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April 8, 2025

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Fast-paced Effort will Address EDAM Congestion Revenue Issue

CAISO has launched an “expedited” initiative to address stakeholder concerns about how the Extended Day-Ahead Market (EDAM) will allocate congestion revenues when a transmission constraint in one EDAM balancing authority area causes congestion in a neighboring BAA. 

The issue came to light in February when Powerex published a paper contending that EDAM contains a “design flaw” that could subject non-CAISO market participants to $1 billion in unfair congestion-related charges that would be conveyed as payments to participants operating within the ISO. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

The problem will arise when a transmission constraint in one system “parallel” (or loop) flows on a neighboring system, the Vancouver, leaving the latter system — and its transmission users — to carry the costs of unexpected congestion, the Canada-based electricity marketer said. 

The paper argued that EDAM’s treatment of firm transmission rights and congestion would leave that market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while failing to provide the ability to recover or hedge against those costs — something the company called an “aberration” among organized electricity markets. 

Powerex, which owns transmission rights throughout the West, said the PacifiCorp, NV Energy and Idaho Power BAAs would be most exposed to the issue, including when those utilities use their own transmission to deliver their own generation to their own load.  

The company identified the issue after reviewing the revised Open Access Transmission Tariff (OATT) PacifiCorp filed with FERC in January to reflect its impending participation in EDAM, and other entities since have filed comments in that docket (ER25-951) expressing similar concerns. 

CAISO and PacifiCorp representatives initially responded sharply to Powerex’s assertions, calling the paper “misinformed and inflammatory.” But the new initiative indicates the ISO is taking the congestion issue seriously, even if it and EDAM supporters point out the issue is the byproduct of overlaying elements of an organized electricity market on the legacy OATT system.   

During a March 24 workshop to kick off stakeholder engagement for the initiative, CAISO staff presented an alternative method for calculating the allocation of certain congestion revenues under EDAM, with meeting participants raising concerns about long-term effects of the proposed method and asking for more clarity. 

CAISO outlined the proposed new method in a March 17 issue paper, which was reviewed in detail at the meeting. The alternative method would be “transitional” and would be informed by newly identified patterns of congestion as EDAM adds other balancing areas, Joanne Serina, CAISO vice president of stakeholder engagement and customer experience, said at the meeting. 

The ISO has cleared its calendar over the next two weeks to make room for the expedited initiative, Serina said. The accelerated timeline reflects CAISO’s desire to prioritize stakeholder feedback on EDAM issues, she said. 

“We are wholeheartedly committed to working with stakeholders to come to an equitable solution,” Serina said. 

CAISO could, as early as May, approve the alternative method, develop a different alternative or decide to keep the existing one. 

Question of Intent

The primary question in the initiative is whether certain congestion revenues should be allocated to the balancing area in which the congestion revenue accrued, or to the neighboring EDAM balancing area where the transmission constraint is located. 

Under existing design, the latter is true: EDAM is set to allocate congestion revenues to the BAA in which an internal transmission constraint is located. This approach has been approved by FERC and implemented for the past decade in the WEIM, and it is the practice today.   

The current congestion allocation approach follows cost-causation principles under which congestion revenues flow to the transmission constraint location. This is because the BA with the constraint must pay for and manage the constraint, CAISO said in its paper. Transmission constraints determine in part the congestion price at a pricing location, and congestion revenues then are allocated back to energy market participants, according to the paper. 

However, under the alternative design, congestion revenues associated with parallel flow schedules would be allocated to the BA where the congestion revenue accrued, not the neighboring balancing area where the constraint is located, the paper says. 

In the paper, CAISO said allocating congestion revenues to EDAM balancing areas based on where they are collected will “enable a more complete sub-allocation of congestion revenue from the EDAM balancing area to transmission customers exercising firm Open Access Transmission Tariff (OATT) transmission rights within their balancing area.”  

The alternative approach could increase or decrease the total congestion revenue available for sub-allocation to a balancing area, CAISO wrote. The EDAM area is not managed as a single balancing area or under one transmission tariff, so CAISO must determine what amount of congestion revenue is to be allocated to each EDAM balancing area, according to the paper. A balancing area then allocates revenues based on their specific tariffs. 

CAISO at the March 24 meeting responded to numerous questions and concerns about the alternative design. Many participants asked for clarification on the methodology and examples in the issue paper, while others looked for more information on potential impacts on the power system and suppliers. 

“What do you mean when you say, ‘Managing a constraint in an area’?” PacifiCorp commercial transmission manager Rohan Chatterjee asked at the meeting. 

CAISO regional markets sector manager Milos Bosanac responded: “Depending on the nature of the constraint, there may be additional steps that the balancing area may need to take. Predominantly, there will be dispatch effects associated with a constraint.” 

Jeff Spires, Powerex’s director of power, said his company is concerned that an alternative option would be transitional without agreement on the “guiding principles” around the future evolution of the markets. 

“I agree [with] letting the markets evolve … but at the same time, I would expect the opportunity to determine what principles are needed to provide that long-term confidence. Until we get to a full RTO world, these markets need to be compatible with that framework.” 

Speaking at a March 25 meeting of the Western Energy Markets (WEM) Governing Body, member Anita Decker said she recognized there would be “bumps in the road” with the rollout of EDAM. 

“But I think the important thing here is the intent, and the intent is to end up with a strong market, at the end of the day, for everyone that’s participating — and I think that intent really goes a long way to build confidence,” Decker said. 

“I just want to reinforce our commitment to making this transition from traditional OATT to a marketplace as smooth as possible, and that’s why I think we’re taking up this initiative and trying to find that path forward,” CAISO COO Mark Rothleder said at the WEM meeting.  

Stakeholder comments on the initiative are due by April 7. CAISO plans to publish a full proposal April 14, with the final proposal presented for decision by the ISO Board of Governors and WEM Governing Body at their May 20-22 meetings.  

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Vote on NYISO Firm Fuel Capacity Accreditation Tariff Language Delayed

NYISO on March 26 unexpectedly pulled a vote on modeling improvements for capacity accreditation from the Management Committee’s agenda, delaying further discussion until April 9.

Shaun Johnson, NYISO vice president of market structures, told the committee the ISO wanted more time to incorporate stakeholder feedback into the proposed tariff language.

“Unfortunately we’ve been entertaining and modifying the tariff up until yesterday,” Johnson said. “And we received feedback from stakeholders that’s really inappropriate for the MC. I completely agree that folks have not had enough time to review and vet the tariff language in advance of the meeting, so we pulled it from today’s agenda.”

Johnson said the revisions would be discussed April 9, on which a meeting of the Installed Capacity Working Group is scheduled. After that the proposal would be brought either to the MC’s normal meeting or a special meeting if needed.

