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January 23, 2025

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President Trump Names Mark Christie as FERC Chair

President Donald Trump named Mark Christie as FERC chair, hours after he was sworn in during a ceremony in the U.S. Capitol Rotunda.

“I am honored to be appointed FERC chairman by President Trump,” Christie wrote on X. “For four years I have emphasized protecting consumers from excessive power bills, meeting the reliability crisis driven by losses of dispatchable generation and failure to build new generation, in the face of rising demand.”

Meeting those priorities will be his first priority, and Christie added he believes states should be “full partners with FERC” in protecting consumers and ensuring reliability.

The President can pick the FERC chair from among sitting commissioners. The move means former Chair Willie Phillips will become just another commissioner, if he decides to stay. In his last press conference at the helm of the agency Jan. 16, Phillips declined to publicly discuss his plans.

“I told you all from the beginning: Reliability is job No. 1 of the commission,” Phillips said. “I am very proud of the work we’ve done to protect the reliability of our system for our nation.”

Phillips’ term runs through June 2026. If he stays on, Christie will work with a 3-2 Democratic majority for the first year and a half. Christie was appointed by Trump in July 2020, and his term expires this June, though he could be renominated. Even if he is not, he can stay until the end of the year when Congress adjourns absent a replacement being confirmed.

Christie said in an interview that the new job is “an awesome responsibility” and though he was chair of the Virginia State Corporation Commission, FERC is at a bigger scale.

“And the biggest thing you know at my age is you realize how many — literally millions of people — are going to be affected by what you do,” he said. “I mean, what we do affects their monthly power bills, and that is a tremendously daunting challenge. We’ve got to make sure that we do everything we can to minimize the impact on the people’s monthly power bills.”

Reliability will continue to be a big focus under Christie, as demand is growing while power plants continue to retire. He has talked about a reliability crisis in public remarks for several years.

“It is absolutely deteriorating, and that’s not my opinion,” Christie said. “We see that in the reports from NERC. You see it in the reports from the RTOs, like PJM. We continue to lose the very resources we need to keep the lights on and the heat pumps going.”

With a cold front hitting the East Coast this week, PJM could break its all-time winter demand record and has fewer resources than it did last year, he added.

FERC has no control over why demand is going up, which largely is due to the expansion of data centers in the development of artificial intelligence.

“We have to accept that we have to serve load, and that’s going to mean keeping the generating resources that we need and stopping the retirements and building the new resources,” Christie said. “Those are big issues, and we have to address them. It really is supply and demand. It’s no more complicated than that.”

Tightening supply and expanding demand generally means higher prices, so Christie will look for ways to control those. One position he’s made clear in numerous dissents is that transmission incentives should be reined in. He also said he wants to address local transmission projects, which in PJM are 80% of the recent construction and often are lightly regulated. (See How FERC Under Trump Might Advance Energy Affordability in 2025.)

“As a utility regulator, I know that you’re always faced with the challenge of balancing the need for utility assets like transmission and generation with the need to keep costs down for customers,” Christie said. “And it’s a tough balance … but it’s what utility regulators do.”

One issue that roiled the FERC world after Trump’s election was his campaign promise to remake how the federal workforce is overseen. What that means for an independent regulatory agency like the commission remains to be seen. (See Chatterjee Post Leads to Worries About FERC’s Independence, Staff Exodus.)

Without any formal guidance from the White House on the federal workforce front, Christie declined to comment.

While the administration and Senate have changed parties and that will have an effect on FERC, by design it will not have as big an impact as on other executive agencies.

“Things don’t change overnight at FERC, because obviously we’re a multi-member commission, and you have to have a majority to do anything,” Christie said. “But I think there’s a lot of agreement among my colleagues on the need to address these issues.”

Trump also Elevates Wright to NRC Chair

Christie is not the only former state regulator to get a promotion on a federal regulatory agency. Trump tapped David Wright to be chair of the Nuclear Regulatory Commission in the same announcement. Wright has been on the NRC since 2018 and was on the Public Service Commission of South Carolina from 2004 to 2013, which included a stint as chair.

