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November 18, 2024

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PNM Picks CAISO’s EDAM

Public Service Company of New Mexico announced Nov. 11 its intent to join CAISO’s Extended Day-Ahead Market, extending EDAM’s reach farther into the Desert Southwest in its latest victory over SPP’s Markets+. 

In a statement, PNM CEO Don Tarry cited the utility’s experience with CAISO’s Western Energy Imbalance Market (WEIM) as a factor in the decision. PNM has received $125 million in benefits since joining WEIM in 2021. 

“Participating in EDAM is the next step in realizing the value of New Mexico’s renewable energy potential for our customers, helping us ensure continued clean and reliable service at the lowest possible cost,” Tarry said. “We know from our experience with the WEIM … [that] coordination with other regional utilities can continue to deliver substantial efficiencies and cost benefits for our customers.”

With about 550,000 customers, PNM is New Mexico’s largest electricity provider. The utility said it plans to begin EDAM participation as soon as 2027. 

CAISO CEO Elliot Mainzer said the ISO was pleased by PNM’s announcement.  

“We look forward to building on the proven track record of the Western Energy Imbalance Market to deliver even greater economic and reliability benefits to PNM customers,” Mainzer said in a statement. 

Modeling Connectivity

Playing a large role in PNM’s choice of EDAM was a study The Brattle Group conducted for PNM and El Paso Electric that compared projected benefits of the utilities joining either EDAM or Markets+. 

The production cost study carefully modeled transmission connectivity. It modeled a scenario in which three Arizona utilities — Arizona Public Service, Salt River Project and Tucson Electric Power — join Markets+. The Arizona utilities haven’t yet announced their day-ahead market choices, but they have expressed a preference for SPP’s market and have participated in its development. 

Even with the Arizona utilities in Markets+, projected annual benefits for PNM would be $20.5 million if it joined EDAM, compared with $8 million from participating in Markets+. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.)  

The Brattle results gave reassurance that PNM didn’t have to follow the market choice of Arizona utilities in order to realize day-ahead market benefits. 

“The Brattle study reinforced that PNM has adequate transmission connectivity to reach the benefits associated with the large and resource-diverse EDAM market,” the company said in an email to RTO Insider. 

At the same time, PNM didn’t have any major concerns with the Markets+ design, the company said, adding that the EDAM choice was based on customer benefits from a reliability and economic perspective.   

“Much of these benefits come from having diverse loads and resources spread over a large geography,” PNM said. 

Guiding Principles

PNM filed a letter with the New Mexico Public Regulation Commission on Nov. 8 sharing its decision to go with EDAM. The brief letter references a set of guiding principles the commission issued Oct. 31 for utilities to consider in selecting a day-ahead market. (See NM PRC Issues ‘Guiding Principles’ for Electricity Market Participation.) 

PNM said it made its day-ahead market decision after considering the commission’s principles, “including the comparative analysis of customer benefits, the efficiency of resource dispatch and the importance of robust stakeholder processes.” 

The utility plans to file a more detailed response on how EDAM satisfies the PRC’s guiding principles before signing implementation agreements with CAISO, the company said in an email. 

PacifiCorp in April became the first Western utility to fully commit to EDAM and sign an implementation agreement with CAISO. That was followed by NV Energy’s announcement in May that it plans to join EDAM. 

The Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric also have made commitments to EDAM. 

As for El Paso Electric, which participated in the Brattle study with PNM, the utility has said it hopes to make a day-ahead market decision by the third quarter of 2025. The study’s projected benefits for EPE are $19.1 million a year for EDAM, versus $9.1 million for Markets+. 

The company may ask Brattle for analysis of additional scenarios, which could include EPE and PNM choosing different markets. EPE is expected to present the results of those studies to the PRC. 

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Large Consumers Vent Frustrations with NYISO’s Proposed SCR Changes

Tensions flared at the NYISO Installed Capacity Working Group meeting Nov. 4 over the ISO’s proposed changes to the special case resource (SCR) demand response program, which large energy consumers said will cause a mass exodus of participants.

“I think NYISO should know that part of the extreme frustration with this project is that we thought there was going to be actual engagement with the demand side; that there would be engagement with SCR participants,” said Mike Mager, speaking for Multiple Intervenors, a group of large industrial customers.

Mager said that he believed the vast majority of the changes proposed to the SCRs would be viewed unfavorably by the participants.

SCRs typically are large industrial consumers that have loads that can be reduced or turned off. In a report to FERC, NYISO said that from November 2023 to April 2024, the SCR market reduced load by about 1,300 MW statewide. Local behind-the-meter generators participating in the SCR program contributed an additional 100 MW. NYISO allows customers who qualify to participate in the Installed Capacity Market to be SCRs, receiving revenue for reducing their load at the ISO’s direction.

The ISO proposes to change how SCR performance and compensation are calculated. Currently they are based on the average coincident load (ACL), which is the average of the SCR’s highest 20 one-hour peak loads from the previous capability year. NYISO wants to change this to the “customer baseline load” (CBL), which uses data from the prior 30 calendar days and is based on the highest five consumption days of the past 10 prior to an SCR event.

NYISO’s market design report from 2023 estimated this would reduce the megawatt value of an SCR by 6% to 26% depending on the zone; in New York City, this would be about 26%. Michael Ferrari, a market design specialist for NYISO, said the changes more accurately would capture the performance of SCRs.

“The whole ACL/CBL change was not part of any type of engagement,” Mager said. “The testing proposal we’re going to get to is also new by the NYISO. The four-hour notices was also new by the NYISO. There was some discussion about the notice period during the engagement phase, but the feedback provided by the SCR participants was largely ignored.”

NYISO also wants to increase the duration of the performance test of an SCR to six hours, up from one. In prior meetings ISO staff also expressed a desire to increase the duration requirement of an SCR to six hours and shorten the notice window from 21 hours to four hours. (See Large Consumers Miffed at NYISO Proposal to Shorten SCR Notice Period.)

