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March 30, 2025

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ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC

ISO-NE plans to reopen its interconnection queue April 1 as it continues to wait for a ruling from FERC on its Order 2023 compliance proposal, the RTO told the NEPOOL Transmission Committee on March 26.

The queue has been closed since June 13, 2024, which was the RTO’s proposed deadline for projects to have a valid interconnection request to participate in the transition cluster study, which would be the first cluster study run under the new interconnection procedures established by Order 2023.

ISO-NE requested an effective date of Aug. 12, 2024, in its compliance proposal but suspended its work to implement the interconnection changes in September 2024 because of the lack of a ruling from FERC. (See With FERC Inaction, ISO-NE Delays Order 2023 Implementation.)

Given the uncertainty around when and how FERC will rule on ISO-NE’s compliance, the RTO now has opted to reopen the queue and will continue to process requests under the existing “first-come, first-served” study process.

Alex Rost, director of transmission services at ISO-NE, said reopening the queue will enable interconnection customers to submit requests needed to participate in the 2025 interim reconfiguration auction (RA) qualification process.

However, Rost stressed that ISO-NE “cannot guarantee the treatment of [interconnection requests] submitted after the June 13, 2024, eligibility date set by Order No. 2023 until FERC issues an order [that] addresses the eligibility date.”

Also starting on April 1, ISO-NE no longer will allow customers to pause studies that are being processed under the existing serial interconnection rules. The pause was intended to enable resources that did not expect to complete their interconnection studies prior to the transitional cluster to avoid unnecessary study costs.

“Given the indefinite delay in FERC action on the compliance proposal and continuing serial studies, the ISO can no longer allow study pauses without potentially impacting lower-queued projects,” Rost said.

ISO-NE also said it likely will not be able to run a transitional capacity network resource (CNR) group study in coordination with the 2025 interim RA qualification process.

The CNR study was intended to help projects with complete system impact studies — but without capacity interconnection rights — to participate in capacity auctions on a shorter timeline.

The RTO had said it would need an order from FERC by the end of March to align the CNR group study with the 2025 interim RA qualification process, which includes a show of interest submission deadline at the end of April. (See New England Generators Remain in Limbo on Interconnection Reform.)

ISO-NE previously aimed to run the CNR group study in coordination with its 2024 interim RA qualification process. Missing the deadline for 2025 qualification creates significant uncertainty for resources hoping to join the study and could result in the elimination or significant delay of the CNR group study.

In recent months, stakeholders urged FERC to rule on ISO-NE’s compliance proposal as quickly as possible.

Flatiron Energy wrote in February that missing the end-of-March deadline “increases the chances that further process changes are necessary and thereby increases the chances that the transitional CNR group study and transitional cluster study are delayed.”

Delays to the CNR study and transitional cluster study would threaten the ability of resources in the queue to come online for the 2028/29 capacity commitment period (CCP 19), Flatiron wrote.

The company estimated 3 GW of projects eligible for the CNR study are proposed to come online before the start of CCP 19.

The New England States Committee on Electricity (NESCOE) wrote in November 2024 that the delay undermines “the efficient and timely interconnection of new resources” and urged FERC to act quickly “to help alleviate the interconnection queue backlogs and uncertainty that continues to exist in New England.”

Clean energy trade associations RENEW Northeast, Advanced Energy United, the New Hampshire Office of the Consumer Advocate and several environmental advocacy groups all submitted comments echoing the concerns of Flatiron and NESCOE.

In response to ISO-NE’s announcement March 26, Alex Lawton of Advanced Energy United said that “unless FERC issues an order within the next few days, the region will face cascading delays to our desperately needed interconnection reforms, which will result in more challenges to how and when new resources can come online.”

“Given the centrality of a functional interconnection process to ensuring reliable and affordable electricity, ratepayers will ultimately bear the cost of further delays,” Lawton added.