The changes include new requirements for generators that say they are firm, with penalties for those that are unavailable when called upon. (See NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept.)

Johnson acknowledged that many stakeholders had concerns over the penalty structure, which would have two tiers based on the reason why the generator says it did not have fuel. Johnson reiterated that the ISO believed it was important to implement penalties that incentivize the correct behavior from generators attesting that they have guaranteed fuel arrangements.

“We are not in favor of pay-for-performance-type penalties that you’ve seen in other ISOs, which, for lack of a better term, can be called ‘bankruptcy penalties,’” Johnson said. “Penalties of that size can incur such high risk that folks are not going to participate, which is not the purpose of the firm fuel concept.”

A stakeholder representing generator interests said that it would be helpful if a special MC meeting was scheduled directly after the April 9 meeting because generators were running out of time to elect for firm fuel.

“If you file in the middle of May and don’t ask for a waiver of the 60-day period, you’re giving us about a week and a half to confirm if we are going to be firm fuel or not,” they said. “That presumes that FERC does nothing.”

The stakeholder said they understood that the ISO was in a tight place schedule wise but that they wanted to make sure the procedures were followable. They did not want generators to opt not to declare firm fuel when they otherwise were firm because they did not understand the new rules. “I’m hoping we can think about how we can maneuver timing so that we can afford as much time as possible.”

Johnson said the ISO would consider those concerns.

“I think your statement itself identifies part of the problem: You envision having the language that you’re looking for as giving the ISO the ability to apply the penalty when the evidence is gray, rather than black and white,” another stakeholder representing generators said. “That’s a huge problem.”

The Market Monitoring Unit also chimed in, saying the language as written would “weaken the firm fuel capacity accreditation rules relative to the status quo.” This was because generators with deficient operating plans could go many years without being detected or penalized, and the proposed penalty would not be an adequate disincentive against this situation, the Monitor argued.

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ISO-NE Finds Potential to Connect 9,600 MW of OSW Without Tx Upgrades

A new analysis by ISO-NE shows about 9,600 MW of offshore wind may be able to connect to the New England transmission system without triggering the need for upgrades. 

The study also found connecting offshore wind to points of interconnection (POIs) closer to the Boston area than previously modeled could reduce the overall amount of transmission investment needed by 2050 by up to $4.1 billion. 

The analysis builds on the findings of ISO-NE’s 2050 Transmission Study and is intended to “provide high-level information about system constraints” affecting offshore wind interconnection. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B and ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.) 

The updated analysis accounts for the finalized location of the Gulf of Maine lease area, which is located further south than ISO-NE assumed in the initial study. 

By shifting two POIs from Maine to Massachusetts and one from Massachusetts to Connecticut, ISO-NE found the region could save up to $2.1 billion in a low-demand scenario (assuming a 51-GW peak in 2050) and up to $4.1 billion in a high-demand scenario (57-GW peak in 2050). 

A spokesperson for ISO-NE noted that, after making the POI adjustments, the four transmission buildout strategies evaluated in the 2050 study all cost roughly the same, with any differences falling within the margin of error. 

Also in the new analysis, ISO-NE screened 50 potential offshore wind POIs using three 2033 load snapshots. While the original 2050 study, which focused on peak load conditions, modeled offshore wind resources at partial capacity, the updated analysis evaluated system conditions with offshore wind resources operating at full capacity. 

The RTO first analyzed the POIs in isolation to determine their interconnection capabilities. It found that 19 may be able to support a 1,200-MW interconnection without upgrades, three could support up to 2,000 MW, and one could support up to 2,400 MW. 

ISO-NE said the results should be viewed as “best-case since the viability of each POI could only decrease when subjected to a full interconnection study with more detailed analysis, along with other non-electrical factors such as permitting and siting.” 

“Up to 38% of the existing major coastal substations in New England studied may be electrically suitable for a 1,200-MW offshore wind interconnection without constructing any new transmission infrastructure and without upgrading any existing transmission infrastructure to address thermal concerns,” ISO-NE found. 

While most substations would need upgrades to support a 1,200-MW injection, ISO-NE found the majority of POIs could facilitate a 1,200-MW wind farm with less than $100 million in transmission upgrades. 

ISO-NE also conducted a “multiple-POI analysis” to evaluate how multiple interconnected projects operating at full capacity at different locations on the system would affect the grid.  

It found the region could add up to 9,600 MW of offshore wind before risking curtailment during low-load periods. Minimum load concerns could be further exacerbated by continued growth of behind-the-meter solar resources, ISO-NE noted. 

However, “if generator owners are willing to accept significant curtailment, or pair wind farms with substantial energy storage, more than 9,600 MW may be able to reliably connect without major upgrades,” ISO-NE said, adding that increasing exports from the region could also reduce curtailment. 

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NM Lawmakers Pass Bills on Grid Modernization, Tx Taxation

A bill passed by the New Mexico Legislature would boost advanced grid technologies, which are seen as a way to make the grid more efficient and potentially reduce the need to build new transmission lines.

House Bill 93 by Rep. Kristina Ortez (D) now awaits a signature from Gov. Michelle Lujan Grisham, who has until April 10 to act. Bills not acted upon by the governor are “pocket vetoed.”

Another bill that passed before the Legislature’s 60-day session ended March 22 was HB 295 by Rep. Nathan Small (D). It would ensure that transmission projects owned by the New Mexico Renewable Energy Transmission Authority (RETA) are exempt from property tax, even if those projects are leased and operated by another entity.

That includes Pattern Energy, according to a fiscal impact report on the bill. Pattern is co-developing the 550-mile, 525-kV SunZia transmission line in partnership with RETA.

Grid modernization also may have a new source of grant funding under Senate Bill 48, by Sen. Mimi Stewart (D), which if signed by the governor would create a community benefit fund.

According to the Sierra Club Rio Grande Chapter, the fund would invest $210 million to create jobs and “strengthen the communities most impacted by climate change.” The Sierra Club is part of a statewide coalition, Clear Horizons New Mexico, that supported the bill.

Community fund allocations would include $70 million to the grid modernization grant fund and $15 million to the community energy efficiency development block grant fund.

Grid Efficiency

HB 93 would require public utilities to consider the deployment of advanced grid technologies as part of their integrated resource plans. Utilities also could include requests for advanced grid technology in their applications for grid modernization projects.

Under existing law, a public utility can file an application with the New Mexico Public Regulation Commission for grid modernization projects. If approved by the PRC, the utility may recover costs of the projects through base rates, an approved tariff rider or both.

HB 93 would update the law to add advanced grid technology to the types of projects for which a utility may seek approval.

