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January 15, 2025

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PJM MIC Briefs: Jan. 8, 2025

1st Read on 2nd Phase of CIFP Manual Revisions

VALLEY FORGE, Pa. — PJM presented stakeholders with proposed manual revisions to implement a requirement that dual-fuel generators must offer schedules with both of their fuels into the energy market during the winter, as well as changes to the operational and seasonal testing for capacity resources.

The proposal is the second package of manual updates to conform with tariff revisions approved by FERC in January 2024 as part of PJM’s Critical Issue Fast Path (CIFP) capacity market rework (ER24-99). (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)

The dual-fuel requirement would be added to Manual 11 and specify that combustion turbines and combined cycle committed as dual-fuel capacity resources offer their alternative fuel into the energy market during the winter or follow outage reporting requirements.

The summer/winter capability testing requirements in Manual 18 would be redefined to focus on whether a resource participating in the capacity market or a fixed resource requirement plan is able to output its daily installed capacity (ICAP) minus the 95th percentile hourly seasonal net output. A resource that has a daily ICAP value exceeding the tested capability during that season would be subject to shortfall charges until it is able to test to a greater capability.

Changes to Manuals 14, 18, and 28 would allow PJM to subject capacity resources to up to two operational tests in the summer and winter. Intermittent resources, including the variable component of a hybrid resource, would be exempt from both testing requirements.

The penalty rate for failing either of the tests also would be changed to be determined by multiplying the daily deficiency rate, ICAP shortfall and accredited unforced capacity (AUCAP) factor; the status quo uses the equivalent demand forced outage rate (EFORd) instead of the AUCAP factor.

The committee will vote on the changes at its meeting in February, with a vote by the Markets and Reliability Committee in April.

PJM Presents Changes to Black Start Compensation

PJM’s Glen Boyle presented a proposal to revise how generators providing black start service are compensated to remove the net cost of new entry (CONE) as an input.

The RTO would instead use a fixed rate derived from the average RTO-wide net CONE values over the past five years, coming out to $272.62/MW-day. That would be multiplied by the unit capacity and varying multipliers depending on resource classification to arrive at the black start service cost, which is one component of the base formula rate that determines compensation. The fixed rate would be reevaluated every five years as part of the holistic review of the service. Boyle said PJM is trying to break the tie between black start revenues and net CONE.

The proposal is set to be voted on by the MIC on Feb. 5, followed by the MRC on March 19.

The net CONE component has come under scrutiny after PJM presented planning parameters for the 2026/27 Base Residual Auction, scheduled for July, which saw net CONE values fall to zero in some zones. One of several pending filings PJM submitted to FERC in December would revert a change in the reference resource that net CONE is based on from a CC generator back to a CT unit. (See PJM MIC Briefs: Dec. 4, 2024.)

While using the status quo formula for the 2025/26 delivery year would result in decreasing black start revenues across all zones — an overall 22.73% decrease and exceeding 50% in one area — the proposal would result in compensation remaining nearly equal to the previous year’s.

Calpine’s David “Scarp” Scarpignato said he does not see a link between net CONE and black start service and added that he appreciates the straightforward nature of PJM’s approach.

Independent Market Monitor Joe Bowring said the proposal appears to be an arbitrary change that would perpetuate the use of what he called an irrelevant metric — net CONE — in compensating black start units. He proposed that black start resources be compensated for the cost of providing black start plus an incentive rather than net CONE. He questioned why net CONE should be subject to escalator given that it depends on net revenues, which vary from year to year.

Bowring also said the original rationale for the PJM proposal is no longer true as it based its proposal on the basis that net CONE would be zero in multiple locational deliverability areas (LDAs) because it was planning to use a CC as the reference unit.

“While the gross CONE of a CC is higher than that of a CT, the net CONE of a CT is higher than the net CONE of a CC. There are no LDAs with negative net CONE,” Bowring said.

Discussions Continue on Demand Response Availability Window

Stakeholders continued to weigh in on PJM’s proposal to eliminate the demand response availability window and instead model the resource class as being available in all hours, following arguments from curtailment service providers that there is unrecognized potential for consumers to reduce their load any time of day. (See “PJM Proposes Changes to Demand Response Availability Window,” PJM MIC Briefs: Oct. 9, 2024.)

The prospect of a wider availability window became especially significant for DR in the wake of PJM’s redesigned risk modeling paradigm, which FERC approved in January 2024. That shifted the focus to winter, when reliability risks are more dispersed across the day, from a few peak hours in the summer.

PJM’s Pat Bruno said the proposal would build a specific load profile for DR in light of analysis that found that program participants have a different average load profile from general load.

When determining the winter peak load (WPL) for the resource class, Bruno said adding up the peak load for each participant would overstate capability because consumers’ load could peak in different hours. Instead, the proposal would measure the WPL across five winter coincident peak (WCP) days at the 8 to 9 p.m. hour, as that is when overall class capability most coincides with system peak load. Because both profiles may change over time, this would be reevaluated regularly.

Aggregate average hourly DR load profiles also would be created across the five WCP days for use in the effective load-carrying capability (ELCC) analysis driving risk modeling and resource accreditation. The average would be at its lowest between 1 and 4 a.m., when DR would be modeled at 63% of its maximum reduction capability.

ELCC ratings for DR could increase by about 20%, with values also increasing for resources that perform better in the summer. Ratings for storage could increase between 8 and 10%, depending on the duration of the resource, and thermal and storage could see more modest boosts. Onshore and offshore wind values would fall by 2% and 4%, respectively. System reliability risk as a whole would shift toward the summer by about 4%.

