NYISO presented its final interim staff recommendations for the demand curve reset for 2025-2029 at the Installed Capacity Working Group’s meeting Sept. 10, with minor updates to some metrics.
The recommendations remain largely the same as the draft presented in August, with the two-hour battery energy storage system (BESS) as the representative lowest-cost peaker plant technology. (See NYISO Presents Draft Recommendations for Demand Curve Reset.)
As part of calculating the cost of new entry for a hypothetical peaker plant, Zach Smith, senior manager of capacity and new resource integration for NYISO, said the ISO opted to factor in land lease payments for the construction period for the hypothetical peaker. Interconnection costs were modified downward across all zones outside of Long Island. The new derating factor for the BESS also was discussed.
Smith said the interconnection costs were estimated to be higher because it was assumed peakers would require 345 kV, but 200-MW battery storage systems can connect to lower-voltage lines, which cost less. “And it appears to be better aligned with the actual interconnection requests that we are seeing,” Smith added.
“The change here is that we force the battery to charge more before the peak load window,” said Paul Hibbard, principal of Analysis Group.
Hibbard said the change causes negligible differences to net EAS revenue across all zones, aside from Long Island, which saw a 12% drop.
Derating Factor Headaches
Smith said NYISO was recommending a 2.5% derating factor for BESS peakers. The derating factor was calculated as a weighted average of the derating factors that batteries should expect to receive across their 20-year amortization period.
NYISO does not yet have a class average for BESS units. “The ICAP Manual (Section 4.5) currently establishes that the initial derating factor a new BESS would receive upon entering the ICAP market is based on the NERC class average equivalent demand forced outage rate (EFORd) of pumped hydro storage until three energy storage resources are participating in the ICAP market and have sufficient historical operating data to establish a ‘NYISO class average’ EFORd for energy storage resources,” the ISO said.
The 2.5% derating factor is based on the assumption that any new BESS would have an initial 9.19% derating factor — the current class average for pumped hydro — for its first year of operation. The derating factor for the second year would be 5.6%, which is the average of 9.19% and 2%, which is the derating factor estimated by NYISO’s consultants. NYISO then assumes a 2% derating factor for years 3 to 20 of the estimated life of the battery. The average over those 20 years is about 2.5%.
But this prompted questions from stakeholders.
“I don’t understand how you can make this change without making companion changes to the manual,” said Doreen Saia, of Greenberg Traurig. “The unit that comes online next year isn’t going to get 2.5%. It’s going to get 9.19% unless and until we make changes to our actual rules.”
Smith clarified the derating factor would be 9.19% for the first year and the average of the 9.19% and the actual availability of the BESS for the rest of its operating life.
“A unit’s derating factor, once it has sufficient operating experience, is always based on its actual production,” Smith said.
Open Questions, Open Frustrations
Smith went over several questions NYISO still was reviewing, such as how to take into account sales tax for BESS labor, operations and maintenance costs; investment tax credits for the transmission lines to the plants; and costs of debt and equity.
Some stakeholders were unhappy that several longstanding questions were not answered and not addressed in the open questions. They said they wanted to see cost declines for battery units included in the analysis.
“The ISO has recently shown the assumptions that it’s doing in the study with the Department of Public Service and the transmission owners, and it shows an expectation of more than a 50% decline in battery storage costs over the next 10 years,” said Mark Younger of Hudson Energy Economics. This meant a decline in revenues for the battery units; thus, NYISO’s net cost of new entry was about 45% too low.
Another stakeholder was disappointed NYISO was not proposing to include revenues for BESS units that come from outside wholesale markets, which could include incentive programs from the state and utilities.
“I think it severely overstates the net CONE of these facilities and therefore it will impose very high, unnecessary costs on New York consumers,” they said.
“Without additional modification, the compliance timelines and related provisions of the rule are not workable and are destined to trigger an acceleration in the pace of premature retirements of electric generation units that possess critical reliability attributes at the very time when such generation is needed to support ever-increasing electricity demand because of the growth of the digital economy and the need to ensure adequate backup generation to support an increasing amount of intermittent renewable generation,” they wrote. EPA’s final rule would strain their ability to maintain the reliability of the electric grid, they argued.
The grid operators had proposed a “reliability safety valve” that would help mitigate their concerns, but EPA did not include that in the final rule, nor did it explain why, they noted. The grid operators had wanted EPA to provide upfront, clear criteria on the “remaining use of life and other factors” and enforcement discretion; the creation of a subcategory of generators needed for reliability; offering states guidance on how to use a reliability valve; and the creation of “regional reliability allowances” that generators could use in emergencies to avoid penalties under the rule.
Instead, they argued, the final rule unreasonably discounts that existing fossil generators will need to decide whether to commit to installing untested technology or retire their units years before the compliance deadline with state compliance proposals due in 2026. That could accelerate earlier retirements of generators, the grid operators said.
The rule requires 90% carbon capture and storage for coal plants that want to run after Jan. 1, 2039, as well as for new and modified natural gas units with capacity factors of 40% and above. Both categories of plants would need to install CCS systems by Jan. 1, 2032.
“None of EPA’s projected time frames reflect historical rates of adoption of CCS technology for electrical generation purposes, nor does EPA adequately consider the risks that the technologies will not mature in time for [electric generating unit] owners to deploy them,” the grid operators said.