Advanced grid technologies are defined as hardware or software that increases the efficiency, capacity or reliability of the grid. They may include advanced conductors or grid-enhancing technologies such as dynamic line ratings, advanced power flow controllers or topology optimization.

“We might not have to build as many transmission lines by making our current [grid] scenario as efficient as possible,” Sen. Michael Padilla (D), a bill co-sponsor, told the Senate Conservation Committee on March 11. Padilla said the bill also would promote economic development.

HB 93 directs the PRC to evaluate whether an advanced grid technology project will reduce ratepayer costs by delaying the need for investment in new generation or transmission. Other factors for the PRC to consider include improved reliability, increased access to clean energy and whether it’s “the most cost-effective among reasonable alternatives.”

Advanced Energy United called the bill’s passage “a major clean energy victory.” Advanced grid technologies can be “a smarter, faster, more cost-effective way to upgrade the grid,” Michael Barrio, a senior principal at AEU, said in a blog post.

Barrio noted that much of the Legislature’s focus this session was on public safety, making it harder for clean-energy-related bills to receive attention. He said one missed opportunity was HB 13, which included a framework for distribution system planning and measures to promote transportation and building electrification. The House passed the bill, but it stalled in the Senate.

Fuel Standard Repeal Fails

Another bill that failed was HB 328, by Rep. Randall Pettigrew (R), which aimed to block the adoption of rules to enact a clean transportation fuel standard. HB 328 was referred to committee but never was heard.

The Legislature finally approved a clean fuel standard last year, after several previous attempts, and the New Mexico Environment Department is in the rulemaking process. The state Environmental Improvement Board is expected to hold a hearing this summer on the proposed regulations.

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All 7 ISO/RTOs Send Senior Executives to Update Congress on Reliability

WASHINGTON — Senior executives from all seven ISO/RTOs testified March 25 about how they are maintaining reliability in the face of growing demand at the House Energy and Commerce Subcommittee on Energy. 

Subcommittee Chair Bob Latta (R-Ohio) noted that NERC has forecasted that 52 GW of generation is retiring in the next four years as demand is shooting up from data centers around the country. 

“When operating correctly, electricity markets should allow clear market signals to drive investment into new generation; efficient interconnection of new resources should address increasing demand; and coordinated transmission planning should bring needed electricity supplies to growing load centers,” Latta said. “However, these organizations and their electricity markets do not operate in a vacuum.” 

Policies like EPA rules and tax credits for renewables have helped to undermine the economics of baseload power and are impacting the markets, Latta said. 

Ranking Member Kathy Castor (D-Fla.) noted that the hearing’s focus on reliability ignores negative impact from Republican policies, including Congress trying to end subsidies for renewables and President Donald Trump’s executive actions. 

“The energy affordability crisis we are grappling with today requires real, forward-looking policy solutions,” Castor said. “It requires a politically independent and well-staffed FERC.” 

During the question-and-answer period, Castor noted that Trump recently fired the two Democratic members of the Federal Trade Commission, even though it already had an open seat that, once filled, would have produced a Republican-appointee majority. FERC is one of many agencies where longstanding precedent holds that members can be fired only for cause, which likely will be the central issue of litigation over the FTC commissioners and other firings by Trump. 

“Is more politicization of FERC a good thing or a bad thing?” Castor asked the assembled ISO/RTO leadership. 

All the ISO/RTO leaders said that a more independent FERC is better, including ERCOT CEO Pablo Vegas, whose organization interacts more with the Texas Public Utility Commission than the federal agency. 

“My observation over the years is FERC has tried to stay in the middle, to the extent possible, and I think that less politicization is helpful,” ISO-NE CEO Gordon van Welie said. “Another point I’d make is there needs to be alignment between federal and state policies.” 

Several others said an independent FERC was important to all of the issues the industry is facing, like load growth, new resources coming online and traditional power plants retiring, which were the focus of the hearing. 

“The stability of FERC is important to move all of these things forward,” MISO Senior Vice President Jennifer Curran said. 

PJM CEO Manu Asthana said having FERC at the helm with the ongoing transition the industry is facing is important. 

“FERC plays a critical leadership role in our industry,” Asthana said. “And the value of having a fully staffed, well-functioning federal regulator, particularly at this time, cannot be understated.” 

Asthana said PJM is seeing three trends that make ensuring reliability more difficult. Federal and state policies are leading to the retirement of dispatchable, thermal generation, and what is coming online and waiting in the queues is almost all intermittent renewables, which help but cannot replace dispatchable power one for one. The third trend is growing demand, largely from data centers. 

“Less supply, more demand — it adds up to increased reliability risk,” Asthana added. 

The grid’s tightening balance contributed to a spike in capacity prices, which led to political backlash that continued at the hearing. 

“I am incredibly frustrated at the costs that PJM’s failures are imposing on my constituents,” Rep. Frank Pallone (D-N.J.) said. “The vast majority of the rate increase on New Jersey families is due to what happened in PJM’s capacity market.” 

New Jersey imported 43% of the energy consumed last year, and its plan to make up that gap was to build offshore wind. PJM helped it as much as it has with any state policy in the region to get that done, Asthana said. 

“The problem is there is not one turbine spinning offshore of New Jersey,” Asthana began. 

Pallone cut him off and noted that the Trump administration has thrown up more roadblocks to offshore wind, including cutting off permits. (See EPA Puts Hold on Atlantic Shores OSW Permit.) 

PJM should have made changes to the capacity market and the interconnection queue sooner, Pallone argued. 

Asthana said the RTO was not delaying anything: It has been making reforms for years, he argued, and even as it continues to work through a queue backlog, about 50 GW of resources are ready to plug into the grid now. 

The spiking capacity prices led PJM to agree to a new cap and floor on its market after negotiations with Pennsylvania Gov. Josh Shapiro (D), but that drew the ire from the other side of the aisle later in the hearing. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

“I am concerned that PJM gave into political pressure of some of the governors of its member states, and this is a very distressing precedent,” Rep. John Joyce (R-Pa.) said. “What are the dangers of governors in the future influencing PJM’s market to score short-term political points?” 

PJM had bipartisan support to institute the price cap, with 11 of its 13 states and five of the region’s governors backing the move to cap prices, Asthana said. “But I do think it’s important to let our markets work, and we’re going to have to ensure that we really allow that in the future,” he added. 

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Stakeholders Call for Further IBR Standard Revisions

ERO stakeholders expressed a range of opinions about NERC’s proposed ride-through requirements for inverter-based resources, with some asking for multiple changes before their acceptance by FERC (RM25-3).

NERC submitted PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers) and PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) for FERC’s approval on Nov. 4, 2024, along with three others. (See NERC Submits IBR Standards to FERC.) The standards addressed the second milestone in FERC Order 901, covering performance requirements and post-event performance validation for registered IBRs.