“This deal just kind of seems to be getting worse and worse,” said Aaron Breidenbaugh, senior director of regulatory and government affairs for CPower. “For a project that’s supposed to be coming out of ‘Engaging the Demand Side,’ I think a word besides ‘engaging’ is more appropriate.”

Mager said the changes were moving in the wrong direction, disincentivizing participation at a time when the state’s reliance on intermittent generation was increasing. Shutting down manufacturing for longer SCR testing, or on shorter notice for less compensation, was an overall bad deal for manufacturers, he said.

“The last time we talked about this, I used the Titanic analogy,” said Breidenbaugh. “Now we’ve just punched a hole in two more compartments.”

Breidenbaugh said if he was working at NYISO and had been given the job of eliminating the SCR program, he would do exactly what the ISO was proposing to do.

“If you’re trying to get rid of it, you’re doing a really good job, but I don’t think that’s what you’re trying to do,” he said. “I think everyone can believe that this could make a better program with more flexible megawatts. You’ll have more flexible resources; they will just be a tiny fraction of what you have.”

“I’ve not been given the request to kill the SCR program. That is not the intent of this series of proposals,” Ferrari said.

After some additional discussion, Breidenbaugh said he didn’t think New York state’s regulatory authorities would allow the amount of DR that is dependent on participating in the SCR program to go away. He said  if the changes caused participants to jettison from the program, the state might work with utilities to get its own program in place.

“I certainly don’t think it’s the best way for NYISO and its operators to lose control of those levers,” he said. “I’m not sure the utilities necessarily want to take on that responsibility, but they oftentimes get tasked with doing things they don’t want to do.”

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FERC Approves PJM Capacity Auction Delay

FERC on Nov. 8 approved a PJM waiver request to offset the RTO’s capacity auction schedule by six months starting with the 2026/27 Base Residual Auction (BRA). 

PJM sought the waiver in anticipation of its Federal Power Act (FPA) Section 205 filing to make several changes to its capacity market (ER25-118). (See “OPSI Speakers Discuss Future Auction Design,” Panels Debate PJM Capacity Market Design at OPSI Annual Meeting.) 

The order shifts the 2026/27 auction from December 2024 to June 2025 and schedules the three subsequent three auctions for December 2025, May 2026 and December 2026. It also cancels the second Incremental Auction (IA) for the 2027/28 delivery year and first IA for the 2029/30 delivery year. 

The commission said the delay would allow PJM to address a complaint filed by several environmental and public interest organizations regarding how generators operating on reliability must-run (RMR) agreements are reflected in PJM’s capacity market.  

Filed by the Sierra Club, NRDC, Public Citizen, Sustainable FERC Project and Union of Concerned Scientists, the complaint argues those units should be required to offer into the capacity market or should be administratively counted in the supply stack by PJM. They contend the status quo requires consumers to pay repeatedly for the same reliability contribution in the form of the RMR agreement, transmission upgrades to mitigate violations caused by the generator’s deactivation, and higher capacity prices when a unit leaves the market to operate on the RMR agreement (EL24-148). 

“PJM explains that the complaint has generated significant market uncertainty and that, to address this uncertainty, it plans to file a FPA Section 205 filing that will propose several capacity market rule changes. PJM’s waiver will provide the time to address potential consequential changes in the market rules by delaying the 2026/2027 BRA and compressing the timelines for subsequent auctions to facilitate the return to a three-year forward schedule,” the order states. 

Insight into Upcoming Filing

PJM presented an overview of its expected filing during a Nov. 7 special Markets and Reliability Committee meeting, in which Vice President of Market Design and Economics Adam Keech said the filing likely will include changing the reference resource back to a combustion turbine (CT) and setting criteria for counting the expected output of the Brandon Shores and Wagner units operating on RMR agreements toward meeting RTO and locational deliverability area (LDA) reliability requirements. 

The change would include sunset provisions with the aim of being applicable to only those two units while broader changes to the RMR rules are worked out through the stakeholder process. 

Those stipulations mandate that units be reasonably expected to operate throughout the delivery year, have a minimum number of available run hours to be available for transmission support, be available to PJM for all emergencies unless on outage and have deliverable capacity interconnection rights (CIRs).  

Keech said PJM has determined that Wagner Unit 3 meets those requirements and it is working to determine whether Unit 4 would as well. Due to an agreement between the Sierra Club and Talen Energy to cease coal combustion at Brandon Shores by the end of 2025, it is not clear that generator could be relied upon. 

While not addressed in the complaint regarding RMR resources, PJM also seeks to revert the reference resource to a CT, undoing a change made in the 2022 Quadrennial Review to shift to a combined cycle generator. Due to the higher energy and ancillary service (EAS) revenues, the net cost of new entry (CONE) value fell to $0/MWh in some LDAs, resulting in a capacity performance penalty rate of zero as well. That could occur in situations where generators face no non-performance charges during emergencies but still could receive overperformance bonuses. The diminished net CONE values also produce a significantly steeper variable resource rate (VRR) curve, creating price volatility in the capacity market. 

The commission’s order says the harms of changing the auction schedule are outweighed by the benefits of addressing the possible consequences of the market rules and allowing market participants to react to any rule changes. 

“Although the auction delay will have an effect on other BRAs through the 2029/2030 delivery year and will require canceling several Incremental Auctions, on balance we find that granting the waiver request provides the opportunity to address potential consequential changes in the market rules and provides the opportunity for market participants to respond to any changed rules by having additional time to prepare and submit requests and elections in advance of the next auction,” the order says. 

FERC disagreed with American Municipal Power’s protest arguing that the waiver request was deficient without a stronger outline of what would be included in the 205 filing, countering that it is reasonable to request a delay to allow for consideration of changes still being drafted. 

The commission dismissed as moot a parallel request to delay the auction that PJM made in its comments on the RMR complaint, saying the approval of the waiver request does not prejudice its consideration of that complaint. 

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PJM PC/TEAC Briefs: Nov. 6, 2024

Planning Committee

Stakeholders Endorse LS Power Issue Charge on CETL

PJM’s Planning Committee voted by acclamation to endorse an issue charge from LS Power to examine a “disconnect” between risk modeling that has shifted loss of load risk from summer peaks to the winter and the calculation of zonal capacity emergency transfer limits (CETLs), which continues to be based on summer peaks.

