infrastructure like the MPRP is built,” the PSEG announcement said. “The additional import capability supported by the construction of the MPRP will help Maryland avoid growing their energy deficit, and thereby easing grid congestion and preventing grid overload, which can also benefit both energy affordability and reliability in the state. More transmission is needed to keep energy costs competitive and reduce the risk of rolling blackouts.”

The project was approved as part of the third window of PJM’s Regional Transmission Expansion Plan (RTEP), which sought to address needs presented by rising data center load growth and generation deactivations. That load growth has continued to accelerate, prompting PJM to open a window to create additional transfer capability into the northern Virginia region through the first window of the 2024 RTEP.

While the MPRP would source energy from the east on 500-kV lines, many of the proposals PJM is considering would run 765-kV lines from the west. (See “2024 RTEP Window 1 Projects Include Expansion of 765-kV Network,” PJM PC/TEAC Briefs: Oct. 8, 2024.)

Maryland and Virginia residents have spoken out against projects in both RTEP windows during PJM Transmission Expansion Advisory Committee meetings, arguing that the projects would disrupt historic and environmentally sensitive regions and burden residents already living along major transmission corridors. Three public hearings — one for each county — are being hosted by PSEG between Nov. 12-14, where information will be presented and feedback solicited.

“Over the last four months, PSEG’s team has analyzed over 5,300 public comments and arrived at a transmission solution. The proposed solution is community-informed, reliable and mitigates impact to individuals, communities and wildlife as much as possible while delivering a cost-effective solution for Maryland and PJM electric customers,” Project Director Jason Kalwa said. “We are committed to transparency and community engagement as a part of this process and encourage all interested residents to attend our upcoming public information sessions so that we can hear their comments and concerns.”

A webpage created for the project states that one of the most common sentiments in the public comments requests that the right of way parallel existing transmission lines in the region. But PSEG stated that a new right of way was preferable to avoid impacts to homes and schools along the existing corridor.

“Due to the built environment that has developed along the ROW over the past 50+ years, MPRP does not recommend this route due to impacts on residents, including direct impacts to more than 90 homes that parallel the right of way, and the community, including at least two places of worship and a school,” the page says.

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US Utilities Face Scramble to Meet New Demand

U.S. electric utilities have been caught “flat-footed” by the impending demand for electricity, Wood Mackenzie asserts in a new report. 

Growth of the U.S. economy has far outpaced growth in the amount of power needed to run the economy so far this century, but that trend is set to reverse, the analytics firm said in the October edition of its Horizons report. 

The expected growth of new electric-intensive technology in data centers, vehicles and industry sets the stage for constraints as the “move fast and break things” ethos of Big Tech bumps up against the five- to 10-year window in which generation and transmission projects are planned and executed. 

The utilities and developers that can adapt most quickly will reap rewards, according to “Gridlock: the demand dilemma facing the US power industry.” 

It adds that an era of upward pressure on wholesale power prices likely is at hand. 

Author Chris Seiple, Wood Mackenzie’s vice chairman of power and renewables, said in a news release that there will be a period of adjustment. 

“Most state public utility commissioners have little experience … regulating in a growth environment,” he said. “And as technology C-suites realize that energy may be the largest constraint on their growth, they are shocked as businesses that move at light speed learn about the pace at which electric utilities move.” 

Growth of U.S. GDP and U.S. electrical demand roughly tracked one another from the 1950s to the 1990s, and then electric demand tapered off, the report notes. In the 2010s, it said, electric demand was flat while the economy grew 24%. 

That is changing in the 2020s. 

The report forecasts demand growth of 4 to 15% through 2029, depending on region, with some utilities seeing a much greater increase. It suggests an integrated response from utilities, regulators and policymakers to meet this challenge. 

Projected sources of new demand through the end of this decade vary by ISO region. | Wood Mackenzie

The last time the U.S. electrical industry saw such unexpected demand growth was during World War II, Seiple said. Manufacturing output tripled from 1939 to 1944, and electricity demand rose 60%. 

“It was a closely coordinated national effort that brought together industry and policymakers to address the challenge and find innovation along the way,” he said. “A similar effort is needed now.” 

Wood Mackenzie identified data centers and artificial intelligence as a main driver of the increased demand — it said new data center announcements since January 2023 total 51 GW of new capacity.  

Not all will be built, the report notes, but neither is the list complete or comprehensive — there probably are more proposals that Wood Mackenzie did not identify. Oncor alone recently reported 59 GW of data center connection requests. 

The report bases its projections for future data center demand on 15% annual growth from 2025 to 2029, a midrange scenario. 