Because individual consumer load profiles can vary, Bruno said there is less correlated outage risk, and the impact of changing the amount of DR that participates in the auction has less of a marginal impact than for other resources.

Bowring said that PJM’s asserted increase in the ELCC value for DR ignored the fact that DR had underperformed during the December 2022 winter storm.

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FHWA Awards $635M for EV Chargers, Hydrogen Fueling Stations

The city of Troy, Ala., soon could have 10 new electric vehicle charging stations located at five sites — the local hospital, museum, university, downtown center and sports complex — all funded with $724,192 in federal funds from the Infrastructure Investment and Jobs Act. 

The city of 17,836 is one of 49 recipients of a total of $635 million in IIJA money announced Jan. 10 by the U.S. Department of Transportation’s Federal Highway Administration. The aim is to put 11,500 chargers in underserved areas ― rural and urban ― and along major highways in 27 states and the District of Columbia, according to the DOT press release.  

The grants represent the second round of funding from the IIJA’s $2.5 billion Charging and Fueling Infrastructure (CFI) program, which is a competitive program. The second funding opportunity drew high interest, with the FHWA reporting it received 416 applications requesting a total of $4.05 billion, more than six times the amount available.  

The first round of CFI funding went out in two installments: $622.57 million to 47 projects in January 2024 and $521.19 million to 51 projects in August 2024. 

In addition to EV chargers, the grants also will support hydrogen fueling stations for heavy-duty vehicles. For example, a $24.8 million award to the Port Authority of Houston will be used to install and operate a publicly accessible hydrogen fueling station in Bayport, an industrial area in the port.  

The California Energy Commission won the largest award, $55.9 million, for EV fast chargers and a hydrogen fueling station for medium- and heavy-duty trucks traveling on major routes in and between California and Nevada.  

Some of the federal money will be used for “micromobility” charging for electric bikes and scooters, such as in San Bernardino, Calif., and Hollywood, Fla.  

Hailing the new grants in the press release, Transportation Secretary Pete Buttigieg said, they will help “support the EV transition and make sure it’s made in America. These investments will help states and communities build out a network of EV chargers in the coming years so that one day, finding a charge on a road trip will be as easy as filling up at a gas station.” 

“Americans deserve real choices in how they get around,” said Gabe Klein, executive director of the Joint Office of Energy and Transportation. “[These] investments supplement a combination of federal tax incentives, state and local funding and private investment to fill gaps in the nation’s rapidly growing alternative fueling network and ensure all communities — whether rural, urban, or suburban — have access to convenient, reliable and affordable zero-emission transportation options.” 

If fully funded, individual grants could put hundreds of fast and Level 2 chargers at public locations across the country, including: 

    • $15 million for D.C. to install 454 charging ports at 220 locations, including retail destinations, multifamily properties, car-sharing spaces, curbside spaces and public parking lots. 
    • $8 million to the Louisville-Jefferson County Metro Government in Kentucky to install an estimated 184 charging ports at 39 city-owned locations and one university campus. Also, an urban charging hub powered in part by a solar canopy would be created at a retired coal plant. 
    • $15 million grant for Minnesota’s Metropolitan Council to deploy 1,875 charging ports across the region, especially prioritizing rental housing, rural areas, low- and moderate-income neighborhoods and environmental justice communities.  

Depending on their speed of charging, direct current fast chargers can top up an EV battery in a half hour or less, while Level 2 chargers, often used for home charging, can take several hours.  

The Trump Effect

But whether Minnesota, Troy or any of the other Round 2 grant recipients will see the money or chargers remains uncertain. The awardees must negotiate final contracts with a DOT that likely will have different priorities under the second administration of President-elect Donald Trump, who has pledged to claw back all unspent dollars from the IIJA and Inflation Reduction Act. 

Trump and the Republican-controlled Congress are likely to target EV-related tax credits and other incentives in the IRA, which they have labeled as outgoing President Joe Biden’s “EV mandate.” 

Trump’s designated nominee to head the DOT is Sean Duffy, who served in the House of Representatives for Wisconsin from 2011 to 2019. Prior to running for office, he was on reality television and now is a Fox television commentator, with no apparent background in transportation. 

The Senate Committee on Commerce, Science and Transportation is scheduled to hold an advance confirmation hearing on Duffy’s nomination Jan. 15. 

A cutoff of federal incentives for EVs and EV charging might slow the transition to electric transportation but, as with other sectors of the U.S. clean energy transition, is unlikely to stop it. 

According to DOT, the U.S. now has more than 206,000 public chargers, including the 38,000 that came online in 2024, putting the country on track to reach Biden’s original goal of having 500,000 public chargers in operation by 2030, if not before. 

Year-end figures from Cox Automotive reported total U.S. EV sales of 1.3 million in 2024, a 7.3% increase from 2023, with a record 15.2% year-over-year increase in sales in the fourth quarter. 

The industry analyst anticipates that sales will continue to grow in 2025, as any rollback of incentives or other regulations will take time to implement. With 68 individual EV models now on the road, and 15 more coming, Cox predicts one in four U.S. car sales this year will “likely be electrified in some way ― a hybrid, plug-in hybrid or pure EV.”  

NEVI Update

The weakest link in Biden’s efforts to deploy more EV chargers has been the National Electric Vehicle Infrastructure (NEVI) program, which is distributing $5 billion in IIJA funds via state-level allocations set by formula. The five-year program requires states to submit annual plans for charger deployment before receiving their formula grants. 

Launched in February of 2022, NEVI was intended to build out a national network of DC fast chargers every 50 miles along state and interstate highways but has been slowed by a range of administrative, regulatory and technological roadblocks. 