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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 that 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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State Briefs

ARKANSAS 

Carroll County Bans New Commercial Wind, Solar Projects

Carroll County voted to enact a moratorium on the construction of new commercial wind and solar energy projects. The moratorium would be in effect for five years after the Nimbus wind project begins operating. The project is in the earliest stages of construction. The company has been working on the project for years, and the county government cannot interfere with contracts that already have been signed. 

More: Arkansas Times 

‘Construction Work in Progress’ Bill Heads to Gov. Sanders

The state House of Representatives passed a “construction work in progress” bill that would allow utilities to finance projects during construction through a new rate increase rider. 

The investments would still have to be approved by the Public Service Commission. The bill would raise rates by about $5 a month for the first year. The bill now heads to Gov. Sarah Huckabee Sanders. If it is signed, it will take effect immediately. 

More: Northwest Arkansas Democrat Gazette 

CALIFORNIA 

Newsom Accelerates Fresno County Solar Project

Gov. Gavin Newsom has certified the 300-MW Cornucopia Hybrid Energy Project in Fresno County, meaning it can bypass legal challenges that often delay large projects. 

Senate Bill 7, passed in 2021, allows the governor to certify clean energy projects under the California Environmental Quality Act. Construction is expected to begin in late 2027, with operations beginning mid-2030. 

More: GV Wire 

SDG&E Cleared to Expand Imperial Valley Battery Site

The Public Utilities Commission has approved San Diego Gas & Electric’s request to expand its existing battery facility in Imperial Valley to 231 MW. SDG&E intends to install 100 MW of additional capacity to the 131-MW Westside Canal battery energy storage system. The expanded site is expected to begin operations by June. 

More: Renewables Now 

CONNECTICUT 

United Illuminating Cuts $70M in Investments

United Illuminating said it has cut nearly $70 million worth of investments in its statewide service territory because of the Public Utilities Regulatory Authority’s decision to deny much of the utility’s request for a rate increase in 2023. 

The announcement came less than a week after a Superior Court judge dismissed most of the company’s claims that PURA acted unfairly by denying its request for more than $100 million in additional revenues in its most recent rate case. A spokeswoman said the company has yet to determine whether it will appeal the decision. 

Eversource made a similar announcement in 2024 when it said it was cutting $500 million in investments as a result of its frustrations with PURA’s regulatory approach. 

More: CT Mirror 

IDAHO 

Idaho Power Agrees to $800K Valley Fire Settlement

Idaho Power has agreed to pay an $800,000 settlement to help the state restore winter wildlife habitat burned during October’s Valley Fire. 

The Legislature’s Joint Finance-Appropriations Committee approved a one-time $800,000 appropriation to the Department of Fish and Games wildlife program to allow the department to accept the settlement money and spend it on restoring burned areas within the Boise River Wildlife Management Area. 

The Valley Fire started Oct. 4 and burned 9,904 acres, including part of the Boise River Wildlife Management Area. A power line touching the ground was found responsible for starting the fire. 

More: Idaho Capital Sun 

LOUISIANA 

Livingston Parish Extends Moratorium on Solar Approvals, Development

The Livingston Parish Council voted to extend its moratorium on solar development through May 2026. The ordinance extending the moratorium says the parish is “undertaking a study and considering new development rules, policies and ordinances concerning the innovative technology of commercial solar power and solar panel farms.” 

More: WBRZ 

MICHIGAN 

PSC Approves Consumers Energy Rate Hike

The Public Service Commission has approved a $153.8 million rate increase for Consumers Energy. The increase, which was less than half of what Consumers initially sought, will take effect in April. It will raise the average residential bill by $2.78 (2.79%) a month. 

More: MLive 

NEVADA 

Reno Approves Data Center

An appeal for a second North Valleys data center was approved by the Reno City Council, which overturned the planning commission’s original denial. 

The Reno planning commission asked the council to hold off on approving more data centers last month until members could fully understand their effects. The council had the opportunity to change regulations in the codes for data centers, but the vote failed. 