Meanwhile, a resurgent U.S. manufacturing sector, particularly for products such as batteries, solar wafers and computer chips, could add as much as 15 GW of high-load-factor demand. Electrolyzers for hydrogen production and chargers for EVs could add 7 GW. 

Against this backdrop, coal-burning plants are scheduled to retire in significant number, transformers and breakers are in short supply, and the interconnection process for new generation is sluggish. 

Outside the Northeast, planned retirement of coal generation facilities could place further strain on the supply of electricity. | Wood Mackenzie

This last factor — transmission planning, permitting and construction — is the biggest bottleneck, the report said. 

Seiple said an interesting dynamic to watch would be the number of coal plant retirements deferred and shuttered nuclear plants proposed for reopening in markets where there is no retail choice, compared to the number in markets where there is choice. More natural gas-fired generation is likely to be proposed, as well. 

The report cautions that projections of future growth in electric demand are fraught with uncertainty — it may not materialize as forecast if utilities cannot respond quickly enough. 

Secondary factors further muddy the picture: 

Many of the new factories being proposed would rely on government policies and/or subsidies that could change or be canceled. 

Developers of data centers want 24-7 clean energy at a steady rate to boost their environmental credibility, but most clean energy coming online today is intermittent. Nuclear fission may provide a solution, but not until the 2030s at the earliest. 

Emissions-free generation often is sited far from these new centers of demand, creating a need for new transmission and adding another layer of cost and complication. 

The report notes that developers, regulators and utilities have been looking for innovative solutions — or in some cases, an end run around each other, such as behind-the-meter generation co-located with demand. 

The report offers a suggestion to the electric utility sector: 

“Over the past 30 years, the industry has evolved the process of large-generation interconnection. It now needs to do the same for large loads to protect the financial interests of utility shareholders and ratepayers, to provide a transparent, non-discriminatory process for large loads competing for access to energy and to provide transparency to market participants on possible demand growth.” 

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New England States Seeking Increase of North-South Tx Capacity

The New England states are planning to solicit project proposals to increase the region’s north-to-south transmission capacity, the New England States Committee on Electricity (NESCOE) wrote in a letter to ISO-NE on Oct. 16.

The solicitations would be conducted through ISO-NE’s recently approved longer-term transmission planning (LTTP) process, which sets a framework and default cost-allocation method for transmission procurements to meet long-term needs. Project costs would be regionalized by load unless the states agree to an alternative cost allocation methodology. (See FERC Approves New Pathway for New England Transmission Projects.)

“NESCOE is interested in focusing the first LTTP solicitation on increasing transfer capability within the system to allow more power to flow from Maine to New Hampshire and into southern New England,” the group wrote.

The need for increased north-to-south transfer capability was one of the key high-likelihood concerns identified in ISO-NE’s 2050 Transmission Study, which projected overloads along the Maine-New Hampshire and North-South interfaces starting in 2035.

While the study showed overloads in both summer and winter, the most significant overloads occurred in the winter amid periods of high output from offshore wind resources interconnecting in Maine and New Hampshire. Connecting offshore wind resources from the Gulf of Maine to the grid in Massachusetts, instead of in northern New England, could help alleviate this stress on the grid. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.)

Although offshore wind will require major transmission investments wherever it interconnects, the first LTTP solicitation appears focused on onshore renewables. NESCOE wrote that one of the key objectives of the solicitation will be to facilitate “the integration and deliverability of additional affordable generation resources located in northern Maine.”

“Recent studies, along with the current interconnection queue, indicate that on the order of 3,000 MW of additional generation capacity could potentially be developed in northern Maine. NESCOE is interested in solutions that would facilitate the integration of these resources,” the group added.

Renewable power advocates in New England have long sought to unlock the potential of renewables — onshore wind in particular — in northern Maine, but this part of the region is not directly connected to the ISO-NE grid.

In 2022, Maine selected a proposal from LS Power for a 345 kV line to connect the area to the region’s grid, but the Maine Public Utilities Commission canceled the procurement after the projects’ projected costs increased. The PUC plans separate solicitations for transmission and generation in the area, and a proposal from Avangrid recently received financial backing from the federal government. (See Long Road Still Ahead for Aroostook Transmission Project.)

Alex Lawton of Advanced Energy United expressed his excitement about NESCOE’s announcement and said it is “amazing to see our region being proactive and leading the way on transmission planning.”

He added that northern Maine has “some of the cheapest, most abundant renewable potential” in New England, and unlocking more north-south transmission capacity is “one of the more low-hanging fruit and promising areas for cost-effective transmission in New England.”

Next Steps

NESCOE said it is seeking stakeholder feedback on how best to achieve its goals of increasing north-south transmission capacity and integrating renewables in northern Maine, as well as “any other feedback that may increase the likelihood of a successful solicitation.”