EPA’s rule did include a short-term reliability mechanism, which requires the declaration of an energy emergency alert 2 before any compliance mitigation can take place.
“This short-term reliability mechanism that EPA did adopt in the rule thus unduly places the grid — and customers — at greater risk before any short-term relief would be available,” the grid operators said. They “should not have to wait until the heightened level of emergency that an EEA2 declaration represents; they should be able to take proactive measures to address reliability issues upon earlier evidence of deteriorating grid conditions as evidenced by declaration of an energy emergency alert 1.”
Compliance flexibility should kick in at EEA 1 because at that point, grid operators can still call on emergency generation. By waiting until an EEA 2, grid operators cannot act until they are in a real-time emergency.
For longer-term issues, states can ask for extended deadlines or lower technology standards, but the grid operators would like to see EPA offer more guidance on that process.
EPA is not responding to the initial briefs until next month, but the RTOs’ comments did generate some response from others. The Clean Air Task Force and Natural Resources Defense Council filed lengthy comments on grid reliability, arguing the rule was designed to give utilities and system operators the flexibility they need to maintain grid reliability.
“While EPA has considered reliability issues in its proposal, FERC is the agency with direct jurisdiction over electric reliability,” the organizations said. “As discussed above and as recognized by FERC, the electric grid is undergoing changes unrelated to the EPA proposal, and the proposed regulations are only incremental to these existing forces. FERC and the electric utilities have the responsibility and many tools available to them to ensure reliability as these grid changes occur.”
A PJM Market Implementation Committee discussion on expanding the demand response (DR) winter availability window to include a wider range of hours branched off into a broader conversation on how the resource class participates in the RTO’s capacity market.
Presenting on behalf of a coalition of demand response providers during the Sept. 11 meeting, Bruce Campbell, principal of Campbell Energy Advisors, said there is excess curtailment capability in the winter that is not being captured in the revised risk modeling and accreditation methodology implemented this year. The coalition includes the Advanced Energy Management Alliance (AEMA), the PJM Industrial Customer Coalition (PJM ICC), CPower, Enel and NRG Curtailment Solutions. (See FERC Approves 1st PJM Proposal out of CIFP.)
Drafted through the Critical Issue Fast Path (CIFP) stakeholder process conducted last year and approved by FERC in January, the changes shifted the bulk of reliability risk from summer to winter. The summer risk also was concentrated in a few mid-day hours, whereas the risk PJM has identified in the winter is more evenly spread across the day. Campbell said about 20% of the winter reliability risk is in hours not captured in the DR availability window, which is 6 a.m. to 9 p.m.
Paired with the “legacy” availability window, Campbell said the changes led to a significant derate in the amount of capacity DR resources can offer. The amount of DR offered into the 2025/26 Base Residual Auction (BRA), while unchanged in ICAP terms, was around 1,300 MW UCAP lower due to the changes, an amount he estimated could have pushed the auction clearing price down to $210/MW-day, rather than the $269.92/MW-day price posted on July 30. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
In previous MIC discussions, Kerinia Cusick, president of the Center for Renewables Integration, representing Voltus, said PJM also is hampering the potential of load that can offer higher curtailment in the winter by capping capability at the lesser of winter peak load (WPL) or peak load contribution (PLC). She said that effectively limits winter curtailment by the lesser of the estimated potential in winter and summer.
Cusick argued PJM’s effective load carrying capability (ELCC) methodology further limits DR accreditation by assuming the resource class’s available curtailment is proportional to the system load being simulated against the peak load forecast. She said that approach reduces the incentive for consumers with load that is steady year-round to participate in DR programs and results in “double capping” in the winter when capability is limited to WPL and PLC.
Monitor Argues for New Definition of DR Performance Before Changes
Independent Market Monitor Joe Bowring said PJM must make changes to how performance is defined for DR before the resource’s availability window should be expanded. He said the current market design is flawed by not requiring DR resources to reduce their consumption during an emergency, instead mandating they maintain their load at or below their firm service level (FSL).
“While DR providers argue for a higher ELCC value, they ignore the fact that DR’s ELCC is based on assumed perfect performance, unlike thermal resources whose ELCC is based on actual performance during identified winter peak hours. DR ELCC should be based on performance data during the same winter peak hours, like other resources. If that were done, it is likely that the ELCC for DR would be much lower than it is, rather than the increase proposed by the DR providers,” Bowring said.
Presenting data from the December 2022 Winter Storm Elliott, he said many industrial DR participants already were offline or had reduced their consumption ahead of the Christmas holiday. When called upon during the performance assessment intervals (PAIs) seen on Dec. 23, he said 83% of resources already were at or below their WPL, a figure that increased to 90% when additional PAIs were declared the following day.
The low starting point for DR load during Elliott was a key factor in the low reduction in load provided by DR resources compared to their expected reduction, which is based on the energy load reductions estimates that DR providers submit to PJM in real-time. Those estimates are derived from a baseline set by recent load on similar hours and days.
Bowring said that while those reduction estimates are used by PJM to get a sense of the amount of DR that could be available ahead of potential PAIs, they do not factor into capacity performance (CP) penalties assessed against resources that fail to deliver load reductions. Instead, CP penalties are assessed against DR resources that maintain a load above their FSL.