The issue charge argues that the CETL calculation continues to focus on summer risk in a holdover from the capacity accreditation model in place before FERC approved PJM’s shift in accreditation and risk modeling in January. The difference could lead to incorrect capacity prices between locational deliverability areas (LDAs), the company wrote. (See FERC Approves 1st PJM Proposal out of CIFP.)

The issue charge considers as out of scope any changes to accreditation outside of the marginal effective load carrying capability (ELCC) accreditation model and consideration of a sub-annual capacity market.

The issue charge is one in a series of changes to the capacity market LS Power is seeking to make in the first quarter of 2025. The Markets and Reliability Committee (MRC) also endorsed two issue charges focused on the transparency and functionality of PJM’s marginal ELCC paradigm, which was also implemented through PJM’s critical issues fast path (CIFP) filing approved in January. (See “Stakeholders Endorse Issue Charges on ELCC,” PJM MRC Briefs: Oct. 30, 2024.)

PJM Floats Fast Track Proposal on Site Control Modifications for Queue Projects

PJM’s Jonathan Thompson presented a fast track proposal to add more detail to Manual 14H: New Service Requests Cycle Process around how developers can modify their site control requirements for projects in the interconnection queue. The fast track process allows for an issue charge to be voted on concurrent with a proposal.

At Decision Point 1, the footprint of a project can be reduced so long as it continues to meet the minimum acreage and energy output listed in the application. The land requirements are scaled down if the project output is correspondingly reduced. Additional parcels can be added to a project as long as they are adjacent to the land included in the application. If they do not abut the original outline, then easements must be provided showing how the additions will be connected to the project.

Parcels can continue to be removed from a project at Decision Point 2, and land can be added similarly to Decision Point 1. No additions are permitted at Decision Point 3; however, reductions in size can be submitted.

The revisions would also rework Exhibit 10 in the manual, which is meant to detail how a generator interconnects to existing transmission substations but incorrectly uses a diagram from a different exhibit.

Transmission Expansion Advisory Committee

PJM Presents Shortlist of Projects for 2024 RTEP Window 1

Eight packages of projects have been shortlisted to expand west-to-east power flows across the PJM region under the first window of the 2024 Regional Transmission Expansion Plan (RTEP). The need is largely driven by data center load growth in Dominion drawing increasing power from the west, which is expected to see growth in generation.

Developers submitted 88 individual projects, along with six joint proposals packaging multiple components together. All the proposals would include expanding west-to-east flows by expanding the 765-kV network, either through a Joshua Falls to Axton-Morrisville corridor or a corridor from the John Amos substation to northern Virginia.

The 765-kV upgrades Dominion, FirstEnergy and Transource jointly proposed to develop to the south of the Dominion region would offer higher initial transfer capability, while upgrades to the north would have greater possible transfers once complete. Variants of the northern reinforcements were proposed by LS Power, NextEra and a joint Transource, FirstEnergy and Dominion package.

The projects will be ranked on their effectiveness in meeting system needs in 2029 and providing long-lead reinforcement for 2032, as well as on how they maximize use of existing rights of way, cost evaluation and containment provisions, development experience and operating 765-kV assets and scalability to address future load growth.

PJM Director of Transmission Planning Sami Abdulsalam said there has been a significant intake in load growth since the RTEP project submission window was opened, leading the RTO to widen the lens it views projects through to include needs being identified in the upcoming 2025 load forecast.

Several stakeholders objected to PJM including an unreleased load forecast in its consideration of the projects, arguing that doing so would be unfair to transmission developers who were unable to include that data when designing their submissions. It could also provide an advantage to incumbent transmission owners, who would have insights into load growth that is not yet public and could design their project submissions to address both the inputs available when the RTEP window opened and future load forecast being supplied to PJM.

Virginia ratepayers also spoke against the possible impacts the projects could have on residents along the proposed corridors, saying that routes could require eminent domain of homes and arguing that PJM is misclassifying expansions of right of way as upgrades rather than greenfield development. Abdulsalam responded to the latter point saying PJM is trying to avoid having several different definitions of greenfield, brownfield and upgrades.

Supplemental Projects

AEP presented a $169.1 million project to serve a data center customer in New Haven, Ind., with an initial load of 480 MW coming online in November 2026, which is set to grow to 1,200 MW by July 2029. The project is in the scoping phase with a projected in-service date of July 1, 2029.

The load would be served by five 138-kV double circuit lines to customer-owned substations, which would be fed by a new Zodiac 138-kV substation in a breaker-and-a-half configuration. Zodiac would be cut into the Allen-Lincoln double circuit 138-kV line, and the Allen- Wayne Trace and Allen-Magley 138-kV lines. Two additional 345/138-kV transformers would be installed at the Allen substation, along with three additional 138-kV breakers and three 345-kV breakers.

PPL presented a $117.8 million project to serve a 138-kV customer in Lancaster, Pa., increasing its load by 350 MW in 2028. The project is in the conceptual phase with a projected in-service date of June 1, 2028.

A new 138-kV switchyard, to be named Pitney, would be constructed in a breaker-and-a-half configuration with five 138-kV breakers to feed into the customer substation. The facility would cut into the South Akron-Prince 138-kV line with 0.2 miles of new line.

A second new 230/138-kV substation, named Lampeter, would be built with two transformers and two breakers for each voltage. The facility would be cut into the Millwood-South Akron 230-kV line and the 69-kV double circuit tap line terminating at the Strasburg substation would be reconstructed to 138-kV to loop into Lampeter and terminate at Pitney. Both the Greenland and Strasburg substations would be upgraded from 69/12-kV to 138/12-kV.

An additional load increase in Lancaster to serve an additional 350 MW of load at the same customer substation by 2029 would be served by a $67.5 million project to build a new 138-kV switchyard named North Lancaster. The project is in the conceptual phase with a projected in-service date of June 1, 2028.