The organization said it is considering a requirement for proposed solutions to “increase the Maine-New Hampshire interface capacity to at least 3,000 MW by 2035 and increase the Surowiec-South interface capacity to at least 3,200 MW by 2035.”

The capacity of the Maine-New Hampshire interface is 2,000 MW, while the more northern Surowiec-South interface has a transfer limit of 1,800 MW.

NESCOE wrote it also is “weighing the tradeoffs of including a requirement for solutions that extend farther north into Maine.”

“While such a requirement would further facilitate the transfer of cost-effective power across these interfaces, NESCOE seeks to avoid an overly prescriptive scope that may hinder the success of a potential [request for proposals] by unduly limiting the pool of bids or by reducing the likelihood of soliciting a cost-effective solution,” the group wrote.

NESCOE will discuss the preliminary scope of the solicitation with stakeholders at the ISO-NE Planning Advisory Committee meeting on Oct. 23, which will be open to the public.

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Regulators Get Look into Monitoring Plans for Markets+

Western regulators on the Markets+ State Committee (MSC) on Oct. 18 probed an SPP Market Monitoring Unit (MMU) official on how the division plans to address the implementation of the new day-ahead market.  

Jodi Woods, SPP director of market monitoring, gave the MSC an overview of the mission and scope of market monitor functions, reiterating that SPP’s monitor is internal to the RTO, functions independently and investigates problems and appeals to FERC, but cannot force a position or set a penalty.  

With the implementation of Markets+, the MMU will engage consistently with the MSC and continue regular functions such as monthly, quarterly and annual reporting.  

New Mexico Commissioner Gabriel Aguilera asked whether the MMU would increase staffing levels to account for Markets+. Woods responded that an increase is accounted for in the budget and that the MMU will likely have a separate set of employees tackle Markets+ issues. 

Arizona Commissioner Nick Myers, who chairs the MSC, asked if there would be staff overlap.  

“There was actually a preference from the Markets+ participants that there not be a lot of overlap and that there [be] assurance that the headcount that Markets+ is paying for, which is completely understandable, is actually working on Markets+ issues,” Woods said. “The construct we’ve proposed would allow for a separate Markets+ team that would be focused primarily just on Markets+ issues.”  

The MMU has budgeted for around 14 additional employees to be added to the team.  

Aguilera additionally asked about the MMU’s process for opposing a tariff change and whether the monitor has its own attorneys.  

“If we do decide to file comments in the docket, once the revisions have been filed, we do have external counsel. Sometimes we do it ourselves … but we don’t have lawyers on our team,” Woods said.  

Aguilera emphasized the value of having an independent group monitoring activity in the new market.  

“It is really essential when we have these incredibly complex machines that are markets and very sophisticated participants who could potentially take advantage of those complex rules,” he said. “I think that the work you do is just invaluable.”  

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SPP Sees Bias in Brattle Western Market Studies, Exec Says

An SPP executive closely involved with developing Markets+ said recent Brattle Group studies on Western day-ahead markets appear to be aimed more at swaying utilities in favor of CAISO’s Extended Day-Ahead Market than providing an unbiased assessment of the two offerings.

“We’ve observed a lot of statements and assertions — and even studies — that really seem more like attempts to pressure Western entities into a market selection rather than work directly with those Western entities to truly understand what their issues and concerns are, and also work to try and accommodate them and address those issues so they want to choose to be within that market,” SPP Vice President of Markets Antoine Lucas said during an interview.

Brattle’s John Tsoukalis, the lead author on the studies, objected to that depiction of his group’s work, saying the company’s clients “are looking for solid analytical support for their decision making, not a biased analysis or advocacy.”

RTO Insider spoke with Lucas and SPP Senior Director of Seams and Western Services Carrie Simpson on Oct. 16 to discuss Brattle’s Oct. 1 comparative white paper on Markets+ and EDAM, which Lucas said “misrepresented” aspects of SPP’s day-ahead platform. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.)

That study, which compared seven key features of the two markets — such as transmission optimization, fast-start pricing and seams management — offered a more favorable assessment of the CAISO market but stopped short of endorsing it.

Vancouver, British Columbia-based Powerex, the first entity to tentatively commit to Markets+ two years ago, quickly published a rebuttal to the study, with SPP following up with its own set of “corrections” shortly after. (See Powerex Contests Brattle’s EDAM/Markets+ Comparative Study.)

Lucas said SPP has tried to stay outside the fray of Western market debates but felt compelled to respond directly to the comparative study because “there were certain things or statements” made about Markets+ “where we felt it necessary and appropriate to address and try to clarify with facts. And then there were other areas where we just felt like there was either a lack of information or characterization of certain things that misrepresented the product.”