For example, in some rural areas, the 150-kW fast chargers required for NEVI cannot be installed every 50 miles due to a lack of adequate distribution lines, and interconnection times for new stations can take as long as two years.  

As of the most recent NEVI update from the Joint Office of Energy and Transportation, at the end of November, 126 NEVI-funded public charging ports were in operation at 31 stations in nine states, and nine more states had awarded their first round of contracts for the installation of new NEVI stations. 

To help streamline and accelerate permitting of new chargers, the Pacific Northwest National Laboratory and Idaho National Laboratory released a report Jan. 6, with several recommendations, including: 

    • developing automated tools that can integrate the capacity of existing lines to accommodate new stations with analyses of new installation requests and EV adoption forecasts, while also improving transparency on the interconnection queue. 
    • improving interconnection processes and timing by creating fast-track options based on pre-screening, while also providing flexibility with phased-in approvals. 
    • sizing distribution system components to accurately reflect the demand requirements of new chargers and proactively investing in expanding grid infrastructure. 
    • improving grid reliability and resilience by using demand management and power control systems at EV charging stations and developing and implementing standards for communication between EV chargers and grid infrastructure. 
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PJM Stakeholders Mixed on Uplift Proposal

VALLEY FORGE, Pa. — PJM and its Independent Market Monitor presented a joint proposal to rework the balancing operating reserve (BOR) credit structure to address a scenario they say can result in generators receiving uplift payments despite not following dispatch orders. 

PJM Senior Director of Market Settlements Lisa Morelli said the current metrics determining BOR credits consider only the most recent five-minute interval, looking at what a unit was dispatched to do and how it responded.  The proposal would create a new Tracking Ramp Limited Desired (TRLD) metric used to determine uplift and deviation charges based on how a resource conformed to its dispatch signal over time. 

Morelli gave an example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch. Additionally, since dispatch is limited by ramp rates in the next interval, PJM could only bring it down to 95 MW again. 

As the intervals pass by, a widening discrepancy can form between where the unit is and where it would be had it followed instructions from the start, but the difference between the unit output and dispatch signal would remain 5 MW. 

Joel Luna, a market analyst with the Monitor, said that between 2018 and 2023, PJM paid $17.9 million in uplift to units that did not operate as requested. 

Stakeholder Takes

Several stakeholders requested additional time to review the proposal before the MIC votes on endorsement, which is currently slated for its Feb. 5 meeting. 

Erik Heinle, of Vistra, questioned why PJM could not use a unit’s security constrained economic dispatch (SCED) instructions to determine uplift and deviation charges. 

“You’ve got SCED telling you one thing, and you’ve got this backcast after-the-fact telling you something else,” he said. 

PJM’s Brian Weathers said SCED is optimal for determining uplift only if a unit is responding to the signal, but because it is parameter-limited, it becomes useless if a unit is not following instructions. He said the proposal is not meant to reduce BOR credits, but rather to “right size uplift” to be paid to those who follow dispatch instructions. 

A PJM example demonstrates how an illustrative unit could continue to receive uplift payments while not following dispatch instructions. | PJM

Luna said the proposal would not change the dispatch signal, which must continue respecting resource parameters to avoid creating power imbalances. 

“We’re not saying the signal is wrong, and that will remain the same. PJM will have to operate the system as given,” he said. 

Tom Hyzinski, of the GT Power Group, said if a generator is late to follow a signal to change its output, it could continue to rack up deviation charges while attempting to catch up. If locational marginal prices increase while a unit is ramping down, following the price signal to reverse direction and increase output could move it further from its TRLD, increasing deviation charges. 

Weathers said LMP profits would outweigh the deviation charges when prices might be above the tracking limit, meaning generators would maximize their profits by following SCED rather than chasing the tracking metric. 

Brock Ondayko, of AEP Energy, questioned how a unit can know if it is following TRLD in real time, adding that there needs to be incremental transparency into how this works.  

Since the best financial outcome for the generation owner is to follow SCED rather than trying to maximize uplift that may not be available, PJM doesn’t see the value in having the tracking limit available in real time. 

Rory Sweeney, of the Northern Virginia Electric Cooperative, asked if a systemwide analysis has been conducted to evaluate how the change would affect generators. Luna and Morelli said that had not been done, with Luna adding the impact would be positive because it would lead to more accurate market signals. Sweeney said the same belief was held when the status quo rules were implemented in 2022. 

The proposal also would add lost opportunity costs (LOCs) to the revenues that offset BOR credits, which Weathers said would avoid possible double payments between the two. 

Eligibility for BOR credits would be expanded to begin when PJM commits a unit, even if it was not online at that time, and continue through the end of the resources’ day-ahead commitment or minimum run time. Weathers said this could increase uplift when PJM actions cause a resource to miss its commitments, such as dispatchers holding a unit online longer and causing its minimum downtime to overlap with the start of its day-ahead commitment. 

Given the scale of the changes, Morelli said PJM would include simulated settlement results showing how the changes would impact market participants in late 2025, with actual implementation around a year later. 

“You’ll have a good long time period to look at the tracking limit time period and become comfortable with it before we start using it,” she said. 

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PJM OC Briefs: Jan. 9, 2025

Stakeholders Endorse Quick Fix Solution to Establish Wildfire Procedures

VALLEY FORGE, Pa. — The PJM Operating Committee endorsed revisions to Manual 13: Emergency Operations to add protocols for the RTO and transmission owners to monitor and coordinate actions when wildfires may disrupt infrastructure.

PJM’s Kevin Hatch said the fires in California highlight the need to be prepared and added that the PJM region has seen an increasing number of fires as well.