The facility would cut into the West Hempfield-Prince and South Akron-Dillerville 138-kV lines and serve the load with three 138-kV lines running 0.1 miles. Around eight miles of the West Hempfield-Prince line would need to be rebuilt as part of the project.

PPL presented a third project to serve a new customer in Hazleton with an initial load of 250 MW in 2027 growing to 1,000 MW by 2030. The $73.3 million project is in the conceptual phase with a projected in-service date of May 30, 2028.

The customer would be fed by a new 230-kV breaker and a half switchyard named Slykerville, which would be equipped with a 125-MVAR capacitor bank. The Harwood-Tresckow 230-kV line would be looped into the Slykerville facility with 0.2 miles of new line.

Around 2.7 miles of the Susquehanna T10-Susquehanna 230-kV lines would be reconductored and 15-ohm series reactors installed at the Susquehanna switchyard on the 230-kV line to Harwood.

Dominion presented a $13 million project to construct a new 230-kV substation, named Towerview, to serve a new customer in Fairfax County, Va., with an initial load of 56 MW in 2027 growing to 300 MW in 2029. The new facility would be cut into the Reston-Park Center 230-kV line. The project is in the engineering phase with a projected in-service date of Nov. 30, 2027.

FirstEnergy presented a $15.4 million project in the JCPL zone to address a possible load drop under N-1-1 contingency on the Gilbert-Martins Creek 230-kV and Gilbert-Pequest River 115-kV lines and replace a 115/34.5-kV transformer at the Morris Park substation. The project is in the conceptual phase with a projected in-service date of Jan. 29, 2027.

The project would reconfigure the Morris Park 230-kV substation into a four-breaker ring bus and cut the facility into the Martins Creek-Gilbert line. A second 230/34.5-kV transformer would be installed at Morris Park and all 115-kV equipment, including the 115/34.5-kV transformer, would be removed.

The utility also presented a $16.3 million project in the Met-Ed zone to mitigate a stuck breaker and fault contingencies at the North Hershey substation. The project is in the conceptual phase with a projected in-service date on Dec. 17, 2027.

The project would convert the 69-kV bus into a four-breaker ring bus and install a second 230/69-kV transformer, one 230-kV circuit breaker, four 69-kV breakers and associated breaker equipment.

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Chatterjee Post Leads to Worries About FERC’s Independence, Staff Exodus

Former FERC Chair Neil Chatterjee sparked concerns about the incoming Trump administration’s control of the federal bureaucracy and how that might impact the commission’s independence with a post on X on Nov. 6, the day after former President Donald Trump’s re-election. 

“For the [Trump] transition team: [If] you want schedule F insight on who to keep and who to remove [at FERC], please DM me,” Chatterjee posted on the social media site formerly known as Twitter. In a later post, he said Trump’s transition team got back to him “seven minutes after I tweeted this,” which he confirmed in an interview with RTO Insider. 

“Schedule F” refers to a new classification for federal workers that Trump created via executive order late in his first term. It applied to federal career employees with jobs connected to policy and made it easier to fire them. When that executive order was issued, the American Federation for Government Employees called it “the most profound undermining of the civil service in our lifetimes.” 

President Joe Biden quickly revoked the order upon taking office, and in April 2024, the Office of Personnel Management completed a rulemaking to bolster labor protections for federal employees. But Trump has promised to reinstate the order, and the OPM rule could be overridden by a Republican-controlled Congress. 

FERC and other independent agencies are insulated from such White House edicts, only having to enact them if their appointed leadership decides to, Public Citizen Energy Program Director Tyson Slocum said. For example, the commission did not implement Biden’s proposed guidance on the National Environmental Policy Act, Slocum said. 

Chair James Danly, who ran FERC for the last 10 weeks of Trump’s first term after the president demoted Chatterjee, had started work on implementing Schedule F. 

Chatterjee expressed surprise to RTO Insider that his post set off criticism and argued that he was trying to help the commission’s staff. 

“I actually viewed it as me being helpful to commission staff; that I could speak on their behalf to the critical role they play around approving gas projects and overseeing reliability,” Chatterjee said. “And I didn’t intend or expect that people would view it the other way. I think it’s been mischaracterized a little bit.” 

The reality is that Trump wants to reinstate the concept of Schedule F, Chatterjee said. While his post on X said Chatterjee could tell the incoming administration “who to keep and who to remove,” he said he did not mean specific individuals. 

“I wasn’t talking about specific people, to be clear,” Chatterjee said. “Could you make changes within the various offices? I’m on the private sector side right now, you know; I’ve got a ton of folks that I work with that are going through reorganizations and reshuffling. The federal government should do the same thing.” 

Scott Hempling, a lawyer and leading expert on regulation who recently left his job as a FERC administrative law judge, said in a statement that the commission’s independence is vital to its work. 

“Hundreds of millions of lives, and an entire national economy, depend on the professionalism of our regulatory workforce,” Hempling said. “Regulation is effective only when ruled by three things: law, logic and facts. Infecting the workforce with anyone who doesn’t live by those limits disserves investors, consumers and the public trust.” 

Chatterjee said that even when staff disagreed with him, like on the minimum offer price rule in PJM, they still did their job. 

“I found during my tenure at the commission that even in instances where the staff disagreed with me, they still produced a very strong, legally defensible work product at the end of the day,” Chatterjee said. “And that’s one of the messages that I want to deliver to the incoming administration.” 

Slocum said that while he has had disagreements with FERC over the years, he said it is vital that the commission and its staff remain free from political meddling. Any who do feel improperly influenced by politics can reach out to Public Citizen, or other watchdog groups, he said. 

“FERC is an independent agency,” Slocum said. “It is unlawful for the administration to make staff decisions at an independent agency other than nominating commissioners and designating the chair, so it would be highly inappropriate for the Trump administration or any administration to make decisions about internal staffing at an agency.” 

Slocum said Trump was able to use his appointment authority in his first term by getting Chatterjee to name Anthony Pugliese as FERC’s chief of staff and Danly as its general counsel before the latter was nominated and confirmed as a commissioner. 