Campbell said the sector has made improvements to the load reduction estimates provided to PJM over the past year.
In an interview, Bowring told RTO Insider he thinks PJM should redefine what a DR resource is providing to require an explicit reduction in load, rather than an expectation a resource will be below its FSL. He called for the RTO to open a separate stakeholder process to reevaluate how DR participates in the capacity market.
Bowring drew a distinction between the redesign he is seeking for DR participation versus the stakeholder adoption of a Monitor proposal to eliminate energy efficiency (EE) from the capacity construct. While the latter also was initiated by PJM as a broad reconsideration of the role EE should play, Bowring argued EE does not provide a reliability benefit for consumers and has no place in the Reliability Pricing Model. With the right market design, he said, DR could provide dependable reductions in load when called upon.
“It’s not like EE — DR is a resource,” Bowring said. “And while it should be on the demand side, if everyone insists on keeping some of it on the supply side it should be demonstrated that it’s providing an incremental benefit to PJM.”
Energy efficiency providers disputed Bowring’s characterization of the resource’s value, arguing that capacity market revenues are used to incentivize the purchasing of more efficient devices, pushing the need for capacity lower. PJM filed governing document revisions with FERC that would eliminate EE on Sept. 6. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)
Bowring said his preference is for the DR to be shifted to the demand side of the market, to be compensated for a year-round reduction in peak loads with a corresponding diminished capacity bill. If stakeholders prefer for DR to remain on the supply side, he said it should be accredited through the same marginal ELCC approach applied to generators, evaluation of performance during emergencies should be based on metered reductions in electric consumption and precise participant locations should be known to PJM for nodal deployment.
“The DR approach in PJM is badly flawed. We believe that DR is an important resource, but to capture its potential, it has to be dealt with in a way that’s consistent with how PJM markets work. It has to be nodal, it has to be metered, it has to be verifiable … based on metered reductions, not on artificially made-up assumptions,” Bowring said.
Calpine’s David “Scarp” Scarpignato said metering the reduction a DR resource provides runs into challenges for longer deployments, where determining the reduction provided requires determining what the load would have been if the resource was not called on. He said if a resource was committed at 10 a.m., the reduction would be apparent for the initial intervals, but assessing performance at noon or 4 p.m. would rely on counterfactuals.
Cusick said DR is designed to be a planning product that provides a capacity reduction that can avoid the need for construction of new generation resources just to serve a few hours annually. She said Bowring’s vision would treat DR as both a capacity resource and energy product at once.
“That is precisely the point. All capacity resources have a must-offer obligation in the energy market,” Bowring said. “Capacity by itself is not an actual product. Capacity resources are paid in order to provide a reliable source of energy. The suggestion that DR should be exempt from the obligations of a capacity resource mean that, in that view, DR should not be a capacity resource.”
As energy demand — and demand peaks — scale up, virtual power plants are turning the energy industry’s traditional models of supply and demand on their heads, said Chloe Holden, an industry analyst at Advanced Energy United, in her opening remarks at a Sept. 16 webinar on the vital role VPPs could play in the U.S. clean energy transition.
“Virtual power plants … are large groups of distributed energy resources in homes and businesses that can be controlled remotely, so that we don’t have to rely on coordinating supply to meet demand,” Holden said. “Instead, we can schedule demand to match supply.”
The technology and business models are well proven, she said. For example, EnergyHub, a provider of demand side services, now manages more than 1.3 million “connected devices” ― including smart thermostats, batteries, electric vehicles and water heaters ― for more than 60 utilities across the country, according to Nick Papanastassiou, the company’s director of market development and regulatory affairs.
“We work with a network of about 50-plus [original equipment manufacturers] across all sorts of devices,” he said.
The U.S. has between 30 GW and 60 GW of VPPs online, Holden said. But the U.S. Department of Energy estimates that 80 to 160 GW more VPP capacity will be needed by 2030, and those millions of connected devices could provide 10% to 20% of the additional demand on the grid.
Holden, Papanastassiou and other speakers at the webinar explored the opportunities and obstacles facing VPP expansion, looking at residential and commercial and industrial programs as well as new electric vehicle-managed charging and vehicle-to-grid (V2G) programs.
An enthusiastic proselytizer for residential VPPs, Papanastassiou reeled off a list of benefits. Like traditional central power plants, they are dispatchable and reliable and can provide not only fast-response for peak demand, but also grid support services, he said.
“There are a lot of flavors of what a VPP could be,” Papanastassiou said. “But at its heart, it’s this notion that customers and devices are providing flexibility to the grid in a really valuable and harmonized way.”
He pointed to a demand management and energy conservation project EnergyHub worked on with Ontario’s grid operator, IESO. With upfront incentives and “a really robust, multichannel marketing effort,” EnergyHub helped enroll more than 100,000 smart thermostats in a VPP that delivered 134 MW of power during a peak demand event.
Carter Wood, who works on electric vehicle policy at Ford Motors, said the automaker continues to partner with utilities, such as DTE in Detroit, on managed charging and bidirectional, V2G programs. But he cautioned that VPPs based on EV batteries are a different value proposition from VPPs aggregating smart thermostats or other home appliances that cost considerably less. Scale will be linked to EV adoption rates.