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Counterflow: A Climate ‘Game of Chicken’

It has become increasingly clear that environmentalists are engaged in a game of chicken, with Earth in the balance.

The environmental community by and large will not tolerate any consideration of Plan B, solar geoengineering (such as sand or salt in the stratosphere), which I’ve discussed before, contending this would discourage measures necessary to get to net zero (Plan A).

Gale Force Headwinds for Plan A

Meanwhile, the world isn’t adopting the requisite Plan A measures for a slew of reasons, such as the reality that renewable resources are expensive, especially when they have to be firmed up by storage to cover renewable droughts. And we need to remember that higher electric rates are themselves deadly.

Steve Huntoon

Carbon dioxide is the ultimate negative externality, meaning that any given reduction by any individual, state or even country provides no particular benefit to whoever makes the reduction. And that’s assuming that carbon reduction measures actually work — a Herculean assumption given actual results over the past 20 years.

And it won’t be enough to reverse the annual increase in the world’s carbon emissions (whenever that might happen). As The Economist points out, “what matters to the climate is not the rate of emissions, but the cumulative total. Until that stabilizes, all other things being equal, temperatures will continue to increase.”

Please note that Plan B need not last long if the environmental community is right that renewable energy actually is cheaper than fossil fuel energy or will become so. But so far that’s not what the world is experiencing, as I’ve discussed and as a recent Wall Street Journal op-ed piece reinforced.

The Fear Factor

Let me address one other objection to solar geoengineering — that it might do scary things (just plug it into Google and you’ll get a parade of horribles). This objection ignores that we have been putting toxic aerosols like sulfur dioxide into the atmosphere for a couple of hundred years. As I discussed before, these toxic aerosols have greatly reduced global warming from what it otherwise would be, and the recent reduction in toxic aerosols due to regulation is greatly adding to global warming from what it otherwise would be. Yes, it’s ironic.

The key takeaway is that solar geoengineering could replace the toxic aerosols of the past with non-toxic aerosols like sand or salt. Not very scary.

Wrapping up

Where does that leave us? Because the environmental community cannot change the economic fundamentals driving decisions by most of the world, it should reconsider its demand that the world suffer the consequences of these decisions. The environmental community should constructively engage on Plan B.

The impossible dream should not be the enemy of the possible good.

P.S. For something completely different: If you’re a fan of classic rock, I’ve compiled, dare I say it, “iconic” videos from that bygone era.  And best wishes for the new year!

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PUC Steers VT Legislature Away from Clean Heat Standard

Vermont’s Public Utility Commission continues to shy away from the Clean Heat Standard mandated in a landmark 2023 law. 

The PUC on Jan. 15 reported to the state Legislature that while the standard (with changes) would be “theoretically workable … the commission does not believe that this program is well suited to Vermont.” 

The PUC recommended that legislators consider other ways to reduce greenhouse gas emissions — such as a fuel tax, thermal efficiency benefit charge or a biofuel blending requirement, or some combination of these or other alternatives. 

A few months earlier, the PUC determined the credit-trading system envisioned in the legislation would be costly and complex and that it made no sense for a small state to create such a system on its own. (See Vermont PUC Rejects Heating Fuel Credit Trading Concept.) 

In the Jan. 15 report, the PUC said its task — study the costs and benefits of the system while designing it — was complex and difficult and that its conclusions should be treated as a very rough estimate. 

With that caveat, it said the Clean Heat Standard could carry program costs of $956 million in its first decade, with an impact on fuel oil prices gradually rising from 8 cents per gallon in the first year to 58 cents in the 10th year. 

The estimated value of the greenhouse gas emissions reductions yielded by the standard over the same decade would be $477 million. 

The PUC said its recommended alternative mechanisms would be less complex and have lower administrative costs than the Clean Heat Standard. 