The question of when Trump will get to nominate a new member is up in the air, with no guarantee that Chair Willie Phillips will step down as commissioner when one of his Republican colleagues — either Commissioner Mark Christie or Lindsay See — is named chair. Phillips’ term ends June 30, 2026; the next seat to open is Christie’s in June 2025. Christie himself was nominated by Trump and is the only commissioner remaining from that first term. 

The fact that the commission has a full complement of five members could limit Trump’s ability to influence senior staffing decisions through his nominee, Slocum said. 

“Christie has established himself as being a very credible and important pro-consumer voice,” Slocum said. “See hasn’t [participated in] many orders, but she joined Christie for the Talen co-location order, rejecting it as being unfair to consumers,” which he applauded. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

Former FERC Chair Richard Glick, who was a FERC commissioner under Trump before Biden tapped him to lead the commission in January 2021, said the discussion of bringing back Schedule F risks a brain drain at the commission. FERC staff have expertise that, especially for more senior members, is very attractive to the private sector, which can pay more than the government. 

“All you are doing here by putting out tweets is increasing their anxiety, and it’s going to cause them to leave sooner than they otherwise would,” Glick said. 

That would leave FERC less capable of tackling the important issues before it, with electricity demand surging around the country from data centers and the need to review LNG export facilities, Glick added. 

A longer-term front to watch out for in terms of FERC independence could come from the legal system. A conservative theory holds that the president’s limited authority to fire commissioners violates the Appointments Clause of the Constitution. 

The second sentence in Project 2025’s chapter on independent agencies references that theory: “In general, the president can appoint people to these commissions but cannot remove them, which makes them constitutionally problematic in light of the Constitution’s having vested federal executive power in the president.” 

The Appointments Clause was at issue in Seila Law v. Consumer Financial Protection Bureau, a 2020 Supreme Court decision that found that the president’s inability to remove the head of an agency with a single director was unconstitutional. But in doing so, the majority opinion said the precedent held no weight for multimember, bipartisan commissions like FERC, and even the authors of Project 2025 noted that such arrangements generally have been upheld by the courts. 

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US Governors, Mayors to Pledge Ongoing Climate Action at COP29

The 29th United Nations Climate Change Conference of the Parties ― COP29 ― opened Nov. 11 in the Azerbaijan capital of Baku, and unlike previous COPs, neither the president nor vice president of the United States are on hand to advance U.S. leadership in global efforts to keep global warming to 1.5 degrees Celsius.

President Joe Biden addressed COP26 in Glasgow in 2021 and COP27 in Sharm-El Sheik, Egypt in 2022. Vice President Kamala Harris led the U.S. delegation to COP28 in the United Arab Emirates in 2023.

But coming just days after President-elect Donald Trump’s victory, the U.S. presence at the conference ― or lack thereof ― could be viewed as an advance signal for a repeat of Trump’s 2017 withdrawal of the country from the Paris Agreement. Biden rejoined the global pact on global warming on his first day in office in 2021, and Trump has pledged to once again withdraw from the agreement as soon as he takes office.

The official U.S. delegation is led by John Podesta, White House senior advisor on international climate policy, and includes Energy Secretary Jennifer Granholm, Agriculture Secretary Thomas Vilsack, National Climate Advisor Ali Zaidi and DOE Deputy Secretary David Turk, according to a State Department announcement. EPA Administrator Michael Regan and Secretary of the Interior Deb Haaland sent deputy secretaries in their stead.

However, U.S. “subnationals” ― governors, mayors and corporate leaders ― are in Baku, carrying a message of continued commitment to the goals of the Paris Agreement, regardless of who’s in the White House.

“We have a responsibility to continue to address the climate crisis and to engage in every way possible, and to remind not just everyone in the United States, but frankly globally, that governors act as subnationals, irrespective of … the White House,” New Mexico Gov. Michelle Lujan Grisham (D) said during a Nov. 8 press call, as reported by ABC News. “We’ve been in this position before. We are going to continue our commitments.”

Lujan Grisham, along with New York Gov. Kathy Hochul (D), are co-chairs of the U.S. Climate Alliance, a bipartisan group of 24 governors formed in 2017 in response to Trump’s withdrawal from the Paris Agreement. All have adopted aggressive emission reduction goals.

A founding member of the alliance, Washington Gov. Jay Inslee (D) is leading a subnational delegation to Baku, including state Maryland Environment Secretary Serena McIlwain and California Environment Secretary Yana Garcia, according to a Climate Alliance press release.

“We look at Donald Trump as a speed bump on the road to progress toward a clean energy economy, and we are rolling big time,” Inslee said during the Nov. 8 press call.

“My number one message is progress is going to continue in the United States. It will be driven by states who have already demonstrated that if you adopt clean energy policies, you will simultaneously grow your economy and reduce carbon emissions.”

Other organizations on the call included Climate Mayors, a nonpartisan group of nearly 350 mayors, and America Is All In, a broad coalition of local governments, educational institutions, tribal governments, investors and businesses.

Gina McCarthy, former EPA administrator and White House climate advisor, is managing co-chair of American Is All In. Speaking on the call, McCarthy said, “We’ll do everything in our power to stop efforts to unwind the progress we have made, to double down on local action, and to push private sector investments and to fill the federal leadership gap so that we can achieve our country’s global commitments.”

Ambition Without Action

Biden and Harris are not the only no-shows at COP29. Other world leaders skipping this year’s conference include European Commission President Ursula von der Leyen, German Chancellor Olaf Scholz and French President Emmanuel Macron, according to reports from Reuters and Bloomberg.

The absence of such key voices in Baku comes at a perilous moment for global action on climate. According to the recently released UN 2024 Emissions Gap Report, greenhouse gas emissions worldwide were up 1.3% in 2023, a significant bump from the pre-COVID pandemic average of 0.8% per year between 2010 and 2019.