Ford, like other automakers, has slowed its plans for rolling out new EV models. Carter said its F-150 Lightning electric pickup truck is its only model offering bidirectional charging that can be tapped for backup power or potential grid support. But as EV adoption scales, EV-based VPPs could supplant natural gas peaker plants, he said.
The 8½-by-11 Principle
Successful VPP programs need three basic elements to draw in customers, Papanastassiou said. “One, a compelling incentive to participate; two, a simple enrollment process supported by effective marketing, and three, a program that isn’t going to actively inconvenience them.”
Raghav Murali, head of policy and government affairs at PowerFlex, agreed VPP programs need to be “simple and streamlined. I like to sort of refer to it as an 8½-by-11 principle,” he said. “If it’s too complicated to fit in a single sheet of paper, then we probably can’t sell it to customers.”
A subsidiary of EDF Renewables, PowerFlex works primarily with commercial and industrial customers, many of which look to VPPs to cut their energy bills and help the grid, Murali said.
He sees “reasonable, common-sense virtual power plant policies that can help these programs scale” as another key component for successful VPPs.
Speaking at AEU’s Sept. 16 webinar on VPPs were (clockwise from upper left) Raghav Murali, PowerFlex; Nick Papanastassiou, EnergyHub; Chloe Holden, AEU; and Carter Wood, Ford. | Advanced Energy United
Some utilities continue to offer more traditional demand response and energy conservation programs and have yet to embrace “a multi-technology stack,” Murali said. “There are certain programs that have onerous [air conditioning] cycling programs that have mandatory terms … [and] data privacy requirements that are completely out of step with what any company would agree to.”
He acknowledged concerns about “double-dipping” in measuring the performance of the different components or devices in a VPP but argued that submetering technology used with battery storage and electric vehicle chargers “is a more efficient and streamlined way to measure asset performance in a VPP paradigm.”
Both Murali and Wood called for tech-neutral regulations for VPPs. “Make sure they’re not ‘smart thermostat’ programs. Make sure they’re not ‘storage’ programs but are VPP or grid services programs that encompass the broad technology type,” Murali said.
“A lot of what we advocate for is, you know, treat [EVs] in same category as stationary storage,” Wood said. “We should be treated tech neutrally.”
Framing VPPs in a tech-neutral context could “become more and more pressing in communications to regulators and decision makers,” Holden said. “There are all these devices on the grid, and either they are tapped to their full potential or they’re not. So as demand rises, there’s a need to enable them to do what they’re technically capable of doing.”
Opponents of the Southeast Energy Exchange Market (SEEM) have argued the market does not provide the benefits to customers promised by its supporters and also violates FERC’s regulations (ER21-1111, et al.).
SEEM’s opponents were responding to a filing submitted by SEEM members in August that argued the market brings savings to consumers and should be allowed to continue. (See SEEM Members Respond to FERC Briefing Request.)
FERC had requested briefings from both supporters and detractors of SEEM as a step toward satisfying a D.C. Circuit Court of Appeals order from 2023 remanding the commission’s approval of the market. (See FERC Requests Briefings on SEEM After DC Circuit Order.)
The reply briefs were filed Sept. 12 by three groups representing various longstanding opponents of SEEM:
Public Interest Organizations (PIO) — a group of mostly environmental organizations including the Sierra Club, the Southern Alliance for Clean Energy, the Natural Resources Defense Council and the Partnership for Southern Equity.
Southern Renewable Energy Association (SREA) — a trade organization promoting renewable energy in seven Southeastern states whose members include National Grid, Invenergy and Ørsted.
Clean Trades — Advanced Energy United, the Clean Energy Buyers Association and the Solar Energy Industries Association.
The commission asked respondents to answer whether SEEM qualifies as a loose power pool under FERC Order 888 and whether the market’s requirements that entities transacting in it have a source and sink inside its footprint violate Order 888. SEEM members argued in their brief the market does not qualify as a loose power pool because “the commission has already found that NFEETS [the market’s non-firm energy exchange transmission service] is neither a discount nor a special rate” and that the D.C. Circuit did not find fault with FERC’s reasoning on that point.
However, the market’s opponents said this argument ignored the clear intent of the court’s remand order. The PIOs wrote that SEEM “has walked and quacked like an exclusive power pool” since its conception and criticized the commission and members for focusing “entirely on questions regarding definitional characterizations and technical limitations of SEEM.”
“These questions have already been asked and answered in the record and rejected by the court,” the PIOs wrote. “By delving deeply into the question of geographic limitations and alternative theories designed to justify SEEM’s existing design rather than address its core problems, both the briefing order and the utilities ignore the court’s broader concerns that SEEM’s overall design violates Order 888’s open access requirements.”
The PIOs said the D.C. Circuit’s ruling was intended to allow FERC, having seen SEEM in action, to reevaluate whether the market actually complies with Order 888. They said that contrary to supporters’ promises, “SEEM has demonstrated the need for Order 888’s protections” by systematically excluding independent power producers; the organizations claimed “no non-utility sellers have transacted in SEEM [and] just one non-SEEM utility participant” has joined the market.