Commissioners called for stakeholder comments on PRC-024-4 and PRC-029-1 in December 2024 in a notice of proposed rulemaking (NOPR) that suggested approving the standards, along with the definition of “ride-through,” and requiring NERC to submit informational filings 12 and 24 months after the close of the period for generator owners (GOs) to seek exemptions for existing IBRs permitted under PRC-029-1. (See FERC Approves NERC Assessment, Seeks Comment on IBR Standards.)

These filings would provide information on the number of legacy IBRs that would be subject to compliance, and on the number of exemptions requested and granted by NERC.

In its comments, NERC acknowledged the proposed information filings were based on concerns about the effect of generator exemptions on grid stability and the desire to avoid issuing too many. But the ERO urged FERC to change its directive to require a single filing 18 months after the close of the exemption period rather than at 12 and 24 months.

NERC said 12 months “may be too soon for NERC to review all exemption requests and determine which requests qualify for the exemption,” while 24 months “would result in FERC not receiving a comprehensive understanding of the exemptions’ impact on reliability as quickly and result in redundant information being provided.” An 18-month deadline would provide enough time to review all data and give the commission the information it needs, NERC said.

Comments also were submitted by a range of ERO participants. In one filing, a group of ISOs and RTOs comprising CAISO, MISO, PJM and SPP generally supported FERC’s NOPR with no issues. However, the writers did observe the exemption process provided in PRC-029-1 “does not contemplate the actual exemption requests also be submitted to … ISOs and RTOs.”

The ISOs and RTOs said they believe it’s reasonable “that generators seeking such exemptions provide copies … to ISOs and RTOs and other system operators,” but added that they could support the standard as written “based on the common understanding” that it would not prevent operators from seeking that information on their own.

Other comments sought more significant changes, particularly to PRC-029-1. In a joint filing, the American Clean Power Association (ACP) and the Solar Energy Industries Association (SEIA) urged FERC to direct the incorporation into PRC-029-1 of the following revisions:

    • Expand exemptions to include resources that have executed an interconnection and primary design, procurement and/or construction agreements by the effective date of the standard.
    • Clarify the evidence required to secure an exemption on the basis of equipment limitations.
    • State that existing equipment that receives an exemption due to hardware limitations will not lose it if new equipment is added separately to the plant.
    • Update the treatment of equipment at HVDC-connected IBRs.
    • Retain the ability of an exemption from frequency ride-through requirements.

ACP/SEIA said the changes would “maximize electric system reliability, ensure just and reasonable rates by avoiding excessive retrofit and replacement costs that do not improve reliability, and prevent undue discrimination.”

The Edison Electric Institute also supported revising PRC-029-1’s exemption eligibility, which “does not consider the impact on [GOs] who have projects under development.” EEI said the standard, as written, did not account for “long lead time projects,” which “require GOs and project developers to make engineering decisions based on equipment design well before resources can be secured [and] built.”

EEI asked FERC to have NERC modify the exemption process to include projects for which the equipment already has been contracted for, delivered or deployed. In addition, it expressed concern about the objectivity of the exemption process and urged FERC to direct modifications aimed at ensuring NERC carries out the process consistently across all regions.

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NJ BPU Head Running Against the Clock

TRENTON, N.J. — Christine Guhl-Sadovy, president of the New Jersey Board of Public Utilities, has a lot to do and little time to do it in.  

Her boss, Gov. Phil Murphy (D), leaves office at the start of 2026 and is not shelving his ambitious clean energy plans, even if the Trump administration would like him to. 

Murphy wants more electric vehicles on the road, a surge in solar, plentiful storage in place to make up for the vagaries of sun- and wind-powered generation, and a steady increase of buildings fitted with electric heat and hot water systems where gas-powered facilities once would have done the job. 

The governor also has not given up on his vigorous efforts to jump-start the state’s offshore wind (OSW) sector, though Trump, rising costs and tortured supply chains may have pushed that beyond his reach. 

“A year is a long time,” Guhl-Sadovy said in an interview with NetZero Insider on her agency’s energy priorities in this unpredictable era. “And I would say we’re running for the tape, as they say. We’re not slowing down.” 

The BPU chief also is charged with keeping the cost to ratepayers manageable, a task made much trickier by an expected 20% hike to the average electricity bill in June as a result of a basic generation services auction in February. 

Some of that hike is driven by the state’s electricity supply shortfall, which is widely expected to get worse as data centers come online in the state and EV adoption rises. New Jersey, an energy importer, is one of the 13 states served by PJM. 

Guhl-Sadovy is convinced cheap, clean energy is the answer to many of these problems, a position that in part reflects her early career. Her resume includes a stint as an organizing representative for the Sierra Club, working on OSW issues, after which she became legislative and political director for Planned Parenthood. 

She became chief of staff to former BPU President Joseph Fiordaliso and then cabinet secretary for Murphy, who first placed Guhl-Sadovy on the BPU and then tapped her to become agency head when Fiordaliso died unexpectedly in September 2023. (See NJ BPU President Fiordaliso Dies.)    

So, she knows the view from inside and outside the state’s halls of power. And she plans to do what she can to make sure Murphy gets the maximum impact from the waning days of his administration. 

“The big priority is getting as much clean energy onto the grid as possible,” she said. “Our goal here is always to do everything that we do with an affordability mindset, and so ensuring that clean energy is helping to drive down prices, and making clean energy available to as many people as possible, is going to be the No. 1 priority.” 

“Unfortunately, a lot of people have intentionally or otherwise confused clean energy with the increase in capacity prices,” Guhl-Sadovy said. “In fact, we know that without solar and storage and onshore wind in other states in the PJM region, those prices would be even higher. And so, we really need to get as much clean energy out of the PJM queue [and] onto the grid as quickly as possible to help provide stabilization to long-term prices.” 

Juggling Priorities

NetZero Insider interviewed Guhl-Sadovy days after the BPU released a draft of the New Jersey’s next Energy Master Plan. It predicts the state will face a 66% hike in electricity use by 2050 under the current policies and forecasts triple-digit growth if the state follows any of three more aggressive electrification policies proposed in the plan. (See NJ Releases Electrification-focused Energy Master Plan.) 

NetZero Insider: What are the BPU’s energy priorities for the next year? 

Christine Guhl-Sadovy: “We know that we have demand increases being projected, primarily resulting from data centers in the PJM region, not necessarily even in New Jersey at this point. And we know that clean energy has helped to minimize the price increases by getting more clean energy. And we want to continue to do that. 