Countries have not achieved the emission reductions they committed to in the initial rounds of climate pledges, called nationally determined contributions (NDCs), in 2015 and 2020-2021, the report says. New NDCs, setting goals for 2035, are due in February 2025, and according to Inger Andersen, executive director of the UN Climate Program, global emissions must fall 7.5% per year through 2035 to limit warming to 1.5 degrees Celsius.

The report calls on industrialized nations to do the heavy lifting on emission cuts, as well as on financial support for developing countries.

“Ambition means nothing without action,” the report says. “Unless global emissions in 2030 are brought below the levels implied by existing policies and current NDCs, it will become impossible to reach a pathway that would limit global warming to 1.5°C. … The next NDCs must deliver a quantum leap in ambition in tandem with accelerated mitigation action in this decade.”

While Trump almost certainly will take the U.S. out of the Paris Agreement, a bigger question is whether he and Republicans in Congress might try to take the U.S. out of the UN Framework Convention for Climate Change, under which the Paris Agreement was finalized. U.S. participation in the UNFCCC required ratification by the Senate. It is uncertain if a Senate vote would be required to withdraw.

In their post-election analysis, ClearView Energy Partners cautioned “it may be premature to say the multilateral process is losing momentum. But the prospect of Trump administration rollbacks could make it harder for the U.S. to stoke greater global ambitions toward accelerating annual transition investments in the multiple of trillions of dollars.”

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Trump 2.0: Rolling Back Regulations, IRA Funding

In the wake of President-elect Donald Trump’s victory Nov. 5, the clean energy industry is now obsessing over how far the next administration will push his own “drill, baby, drill” agenda in favor of fossil fuels and how quickly he will try to unravel programs funded by the Inflation Reduction Act at the Department of Energy and EPA. 

While D.C. clean energy industry groups are reaching out to work with the incoming administration and Congress, the policy landscape ahead could be treacherous. Trump and Republicans in Congress see the election results as giving them a mandate focused on “deregulation and deglobalization,” according to industry analysts ClearView Energy Partners. 

What that means is major reversals of Biden administration regulations and programs aimed at cutting greenhouse gas emissions, withdrawal from the 2015 Paris Agreement on climate change and high tariffs on Chinese and other imported goods, including many components critical to clean energy manufacturing. 

As detailed on his campaign website, Trump wants to roll back President Joe Biden’s signature legislative achievements, the IRA and the Infrastructure Investment and Jobs Act. He wants to ensure the U.S. has the lowest energy costs of any developed country in the world by bringing back incandescent light bulbs and protecting Americans’ access to gas stoves, promoting fossil fuel drilling on federal land and speeding up approvals of natural gas pipelines. 

While providing no concrete details, Trump also pledged to “stop the wave of frivolous litigation from environmental extremists that hold up critical energy development projects.” 

Speaking at Bracewell’s post-election webinar Nov. 6, Scott Segal, co-chair of the law firm’s Policy Resolution Group, expects that, once inaugurated in January, Trump will issue “an immediate spate of executive orders,” which could resurrect previously rejected fossil fuel projects and pipelines and expand offshore drilling. 

Another likely Day 1 action could be a lifting of Biden’s highly contentious pause on the approval of LNG exports to countries without free trade agreements with the U.S. 

The re-election of Sen. Ted Cruz (R-Texas) ― who will chair the Senate Commerce Committee ― will open the way for more offshore drilling permits, Segal said. The committee oversees offshore permitting, and Segal expects “some connectivity there between the administration and the Cruz team [on] reduced environmental reviews, which can have impacts even for independent agencies like FERC.” 

ClearView’s post-election analysis contains a list of IRA programs, tax credits and funding streams most likely to be targeted by Republicans in Congress: 

    • a clawback of IRA and IIJA funds that have not been spent, whether already obligated or not; 
    • cancellation of programs and incentives such as EPA’s methane Waste Emissions Charge, tax credits for clean commercial vehicles (45W) and used electric vehicles (25E), and funding for DOE’s Loan Programs Office; and 
    • tightening of IRA provisions on domestic content, not only for EVs and critical minerals, but for components used in solar and wind projects, along with narrowing the number of locations qualifying for bonus credits as energy communities. 

The extent of IRA revisions will depend on whether the Republicans hold the House of Representatives, in addition to their control of the Senate, ClearView says. The Associated Press count as of press time shows Republicans with 214 seats and Democrats with 203. 

A red sweep could allow lawmakers to dismantle the IRA via a “filibuster-proof” budget reconciliation bill ― which can be passed by a simple majority ― the same legislative maneuver the Democrats used to pass the IRA in 2022, ClearView says. 

Keith Martin of Norton Rose Fulbright, another law firm with energy policy experts, also anticipates Republican efforts to move up the phaseout dates of some of the IRA clean energy tax credits, from the 2040s to the 2020s. Even the possibility of such changes already has developers getting steel in the ground for some projects to make sure they remain eligible for the tax credit, regardless of any accelerated phaseouts, Martin said at the recent Southeast Renewable Energy conference. (See SE Renewable Energy Conference Hears Blunt Talk on Trump.) 

Permitting Stalemate

Analysts also see legislative uncertainty on both sides of the aisle for bipartisan action on permitting reform. Sens. Joe Manchin (I-W.Va.) and John Barrasso’s (R-Wyo.) bipartisan Energy Permitting Reform Act (S. 4735) was approved by the Energy and Natural Resources Committee in July but could lose momentum during the lame duck session beginning Nov. 12. 

A top priority will be hammering out a budget bill or another continuing resolution to keep the government operating for a few more months. 

Such budget turbulence notwithstanding, ClearView argues that for Democrats, pushing forward on EPRA could be a “last, best” opportunity for any movement on accelerating permitting, while Republicans may be motivated to “close out contentious issues to clear the decks for a new president’s agenda.” 

Still, other analysts have countered that if Republicans control both the House and Senate, they might want to hold and revise the bill to include revisions to the National Environmental Policy Act. 

But ClearView warns that taking no action might kill not only the Manchin-Barrasso bill but any appetite for action on permitting. “A fractious lame duck session might not merely eliminate the negotiating space necessary for Democrats and Republicans to broker a deal, but could set a standoffish tone for the next Congress. … Indeed, the less that transpires during the lame duck, the less momentum there might be going into the next year.” 