‘Nominal Cost Savings’
Energy sales have been dominated by just a few utilities, the PIOs claimed, citing a report from SEEM’s market auditor showing that “a single seller accounted for between 30 and almost 80% of all sales” in the market’s first few months and the two largest sellers combined accounted for 55 to 90% of sales. The arrival of utilities from Florida in July 2023 lessened this dominance, but the PIOs observed that two sellers alone still account for more than 40% of all sales in each month.
The PIOs said that the lack of competition has resulted in only “nominal cost savings.” Sharing this view was SREA, which pointed out that while SEEM proponents originally projected benefits of $40 million annually, the market reported total benefits of $3.7 million in 2023, which “appears to be a gross benefit.” Taking estimates for annual non-centralized costs of $2.8 million and payments for legal work, auditing and platform development, SREA estimated an overall net cost of $824,591 per year.
SREA also cited data from the auditor to point out that trading on SEEM virtually shut down during the widespread blackouts arising from winter storms in December 2022, with less than 1,000 MWh traded on the platform between Dec. 23 and Dec. 27. The association also noted 53 hours this July, mostly at night, during which no trades occurred on SEEM at all. SREA quoted the market auditor’s report of “a statistically significant relationship” in which high demand is matched with decreased trading activity on SEEM.
Regarding the SEEM members’ assertion about NFEETS, the Clean Trades called their description of NFEETS as a pancaked rate a “post-hoc rationalization,” noting that members called the service “non-pancaked” when they first filed the SEEM agreement. Now, however, the Clean Trades said that members have called their previous description of NFEETS “shorthand.” They called on the commission to recognize the truth of the matter, as they described it, and treat SEEM as a loose power pool.
“The commission should reject the SEEM Members’ attempt to have their pancakes and eat them too,” the Clean Trades said. “The bottom line is that … SEEM represents a pooling arrangement that favors members over non-members through a ‘discounted’ rate. It is a textbook example of a ‘loose power pool’ and must satisfy the associated regulatory strictures.”
VALLEY FORGE, Pa. — The PJM Planning Committee and Transmission Expansion Advisory Committee meetings were originally scheduled for Sept. 10 but were rescheduled to Sept. 12 and 13, respectively.
Planning Committee
Voting on CIR Transfer Proposals Deferred to October
The PC on Sept. 12 voted to defer action on three proposals to rework the RTO’s process for transferring capacity interconnection rights (CIRs) from a deactivating generator to a new resource. The committee will vote on them at its next meeting, currently scheduled for Oct. 8.
Each of the packages is aimed at creating an expedited process to shift the transmission capability underlying the CIRs of a retiring unit to support the interconnection of a new resource. Proponents of the concept say it could alleviate the need for costly reliability-must-run (RMR) contracts to keep resources online while upgrades are made to the grid to pre-empt any transmission violations prompted by removing a generator.
The vote was delayed after the committee rejected an amendment to a proposal sponsored by Elevate Renewable Energy and the East Kentucky Power Cooperative. (See “Elevate Reviews CIR Transfer Proposal,” PJM PC/TEAC Briefs: July 9, 2024.)
The amendment, proposed by MN8 Energy, would have added thermal violation analysis to the studies to be conducted on projects seeking CIR transfers and expedited interconnection. MN8 had withdrawn its own package ahead of the meeting and thrown its support behind the Elevate-EKPC coalition.
The MN8 amendment would have required thermal studies on the peak and off-peak deliverability cases, but Elevate’s Tonja Wicks said the coalition could only accept studies on the off-peak case.
The issue of thermal studies gets to the heart of whether storage resources should be eligible for CIR transfers, with PJM arguing that the capability to charge off the grid could pose “material adverse impacts” not envisioned by the original interconnection studies conducted on the deactivating generator. The PJM proposal would outright disqualify storage and open-loop hybrids, whereas both the coalition and Independent Market Monitor packages would allow all resource classes to participate.
Coalition supporters argued storage is one of the best-suited resources for replacing deactivations owing to its quick installation time, minimal footprint and minimal environmental restrictions. Alternatives like renewable generation can require too much land to be viable for replacements in urban settings, such as the retiring Brandon Shores generator outside Baltimore, and the timeline for new nuclear is too lengthy to be suitable, they said.
The material adverse impact standard would also preclude many CIR transfers to resources with a different fuel type, PJM’s Ed Franks said. Any projects requiring network upgrades would be removed from the expedited process and moved to the general interconnection queue.
Both the PJM and coalition proposals would only allow CIR transfers to resources seeking to site at the same point of interconnection (POI) as the deactivating unit. The voltage would also be required to be the same, though the interconnection could be at a different breaker.
The coalition proposal comes with a nine-month time frame for most projects to get through the expedited process, with 60 days for initial application review, 180 days for a replacement impact study looking at any potential transmission violations and 30 days for the interconnection service agreement to be approved. Projects with minor network upgrades required would take an additional 90 days.
It would also allow the transfer process to begin before an official deactivation notice has been filed with PJM, allowing discussions between market participants and the RTO’s study process to begin quicker. PJM’s proposal would require an official notice before CIRs transfers could be initiated.
Interconnection studies on expedited projects would be conducted in parallel with Phase 2 studies being conducted on the contemporaneous cluster in the transitional cycle. PJM’s proposal would also place expedited studies at the second phase of the current cluster.