The language would direct the RTO to run studies to identify transmission assets that may need to be taken offline due to active fires in real-time and in advance, coordinate with TOs regarding canceling scheduled outages and bringing offline lines back to service and consider whether conservative operations may need to be initiated.

Transmission owners would be asked to monitor wildfire red flag warnings and notify PJM of high risk conditions, evaluate outages to determine whether any need to be recalled or rescheduled, identify facilities that may need to be derated due to wildfire impacts, and notify PJM of any circuits that may need to be de-energized due to active fires or to prevent sparking one.

System Performing Well During Cold Weather Advisory

The generation performance and communication between operators and unit owners was strong during the second day of a cold weather alert that was issued for the western region of PJM between Jan. 8 and 10, Hatch told the committee. Units were started early to ensure they would be able to operate as requested and maintenance was rescheduled to ensure availability.

As the cold weather moved in, outages increased by 2 GW, which Hatch said was a strong improvement over the 7 GW increase seen during the January 2024 Winter Storm Gerri.

“That correlates with very good generation performance, so I think that’s something we really need to note. There’s been a lot of work with generators preparing … and that seems to be paying off,” he said.

He noted that more cold weather was on the horizon the following week and generation owners had been asked to move any maintenance scheduled for that period to the preceding weekend. A cold weather alert has been issued between Jan. 14 and 16 for the western region.

December Operating Metrics

PJM’s Marcus Smith said the RTO saw a 1.52% peak hour forecast error rate for December 2024 and an hourly forecast error rate of 1.63%. Five days exceeded the 3% benchmark staff target, with overforecasting on Dec. 12, 23, 25 and 30 and an underforecast on Dec. 31. Loads came in lower on days when temperatures came in warmer than expected or when holidays led to smaller than expected peaks. The forecast models had a large spread of load ranges on Dec. 30 and 31, which he said was due to the aftermath of an unseasonably warm weekend and the holidays.

December saw four shared reserve events, one spin event, one high system voltage action and 16 post contingency local load relief warnings (PCLLRWs). One shortage case was approved Dec. 6 at 5:40 p.m. due to high loads and interchange. The spin event was declared on Dec. 11 at 6:21 p.m. and lasted six minutes. The 1,872 MW of generation assigned had a 73% response rate, while the 643 MW demand response committed had a 112% response.

Winter Voltage Reduction Testing Scheduled for February

PJM plans to conduct an RTO-wide voltage reduction test Feb. 5, with Feb. 12 set as an alternate if there are cold weather alerts, storms expected or other concerns on the earlier date. Regular tests of the capability were one of the recommendations made following the December 2022 Winter Storm Elliott, during which Hatch said dispatchers were one unit trip away from potentially beginning the first voltage reduction action since the 2014 Polar Vortex.

The first test was conducted in two parts Aug. 14 for the mid-Atlantic region and the following day for the west and south. The manuals assume an average peak load reduction of 1.6% across the mid-Atlantic, amounting to 635 MW. However, a reduction of 0.7% or 280 MW was observed during the test.

In the west and south, a 2.2% reduction is expected, or 920 MW, and the test resulted in a 0.85% reduction or 360 MW. Hatch noted the test was not conducted on a peak day, but it revealed TO equipment may need modification to handle an emergency voltage reduction action. Transmission owners also reported to PJM that the test was beneficial for staff education and in identifying improvements that can be made.

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Fire Agencies Investigating SCE’s Role in LA Fire, Utility Says

Fire agencies are investigating whether Southern California Edison’s equipment ignited one of the fires currently ravaging Los Angeles, the utility said in a news release Jan. 12. 

SCE stated that it filed electric safety incident reports with the California Public Utilities Commission related to the Eaton and Hurst fires. Utilities are required to file reports for incidents that meet certain criteria, such as media attention or governmental investigation, according to the news release. 

The utility filed one such report Jan. 10 after learning that fire agencies are investigating whether SCE equipment ignited the Hurst Fire in Sylmar, a neighborhood in Los Angeles. 

The Hurst Fire started late on the evening of Jan. 7, hours after the Palisades and Eaton fires had erupted. The blaze covered almost 800 acres and was 95% contained as of Jan. 13, according to the California Department of Forestry and Fire Protection (Cal Fire). 

SCE said the fire was reported at approximately 10:10 p.m. and that a 220-kV circuit experienced a relay at 10:11 p.m. A downed power line was discovered at a tower associated with the circuit, and “SCE does not know whether the damage observed occurred before or after the start of the fire,” the utility added. 

Jeff Monford, a spokesperson for SCE, told RTO Insider that the utility is “cooperating with a fire agency investigation.” 

SCE also filed an incident report related to the Eaton Fire after receiving “significant media attention” and preservation notices from counsel representing insurance companies. 

“It’s important to note that no fire agency has suggested that SCE facilities were involved in the ignition of the [Eaton] fire, and they have not requested the removal and retention of any of our equipment,” Monford said. 

The Eaton Fire began around 6:18 p.m. Jan. 7 and has burned over 14,000 acres. The deadly fire has engulfed parts of the Altadena community, with thousands of structures either damaged or destroyed. The flames have claimed at least 11 lives and continue to threaten nearby communities, according to Cal Fire. 

A preliminary analysis of the four energized transmission lines going through the area showed that there were no interruptions or anomalies in the 12 hours prior to the fire’s reported start time until an hour after the fire started, SCE stated. 

As of Jan. 13, out of SCE’s approximately 5 million customers, almost 40,000 were still without power due to public safety power shutoffs, and more than 400,000 were being considered to have their power turned off. Meanwhile, about 500,000 customers had their power restored in the past few days, Monford said. 