Speaking at the Bracewell webinar, Ben Storrow, climate reporter at POLITICO’s E&E News, said another challenge for permitting reform is that Democrats have prioritized getting permitting provisions for transmission into the bill, which has been opposed by Republicans, especially in the Southeast. With their election losses, “the Democrats have less leverage now in those negotiations,” Storrow said. 

A Republican Congress also could mount an all-out attack on any regulations issued by DOE or EPA during the lame duck session using the Congressional Review Act, said Joseph Brazauskas, senior counsel at Bracewell. Under the 1996 law, a new Congress can pass resolutions of disapproval on any regulations that were finalized within 60 days of the House and Senate returning to session. A CRA resolution of disapproval, signed by the president, would invalidate any final rule in its entirely. 

Brazauskas said the Biden administration has factored the CRA into its release of regulations. “They did a pretty good job of isolating … and finalizing a number of key environmental and energy regulations,” he said, but he also noted that Trump would have other ways of rescinding or replacing emission-reduction regulations. 

The question now is what the Biden administration can do in the next two months to push forward and protect its clean energy and climate policies.  

Under the Administrative Procedures Act, an incoming administration can order agencies to stop any pending rulemaking, withdraw proposed or final rules that have not been published in the Federal Register, or push back or put a hold on the date a published rule is scheduled to go into effect. 

In the runup to the election, DOE had been making nearly daily announcements of new funding opportunities and awards but has been uncharacteristically subdued since Trump’s victory. One sign of what’s ahead was a LinkedIn post from Jamie Nolan, media lead at the Loan Programs Office.  

“SPRINTING TO THE FINISH,” she wrote. “Watch us go!” 

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ISO-NE Sees Manageable Shortfall Risk for Upcoming Winter

ISO-NE projects shortfall risks from extreme weather events to be manageable this winter and expects market mechanisms to provide relief by encouraging fuel conservation and replenishment, the RTO told the NEPOOL Participants Committee on Nov. 7. 

The shortfall assessment modeled “four representative extreme 21-day events” using the RTO’s recently developed probabilistic energy adequacy tool (PEAT). This winter marks the first season ISO-NE has incorporated the PEAT into its seasonal outlook. The modeled events are meant to assess the worst-case conditions for the system, “characterized by periods of extreme cold temperatures, low winds and low solar irradiance.”  

For each event, ISO-NE looked at how varying levels of fuel inventories, fuel prices, generator outages and imports would affect shortfall risks. The modeling showed a limited amount of shortfall associated with the extreme events on average, with a 244,353-MWh 21-day energy shortfall shown for the worst-case scenario, with a 0.000031% probability. 

“ISO expects these shortfalls are manageable and that market-based incentives will provide relief in the form of market response, including the use of opportunity costs in energy offers and fuel replenishment,” said Vamsi Chadalavada, ISO-NE chief operating officer.  

“If necessary, the ISO would implement additional preventive operational measures such as reducing exports [and] scheduling additional imports, seeking waivers of emissions or air permit limitations, [and] conservation appeals,” Chadalavada added.  

According to data from the National Oceanic and Atmospheric Administration, New England faces a 33 to 50% chance of above-average temperatures this winter, with above-average temperatures more likely in the southern part of the region.  

As carbon emissions drive higher temperatures, New England has warmed faster than the global average since 1900, and winter is the region’s fastest-warming season. Last winter featured the warmest December-February stretch on record in the Northeast, while the prior winter featured the third-warmest December-February period.  

ISO-NE projects the winter peak load to be 20,308 MW under average conditions, about 39 MW higher than the RTO projected prior to the 2023/24 winter. ISO-NE’s more extreme 10th percentile forecast projects a 21,089-MW peak. 

Chadalavada said there are “no significant generation or transmission outages” scheduled, adding that current fuel-oil inventories are about 48% of their maximum and the LNG tanks in St. John “are expected to be full heading into the winter.” 

He said the Everett Marine Terminal may be available to meet generation demand but noted ISO-NE has less insight into the availability of the facility after the Mystic Agreement expired at the end of last winter. The facility now is under contract with gas distribution companies. (See Massachusetts DPU Approves Everett LNG Contracts.) 

“Consistent with past winter seasons, the ISO assumes that approximately 3,900 [MW] to 4,800 MW may be at risk due to constrained natural gas pipelines,” Chadalavada added, noting that the RTO will “continue to monitor natural gas deliverability throughout the winter.” 

ISO-NE will have its inventoried energy program in place for the upcoming winter, which compensates generators for keeping up to 72 hours of stored fuel throughout the winter. The RTO has not indicated whether it plans to extend the program beyond the 2024/25 winter. 

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$21.8B Long-range Tx Plan Goes to Membership Vote; MISO Resolute, IMM Protesting

CARMEL, Ind. — MISO members are mulling an advisory vote on whether to support the RTO’s $21.8 billion long-range transmission plan (LRTP) portfolio while tensions simmer between MISO and its Independent Market Monitor over the necessity of the major transmission expansion.  

On Nov. 8, MISO’s Planning Advisory Committee (PAC) took up whether to recommend that the 2024 Transmission Expansion Plan (MTEP 24) — which includes the second LRTP portfolio — proceed to the System Planning Committee of the Board of Directors for consideration. The PAC settled on an email ballot that will be conducted over the next two weeks. A final decision on the LRTP portfolio alongside MTEP 24 is expected from the full MISO Board of Directors in early December.  

Director of Cost Allocation and Competitive Transmission Jeremiah Doner said from a reliability perspective, it’s cost-effective to build the 24-project, mostly 765-kV “regional highway” and confidently avoid future risks rather than building one-off projects to handle vulnerabilities.  

MISO anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the LTRP projects’ lives through reliability improvements, production costs, capacity that won’t be built and environmental benefits. 

“What is happening on the system is unprecedented with the resource transition, and we have a shared responsibility … to be proactive,” Doner told stakeholders. 