“Solar and storage are the fastest resources to get onto the grid and to get through PJM, and so we want to get as much as possible onto the grid. If there’s one or two (priorities), a big one would be getting the storage incentive program open. We are going to move forward with our competitive solar solicitation, our next community solar allocation (and) working toward our [2025] energy efficiency program,” known as Triennium Three. 

NZI: A common assessment of the state’s problems is that supply is limited, and PJM often is blamed. (Critics say the RTO failed to forecast and prepare for the demand surge, which has been exacerbated by lengthy delays that prevent new generation projects — especially clean energy — from exiting the waiting queue and opening for business). What is BPU doing to try to address the problems at PJM? 

CGS: “A couple of things. Supply is really important, but I think it’s also very important to understand that it’s not just the supply that is driving up prices. (It’s also) the PJM market rules, which the BPU has been advocating changes for, and the PJM queue, which, when Joe Fiordaliso was president, we were pushing PJM to expedite their queue reform — even before we saw these auction prices that were as high as they are. 

“Those are two related, but not exactly the same, issues that are driving up prices. One is the market rules, which we have been pushing PJM on and continue to push PJM on and have gotten some changes as directed by FERC. We have filed numerous comments (with FERC) on these market rule issues, on the queue reform issues. We supported Gov. [Josh] Shapiro’s lawsuit around the cap.” (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

NZI: What PJM rules are at issue? 

CGS: “The (PJM) auction for July of last year set prices for the energy year that is coming up and implicated our own auction. It’s a projection for how much capacity is going to be needed a year in advance, and those projections changed dramatically from 2022 to 2024 — … PJM’s own projections for what we were going to need in the upcoming five years, in terms of capacity, driven by some retirements of some generation, or planned retirements of some generation, and an increase in demand.” 

Based on that process, bid prices in July were 10 times those of the previous year, she said. 

“And so, we want to make sure, at minimum, that the auction prices and the auction reflect the real projected supply and demand. We want to make sure that all available generation is being counted so that that doesn’t have an artificial scarcity effect on the market, so all the available renewables are bidding into the market and are counted, making sure that peaker plants are counted, as available generation.” 

Paying for Infrastructure

NZI: What is the future for New Jersey’s wind sector? EPA just reversed the permits on the Atlantic Shores project, which is New Jersey’s most advanced wind project and had final approval from the federal government. Is the wind sector dormant until Trump decides it’s not, or ― assuming the EPA reversal is overcome ― could Atlantic Shores move ahead anyway? (See EPA Puts Hold on Atlantic Shores OSW Permit.) 

CGS: “We have three awarded projects still in New Jersey, including Atlantic Shores and Attentive [Energy Two] and Invenergy [a joint venture with energyRE, known as Leading Light Wind]. But there is supposedly an executive report coming out at some point [from the Trump administration]. I would assume over the summer. That will be a deciding factor for how these projects can move forward, not just in New Jersey. All the developers are waiting to see how this executive report plays out, whether it’s going to be narrow or broad. 

“We certainly hope that the president, over the next several months, will see the importance of getting offshore wind online. When we think about needing generation, and I think the president has noted, we know we need large-scale generation to help keep prices stabilized over time. When we think about the projects that could connect to the grid, even in this PJM region, in the medium term, five to seven years, those [offshore wind] are the projects.” (See NJ Abandons 4th OSW Solicitation.) 

NZI: What is the status of the pre-build project to develop the infrastructure to tie offshore projects to the grid? 

CGS: “It’s still pending. It’s an open solicitation.” 

NZI: What are the state’s plans for upgrading infrastructure? 

CGS: “For things like solar and storage and transportation electrification, we have our grid modernization proceeding. We put together several working groups, and we’re finalizing the changes to the interconnection rules from those. That’s really about efficiency, alignment amongst the utilities, so that there’s a very clear process for how projects can get into the grid, and whether there’s available capacity ― doing hosting capacity maps so that developers can know where there’s capacity for projects to come online. And we’re already working on recommendations from our second set of grid modernization rules.” 

NZI: Is there funding in place for grid upgrades? 

CGS: “That will be part of the conversation for the second grid modernization rules. How should funding and funding needs be allocated? But infrastructure costs money. If we are expanding economic development in parts of the state like Cumberland County, where they traditionally didn’t have the same kind of capacity needs for the grid as they might now have, whether it’s data center or storage or solar, they need new infrastructure to support economic development. So, we have to figure out a way that allocates the costs of meeting new infrastructure, whether it’s for load growth related to data centers, whether it’s for solar interconnecting.” 

EV Adoption Rate Slows

NZI: Do you think the state is doing enough to promote EV adoption, or does there need to be a change of course? (ChargeEVC-NJ announced the growth rate of EV registration slowed a bit in 2024, growing by 40% compared to a 66% increase in 2023.) 

CGS: “All of the EVs on the road didn’t get incentives from the state, obviously. The incentives through the BPU and the [EV charging] infrastructure, through [the Department of Environmental Protection], were really about helping to spur the market. And I think that we have been successful in doing that. Now we’re focusing a lot of our incentives on income-eligible drivers, so that the people who really need the incentive to make the switch can do that. But certainly, there’s uncertainty at the federal level with how there’s going to be federal support and tax incentives for EVs. So, we’re trying to do as much as we can at the state [level] to make sure that market continues.” 

NZI: You were a grassroots activist early in your career. What does that bring to your job as BPU president? 

CGS: “That’s such an interesting question. When I was an organizer at the Sierra Club, I actually organized around issues that this department was handling and [was] advocating for progress … at that time [on] the Offshore Wind Economic Development Act. I think that has given me a really clear view of stakeholder interests, and what is important. Coming into the administration and coming into government from that kind of background has been a valuable experience for me to have because of being able to identify what things matter to different stakeholders and also being able to communicate with stakeholders. 

“The importance of balancing interests and making sure that everyone is heard and getting feedback from different industries and parties ― I feel like it’s one of the most valuable experiences that I’ve had to bring to this role.” 

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Utilities Ask FERC to Toss Local Tx Planning Complaint; Others Support It

FERC was flooded with comments on a wide-ranging complaint consumers filed seeking increased oversight of local transmission planning, with utilities arguing the complaint should be tossed, while others contend it has merit and raises issues that need to be addressed.

The complaint alleges that transmission owners around the U.S. have been moving more projects into local transmission siting processes because they fall into a regulatory gap with minimal oversight (EL25-44). To remedy that, the complainants contend, all lines rated at 100 kV and above should be regionally planned, and FERC should set up “independent transmission monitors” to oversee the planning process. (See Consumer Groups Seek Independent Oversight of Local Tx Planning.)

The complaint was lodged against every RTO and ISO and all other transmission planners under FERC jurisdiction.