Franks said moving new CIR transfer requests up to be studied with the current cluster is one of the defining features of the packages. While the status quo does allow transfers, only submissions made before the start of the transition to the cluster-based process were sorted into either Transitional Cycle 1 or 2. Later requests must wait until the end of the transitional cycle to be studied as part of TC 1, which is not scheduled to begin reviewing applications until 2026. Franks said the proposals would also result in some cost savings over the status quo even after the transition is complete.
The Monitor’s proposal would break with the concept of bilaterally transferring CIRs to instead create a PJM-administered process when a deactivation study identifies transmission violations. The RTO would evaluate projects in the queue for any that could use existing headroom to resolve the violations, prioritizing those that could do so with a balance of speed and affordability. Generation developers would also be able to propose alterations to their projects or entirely new resources to meet the need. (See “Monitor Presents CIR Transfer Proposal,” PJM PC/TEAC Briefs: Aug. 6, 2024.)
“CIRs should go back in the pool and PJM should in a parallel have an expedited process in its control to move forward with any project that can solve the reliability problem,” Monitor Joe Bowring said. He argued that the coalition proposal would grant existing generators market power through their ownership of CIRs, while the Monitor proposes that CIRs end on the date of unit retirement.
Bowring also argued that putting the transfer of headroom under PJM’s control ensures that resources receiving CIRs are oriented toward resolving the transmission violations. It would also enable projects sited at different POIs to be expedited, including those that would require network upgrades. If no project in the queue addressed the identified reliability issue, PJM would run an auction for proposals to build new generation to address the reliability issue within a defined period of time.
If no transmission violations are associated with a deactivation, the CIRs would be made available to projects in the general queue cycles according to their cluster position. The same would be true of any CIRs not allocated through the expedited process. Bowring argued that the value behind interconnection rights is derived from the sum total of transmission investments across PJM and thus should not be considered the property rights of developers who paid for network upgrades as part of a generation interconnection.
“CIRs are a network resource, are essential to FERC-mandated open access, and derive their value from all the investments made by customers and generators over a long period,” Bowring said.
The committee endorsed a set of revisions to Manual 14F: Competitive Planning Process that remove out-of-date references and update details in the document.
PJM’s Brian Lynn said the changes were identified during PJM’s Long-term Regional Transmission Planning (LTRTP) workshops but were not adopted as the overall LTRTP changes were not voted on. Stakeholder focus has shifted to revising long-term planning through PJM’s compliance filing on FERC Order 1920.
First Read on Manual 21B Revisions
PJM’s Andrew Gledhill presented the first set of proposed revisions to the newly established Manual 21B, which details the rules for capacity resource accreditation. The changes would align the definition of dual-fuel combustion turbine and combined cycle units in the manual with revised Reliability Assurance Agreement definitions accepted by FERC in July (ER24-1988).
The change allows gas generators that are capable of operating on a secondary fuel after starting on their primary fuel to qualify as dual-fuel, a change sought by Calpine earlier this year. During the earlier stakeholder process, Calpine’s David “Scarp” Scarpignato said some gas units can start on a small amount of fuel already purchased and packed into the portion of the gas pipeline on generator property, even if the regional pipeline is offline. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.)
Transmission Expansion Advisory Committee
Supplemental Projects
During the TEAC meeting Sept. 13, FirstEnergy presented a $99.1 million project to rebuild its 138-kV New Departure substation to serve a new 540-MVA customer, with a 345-kV delivery point in the ATSI transmission zone.
The three-phased project would begin with adjusting relay settings at the substation, work that is expected to be completed in March 2025, followed by the rebuilding of the 138-kV infrastructure already present at the site. It would be reconfigured as a breaker-and-a-half switching station with nine breakers. The second phase, to be completed in May 2028, also includes cutting New Departure into the 138-kV Nasa-Greenfield and Ford-Greenfield lines. The first two phases together are estimated to cost $27 million.
The $72 million third phase involves building a new 345-kV ring bus at New Departure with four breakers and two 345/138-kV transformers. The facility would be looped into the 345-kV Davis-Besse-Hayes line with two new lines. An additional six 138-kV breakers would also be added to New Departure in the third phase, which FirstEnergy envisions being complete in November 2029.
Dominion presented the TEAC with a $35 million project to construct a new Old Limb Substation serving a data center complex in Prince William County, Va. | PJM
Exelon presented a $92.1 million project to rebuild its 10-mile 230-kV Ryceville-Morgantown line in the PEPCO zone, a line that the utility said is nearing its end of life at 56 years old. The work would include replacing 55 lattice towers with steel monopoles and new conductor. The project is in the engineering phase, with a projected in-service date of April 1, 2028.
Dominion Energy presented a $35 million project to construct a new 230-kV Old Limb substation to serve new data center load in its transmission zone. The new facility would be configured with a six-breaker ring arrangement cut into the Heathcote-Gainesville and Loudoun-Youngs Branch lines. Two new 230-kV tie-lines would be constructed between Old Limb and Youngs Branch, the latter of which would have two new breakers and terminal equipment installed.