MISO’s End-Use Customer Sector asked that this year’s PAC vote on MTEP be a proportional vote, where sectors can divide their votes into a percentage to separately consider the $6.7 billion of traditional MTEP 24 local spending, the $21.8 billion LRTP and the $1.65 billion Joint Targeted Interconnection Queue transmission portfolio in partnership with SPP. MTEP 24 comprises all three. The End-Use Sector said this year’s PAC vote deserves some nuance because of the sheer amount of investment involved.   

MISO’s Independent Market Monitor David Patton capped a campaign against the second LRTP portfolio during a late October meeting of some of MISO’s board members. Patton once again argued that benefits are exaggerated and MISO is not working from a realistic set of future resource assumptions. (See MISO IMM Makes Closing Arguments Against $21.8B Long-range Tx Plan.)  

MISO said it “disagrees that the benefit calculations are flawed, in error or arbitrary.” The grid operator also is resolute that it will not test the value of the LRTP portfolio against a future scenario where it never develops the LRTP projects. 

“The future scenarios used for LRTP are appropriate, and the development of a new resource plan without transmission would be inappropriate,” MISO said. “The objective of LRTP is to understand the value of transmission based on the collective member resource plans as represented in the future. This approach is how MISO and others have performed benefit analysis for regional transmission for more than a decade.” 

Further, MISO formally disagreed with the IMM’s State of the Market recommendation from 2022 to improve the LRTP process and benefit projections. The RTO said it was contradicting its Monitor after extensive evaluation and affirmed its support for the LRTP process. 

MISO said the LRTP and “other transmission planning processes are not in scope for the IMM’s role to evaluate and monitor the performance of the markets.” 

At the October Market Subcommittee meeting, Patton argued that the capacity expansion MISO envisions through the early 2040s and based the portfolio on is “extremely unrealistic” and “not reflective of what the states and utilities say they’re going to do.” He also said MISO continues to overinflate the benefits of the portfolio and pinned the value of LRTP II closer to a 0.3:1 benefit-to-cost ratio. 

“I think we have a major problem here on where we are on LRTP,” he told stakeholders, and advocated for a pause on the process to “come up with a portfolio with benefits that truly justify the costs.” At that point, Market Subcommittee Chair Tom Weeks asked the lMM to focus solely on issues germane to markets. He said the Market Subcommittee isn’t the venue to discuss transmission planning. The exchange was emblematic of some members maintaining that the IMM shouldn’t interfere with MISO transmission planning.  

“I don’t see such a clear distinction between planning and markets because of how they interact with one another,” Patton responded.  

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PJM MIC Briefs: Nov. 8, 2024

PJM Presents Issue Charge on Black Start Compensation

PJM’s Glen Boyle presented an issue charge focused on the potential for compensation for generators providing black start service to fall to zero in net cost of new entry (CONE) values in the 2025/26 Base Residual Auction (BRA). 

The problem statement says the drop in black start compensation would be an unintended consequence of a drop in net CONE that is likely to continue, or continue to go lower, in the following delivery year. Compensation is determined by multiplying net CONE, the amount of black start service provided and a 0.01 modifier for hydroelectric generators or 0.02 for combustion turbines and fuel-assured black start units. 

“This significant drop in revenues for resources on the Base Formula Rate may lead to black start units withdrawing from providing Black Start Service. This could result in reliability concerns or use of the reliability backstop if black start requirements can’t be met,” the problem statement says. 

Since black start is a voluntary service, Boyle said PJM is concerned that without proper compensation, generation may exit the market and leave PJM unable to procure resources for all zones. 

Stakeholders Endorse Expansion of Lost Opportunity Cost Credits for Renewables

The Market Implementation Committee endorsed revisions to Manual 28: Operating Agreement Accounting to include solar, hybrid and energy storage resources in the lost opportunity cost (LOC) credit calculation. The formula was developed for wind generation and is being expanded in accordance with FERC’s approval of PJM’s second phase of its hybrid resource rules (ER23-2484). (See “PJM Presents Conforming Revisions to Manual 28,” PJM MIC Briefs: Oct. 9, 2024.) 

The calculation multiplies the LOC deviation by real-time locational marginal prices, minus the total LOC offer, all of which is then divided into 12 months. The deviation is based on actual forecast output. 

PJM Drafting Second Cluster of CIFP Manual Revisions

PJM’s Skyler Marzewski presented the RTO’s timeline for seeking revisions to several manuals to implement aspects of its capacity market changes drafted through the Critical Issue Fast Path (CIFP) process last year and approved by FERC in January. (See FERC Approves 1st PJM Proposal out of CIFP.) 

The changes include summer and winter capability testing, which would be codified in Manual 18: generation operational testing. That would require revisions to manuals 14D, 18 and 28, and attestation requirements for dual-fuel units, which would come with changes to Manual 11. 

The manual revisions are set to go for first reads and endorsement votes at the MIC and Operating Committee in the first quarter of 2025, with an endorsement vote possible at the Markets and Reliability Committee at its April meeting. The changes are intended to go into effect at the start of the 2025/26 delivery year. 

PJM Details Path Forward on Reactive Power

PJM Assistant General Counsel Thomas DeVita outlined PJM’s plan to remove the reactive power compensation component of the energy and ancillary service (EAS) offset in accordance with FERC’s order that RTOs cannot charge transmission customers for receiving reactive power within a standard range (RM22-2). 

PJM was one of three RTOs granted a longer compliance filing timeline to allow for a transition mechanism for eliminating those revenues from its markets. But the commission specified that removing the reactive component from the EAS offset would need to be done in a separate docket apart from the compliance filing. 

DeVita said PJM plans to seek that change as part of a Federal Power Act Section 205 filing being written to revise the reference resource and treatment of reliability-must-run units in the capacity market. (See “OPSI Speakers Discuss Future Auction Design,” Panels Debate PJM Capacity Market Design at OPSI Annual Meeting.) 

Changes to the Tariff and Consolidated Transmission Owners Agreement would be required and are expected to be effective for the 2026/27 delivery year.