In comments filed March 20, the Edison Electric Institute said the complaint “is anti-infrastructure, suggesting unworkable requirements that would stymie the development of necessary transmission projects at a time when substantial investment in transmission is needed to serve growing load, support generation expansion, and maintain reliability, as well as to support national security and ensure the United States is positioned to be economically competitive in the global market.”

EEI echoed an argument common among opponents of the complaint: that in highlighting broad general issues with local transmission, the complaint failed to meet the burden of proof FERC requires to grant filings under Section 206 of the Federal Power Act.

“Complainants take pages to recount history, identify a host of transmission projects rated at 100 kV, cite to various studies in support changes that would apply nationally, apparently in service of ensuring that consumers are afforded ‘economically efficient energy services at a reasonable cost,’” EEI said. “Yet, they draw no clear linkage between the recitation of history, listing of projects, and the requested relief.”

Like many other opponents, EEI also said the complaint amounts to a collateral attack on previous FERC orders on transmission, including Order 1920. FERC considered requiring more oversight of local transmission and independent transmission monitors in the rulemaking process that led to Order 1920, but did not include those changes in the final rule.

“Local transmission investments are vital to enabling the interconnection of distribution resources, as even concentrated pockets of distributed resources can require localized transmission system reinforcements such as the reconductoring of lower-voltage lines or the construction of new substations,” EEI said. “Local projects also enable transmission owners to nimbly develop infrastructure needed to effectuate state goals. In addition, upgrades to local, lower-voltage facilities are often needed to quickly meet changing system conditions and improve operational flexibility.”

WIRES Group also urged FERC to reject the complaint, saying now is not the time to inject uncertainty into the transmission planning process given the challenges facing the grid.

“Utilities are facing potentially overwhelming demand driven by data centers, and artificial intelligence,” WIRES said. “Investment in transmission infrastructure will enable the interconnection of new generation, the service of new load demands and efficient operation of the grid.”

Centralizing all local planning at 100 kV and above would prove unworkable, WIRES said. Regional planners would have to replicate a public utility’s in-house staff, including transmission and substation engineering experts, real estate specialists, field crews, environmental staff and operational personnel.

“It is difficult to conceive how a regional planner could fill those needs in a timely fashion, even if such experts were available for hire,” WIRES said. “Complainants fail to explain how this transfer or duplication of staff, knowledge or expertise is even reasonable, efficient, or cost effective for customers.”

On top of staffing, there are issues with handling data from local utilities that often is confidential, WIRES said.

NARUC did not weigh in on the specifics of the complaint, but it intervened to note it had passed a resolution at the recent winter meetings that is related to local transmission planning oversight.

“NARUC urges the commission to act swiftly to put in place effective and robust transmission cost management and oversight processes for ‘end of life’ or ‘asset condition’ transmission projects in RTO regions, when requested by states within the region, with recovery of associated costs borne by those regions,” it said in brief comments.

Regional Views

Some comments from individual states highlighted how inconsistent oversight for local transmission is at the state level.

The California Public Utilities Commission said any “repair and replace” projects that do not expand grid capacity are not included in CAISO’s planning process. From 2019 to 2021, 63% of capital additions in the ISO’s territory were “self-approved” by utilities.

“The proportion of spending on utility self-approved projects continues to be the overwhelming majority of transmission spending by California’s three large IOUs and has actually increased over past years,” the CPUC said. “In the most recent data from the CPUC’s Transmission Project Review (TPR) Process, nearly 75% of the capital expenditures on the IOUs’ transmission projects over $1 million for years 2020 through 2024, were on self-approved projects.”

Cost estimates for new CAISO transmission required over the next 20 years range from $45.8 billion to $63.2 billion.

“Taken in its entirety, transmission investment in the CAISO in the next 20 years could be staggering, and measures are needed in the CAISO and elsewhere to enhance transparency and oversight of more transmission projects to promote affordability and to achieve the most cost-effective transmission grid possible,” the CPUC said.

The New York Public Service Commission told FERC that local transmission projects in its territory are covered either through utility rate cases or state-run planning processes designed to meet the state’s climate and renewable energy goals.

“While the complaint is directed at the NYISO, it implicates the traditional regulatory authority exercised by the NYSPSC,” it told FERC. “The NYSPSC strongly opposes the complaint, which seeks a remedy that would preempt the NYSPSC’s existing planning authority and rate oversight covering local transmission upgrades and replacements under state law.”

New York’s transmission owners agreed, saying FERC should deny the complaint for being legally and factually deficient.

“The ink is barely dry on Order No. 1920-A, rehearing requests are still pending commission consideration, and transmission providers across the United States — including the NYISO — are hard at work developing their compliance proposals,” they said. “The commission, for its part, is actively overseeing compliance — a process that is both deliberate and essential to ensuring a smooth transition to a long-term orientation in regional transmission planning.”

New England states generally supported the complaint, but the Maine Public Utilities Commission intervened to say that its review of local transmission projects offered enough oversight, though it couldn’t extend that claim to the entire region.

“While the complainants correctly identified a regulatory gap present in New England, the MPUC submits that the one-size-fits-all remedy proposed by the complainants is inappropriate and should be rejected,” the regulator said. “Any remedy to the regulatory gap identified by complainants should consider regional differences and provide for regional flexibility, especially since, as described below, there are already regulatory and state statutory frameworks in place that address certain aspects of asset condition projects.”

The New England States Committee on Electricity agreed with complainants that the process in New England is not just and reasonable because asset condition projects are too lightly overseen.

“Unlike transmission projects in New England that ISO-NE selects to meet reliability needs through the regional planning process, the process to rebuild, refurbish or replace aged and damaged transmission facilities is conducted by individual and investor-owned transmission companies on an ad hoc basis,” NESCOE said. “The scale of these projects, to a substantial degree, go beyond mere ‘in kind replacements’ and instead are leading to the massive reconstruction of the regional electric power grid. Yet ISO-NE, the regional system planner, is largely shut out of this process.”

While the New England states complained about the process there, some of the biggest transmission owners in the region (Avangrid, Eversource, National Grid and others) argued the process already benefits from oversight.

“The NETOs’ [New England Transmission Owners] asset condition project planning process provides opportunities for state regulators, consumer advocates and other stakeholders to participate, ask questions and challenge projects before costs are allocated to customers across the region,” they told FERC. “Additionally, the NETOs, the New England states and regional stakeholders have been working to further improve the transparency of asset condition project planning and enhance opportunities for stakeholder participation in that process.”

The complaint also led to a split among PJM stakeholders, with the Organization of PJM States Inc. filing brief comments at least agreeing that FERC should deal with the issues highlighted in the complaint.

“Local planning of transmission in the PJM region has vastly outstripped regional planning in recent years, and thus retail consumers have not been able to reap the benefits of regional, more holistically planned projects,” OPSI said.