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Duke Names Harry Sideris as Company’s Next CEO

Duke Energy has named Harry Sideris its next CEO, effective April 1 when Lynn Good retires after more than a decade leading the utility holding company.

Sideris has been with Duke and its predecessor firms for decades and is the company’s president. It also was announced that lead independent director Ted Craver will become independent chair of Duke’s board of directors. The former Edison International CEO has been on Duke’s board since 2017.

“After a multiyear and comprehensive CEO-succession process, we are delighted that Harry will become our next president and CEO,” Craver said Jan. 13. “Harry’s nearly three-decade-long record of extraordinary accomplishments makes him uniquely qualified to lead Duke Energy. In an era of growth and rapidly evolving customer demands, Harry’s experience in operations, customer service, strategy, and stakeholder and regulatory engagement makes him the ideal choice for CEO.”

In addition to congratulating Sideris, Craver also praised Good for her tenure as CEO and her nearly 20 years with Duke.

“Her many contributions delivered value to our customers, shareholders and other stakeholders,” Craver said. “Thanks to her leadership, Duke Energy today is an industry leading, fully regulated utility company well positioned to thrive in the years ahead. Lynn’s legacy is defined by the power of her strategic course, an unwavering commitment to our customers and shareholders, industry-leading operations and safety, excellence in stakeholder engagement and the team she built.”

Sideris has been president at Duke since April 2024. He began his 29 years with the utility at Carolina Power & Light, which eventually became Progress Energy before it merged with Duke in 2012. He has led the firm’s electric and gas utilities, and his experience includes a variety of customer, operations and regulatory leadership roles.

“I am honored and excited to assume the leadership of Duke Energy at this dynamic time for our company and industry,” Sideris said. “I’d also like to thank Lynn for her leadership and guidance over the years. The valuable position that we’ve attained under her leadership, the opportunities before us, and our employees’ steadfast commitment to our customers and shareholders make our future bright.”

During Good’s time as CEO, she enhanced stakeholder engagement, modernized regulatory constructs in multiple states, developed innovative customer solutions, delivered industry leading safety and operations, and transformed the company into a pure-play portfolio of regulated utility businesses.

“It has been the honor of a lifetime to lead this company for the last 11 years and to serve with an industry leading team,” Good said. “Working with communities, policymakers and other stakeholders, I’m so proud of what we’ve accomplished. Duke Energy is in a strong and enviable position and, under Harry’s leadership, will surely seize upon the opportunities ahead to deliver for our customers, communities, investors and other stakeholders.”

In a filing the firm made Jan. 13 at the Securities and Exchange Commission, it said the board had approved an annual base salary of $1.3 million for Sideris, a short-term incentive opportunity of 150% of his base salary, and a long-term incentive opportunity equal to 750% of his annual base salary.

The document also noted that Good was retiring and that was “not the result of any disagreement regarding any matter relating to the corporation’s operations, policies or practices.”

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First FERC Filings Shed Light on New England OSW Tx Project

The transmission companies behind a major project to preemptively build two offshore wind interconnection points in New England have submitted their first FERC filings for the project, outlining the potential benefits of the project and the significant risks that could derail its development. 

The Power Up New England Project, a collaboration among the six New England states, Eversource Energy, National Grid and Form Energy, was selected in 2024 to receive $389 million from the U.S. Department of Energy’s Grid Innovation Program. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

The project would create two interconnection points, located in Massachusetts and Connecticut, each capable of accommodating up to 2,400 MW of offshore wind capacity. Power Up also proposes to build a first-of-its-kind 100-hour battery in Maine. (See Form Energy to Develop First Multiday Storage Project in New England.) 

National Grid plans to develop its interconnection point at Brayton Point in southern Massachusetts (ER25-866), while Eversource proposes to build its portion of the project at the Huntsbrook Junction in eastern Connecticut (ER25-747).  

In the initial FERC filings for the project, the transmission owners requested that the commission authorize the full recovery of all prudently incurred costs if the project is canceled because of factors beyond the companies’ control. They said they likely would need approval of this request to proceed with the project. 

“It is highly unlikely that National Grid would be able to develop and construct NGPUP in the absence of firm assurance that it can recover its full prudent investment in the project in the event of termination, cancellation or abandonment outside of National Grid’s control,” said Andrew Schneller, vice president of New England electric regulation and strategy at National Grid. 

Eversource also requested a 50-basis-point adder for giving ISO-NE control of the facility when built. 

The New England States Committee on Electricity (NESCOE) has expressed support for the Eversource and National Grid requests. In a filing supporting Eversource’s request, NESCOE wrote that the cost recovery assurances are justified because the project features a lower profitability and additional risks of cancellation relative to a typical project. 

The transmission owners will not be able to earn a return on the portion of the project investment covered by the federal grant and have agreed to give NESCOE the right to cancel the project if the costs exceed the original estimate. 

“Although NESCOE would ordinarily be skeptical of a request for an incentive that would allow a transmission developer to recover 100% of its prudently incurred costs for its abandoned plant, NESCOE agrees with [Eversource] that the full abandoned plant incentive is just and reasonable here given the uniqueness of the Huntsbrook Project,” NESCOE wrote. 

Power Up also faces unique limits on its development timeline. It must be in service within eight years of the finalization of the federal funding agreement, which National Grid wrote is likely to occur in early 2025.  

“Eight years is a tight schedule for a project like NGPUP in the best of times,” Schneller said, noting that worker shortages and supply chain delays for transmission equipment have increased since the COVID-19 pandemic. 

He added that the project faces political risks at the state and federal level. 