The commission had denied the Oppidan Data Center over concerns there weren’t enough water or power resources available for the project. The data center is planning to use 8 acre-feet of water and 8 MW a year. 

More: Reno Gazette Journal 

NEW MEXICO

Forestry: Utility Line Caused Mogote Hill Fire

The Mogote Hill Fire that ignited March 14 was started by a utility line, according to investigators and a State Forestry spokesperson. The grass fire ignited a little after noon amid dry conditions and high winds, prompting evacuation orders along a nearby state highway. It grew to about 33 square miles before being curtailed. 

Forestry spokesperson George Ducker said he did not know who owned the line that sparked the blaze and referred the issue to the Mora County Sheriff’s Office. Rural electrical co-ops own most of the lines in the area. 

More: Source NM 

OHIO 

Senate Approves Measure Eliminating HB 6 Surcharge

The state Senate has approved a measure that, among other things, eliminates the legacy generation rider — a surcharge devised to prop up two aging coal plants that are part of the Ohio Valley Electric Corporation. 

The rider was part of 2019’s House Bill 6, which was at the heart of a massive bribery scheme that landed former House Speaker Larry Householder in federal prison with a 20-year sentence. So far, the rider has cost ratepayers about half a billion dollars. 

The proposal also encourages investment in new gas-fired power plants, as well as reducing the time for regulatory decisions. 

More: Ohio Capital Journal 

OREGON 

Forestry Report Says PacifiCorp Wasn’t Responsible for Santiam Canyon Fire

State Department of Forestry investigators determined the 2020 Santiam Canyon fire was not caused by downed power lines as plaintiffs’ attorneys have alleged but rather by hot embers drifting into the canyon from the nearby Beachie Creek fire. 

The report, released to the Oregon Journalism Project under a public records request, is a victory for PacifiCorp, the embattled utility that in 2023 was found by a jury to have been grossly negligent in declining to shut off power to the fire. 

“ODF investigators did not find any evidence that reported powerline ignitions had contributed to the overall spread of the fire in the Santiam Canyon,” the report read. “The most probable explanation for these ignitions is spot fires from the main Beachie Creek Fire, which was burning upwind of the ignitions in the Santiam Canyon.” 

More: Willamette Week 

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Company Briefs

DOE Approves Venture Global to Export LNG to More Countries

The U.S. Department of Energy has approved Venture Global to export LNG from its Cameron Parish facility to more countries. 

The approval means Venture Global can export LNG from its Calcasieu Pass 2 project to any country, including Europe. Previously, the plant was limited to exporting to the 20 countries the U.S. has free trade agreements with, which includes nations such as Australia, Canada, Israel, Korea, Mexico and Singapore. 

CP2 is expected to pump out about 20 million tons of LNG annually, which would make it the third-largest exporter in the nation. 

More: Nola.com 

OCI Holdings to Build 2-GW Solar Cell Plant in Texas

Korean chemical industries company OCI Holdings says it will build a 2-GW solar cell production facility in Texas. The company will invest $265 million in the plant that will initially produce 1 GW of cells annually before increasing to 2 GW in 2026. 

More: PV Tech 

RWE, Meta Sign PPA with Texas Solar Project

RWE and Meta has announced a new power purchase agreement with a 200-MW solar project in Texas. Under the agreement, Meta will purchase 100% of the output from RWE’s Waterloo Solar project, which is set to begin construction in late 2025. 

More: RWE 

T1 Energy Reveals Site of New Solar Factory

T1 Energy, formerly FREYR Battery, has revealed that the location of its new U.S. solar cell factory will be in Milam County, Texas. The $850 million facility will be a part of the Advanced Manufacturing and Logistix Campus at Sandow Lakes and will produce up to 5 GW of solar cells. Construction of the factory, which is expected to be one of the largest solar manufacturing facilities in the U.S., is scheduled for mid-2025. 

More: Electrek; Houston Chronicle