The fuel tax option would be simple and efficient, the PUC said, as it would be an expansion of the fuel tax mechanism that for many years has been sending money to the low-income Weatherization Trust Fund. 

A thermal efficiency benefit charge could function similarly to the electric energy efficiency charge collected by the state’s electric distribution utilities and could run alongside the fuel tax that fuel dealers collect. 

Neither of these alternatives would achieve the greenhouse gas emissions reductions required under the Global Warming Solutions Act of 2020, the PUC wrote, but increasing the amount of biofuel burned in Vermont would accomplish this, and a blending requirement could be complementary to the fees. 

Legislators now must decide whether or how to implement the Clean Heat Standard. Democrats still control both chambers of the Legislature but have lost seats since 2023, when they overrode a veto by Gov. Phil Scott (R) to make the Clean Heat Standard a law. 

Local media reports suggest legislators remain concerned about the financial impacts of such a system, particularly on lower-income Vermonters who spend a larger portion of their income heating their homes during the state’s long, cold winters.  

Vermont has among the highest percentages of homes heated with fuel oil of any state. 

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DC Circuit Vacates LNG Rail Safety Rule from First Trump Administration

A three-judge panel on the U.S. Court of Appeals for the District of Columbia has vacated a safety rule on transporting liquified natural gas over rail.

The Sierra Club, a group of state attorneys general and others filed an appeal of a rule crafted by the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) authorizing LNG’s transportation in newly designed tank cars with no permit required.

“The new final rule … imposed no limit on the number of LNG tank cars that could be included in a single train and set no mandatory speed limit for trains that carry LNG,” said the Jan. 17 decision.

One company was considering a single train with 80 cars carrying LNG, when a group of environmentalists said that the explosive force of just 22 cars full of LNG would be the equivalent of the atomic bomb dropped on Hiroshima.

In addition to being highly flammable, LNG has the risk that if its temperature rises, it can expand and place tremendous pressure on tanks leading to an explosion. If it is spilled without igniting, it can form an ultra-cold gas cloud that quickly expands, severely injuring people and damaging property in its path, the court said.

PHMSA determined shipping LNG by rail would have no significant impact on the environment and declined to prepare an environmental impact statement. Sierra Club and other petitioners argued that the National Environmental Policy Act required the agency to craft an EIS and its failure to do so was arbitrary and capricious. The court agreed, vacating the rule for additional proceedings at PHMSA.

Historically, LNG could be transported only by truck or pipeline, and shipping it by train required a special, one-off permit. That changed after President Trump issued an executive order in 2019, which told PHMSA to issue a blanket approval for shipping LNG by rail.

The agency authorized that the fuel could be shipped in tank cars that had been operating on the rails for decades and were designed to carry cold, dense gases. The rules for shipping similar chemicals involved communication, and the rail industry adopted a voluntary speed limit of 50 mph when trains had more than 20 cars with them. PHSMA proposed no such limits to trains hauling LNG.

Opponents criticized the rule for failing to take the risk of an accident seriously and for failing to put a speed limit or a cap on the number of cars. They also argued the train cars to be used, DOT-113 tank cars, had seen 14 breaches in prior incidents and petitioners questioned their record, as did the National Transportation Safety Board.

PHMSA did require some upgrades for the cars to carry LNG, including a thicker outer tank and better steel, calling the new model a “120W9” car. It also authorized the new cars to carry a higher density of LNG, raising it from 32.5% of total volume to 37.3%.

The agency required special monitoring equipment for all LNG cars and required trains with 20 in a row, or 35 in total, to have special braking technology. Railroads also were required to consider safety risk factors such as population density when scheduling LNG shipments.

After President Biden assumed office, PHMSA suspended the July 2020 rule, but it did not complete a replacement.