“A reduction of federal tax incentives for renewable energy development or a slowing of federal regulatory review of offshore wind generation licenses could lead the states to re-evaluate the feasibility or benefits of new projects,” Schneller said, adding that the project could face a funding shortfall if one of the New England states rescinded its support.  

Potential Benefits

While the project features substantial risks, the states and transmission owners expect it to bring significant cost, reliability and emissions benefits if it is successfully built.  

According to DOE’s Grid Deployment Office, the project would provide an estimated $1.55 billion in wholesale energy costs savings. Eversource estimated “the offshore wind enabled by the Huntsbrook Project will reduce wholesale energy supply costs borne by New England customers by approximately $498 million (2023 real dollars) over a 10-year period.” 

Benjamin D’Antonio, director of economic analysis and transmission strategy at Eversource, testified that the project would help reduce the risks associated with offshore wind interconnection, lowering “the risk premium that an offshore wind developer may include in their clean energy supply offer in the solicitation context.” 

The additions of offshore wind also would provide significant reliability benefits to the region’s grid, D’Antonio said. He estimated the addition of 2,400 MW of offshore wind at Eversource’s proposed interconnection point would reduce energy shortfall by 187,000 MWh over a worst-case, 21-day winter scenario.  

“ISO-NE has shown that offshore wind can provide significant resilience benefits to the New England electric and gas systems during extreme cold weather events by reducing both stress on gas pipelines and reliance on other fossil fuels such as oil,” D’Antonio said. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.) 

The 2,400-MW injection of offshore wind also would reduce carbon emissions by at least 3.6 million tons annually, D’Antonio noted.  

NESCOE wrote that its own analysis “showed similar results to Mr. D’Antonio’s analysis of the Huntsbrook Project.” It added that it projects Power Up to provide net benefits even with a 150% cost overrun, 50% decrease in benefits and three-to-five-year delay in offshore wind deployment. 

“Due in large part to the significant benefits provided by the DOE grant, net benefits remained positive unless NESCOE assumed that offshore wind projects were delayed by several decades,” NESCOE wrote.  

If successful, the project could serve as a model for additional projects focused on interconnecting the resources needed to meet load growth and decarbonize the grid. ISO-NE estimated in October that the region would need to add an average of 1,293 MW of offshore wind, 268 MW of onshore wind, 955 MW of solar and 952 MW of batteries per year to meet state goals. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) 

“The success of the Huntsbrook Project in establishing an onshore interconnection hub for offshore wind resources will offer a replicable model for any region aiming to integrate large-scale renewables like offshore wind,” Eversource wrote. 

However, the incoming Trump administration appears likely to attempt to roll back DOE funding for transmission projects, which would hurt the state’s chances at receiving additional funding for similar efforts over the next four years. The Heritage Foundation’s “Project 2025” calls for the Grid Deployment Office and the DOE Loan Program to be “eliminated or reformed.” (See How Much of the IRA Can be Saved in 2025?) 

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NERC Board Invokes Section 321 Authority for Cold Weather Standard

As snow and freezing temperatures enveloped the Central and Southeastern U.S. on Jan. 10, NERC’s Board of Trustees met virtually to exercise for the second time their authority to streamline the ERO’s stakeholder approval process in hopes of passing a cold weather standard before a FERC-imposed deadline in March. 

The board voted unanimously to invoke Section 321 of NERC’s Rules of Procedure, as recommended by the organization’s Regulatory Oversight Committee at its own special meeting before the board’s. The trustees’ decision was not a surprise, as NERC management has previously warned that the normal ballot and revision process was unlikely to produce a suitable revision to EOP-012-2 (Extreme cold weather preparedness and operations) in time to satisfy FERC’s directive. (See NERC: Board’s 321 Authority on the Table for Cold Weather Standard.) 

FERC approved EOP-012-2 (itself a revision ordered by the commission to address shortcomings of EOP-012-1) in June 2024, but it ordered additional “targeted modifications” to be completed by March 27, 2025. Although NERC has been working on the revisions since then, the replacement standard, EOP-012-3, garnered only a 44.54% segment-weighted vote for approval in its most recent formal ballot round that concluded Dec. 20. 

Board Chair Kenneth DeFontes had noted that the result was “not even close to reaching the required two-thirds [required] approval under our normal process, and the clock is ticking.” He said the ballot results indicated an “impasse” that will likely not be cleared through NERC’s normal processes. 

The board’s resolution directs NERC’s Standards Committee to work with stakeholders and ERO staff to prepare a standard that satisfies FERC’s order. If the committee is unable to draft a suitable standard, or determines that NERC’s management would be better suited to do so, then ERO management will write the standard. The standard will then be posted for a 45-day public comment period no later than Jan. 29. 

After the comment period, NERC management will bring the standard, along with all public comments, to a special meeting of the board in March to vote on adoption or consider other steps. No further ballots will be held, although the board’s resolution called for continued stakeholder involvement in the drafting and commenting process. 

This procedure differs from the last time NERC’s board invoked Section 321, to accelerate the development of PRC-029-1 (Frequency and voltage ride-through requirements for inverter-based resources) at its Aug. 15 meeting in Vancouver. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) In that case, the board ordered the SC to conduct a technical conference to gain industry input on the proposed standard, then revise it and submit it for stakeholder ballot. 

Under Section 321.2-321.4, a standard needs only a 60% segment-weighted approval to pass; for this reason, NERC staff have informally dubbed the plan used for PRC-029-1 the “60% path.” The process proposed for the cold weather standard is found in Section 321.5; because it resembles a rulemaking procedure more than a normal balloting process, NERC Vice President of Engineering and Standards Soo Jin Kim said staff have called this the “NOPR option,” referring to federal Notices of Proposed Rulemakings. 