The SPP response criticizes the Brattle study in four areas, including its conclusions around “look ahead” unit commitment design, fast-start pricing, greenhouse gas accounting design and congestion rent allocation.

Regarding the first subject, SPP faults the study for conflating the real-time unit commitment design used in RTO’s Western Energy Imbalance Service with the different one to be implemented in Markets+. On the GHG issue, SPP contends the study overlooks the full set of methods Markets+ uses to reduce “leakage” when accounting for emissions from generating resources.

On the last subject, SPP contends Brattle “grossly oversimplifies the complex policy considerations behind fair congestion revenue allocation” by concluding the two markets’ differing models will yield similar results.

Lucas said SPP finds Brattle’s conclusions “concerning” because third-party studies are “typically intended to bring trust to the process.”

“We wanted to make sure that people were aware of the mischaracterizations of Markets+ and also recognize that in every one of those cases, those errors and mischaracterizations tended to depress the anticipated value proposition for Markets+,” he said. “We know that a lot of people are looking at these studies and then using them in different ways to inform themselves around either decisions that they’re going to make or positions that they’re going to take on the markets.”

‘Equitable Distribution’

Lucas said SPP was not yet prepared to comment on a more recent Brattle study zeroing in on benefits for the Bonneville Power Administration (another Markets+ supporter) and the Pacific Northwest at large.

That study, which focused on adjusted production costs (APC), found BPA could earn an estimated $65 million in annual benefits from joining EDAM while facing increased yearly costs of $83 million in Markets+. Similarly, the Northwest could reap $430 million from widespread participation in EDAM but might see net revenues decline by $18 million in Markets+, according to the study. (See Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)

Lucas questioned why Brattle produced a study trying to estimate BPA’s benefits “rather than BPA themselves being able to conduct those assessments and if those [benefits] provide what they see as value to them and their customers.”

Asked whether Western utilities’ day-ahead market decisions should come down to estimates of economic benefits based on APC or other factors, Lucas said the discussion should extend beyond the notion of calculating “regional benefits” to considering how those benefits are distributed.

“What we constantly wrestle with in policy development is we’re finding policies that benefit the overall region, but also do it in a manner where there is equitable distribution of value among the participants who are bringing the assets into that market,” he said, adding that APC estimates, while important, are just one component of overall market benefits.

Lucas responded with good humor to a hypothetical question about whether Markets+ could ensure an equitable distribution of benefits in a footprint that included California and the CAISO area or if, as some Markets+ supporters believe, participants would do better to negotiate with the larger entity from behind a market seam.

“Under a scenario where California was part of Markets+, they would be another [balancing authority], just like the other BAs. They would be a very large BA, and from our standpoint as SPP, our approach to facilitation doesn’t change. You just have another BA who’s participating in that stakeholder process that’s advocating for the things that they believe are best for them and their consumers,” he said.

Simpson said the “independent, inclusive” Markets+ governance framework is designed to accommodate a BA the size of CAISO.

“I think the design, the actual market design, in addition to the governance, would support that equity that we’re talking about. So that hypothetical, I think, would work,” Simpson said.

“And in the alternative, then you have market operators representing their respective customers’ interests at the seam on a peer-to-peer basis, and so that is also really helpful, too, if you’re an entity in Markets+, in having that representation by your market operator to look out for the interests of that market,” she said.

No ‘Preconceived Notions’

Reached for comment, Tsoukalis said Brattle “appreciates all responses” to its Western markets work and is “always open to input on our analyses, assumptions, and our understanding of the market options.”

“We do not engage in advocacy work and do not take on work on preconceived notions of what our results will look like. Rather, we strive to do unbiased, high-quality work to support well-informed decision making by our clients, who in this case are Western utilities, cooperatives and public power entities,” Tsoukalis said in an email.

Tsoukalis said he wanted to ensure other “key points” aren’t lost in the Western debate, including the fact that both Markets+ and EDAM represent an improvement over the status quo; that most “market-related benefits to specific entities will be driven by the transmission capabilities, and diversity of loads and generation resources of market participants;” and that Brattle recognizes that estimated cost savings in either market are not the only — or even most important — factor affecting market participation decisions.

He noted that Brattle has found that each market includes design elements that are “more attractive” than the other market.

“The availability of (and competition between) two market options has benefited the development of both EDAM and Markets+ as both markets have worked harder to offer an attractive and efficient market design.  The benefit of this competition is expected to continue as both markets evolve over time,” Tsoukalis said.

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Utilities and Grid Operators Urge Caution on DLRs, State Regulators and Consumers Want Action

FERC got more than 60 comments on its advanced notice of proposed rulemaking (ANOPR) on dynamic line ratings (DLRs), with utilities and grid operators urging caution on new requirements while state regulators, consumers and grid-enhancing technologies (GETs) firms want mandates. (See related story: FERC Gets Mixed Advice on How Quickly to Move on DLR Requirements.) 