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SCE Faces Scrutiny and Risks Amid LA Wildfires

Though no utilities have been blamed for the deadly wildfires in Los Angeles so far, stakeholders have cautioned that companies like Southern California Edison are not completely out of the woods and still face financial and legal risk. 

Commenting on the wildfires in a Jan. 16 newsletter, investment bank Jefferies noted that electrical monitoring company Whisker Labs did not find evidence of a major transmission line fault before the Eaton Fire erupted. The blaze burned more than 14,000 acres, causing damage to thousands of structures and at least 17 fatalities, according to officials. 

However, Whisker Labs found there were energized distribution lines west of Eaton Canyon despite warnings about high winds prior to the fire’s start, the newsletter stated. 

Whisker Labs cannot point to a specific source for any fault event, but “based off of multiple faults detected in the lead up to the fire’s reported start time, the team confirmed with certainty there were energized distribution lines west of the fire,” according to Jefferies. 

SCE, one of the area’s largest utilities, told RTO Insider on Jan. 13 that no fire agency has suggested its facilities were involved in igniting the Eaton Fire. 

Local utility Pasadena Water and Power also operates in the region. 

Still, if SCE’s equipment is found to be at fault down the line, the utility’s credit rating could take a hit, Moody’s Ratings cautioned in a report Jan. 16, per Reuters. The report also said the company could see financial damage if the California Wildfire Fund runs out of money. Utilities pay into the fund to receive reimbursements for some wildfire claims. 

Additionally, legal challenges are already starting to trickle in. Some affected by the Eaton Fire filed lawsuits against SCE last week, alleging the blaze began under one of the company’s transmission towers. SCE has also received preservation notices from counsel representing insurance companies. 

Another issue is whether SCE took adequate measures to mitigate risks under its California Public Utilities Commission-approved Wildfire Mitigation Plan, Jefferies contended. 

“To date, we have not seen evidence supporting ‘serious doubt’ of prudency, but we will be closely looking to see whether EIX followed its preemptive safety power shutoffs to the letter,” Jefferies stated. 

Fire agencies are investigating whether SCE equipment was involved in the smaller Hurst Fire, the utility announced Jan. 12. 

SCE said the Hurst 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. 

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NYISO Operating Committee Approves LCR for 2025

The NYISO Operating Committee has approved the final Locational Capacity Requirements for the 2025/26 capability year. These were the same LCR values presented earlier to the ICAP working group.  

The LCRs, expressed as a percentage of the peak load forecast, represent the minimum capacity New York’s generators and load-serving entities must maintain within each of the downstate zones, which have transmission constraints.  

“I’m going to vote yes because the ISO did the LCR study consistent with all its rules,” said Mark Younger of consulting firm Hudson Energy Economics. “However, I am quite concerned that we still have a major inconsistency between the transmission security needs that are represented in the TSLs [transmission security limits] and ultimately affect the LCR.” 

2025-2026 final LCR results | NYISO

Younger said this had been an issue for several years, had been undercutting price signals and was more important now because the ISO had found a reliability need in its most recent RNA. 

Operations Report, December 2024

NYISO also presented the monthly Operations Report for the previous month. The peak load, 23,065 MW, occurred Dec. 23, 2024. 

Over the last month of 2024, 2,736 MW of land-based wind, 136 MW of offshore wind, 6,048 MW of behind-the-meter solar and 571 MW of front-of-the-meter solar were installed. Additionally, 63 MW of energy storage was installed.  

Aaron Markham, vice president of operations, noted that NYISO was taking preparatory action for severe winter weather. NYISO said it was prepared to meet anticipated demand for the current cold snap.  

NYISO expected demand to peak at 24,400 MW on Jan. 21 and 24,200 MW on Jan. 22. 

NYISO’s 2024/25 Winter Assessment found that 29,514 MW of resources were available statewide; 2,275 MW were available through emergency dispatch. 