The California Public Utilities Commission on Sept. 12 approved rules requiring the state’s three large investor-owned utilities to meet stricter timelines and targets for connecting electricity customers to the grid.
“Electricity is the fuel of our future, and the utility grid must be ready to meet customer needs for energization without delay,” said CPUC President Alice Reynolds. “This decision moves us forward by improving oversight, transparency and accountability to serve the needs of EV charging stations, new housing developments, building electrification and other customer requests for service.”
The timelines are meant to expedite the process for new and upgraded electrical services, enhance utility accountability, offer greater transparency for customers and support California’s climate goals, according to a CPUC press release.
The new rules apply to Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
If targets are met by IOUs, maximum timelines for grid connections could be reduced up to 49% compared with current operations, increasing the speed of energization for projects reliant on electricity connections, the press release notes.
The decision implements Senate Bill 410, known as the Powering Up Californians Act, and Assembly Bill 50, both of which direct the CPUC to define reasonable average and maximum energization timelines for new or upgraded electrical loads, publish biannual reports, establish a process for reporting delays and adopt remedial actions if they are exceeded.
SB 410 addresses the time necessary to complete customer energization requests, including upgrades to the distribution system and the extension of new electric service. It requires the commission to, no later than Sept. 30, 2024, establish the average and maximum time an IOU should take to complete upgrades or establish new service, as well as a method for customers to report instances when those energization targets are met.
“The bill recognizes that to meet California’s decarbonization goals, new customers must be promptly connected to the electrical distribution system, and existing customers must have their service level upgraded in a timely manner,” the decision said.
AB 50 requires the CPUC to determine the criteria for what is considered timely energization for electric customers. It also requires “each large electrical corporation that energized less than 35% of customers with completed applications exceeding 12 months in duration by Jan. 31, 2023, to submit a report to the commission, as specified, on or before Dec. 1, 2024, demonstrating that the large electrical corporation has energized 80% of customers with applications deemed complete as of Jan. 31, 2023, as specified.”
The CPUC’s decision sets a target for an average timeline of 182 days and a maximum timeline of 357 days for energization of the commission’s Rule 15 projects, which involve distribution line extensions for IOUs. For Rule 16, which refers to service line extensions typically associated with a single customer instead of multiple customers, the target sets an average timeline of 182 days and a maximum of 335 days for energization.
Rule 29, which refers to EV infrastructure, shares the same timelines, and several other energization timing targets are set for application decisions, circuit or substation upgrades, and main panel upgrades.
“As we move further along in the energy transition, we must ensure that all customers have timely access to electric service,” said CPUC Commissioner Darcie Houck. “This decision is a positive step forward in helping to meet California’s ambitious clean energy goals while appropriately balancing customer need and affordability with utility capabilities.”
Price Cap Increases in 2026/2027 BRA Planning Parameters
VALLEY FORGE, Pa. — PJMpresented on how the planning parameters for the 2026/27 Base Residual Auction (BRA) affected the variable resource rate (VRR) curve, which intersects with supply and demand to determine auction clearing prices.
The curve is taking a more linear and steep shape in this auction, with the RTO-wide price cap increasing to $696/MW-day should 145,774 MW or less clear the auction. Point B, set at net cost of new entry (CONE), quickly falls to a $0 clearing price at 149,455 MW capacity clearing and remains at zero through to Point C at 153,873 MW.
The planning parameter posting comes weeks after the completion of the 2025/26 BRA and as stakeholders digest a significant jump in clearing prices, including two regions clearing at their price caps. (See PJM Market Participants React to Spike in Capacity Prices.)
Scheduled for December 2024, the 2026/27 auction will be the first to use a combined cycle generator as the reference resource (RR), which is the generation class for which the CONE estimates construction costs. Estimated net revenues for the RR and CONE values both are higher for CC generators than the combustion turbines previously used as the reference, steepening the curve and setting the maximum price higher.
The formulas defining the points along the VRR curve were also changed over the previous auction, with Point A now set at the greater of gross CONE or net CONE times 1.75, whereas the point was previously gross or net CONE times 1.5. The reliability requirement multiplier for each point was also changed.
AEP Energy Director of RTO Operations Brock Ondayko questioned whether auction design changes were intended to result in a 3,500-MW difference between clearing at the price cap or at zero.
“It’s not going to take much from allowing capacity resources to have some type or revenue to having them have zero revenues,” he said.
Market Monitor Joe Bowring said the use of gross CONE to set the maximum price on the VRR curve means that prices could reach approximately $700 per MW-day but that there is no logical or economic basis for capacity market prices at that level.
PJM’s Pete Langbein said the changes were drafted through the quadrennial review process by both stakeholders and PJM.
PJM Proposes Rules for Non-inverter Hybrid Resources
PJM presented its proposal for how non-inverter resources paired with battery storage can participate in its markets as a hybrid resource, such as a gas generator paired with storage.
The effort is the third phase in PJM’s development of hybrid market rules, with the first focused on solar and storage and the second looking at all inverter-based resources. While the hybrid model allows for different inverter-based generation types to be combined without storage, the non-inverter option requires generation and storage components.
Both inverter and non-inverter hybrids with storage would be able to provide reserves — except for non-synchronized and secondary reserve products — and be required to do so if committed in the capacity market. Generation-only hybrids would not be able to provide reserves unless granted an exception.