The ANOPR proposes requiring transmission providers to reflect the impacts of solar heating on transmission line ratings, reflect forecasts of wind on certain lines, ensure transparency in the development and implementation of DLRs and enhance data-reporting practices in non-RTO regions to identify candidate lines to reflect wind conditions. 

PPL is an investor-owned utility with subsidiaries in the Eastern Interconnection that have been testing DLRs. It said they promote operational performance and save customers money. 

“By measuring wind, sag and conductor temperature directly, a machine-learning tool can fine-tune the external forecasts for each transmission facility,” PPL said. “When these forecasts are accurately incorporated into day-ahead models, RTOs like PJM can dispatch lowest-cost generation where it might otherwise be blocked by transmission line congestion.”  

But the ANOPR needs to better consider where DLR implementation would be most effective. PPL argued that FERC should reconsider mandating that transmission owners calculate and apply ratings using a specific methodology. 

“Doing so would upend the risk tolerances built into the utilities’ existing ratings methodologies and limit their ability to allocate acceptable risks throughout their systems,” PPL said. 

The fundamental question for line ratings is how much thermal energy to allow, which has never been dictated by regulators and always left to transmission owners, informed by good utility practice. 

“FERC taking more control of the factors being used in ratings calculations means that regulators in Washington, D.C., not the owners of the assets who are responsible for their reliability, safety and longevity, are the ones deciding on how much risk is acceptable,” PPL said. “FERC does not have, and can never have, all the relevant information needed to make these decisions.” 

Dominion Energy is working with the U.S. Department of Energy to test out DLRs around “data center alley” in Loudoun County, Va., which is home to the largest concentration of the facilities in the world and is a major factor in the load growth in PJM. The utility argued that the technology makes more sense for short-term operational efficiencies or for contingencies. 

“Short-term DLR benefits are not a substitute for the transmission planning necessary to ensure long-term reliability,” Dominion said.

The New York Transmission Owners also voiced some support for GETs in general, but do not want FERC to move ahead with DLR requirements now. 

“Rather than ordering prescriptive DLR requirements, the commission should continue to promote and explore DLR technologies and allow regional flexibility for TSPs and TOs to develop targeted DLR programs that make sense for their respective systems,” they said. “For example, much of the Consolidated Edison transmission network is underground, and DLR implementation clearly should not be required for transmission lines that are not exposed to sun or wind.” 

The issues in New York go beyond underground lines in Manhattan, with the NYTOs telling FERC that much of their system is getting old and it would make more sense to replace aging infrastructure rather than try to squeeze a few more efficiencies out of it. 

ISO/RTOs also Preach Caution

PJM told FERC it supports DLRs in high congestion areas as a real-time optimization tool. But it said FERC should let the benefits of Order 881 that mandated that the related Ambient-Adjusted Ratings (AARs) in ISO/RTOs be better understood before moving onto DLRs. Order 881’s requirements for AARs go into effect in July 2025 and will have line ratings take temperature into account, which has some overlap with DLR benefits. 

PJM supports delaying DLR implementation until after Order No. 881 requirements provide the data “needed to identify changed transmission line congestion patterns,” the RTO said. “The potential benefits of DLR cannot be reliably estimated before implementation of Order No. 881.” 

Projecting the cost-benefit ratio of using an ANOPR-adjusted rating on a congested facility as compared to a seasonal rating “may grossly inflate the benefits if not adjusted for the efficiencies gained using an Order 881 AAR,” it added. 

MISO supports using DLRs as another tool to help reliably deal with the changes its system is going through, but it argued they do not make sense everywhere. It also highlighted overlap with Order 881. 

“DLRs, when selectively deployed, can support the efficient use of existing transmission infrastructure,” MISO said. “But they are not a long-term solution to meet emerging system needs. Like AARs, DLRs can provide operational benefits but cannot solve significant long-range transmission problems. Development of additional transmission investment will be critical to meeting the challenges of grid transformation.” 

CAISO said DLRs make sense where they materially enhance the reliability and efficiency of transmission operations. “Requiring the blanket use of dynamic line ratings — even through a phased implementation and subject to an exception process as set forth in the ANOPR — may not advance reliability and efficiency in all cases,” CAISO said. 

State Regulators and Consumer Groups Support ANOPR

The Organization of MISO States said the reforms in the ANOPR are needed to ensure reasonable rates and the use of DLRs will increase efficiency and reliability while cutting costs to consumers. 