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NECA Conference Previews the Future of Markets in the Northeast

BOSTON — Managing the often-at-odds priorities of affordability, reliability and decarbonization will require a delicate balance of innovation, market reforms and stability, industry experts told attendees of the Northeast Energy and Commerce Association’s Power Markets Conference on Jan. 16. 

Speakers discussed some of the major changes on the horizon for the region’s wholesale markets as grid operators prepare for significant load growth and an increasingly distributed and intermittent resource mix.  

ISO-NE is undergoing a major effort to reform its capacity markets, which includes resource accreditation updates and changes to the timing and format of capacity auctions. FERC accepted similar accreditation changes for NYISO in July, which will take effect in 2026. (See FERC Accepts NYISO Capacity Accreditation Changes, with 1-Year Delay.) 

Chris Geissler, director of economic analysis at ISO-NE, said the RTO is trying to design the accreditation methodology so “everyone is essentially selling the same product.” 

The proposed accreditation framework is intended to quantify how a resource would perform during the periods with the greatest reliability risks, meaning that assumptions related to the resource mix, outages and demand profile could have major effects on how different resources are valued. 

For example, adding wind capacity would improve grid reliability during the periods with high wind, reducing the reliability value of subsequent additions of wind resources, Geissler said.  

Meanwhile, energy storage likely will be complementary to weather dependent resources. Increasing the amount of solar or wind power on the system could improve the reliability contributions of energy storage, Geissler noted.  

Michael Borgatti, senior vice president of RTO services and regulatory affairs at consulting firm Gabel Associates, said the nearly 10-fold increase in prices in PJM’s most recent capacity auction should serve as “a cautionary story for all other RTOs across the country, including NYISO and ISO-NE.” (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

Capacity prices are “a symptom of how you set the underlying supply and demand fundamentals,” Borgatti said, adding that PJM determined its capacity need on an unprecedented extreme scenario. 

“PJM built its capacity model on the backs of Winter Storm Elliott,” Borgatti said. “They wanted to make sure their model reflected the possibility of these big dangerous storms matching up with the highest load.” 

Despite the high prices in PJM, uncertainty regarding potential changes to PJM’s capacity market makes it hard for developers to invest in new resources that could help address the lack of capacity, Borgatti said. 

New Market Mechanisms

While ISO-NE’s capacity accreditation reforms likely will increase compensation for dispatchable resources that provide winter reliability benefits, ISO-NE has indicated new market mechanisms may be needed to support resources that are called upon only in extreme situations. (See ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability.) 

The RTO’s Economic Planning for the Clean Energy Transition (EPCET) study, published in October, found a major need for dispatchable resources to meet a higher and increasingly variable winter peak. The resources, ISO-NE noted, “may only run once every few years.” (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) 

The EPCET study also found ISO-NE’s energy market likely will decrease in value as renewables supported by power purchase agreements come online, with the capacity market and PPAs increasing in importance. The RTO also outlined concerns that the current PPA model will struggle to support new resources starting in the mid-2030s.  

“We’re going to need steel in the ground,” said Jeff Turcotte, assistant vice president of government affairs at the Electric Power Supply Association. “Markets are going to have to continue to signal that investment.” 

“If we are thinking about big ideas and big investments … some of those answers are already out there.” Turcotte said, pointing to the Pathways Study, which Analysis Group conducted for ISO-NE in 2022.  

Cutler Cleveland, professor at Boston University | © RTO Insider LLC 

The Pathways Study considered several strategies for decarbonizing the grid to meet state goals and ultimately concluded that net carbon pricing would be the most cost-effective way to reduce power sector emissions in the region. (See Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE.) 

However, adopting net carbon pricing would require buy-in from all six New England states, which so far has prevented further development of this proposal. 

“ISO-NE has made it very clear that it thinks net carbon pricing is the most efficient way to decarbonize the grid,” said Ashley Gagnon, senior director of Massachusetts’ office of Federal and Regional Energy Affairs. “From Massachusetts’ perspective, we’re always interested in having conversations about new market mechanisms to in connection with the future grid.” 