OPSI did not take a position on the complaint, but said it wants FERC to address the proliferation of locally planned transmission projects with finality.

PJM, on the other hand, urged FERC to reject the complaint.

“The complainants failed to bear the burden of demonstrating with substantial, specific evidence that PJM’s regional planning provisions are unjust and unreasonable because they do not also encompass local transmission planning,” the RTO said. “PJM’s regional transmission planning authority stems from that granted by the PJM Transmission Owners which have each turned over operational control of their interstate transmission systems to PJM, and reserved for themselves the continued right to local transmission planning.”

Some Ask ‘Why Us?’

With its broad allegations against the entire industry, some of the respondents questioned why they had been cited in the complaint in the first place.

SPP noted that its planning process largely already aligns with what the complaint wants, but it still was compelled to file a response. A group of its transmission owners, including American Electric Power, Evergy and Xcel, agreed with the RTO.

“As a threshold matter, the complaint should be dismissed outright with regard to the Southwest Power Pool and the SPP TO Group because the complaint concedes that ‘SPP’s regional approach is consistent with the relief requested nationally through this complaint,’” the TOs said.

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PJM MRC/MC Briefs: March 19, 2025

Markets and Reliability Committee

Stakeholders Endorse IRM and FPR for 2026/27 Capacity Auction

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed by acclamation PJM’s recommended installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2026/27 Base Residual Auction (BRA), with 40 load-serving entities and consumer advocates abstaining over what they called a lack of transparency into how the RTO arrived at the figures.

The IRM would increase to 19.1%, up from 17.8% in the 2025 Third Incremental Auction (IA), and the FPR would fall to 0.917 from 0.938. PJM’s Patricio Rocha Garrido said almost all of the change is being driven by increasing demand in the load forecast, particularly in the winter. The seasonal balance of risk tilts to 65% loss-of-load expectation in the winter, increasing from 54.5% in the third IA; for the expected unserved entry metric, 93.9% of the risk would be in the winter.

The effective load-carrying capability ratings for most classes would also shift in line with increased winter risk. The rating for offshore wind would increase by 7%, to 69%, followed by onshore wind at a 3% increase, to 41%. In addition to having strong winter performance, Rocha Garrido said resources in the wind categories received transitional capacity interconnection rights (CIRs), which boosted the class’s overall ratings.

Demand response resources would see their ratings fall by 8 points to 69%, while storage ratings would decline between 5 and 7% depending on the resource duration. Gas resources would see more modest drops, in part because of changes in class membership, while other thermals would be flat or fall by 1%.

Rocha Garrido said PJM ran a sensitivity using the 2025 resource portfolio and found there was minimal impact on ratings compared to 2026 expected resource mix, which he said supports the conclusion that most of the changing dynamics are being prompted by the load forecast. He explained the reason there is more winter risk is because of extreme peak loads increasing in the 2025 forecast relative to 2024, while the summer peak loads are not growing relative to the 2024 forecast.

Scope of Deactivation Task Force Widened to Include RMR Agreements

Stakeholders endorsed charging the Deactivation Enhancement Senior Task Force with exploring the creation of a pro forma reliability-must-run agreement.

The MRC endorsed the change with 85% support, followed by the Members Committee endorsing by acclamation the same day. (See “PJM Presents Changes to DESTF Issue Charge,” PJM PC/TEAC Briefs: March 4, 2025.)

The revisions to the task force’s issue charge add a new key work activity (KWA) to draft a pro forma arrangement that recognizes the possible resource adequacy that RMR units can contribute and be effective for the 2028/29 delivery year. That year is when a temporary tariff provision allowing PJM to model the output of some RMR resources as capacity is set to expire (ER25-682). (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

The new language also expands the scope of the issue charge to allow consideration of a pro forma RMR agreement and changes to the capacity market rules around generators that have requested deactivation but which PJM has determined are necessary to maintain reliability. The out-of-scope section also was revised to carve out the new KWA.

Several generation owners noted PJM’s target of submitting a proposal to FERC around the end of the year would prevent changes to how RMR resources interact with the capacity market from being considered in the Quadrennial Review, which is in its early stages at the Market Implementation Committee.

Vistra’s Erik Heinle said each RMR resource is unique and any pro forma agreement should retain the ability for a generation owner to pursue a cost-of-service rate at FERC. He suggested including language in the issue charge stating that owners of a deactivating unit can develop an agreement with PJM outside of the pro forma approach.

PJM Senior Counsel Chen Lu said he does not believe the proposed language would preclude that ability, adding it would be up to stakeholders to come up with rules that govern that.

Stakeholders Endorse Manual Language Expanding SIS

The committee endorsed revisions to Manual 14H implementing expanded eligibility for surplus interconnection service (SIS), reflecting tariff changes FERC approved in February. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)

SIS allows generation owners with resources that are not using their full injection rights to co-locate additional resources at the same point of interconnection, so long as the host resource’s CIRs are not exceeded and no network upgrades are triggered.

The new language eliminates categorical restrictions on what resources — battery storage in particular — are eligible for SIS; changes how PJM models projects proceeding through SIS alongside those in the general interconnection queue; expands eligibility to applications where the host generator still is in development; and allows projects that consume transmission headroom but do not require network upgrades. It also would allow projects that require additional interconnection facilities for the service while still prohibiting new network upgrades.

Applications that could affect the network upgrades required for projects in the interconnection queue that have not had PJM determine if they will require upgrades also no longer would be prohibited from proceeding as SIS projects. The changes also eliminated language preventing SIS applications from proceeding if PJM has identified that the project would have a “material impact” on dynamic system stability response, steady-state thermal and voltage limits, or short-circuit capability limits.

The manual language was endorsed by the Planning Committee during its March 4 meeting. (See PJM Stakeholders Approve SIS Manual Language.)

PJM Presents 1st Read of Proposal to Rework Black Start Compensation

PJM’s Glen Boyle presented a first read of a proposal to rework the base formula rate (BFR) used to compensate black start resources not carrying investment costs for providing the service.

The proposed tariff revisions were endorsed by the MIC during its March 5 meeting. (See PJM Stakeholders Endorse Changes to Black Start Compensation.)

The BFR includes numerous variables, including fixed and variable costs, training, fuel storage, and an incentive factor. The proposal would revise the fixed cost element to replace the zonal net cost of new entry (CONE) with a fixed value derived from the five-year RTO-wide CONE, which thereafter would be adjusted using the Handy-Whitman Index. Boyle said PJM does not see a correlation between net CONE and the need for black start resources, nor should there be a locational element to the price.

Boyle said PJM is concerned that if compensation for existing black start units is not increased, more resources will cease participation and they will have to be replaced on the more costly capital recovery factor (CRF), which is used to determine compensation for resources that require upgrades to provide black start. PJM is not proposing any changes to the CRF.