Trustee Sue Kelly noted that NERC already held a technical conference for this standard after it received a 42.29% segment-weighted approval vote in its first formal ballot round and that even though the conference had more than 400 attendees, the favorable vote only increased by just over 2%. Because of this, she said it seemed unlikely that enough industry support could be rallied in time to meet FERC’s requirement, even with another technical conference. 

“I … looked at the summation of the comments from the last [ballot] round, and honestly, I was a little distressed to see that many of them are what I would describe, at this point in the game, as being off-topic,” Kelly said. She cited comments that said market forces should be enough to drive utilities to the right level of winterization, or that NERC did not have the statutory authority to create the standard “because it would have competitive implications for generators.” 

“I found those comments pretty distressing, because when you step back and look where we are in this process — back in January 2014, NERC wanted to do a mandatory standard, and industry said, ‘No, let’s do a guideline,’” Kelly continued, noting that since that time, several severe winter storms have hit the U.S. with significant impacts to the grid. “We are way down the road at this point: We are being asked to [meet] specific FERC directives, [and] we’ve been told we have a time frame, and I believe that we … need to meet that challenge.” 

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WEIM Q3 Prices Down Despite Increased Loads, CAISO DMM Finds

Prices in CAISO’s Western Energy Imbalance Market fell sharply in the third quarter of 2024 compared with a year earlier, as declining gas costs outweighed the impact of increased summer loads, the ISO’s Department of Market Monitoring (DMM) found. 

Fifteen-minute market prices across the WEIM averaged about $40/MWh, down 31% from Q3 2023, while the five-minute price average fell by 32%, according to the DMM’s Q3 Report on Market Issues and Performance, which also touched on two issues supporters of SPP’s Markets+ raised late last year in one of a series of “issue alerts” comparing the SPP market to CAISO’s Extended Day-Ahead Market (EDAM). 

Day-ahead prices, which currently apply only to CAISO’s balancing authority area, fell by 28% year over year, the DMM found.

“Lower gas prices … brought electricity prices down with them,” Ryan Kurlinski, senior manager in the ISO’s Market and Policy Analysis Group, said during a Jan. 9 call to discuss the DMM report. 

Kurlinski noted that Q3 gas prices were down 37 and 58%, respectively, at the PG&E Citygate and SoCal Citygate delivery points in California and fell by 60% at the Sumas hub in the Pacific Northwest. 

Northwest hydroelectric output also increased by 15% compared with a year earlier, making the region a net exporter on average during all-in hours for the quarter. 

In the WEIM’s 15-minute market, prices averaged $47.50/MWh in California (down 27%), $35.60/MWh in the Desert Southwest (down 27%) and $33.30/MWh in both the Intermountain West and Pacific Northwest (down 23% and 30%, respectively). Powerex average prices declined by 60% to $37.90/MWh. 

“The [greenhouse gas] costs in California were the main contributors to elevating prices in California balancing areas relative to other WEIM balancing areas,” Kurlinski said.  

He added that “significant congestion” on WEIM transfer constraints into the Powerex and Bonneville Power Administration BAAs led to relatively higher prices there relative to other non-California BAAs.  

The DMM also found that WEIM 15-minute market prices in the Northwest and Southwest were “significantly lower” than bilateral market day-ahead prices for power traded on the Intercontinental Exchange for the Mid-Columbia and Palo Verde hubs. In contrast, prices for day-ahead power traded in CAISO’s integrated forward market (delivered in the Pacific Gas and Electric and Southern California Edison areas) tracked more closely with 15-minute prices, reflecting the kind of price convergence that organized markets are designed to achieve. 

In Q3, average hourly prices continued an ongoing pattern of following net load, with the highest prices occurring during net peaks accompanying evening ramps and — to a lesser extent — morning peaks.  

Loads, Renewable Output up

The DMM found load in the WEIM increased 4% compared with the third quarter of 2023 and had more hours with high system load (over 110 GW) and fewer hours with low system load (below 80 GW). 

The Monitor additionally determined that peak load in most WEIM BAAs did not coincide with the market’s overall system peak load of 135 GW occurring July 10, which Kurlinski noted was much lower than the sum of the peak load for each individual BAA: 146 MW. 

“This 11-GW difference is one way of describing the benefit of multiple balancing areas [having] peak loads occurring on different days and times and being in one market,” Kurlinski said. 

The report showed WEIM hourly transfers averaged about 4,560 MW, down 10% from a year earlier. 

“During mid-day solar hours, the majority of regional transfers were from the CAISO area to the Pacific Northwest and non-CAISO California areas. During morning and evening hours, the Desert Southwest was the major exporting region,” the report said. 

Average hourly generation from WEIM renewable resources increased by 4,110 MW (11%), with solar accounting for more than 60% of the increase. Meanwhile, average output from coal-fired generators in the Intermountain West fell by 1,220 MW (27%) while gas generation increased by 810 MW (28%).  

Batteries played a much greater role in operations compared with a year earlier, as average hourly battery discharge in California and the Desert Southwest increased by 550 MW (87%) and 310 MW (130%), respectively. (See Batteries, Energy Transfers Support ‘Uneventful’ Summer in West.) 

Kurlinski pointed out that 10 WEIM entities opted into the market’s assistance energy transfer program for at least one day during Q3, with seven receiving additional transfers after failing the WEIM resource sufficiency evaluation (RSE) ahead of a delivery interval. Public Service Company of New Mexico, which failed the RSE’s upward flexibility test during 1% of intervals, was the largest recipient of assistance transfers. 