Cutler Cleveland, associate director of the Institute for Global Sustainability at Boston University, emphasized the importance of rapid decarbonization.  

“It’s quite clear that we’re not moving quite as fast as we need to avoid the wheels coming off the bus,” Cleveland said, outlining the wide range of severe consequences climate change is projected to have on human mortality, disease vectors, air and water quality, and labor productivity. 

“Business as usual with decisions driven only by market forces will not work,” he said, adding opposition from politicians and the public to climate policies — including carbon pricing — “is a real problem.” 

Demand Response and Load Flexibility

Another major topic of the conference was how the region can unlock savings by shifting demand away from peak hours as the electrification of transportation and heating accelerates. 

The costs savings of reducing the region’s peak load could be massive: ISO-NE’s 2050 Transmission Study found that a 10% reduction in the projected 2050 peak could save nearly $10 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

Across the region, utilities are working on advanced metering infrastructure (AMI), which should enable incentives for residential customers to decrease peak demand. In Massachusetts, the utilities plan to complete their rollout of AMI by 2030, which likely will be followed by some form of time-varying rates. (See Mass. Electricity Rates Working Group Issues Recommendations.) 

While there was some disagreement between speakers about whether policymakers should focus on automating demand response or rely on real-time pricing to incentivize behavioral changes, most agreed automating demand response for willing customers will be an important piece of the puzzle.  

George Twigg, executive director of the New England Conference of Public Utilities Commissioners (NECPUC), said residential demand response likely needs to be automated to reach a wide scale. He noted that the commercial and industrial sectors — despite the attention given to the residential sector — likely hold the greatest potential for demand response.  

Austin Dawson, deputy director of energy supply and rates at the Massachusetts Department of Energy Resources, said the state likely will need “some significant reforms” to rate design to make the most of advanced metering infrastructure, adding that long-term recommendations from the state’s Interagency Rates Working Group should be released later in January. 

While electric vehicle load probably is the easiest to shift, “I don’t think we can write off heating load as a flexible end use,” Dawson noted.  

He emphasized the importance of research and pilot programs to prepare for the transition to a winter-peaking system, which ISO-NE expects to occur in the mid-2030s. 

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PJM MRC/MC Preview: Jan. 23, 2025

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Jan. 23. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will cover the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:20)

B. Endorse proposed revisions to Manual 01: Control Center and Data Exchange to conform to FERC‘s approval of PJM’s second phase of hybrid generation rules. The package also includes changes identified through the manual’s periodic review.

C. Endorse proposed revisions to Manual 01 to establish alternative communication protocols for use during an unexpected​ outage of PJM’s EMS Real Time Assessment (RTA) capabilities. (See “Several Manual Revisions Endorsed,” PJM MRC/MC Briefs: Dec. 18, 2024.)

Issue Tracking: EMS Telemetry Protective Measures

D. Endorse proposed revisions to Manual 27: Open Access Transmission Tariff Accounting and Manual 29: Billing resulting from their periodic review. The changes include removing outdated references and spelling corrections.

E. Endorse proposed revisions to Manual 38: Operations Planning drafted through its periodic review.

Endorsements (9:20-11:05)

  1. Manual 14H: New Service Requests Cycle Process Revisions (9:20-9:45)

PJM’s Jonathan Thompson will present revisions to Manual 14H: New Service Requests Cycle Process to add to PJM’s site control requirements for projects in the interconnection queue. Renewable developers have objected to the changes, arguing that they will require them to hold onto land not necessary for their projects, while PJM has held that a common standard is needed. Voting was delayed from the committee’s December meeting. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.) 

The committee will be asked to endorse the proposed manual revisions at this meeting. 

Issue Tracking: Site Control Modification Clarification 

  1. Modeling Users Forum (MUF) Charter (9:45-10)

PJM’s Jeff Schmitt will review a proposed charter that would convert the Data Management Subcommittee (DMS) to the Modeling Users Forum. The change would facilitate having more frequent meetings that focus on modeling tools and more long-term initiatives. 