“The ANOPR proposes additional requirements beyond Order No. 881 that require line ratings that account for solar heating, wind speed and wind direction,” OMS said. “Without taking these conditions into consideration, transmission owners are likely not fully utilizing the available capacity on transmission lines.” 

The proposal builds on five years of work looking into GETs with AARs expected to save up to 15% of total congestion in MISO. While many of the benefits come from pushing more energy through lines, OMS noted that DLRs can lower them with a study out of Massachusetts showing that effect 22 to 27% of the time. 

“This lowering of transmission line ratings also suggests that DLRs have additional long-term benefits because overrating a transmission line can lead to safety risks and premature degradation of a transmission line,” OMS said. 

The Organization of PJM States (OPSI) supports the reasonable implementation of DLRs, which is in line with its mission of ensuring reliable service at affordable rates. But the group did caution FERC against being overly prescriptive and ensuring DLRs can be implemented strategically. 

Utilities have been too slow in taking up the technology, which OPSI said requires some regulatory mandates. In PJM’s case, OPSI said the issue was with a lack of competition in the transmission planning process, which in the 2022 Regional Transmission Expansion Plan Window 3 procured $5 billion worth of new lines with zero DLRs. 

“PJM itself has made the case that the sponsorship model is insufficiently competitive,” OPSI said. “In its comments in the ANOPR that eventually became Order No. 1920, PJM noted that only three total project selections were awarded to non-incumbent developers out of 185 total project awards. According to PJM, the reason for this mainly comes down to the availability of existing right-of-way for incumbent developers, which is a major cost and constructability advantage.” 

The R Street Institute supports the ANOPR and pinned utilities’ lack of movement on the technology on a more basic issue. 

“DLRs have been and will continue to be chronically underutilized because of [transmission providers’] perverse incentives under cost-of-service regulation,” R Street said. “This inhibits market trading by inflating congestion costs unnecessarily. Thus, the status quo is unjust and unreasonable.” 

FERC should require DLR with a rebuttable presumption of prudence, unless transmission providers can show they fail a cost-benefit test.  

R Street also argued that FERC needs to start getting more information from non-RTO regions and it should not fail to require DLRs inside organized markets out of a fear of making a disincentive for new participation. DLRs would only enhance the net benefits of RTO participation, R Street said. 

“The determinates of RTO expansion hinge on many factors that tilt in favor of DLR adoption to enrich RTO value proposition, as the perceived net benefits are strong considerations in state RTO expansion conservations, such as those underway in the West,” R Street said. 

The Electricity Consumers Resource Council (ELCON), Clean Energy Buyers Association and Electricity Consumers Alliance represent large customers, and they all want to see DLR requirements move forward. 

“Given the potential economic and reliability benefits of implementing grid enhancing technologies, such as DLR, large consumers urge the commission to expeditiously incorporate the information gathered in this ANOPR into a formal proposal that supports adoption of all beneficial grid enhancing technologies rather than individual technology-specific solutions on a case-by-case basis,” they told FERC. 

GETs Firms Support the Rule Change but Have Suggestions

LineVision argued that the wind ratings proposed in the rule, which FERC would require on some congested lines as opposed to the more universal solar radiance requirements, are the more important of the two. If anything, having one standard with wind and solar radiance rolled into one would make sense. 

“More accurate line ratings that reflect the impact of wind on a transmission line will result in increased line ratings a vast majority of the time, which will relieve congestion and quickly result in more affordable rates for customers,” LineVision said. “Without sensor-based DLR, transmission owners will continue to rate their lines based on simplistic assumptions that do not represent the real-time or [forecast] capacity that lines can deliver.” 

Even when DLRs do not significantly affect congestion, they still can improve overall system efficiency. 

“In those instances where DLR may not relieve congestion, it will still result in more just and reasonable rates because asset life will not be shortened due to running a line at its overstated capacity,” LineVision said. “The need for DLR is critical in avoiding the scenario that occurred in 2003, when a conductor sagged beyond its limits and touched vegetation, causing the Northeast blackout, which caused outages for approximately 55 million customers.” 

Addressing transmission line ratings “was one of the recommendations made by the U.S.-Canada Power System Outage Task Force in its review of the blackout. In the long run, a grid operated according to accurate ratings will be more affordable for all,” LineVision said. 

An open question is whether the wind speed DLRs will even require sensors, noted the Southwest Power Pool’s Market Monitoring Unit. The technology is new, so FERC should allow for some more testing of alternatives. 

“A phased-in timeline will allow transmission providers to explore the least-cost options for wind requirement implementation, identify lines where costs might outweigh the benefits and potentially allow new, lower cost technology to enter the market,” the MMU said. “The commission should solicit comments from transmission providers on what an appropriate phase-in timeline for 100% implementation of the wind requirement would be.” 