Special Issues

The DMM report additionally touched on two matters raised by supporters of Markets+ in a November “issue alert” that took aim at CAISO’s dual roles as operator of and participant in the EDAM, which will expand the scope of the WEIM to include day-ahead trading. (See Markets+ ‘Alert’ Covers CAISO’s Dual Roles as Market Operator, BA.) 

The first of those matters deals with “load conformance,” a WEIM process that allows a participating BA to adjust its demand forecast in the hour-ahead scheduling process (HASP) and 15-minute market to better position itself for a real-time interval.  

In the alert, Markets+ supporters contended that, among WEIM entities, CAISO has a “unique” history of making unusually large upward adjustments to its demand forecasts during morning and evening peaks “to acquire flexible capacity through additional energy imports rather than explicitly purchasing flexible capacity itself.” CAISO has contested the second part of that contention, while pointing out that the adjustments carry a financial price for the ISO. 

While the DMM’s Q3 report didn’t wade into that specific controversy, a “special” section within the report notes that “[t]he size and frequency of CAISO balancing area operators’ use of imbalance conformance in the 15-minute market made it an outlier amongst WEIM areas” in the third quarter and resulted in increases in average hourly imbalance conformance adjustments in the hour-ahead and 15-minute markets relative to Q3 2023, especially during evening ramps. 

“Imbalance conformance over the evening peak net load hours continued to be significantly larger in the hour-ahead and 15-minute markets than in the five-minute market. This contributes to higher prices in the 15-minute market than in the five-minute market over these hours,” the DMM said. 

The second matter in the November issue alert dealt with CAISO’s decision in 2023 to block WEIM transfers into the ISO in the HASP and 15-minute market — but not real-time — during net peak load hours from July to November. The Markets+ supporters pointed out that the DMM itself had determined the practice “created a significant, systematic modeling difference between the 15-minute and five-minute markets,” which negatively “impacted market results in several ways.”  

CAISO countered that it imposed the limits after large volumes of WEIM transfers scheduled in the HASP began failing to materialize in real time. 

The DMM report noted that CAISO didn’t resume the practice at all last summer.  

“California ISO balancing area operators did not implement peak hour dynamic WEIM transfer restrictions into the CAISO area during any hours of the third quarter of 2024,” it said. 

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Benefits of Fast-start Pricing Questionable, CAISO DMM Says

Establishing a fast-start pricing mechanism in CAISO and the Western Energy Imbalance Market (WEIM) is complex and would bring few benefits compared with other potential market enhancements, the head of CAISO’s Department of Market Monitoring (DMM) said Jan. 10.

Though other organized markets have introduced the mechanism, doing so in the WEIM would be complex because WEIM has “some very unique features,” such as a flexible ramping product and multi-interval optimization, that do not exist in the other markets, said Eric Hildebrandt, executive director of CAISO’s DMM, during a presentation to a meeting of the Western Energy Markets Body of State Regulators.

Hildebrandt said fast-start pricing should not be prioritized over other potential market enhancements such as a “new or better real-time product for managing uncertainty and ramping capacity.”

“We have a 15-minute flexible ramping product in the real time market,” Hildebrandt said. “But frankly, it doesn’t do much, because it only looks out 15 minutes and the operators really need to look one to two hours out in terms of positioning units so that we have enough capacity to ramp up and meet uncertainty.”

Out of the six FERC-jurisdictional organized markets, CAISO alone doesn’t use fast-start pricing, a mechanism that factors the cost of starting and operating gas-fired peaking units into the wholesale market price.

In December 2023, CAISO presented its own analysis of fast-start pricing and sought stakeholder feedback for developing its scope.

Proponents have argued that fast-start pricing can decrease bid cost recovery and support new investments in new supply and ramping capacity, among other benefits.

The issue has also turned up in the competition between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+, with Markets+ supporters such as Powerex and other Northwest entities faulting the ISO for not including fast-start pricing in the EDAM’s initial design.

But Hildebrandt said data reveals that bid cost recovery for gas peakers is already low in the CAISO balancing area. For example, bid cost recovery paid to fast-start combustion turbines in the CAISO balancing area totaled about $32 million in 2022, or about 16% of total bid cost recovery payments to gas resources, according to DMM.

The numbers are lower in the WEIM footprint. Approximately $1 million was paid out in 2022, or about 3% of total bid cost recovery payments to gas resources in WEIM areas.

The 15-minute locational marginal pricing is usually sufficient to cover the startup minimum load energy costs of the peakers that are committed, Hildebrandt said.

“At least in our markets, there doesn’t seem to be significant benefits there, in terms of decreased bid cost recovery,” he added. “And I think that is reflection that they’re not used. These units are not usually being dispatched where there’s a big disconnect between the prices and their costs.”

Similarly, data does not support claims that fast-start pricing will lead to significant investments in new generation resources, according to Hildebrandt.

“You can argue anything that raises prices increases investment in new supply and ramping capacity,” Hildebrandt said. “But again, I think some of the data show that the increase from fast-start pricing is not going to have a significant impact on that.”

“In all the markets in the West, new investment comes from resource adequacy,” he added. “You know, utility planning, resource planning, and not from energy market revenues. So we question the benefits there.”

Hildebrandt also argued that CAISO should not be swayed by the fact that other ISOs have fast-start pricing, saying the Eastern ISOs introduced the pricing mechanism more than 10 years ago when they still had old and “very lumpy peakers.”

“They were more geared toward hourly prices rather than the five- or 15-minute prices that we’ve really kind of based the markets on out here in the West due to the higher penetration of renewables,” Hildebrandt said.