The committee will be asked to approve formation of the Modeling User Forum at this meeting. 

  1. Deactivation Enhancements Senior Task Force (DESTF) (10-10:25)

PJM’s Chantal Hendrzak is set to present a proposal to rework how generators operating on reliability-must-run (RMR) agreements are compensated, the advance notice generation owners must provide PJM ahead of bringing a unit offline, and added transparency around related processes, such as the RMR revenue allocation zonal rate and Independent Market Monitor determinations of market power. The DESTF supported the PJM-sponsored proposal over two others offered by the Monitor and RTO. 

The committee will be asked to endorse the proposed solution and corresponding tariff revisions. Same-day endorsement will be sought at the Members Committee. 

Issue Tracking: Enhancements to Deactivation Rules 

  1. ELCC Accreditation Issue Charge (10:25-10:40)

PJM’s Michele Greening will present revisions to an issue charge addressing how PJM’s effective load-carrying capability (ELCC) framework is used in resource accreditation. The change would add a key work area examining how market participants can hold greater certainty in ELCC ratings between the Base Residual Auction (BRA) and delivery year. 

The committee will be asked to approve the revised issue charge upon first read at this meeting. 

Issue Tracking: Capacity Market Enhancements – ELCC Accreditation Methodology 

  1. IRM and FPR for 3rd IA (10:40-11:05)

PJM’s Josh Bruno will present a proposal to revise the IRM and FPR parameters for the third 2025/26 Incremental Auction (IA). Rising load growth in the 2025 Load Forecast has led to shifting ELCC ratings for resources participating in the IA. (See “Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction,” PJM PC/TEAC Briefs: Jan. 7, 2025.) 

The committee will be asked to endorse the 3IA IRM and FPR upon first read at this meeting. Same-day endorsement will be sought at the Members Committee. 

Members Committee

Endorsements (11:55-12:35)

  1. Manual 34 Revisions (11:55-12:05)

Greening will present revisions to Manual 34: PJM Stakeholder Process to codify a process for the RTO and members to follow after FERC rejects a stakeholder-endorsed proposal. 

The committee will be asked to approve the proposed revisions at this meeting. Lynn Horning, of American Municipal Power, will move the motion and Ruth Price, of the Delaware Division of the Public Advocate, will second the proposed revisions. 

  1. Deactivation Enhancements Senior Task Force (DESTF) (12:05-12:20)

Hendrzak is set to present the DESTF-endorsed proposal to the Members Committee should the MRC approve the changes. 

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

  1. IRM and FPR for 3rd IA (12:20-12:35)

Bruno will present the proposal to revise the IRM and FPR parameters for the third 2025/26 IA, should the MRC endorse the proposal. 

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MISO, SPP Ask FERC for JOA Waiver to Conduct More Meticulous Interregional Study

MISO and SPP have asked FERC for a temporary departure from sections of their joint operating agreement to be able to conduct a more comprehensive interregional planning study to land on mutually beneficial transmission projects.  

MISO and SPP filed the limited waiver request Jan. 15, asking for a one-time reprieve from a multiyear modeling requirement and a restrictive benefit valuation directive for their 2024/25 interregional planning cycle (ER25-943). The pair of grid operators said they don’t want to be constrained by certain sections of their joint operating agreement (JOA) when conducting their in-progress Coordinated System Plan (CSP) study and requested a response from FERC by March 15, 2025. 

MISO and SPP said current JOA wording limits them to using only the value of avoided regional projects to measure the reliability and public policy benefits of interregional projects. The JOA also requires MISO and SPP, when conducting a CSP, to use multiyear modeling, which the RTOs interpret to mean using multiple model years, like two, five and 10 years out.  