GE Vernova Electrification Software said its software can avoid the need for sensors, the cost of which has been a hurdle to DLR deployment. The software also can be used on substations, which often are the limiting element on a line, not just the overhead line conductors. 

Software solutions also can work alongside sensors to develop a hybrid approach that maximizes DLR effectiveness. 

“Such hybrid solutions can be provided by a single vendor with capability in the hardware and software realm, through partnerships between vendors or, more generically, via appropriate data integration projects of separate vendor solutions at a customer site,” GE Vernova said. 

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FERC Accepts SPP’s PRM Compliance Filing

FERC has accepted a second compliance filing from SPP outlining its process for determining its planning reserve margin (PRM) with an Oct. 17 order that found the RTO’s response met the commission’s directives, effective April 10, 2024 (ER24-1221).

SPP was responding to FERC’s May order asking for more information on how it uses loss-of-load expectation (LOLE) studies to determine the PRM. (See FERC to SPP: Show More Work on PRM Determination.)

FERC directed SPP to revise its tariff to include more information related to a “non-exhaustive” list of the factors SPP staff, its board and its state regulators will consider when determining the recommended PRM value.

The commission disagreed with protests filed by several SPP members (American Electric Power, Golden Spread Electric Cooperative, Arkansas Electric Cooperative Corp., Xcel Energy, East Texas Electric Cooperative and Northeast Texas Electric Cooperative) that the grid operator did not explain how it will use the LOLE results to determine the PRM. FERC said the proposed tariff language “makes clear” that the PRM value will be determined based on the LOLE study results and that SPP set forth factors that its staff, board of directors and state regulators will consider when using the study results.

SPP’s Market Monitoring Unit also protested, arguing that the tariff shouldn’t reference available generating capacity and new generator development timelines as considerations for recommending or determining the PRM. FERC disagreed, noting that it already accepted a similar provision in the first compliance order.

“That’s a win, I guess, depending on who you ask,” SPP attorney Justin Hinton said to chuckles during a stakeholder meeting Oct. 18, referencing the stakeholder arguments that preceded the PRM’s revision in 2022.

The board approved changing the PRM to 15% from 12% over opposition from stakeholders advocating a three-year phase-in. Load-responsible entities unable to meet the requirement can incur financial penalties from the RTO. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

Commission OKs LTCR Change

In an Oct. 11 letter order, FERC also accepted SPP tariff revisions to allow the nomination of candidate long-term congestion rights (LTCRs) for firm transmission capacity associated with the Federal Service Exemption (FSE) and for firm transmission service associated with grandfathered agreement (GFA) carve outs in the LTCR allocation process (ER24-2003).

FERC said the revisions, effective July 14, 2024, are likely to benefit load by further reducing uplift charges that load currently pays to compensate for the congestion and marginal loss charges that GFA carve outs and FSEs do not pay.

SPP said congestion charges associated with the carve outs and FSE transmission reservations have been offset by revenues that SPP receives from nominating auction revenue rights (ARRs) attributable to the carve outs and FSEs. The remaining amount is recovered from SPP-wide load as uplift.

The RTO said it will nominate LTCRs attributable to the carve outs and FSEs under the same criteria by which it currently nominates ARRs attributable to the same exemptions. It said the LTCRs’ revenue will be used to further offset the uplift charges that must be paid by load.

FERC rejected Missouri River Energy Services’ protests that the revisions shift costs to market participants with transmission reservations near the carve out and FSE reservations. It said the alleged cost shifts result from better aligning the tariff’s treatment of ARRs and LTCRs attributable to carve outs and FSEs with the tariff’s treatment of ARRs and LTCRs attributable to all other transmission reservations.

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MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects

CARMEL, Ind. — MISO announced it will move forward on an annual interconnection queue cap based on 50% of peak load for the year in question, this time removing exemptions for projects regulators deem essential.  

Stakeholders learned at an Oct. 16 Planning Advisory Committee meeting that MISO plans to scrap a regulator exemption from the annual megawatt cap it has designed for its generator interconnection queue. The deletion appeared unpopular among some stakeholders and state regulatory agencies.  

MISO’s Ryan Westphal said removal of regulators’ ability to name exempted generation projects will prevent the cap from being diluted with exceptions to the rule. He also said MISO heard stakeholders’ concerns about how MISO would limit the number of regulators’ exemptions and how it would give those exemptions priority.  

FERC last year rejected MISO’s first attempt to institute an annual megawatt cap on the queue based on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)   

Westphal said MISO needs a “reasonable number of resources and a reasonable dispatch” to be able to build sound study models.  

“All of us can agree that in the 2022, 2023 modeling, there are a lot of resources in there that are creating a lot of difficulties, engineering problems,” Westphal said.  