Since 2019 there have been 29 resources that stopped providing black start service, 26 of which were replaced through requests for proposals. All but two of the new black start units began providing the service on the CRF. Boyle said about 85% of the black start fleet is compensated through the BFR.

Independent Market Monitor Joe Bowring said there should be a focus on finding a way to compensate resources that fully considers their costs and ensures they see an appropriate return. He argued that the proposal, which was sponsored by PJM at the MIC, does not have a definition of an appropriate payment.

The Monitor’s proposal, which did not win the MIC’s support, would have used the RTO-wide net CONE, rather than zonal values, and included a recommendation that a more holistic stakeholder discussion be initiated to reconsider compensation.

“This is simply refusing to address the underlying issue and making vague and unsupported allegations,” Bowring said.

In previous meetings, Bowring noted the process was instigated by the net CONE for future BRAs falling with the shift to a combined cycle turbine as the reference resource. FERC since has granted PJM’s request to keep the reference resource as a combustion turbine.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates have been troubled by the lack of a metric to demonstrate the RTO’s concerns that generation owners may be considering pulling their resources out of black start service.

Stakeholders Discuss Uplift Costs Seen During January Storms

PJM presented the impact winter storms during January had on uplift payments, which amounted to nearly $332 million between Jan. 19 and 23.

Storms falling on long holiday weekends have proven to be a challenge for PJM, as gas resources typically must purchase a package with a steady rate of fuel when nominating for supply on weekends and holidays. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.)

Senior Dispatch Manager Kevin Hatch said the Martin Luther King Jr. Day weekend saw highly variable load, which complicated efforts to block schedule gas. The start of the weekend was forecast to have fairly modest loads, but ramped up to some of the highest winter peaks PJM has seen. Gas pipelines already had restrictions in place going into the weekend, and there was uncertainty about whether resources connected to those pipelines would be able to get fuel on the spot market.

PJM also had some resources start ahead of time so that any equipment failures associated with start-ups could be resolved before the storms rolled in. Once those units were online, Hatch said operators sought to avoid cycling them on and off throughout the storm to ensure they could remain available.

The RTO employed a new conservative operations procedure established after December 2022’s Winter Storm Elliott, allowing operators to commit resources in advance when they believe those units could have difficulty procuring fuel or otherwise are at risk of not being able available. Several stakeholders have argued the practice violates market principles and significantly increased uplift costs.

The majority of the uplift was balancing operating reserve credits, amounting to $206 million, while day-ahead operating reserve credits accounted for an additional $126 million.

In addition to impacts on the energy market, the amount of uplift paid during the January storm had a notable effect on the net CONE aspect of the capacity market, said Adrien Ford, director of wholesale market development for Constellation Energy.

“This is not acceptable to continue on the path that we’re on,” she said. “I’d like to note that this tie in is not just energy and uplift … but also net CONE.”

Members Committee

Stakeholders Endorse Changes to MC Webinar Scope

The MC endorsed reducing the number of reports delivered to the committee via the webinars held between its face-to-face meetings.

The revisions to Manual 34 were advanced by Calpine and seconded by Vistra in an effort to move substantive discussions to venues that are attended by a wider spectrum of PJM’s membership. (See “Manual Revisions Seek to Reimagine Role of MC Webinar,” PJM MRC/MC Briefs: Feb. 20, 2025.)

Vistra’s Heinle said the March 17 webinar included a fervent discussion about how load bids in the day-ahead market. He argued it would have been beneficial for more participants to be involved.

The language also shifts PJM’s regulatory, system and market operations reports to the MC, along with reports delivered by the Monitor and the Organization of PJM States Inc. Interregional coordination reports would be moved to the MIC.

The changes also would move the timing of the webinars to be held on the week following MC meetings, with the possibility of it being canceled if there is little to discuss. Currently it is held on the Monday before the committee meets.

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NERC Selects Berkshire’s Michael Ball as E-ISAC CEO

NERC has selected Michael Ball, senior vice president and chief security officer at Berkshire Hathaway Energy, to replace Manny Cancel as CEO of the Electricity Information Sharing and Analysis Center (E-ISAC) and senior vice president at NERC, the ERO said March 24. 

Ball will take over effective April 14, with Cancel planning to remain with the E-ISAC as an adviser until May 30, according to NERC’s press release. 

The ERO began the search for a new E-ISAC head in April 2024, after Cancel announced he would retire in early 2025. (See NERC’s Cancel, Hoptroff to Retire in 2025.) NERC CEO Jim Robb said Ball’s “experience working with the E-ISAC over the years coupled with his relationships and reputation with industry leaders and key government agencies will provide us with the skills needed to continue maturing and elevating our E-ISAC capabilities.” 

Ball has been with Berkshire Hathaway for 27 years, most recently leading a security team focused on strategic global cyber and physical security policies and practices. Previous roles at the utility include leading its company-wide risk management program and the quality assurance and business continuity teams at PacifiCorp. 

“I’ve had the privilege of protecting critical infrastructure throughout my 27 years at Berkshire Hathaway Energy,” Ball said. “I’m honored to carry that mission forward on a broader scale, supporting industry as a whole and the key services that our members and stakeholders provide to their communities.” 

Ball will take over the E-ISAC at a time of ongoing online pressure against North American utilities. In a recent filing, NERC told FERC that North American utilities reported three cyber intrusion attempts in 2024 that showed “an increased level of sophistication” on the part of the perpetrators. (See related story, ERO Says 2024 Cyber Incidents Showed “Sophistication”.) 

In recent months, the E-ISAC and its counterparts for other industries have had to work without a leader at the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), which is charged with identifying and managing risks to U.S. cyber and physical infrastructure. The agency’s previous director, Jen Easterly, resigned prior to President Trump’s inauguration. 

Trump recently nominated Sean Plankey, former Coast Guard officer and head of cyber policy at the National Security Council, to head CISA. The Senate has not yet acted on Plankey’s nomination. 

Cancel joined the E-ISAC in 2020, taking over from Bill Lawrence. Before joining the ERO, he was chief information officer at Con Edison. Cancel has represented the industry before Congress and in other forums, such as the ERO’s annual GridSecCon security conference, and has overseen the past two iterations of the biennial GridEx security exercise. 

During Cancel’s term at the E-ISAC, North American utilities have seen a marked increase in physical threats to grid reliability, as well as danger to electric equipment. Some of the threat actors have political motivations, such as the neo-Nazi leader who allegedly plotted to damage substations in Baltimore to start a race war. Other attackers have smaller-scale goals, like the men accused of damaging electric facilities in Washington state to cover up a burglary.