For their 2024/25 CSP, MISO and SPP instead want to use several differing scenarios all 10 years into the future using a combination of their respective 2034 modeling. They said they’re hopeful the study will turn up more potential projects than a broad-brush study with pit stops at five, 10 or 15 years.  

MISO and SPP added that 2034 is a pivotal point, on the other side of many utilities and states’ 2030 decarbonization goals and on the road to bigger net-zero goals.  

MISO and SPP also said establishing the reliability value of a project solely on its ability to avoid regional projects likely hamstrings them from analyzing projects’ usefulness in other areas, like expanding interregional transfer capability or standing the grid up to weather extremes.  

“The requirement to value reliability or public policy interregional projects as the cost avoidance of pre-existing regional projects will hinder such projects from being proposed based on additional or alternative benefits. It is likely that reliability needs will be identified along the seam in the analysis, yet not observed in prior regional processes due to modeling differences or because the planned study offers a more robust evaluation of the 10-year horizon,” MISO and SPP explained. 

MISO and SPP said they’re casting a wider net for interregional projects in the current CSP and want to use comprehensive reliability, economic and transfer analyses using 10-year forward modeling. They said using detailed, long-term views will help them move beyond solely “studying and resolving transmission issues” and better line up with FERC Order 1920.  

This CSP would prioritize “immediately actionable enhancements,” MISO and SPP said, like upgrades in existing rights-of-way, terminal equipment, transformers or greenfield development that might not be contemplated in regional studies.  

MISO and SPP decided months ago that this year’s CSP “would not yield different results” from fruitless past studies unless it considers “near-term upgrades that incrementally enhance transfer capability and yield multiple benefits across the RTOs’ respective footprints without limiting upgrades to the replacement of regional projects.”  

“The RTOs believe that, unless the study scope is broadened as proposed, the 2024/25 CSP study would become a futile, pro forma exercise that would not result in recommended interregional projects,” MISO and SPP said. “History has proven that there have been high-potential projects considered, but ultimately not recommended, as cost shared interregional projects in the MISO-SPP CSP studies, and many projects have not been able to pass the interregional project criteria as narrowly defined in the MISO-SPP JOA.” 

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MISO Ponders Redistributing LSEs’ MW Obligations Based on Demand During Risky Periods

CARMEL, Ind. — MISO hopes to mete out different reserve margin obligations to its load-serving entities as it sees bigger perils on the horizon. 

The grid operator says because of shifting and growing risks to the system, its reliability requirement should be reallocated among LSEs based on periods that contain the highest reliability risks. Today, MISO divvies up its planning reserve margin requirement (PRMR) based only on LSEs’ 50/50 load forecast for its coincident peak.  

MISO instead would like the PRMR spread among load-serving entities based on historical load during MISO’s set of predefined risky hours that already are used to gauge capacity accreditation values.   

At a Jan. 15 Resource Adequacy Subcommittee meeting, MISO’s Neil Shah said the RTO would look back one year to get an idea of historical load. The RTO first mulled using three years of historical load data but said a one-year lookback should be sufficient in an era of expanding load. 

Shah said the demand uncovered in MISO’s loss of load expectation study — which is used to set the PRMR — diverges from the demand it sees in its capacity auctions. He said MISO’s probabilistic modeling “observes risks at load levels that are much higher than 50/50 coincident peak load.” 

A recalibration of the PRMR distribution should remove a “misalignment” between LSEs’ obligations and the load LSEs are consuming at the times of highest need on the system, Shah said.  

Shah said MISO hopes to make a filing with FERC on LSEs’ PRMR values sometime in 2025 after workshopping the proposal with stakeholders.  

MISO also said portioning out the PRMR to LSEs based on demand during system risk will line up with its recently approved resource accreditation, which accredits resources based on their availability during risky hours. (See FERC Approves New MISO Probabilistic Capacity Accreditation.) MISO originally considered including a PRMR reallocation as part of the early 2024 capacity accreditation filing to FERC but later decided to hold off and make a separate filing.