Westphal also said a 50% peak load cap should eliminate the need for “backbone” network upgrades, where interconnection customers are responsible for large transmission projects.  

MISO previously said regulatory authorities would be allowed exemptions to the cap when generation additions are needed for resource adequacy or to serve documented load that regulators have authority over. MISO said it would allow one cap exemption per 3 GW of documented load that the regulatory authority serves. (See MISO: 50% Peak Load Cap, Software Help Key for Crowded, Delayed Queue.) 

MISO has said that even with a cap in place, it could achieve a total 310-GW queue throughput through 2042. The RTO assumed a 68-GW annual cap based on its current annual peak and took its historic 21% completion rate into account to come up with 14.3 GW per year in completed projects. MISO has about 320 GW in active interconnection requests in its queue. 

MISO staff have said controlling the cadence of project submissions is key to improving the quality of initial studies and potentially reducing network upgrade costs by being able to use a more true-to-life resource dispatch in models. MISO said once a cap is met for an interconnection cycle, projects will line up for the next year’s study cycle.  

The RTO has also committed to a three-year review of the effectiveness of the queue cap. 

MISO: 2nd Filing on the Way to Address Regulators’ Necessities

MISO’s Andy Witmeier said MISO dropped regulators’ exemption because planners didn’t see how a single exemption could address the multitude of imminent resource adequacy troubles.  

Instead, Witmeier said MISO will develop a separate, “more holistic” proposal with stakeholders to find ways to speed up queue processing for projects that keep MISO in the black on resource needs.  

Duke Energy’s Jay Rasmussen said he thought MISO is missing an opportunity to address resource adequacy issues within the cap.

Rasmussen pointed out that large load additions are on the horizon for load-serving entities. He said filing to implement a cap without acknowledging generation needs creates a “lag” for interconnection customers. 

Illinois Commerce Commissioner Michael Carrigan said while the Organization of MISO States sympathizes with how difficult queue studies have become for MISO, “states very clearly value their respective authority.” Carrigan said he didn’t see a path to states supporting MISO’s queue cap proposal at FERC without some sort of exception for generation needed to preserve resource adequacy. 

“This is a concern and could be very problematic,” Carrigan said.  

“Our decision is that we need to address these in separate filings because they’re separate issues,” Witmeier said. He said MISO staff plan to discuss how to expedite generation projects necessary to resource adequacy in upcoming Planning Advisory Committee meetings through January. He said MISO could be ready for a separate filing by the first quarter of 2025.  

MISO’s Andy Witmeier | © RTO Insider LLC 

At a Sept. 12 Organization of MISO States board meeting, OMS Director of Legal and Regulatory Affairs Brad Pope said MISO’s queue cap needs a “workable” exemption for regulatory agencies when they are reliant on a developer’s generation submittal. 

While it’s jettisoning its regulator exemption, MISO said it would maintain cap exemptions for existing resources. Those resources may need to enter the queue to replace their output with an approved generation facility, receive provisional interconnection agreements or upgrade their current basic, unguaranteed energy resource interconnection service to the higher-quality, firm network resource interconnection service. Staff said those reasons don’t include proposing speculative generation projects and can earn exemptions.  

Bill Booth, consultant to the Mississippi Public Service Commission, argued that projects regulators approve under utilities’ integrated resource plans are not speculative.  

“The goal of this whole approach is to reduce speculative projects. Do you think projects approved under a state IRP process are speculative?” he asked rhetorically.  

Witmeier said the past few times MISO discussed its proposed cap with stakeholders, the regulator exemption proved to be a sticking point.  

“Folks are concerned about what it means and how it will be managed,” he said.  

Some stakeholders asked MISO to delay its planned early November filing with FERC for a queue cap until it devises a way to address projects deemed necessary by states for resource adequacy.  

NextEra Energy’s Erin Murphy said a “brief pause” makes sense considering MISO is working with tech startup Pearl Street to automate some study processes. She said perhaps MISO could wait to gauge the effectiveness of the new software’s ability to shrink wait times before it limits entrants.  

Witmeier, however, said a queue cap has been in the works in MISO’s stakeholder process for two years. He said the need for a queue cap and creating a means to usher resource adequacy projects through faster are unrelated matters.  

“I see no need to put it on the shelf just because we’re going to go after a separate process,” Witmeier said.  

Booth said MISO required a little “intellectual integrity.” He said instead of MISO polishing and explaining a regulator exemption, MISO simply chopped its filing in half, with no guarantee of when it would address state-required generation projects.  

Consumers Energy’s Dan Alfred said his utility’s support of the queue cap hinges on a companion resource adequacy exemption.  

“I don’t understand why you’re not listening to the feedback here,” Alfred said.