The make-whole and lost opportunity cost (LOC) design would be similar to the pumped-hydro rules, allowing make-whole payments for hybrids instructed to charge at a higher cost than their desired LMP, while hybrids reducing charging according to manual PJM dispatch would not be eligible for LOC payments.
The changes include several clarifications of existing market rules, including that non-inverter hybrids can provide regulation but, like inverter-based hybrids, they cannot only provide regulation. It also differentiates between station power and the storage charging mode, which must be reported to PJM separately through Power Meter.
The proposal would also clarify how generation-only inverter hybrids are subject to the must-offer requirement. The resource would be required to offer an economic maximum (EcoMax) value into the day-ahead market equal to or greater than its hourly forecast. For inverter hybrids with storage, the energy offered over 24 hours must add up to forecast generation, “grossed up” with the efficiency of the storage.
Non-inverter resources would participate in the energy and ancillary service markets similarly to the standalone storage model.
PJM’s Maria Belenky said staff have received inquiries regarding the number of existing resources that would be subject to the non-inverter hybrid rules, but PJM does not yet have a total that can be shared.
PJM Proposal Would Allow Changes to RPM Auction Deadlines
Stakeholders reacted sharply to a PJM problem statement and issue charge that would consider revising governing documents to add language saying that BRA deadlines are subject to change and the posting of planning parameters does not carry legal consequence.
The issue charge states that the notice would allow PJM to make “potential corrections to capacity market rules that are filed in advance of the commencement of the relevant auction window.”
PJM Associate General Counsel Chen Lu said the changes are being contemplated in response to the 3rd U.S. Circuit Court of Appeals vacating a FERC order allowing PJM to revise the locational deliverability area (LDA) reliability requirement for the DPL-S region in the 2024/25 BRA. The court determined that making such a change so far into the auction process would violate the filed rate doctrine. (See Following Court Ruling, FERC Reluctantly Reverses PJM Post-BRA Change.)
Adrien Ford, Constellation’s director of wholesale market development, said the expected deliverables listed in the issue charge seem overly prescriptive and would guide stakeholders towards a predetermined outcome. She also argued more language should be added around how far in advance any change in auction deadlines would have to be noticed.
Vitol’s Jason Barker said market participants need certainty around rules, and it would be imprudent to establish a paradigm where PJM can make after-the-fact rule changes in market design that mandates participation. Instead, he said, the RTO should bring concerns that arise after commencement of mandatory pre-auction activity to stakeholders and FERC for review.
Bowring said the proposal would give PJM unprecedented and inappropriate discretion over deadlines, including those related to the Monitor’s responsibilities as well as deadlines for market participants and PJM itself. In addition, he said, the suggestion that market participants cannot rely on the parameters posted by PJM is not consistent with transparency and efficient markets.
External Resource Capacity Clearing
The North Carolina Electric Membership Corp. (NCEMC) presented a problem statement and issue charge focused on how PJM accounts for external, pseudo-tied capacity resources outside the RTO’s footprint which are being committed to serve a load-serving entity.
The documents say the utility is focused on three areas: recognizing when there is a direct transmission path between external generation and LSE load; reflecting the LDA price in the region the external generation is serving in how the resource is compensated; and including that generation in LSE self-supply obligations.
When modeling and clearing capacity resources, the problem statement says, external generation is not assigned to a specific LDA, even when there is a direct path between the unit and an internal region. However, PJM does assign those resources to an LDA to assess Capacity Performance (CP) penalties or bonuses for over- or underperformance during emergencies. The practice of ensuring deliverability to the rest-of-RTO, but not to an LDA, is not reflected in the manual language.
“There is an opportunity to review certain existing provisions pertaining to external capacity resources to determine if there are modifications that would better align the external capacity resource transmission pathway with external capacity resource LDA modeling, the applicable sink LDA used in RPM clearing, and resource performance obligations and mapping. Such mismatches are particularly harmful to Load Serving Entities self-supplying resources to serve load,” the problem statement reads.
Calpine’s David “Scarp” Scarpignato said it might be prudent to also consider the interaction with the stop-loss limit to CP penalties, noting that PJM has changed the annual limit to penalties that can be assessed against a generator to be based on auction clearing prices, rather than the CONE parameter. For major emergencies, the stop-loss limit can be a more significant factor than the penalty rate for individual performance assessment intervals, he argued. (See FERC Approves 1st PJM Proposal out of CIFP.)
Bowring said the Monitor has also said there is a mismatch between external resources getting rest-of-RTO pricing, regardless of the actual electrical path it takes to be delivered to PJM.
Other Committee Activities
Stakeholders endorsed by acclamation revisions to Manual 15: Cost Development Guidelines drafted through the document’s periodic review. The changes focus on correcting formulas and updating section numbers. The alterations also remove a table displaying variable operations and maintenance costs, which PJM said could give a false impression that the values are fixed in the manual language; the values are updated annually and posted to its website. (See “First Reads on Several Manual Revision Packages,” PJM MRC/MC Briefs: Aug. 21, 2024.)
The committee endorsed by acclamation a quick fix proposal brought by PJM to eliminate the high/low and marginal cost proxy interface pricing options. PJM’s Phil D’Antonio said they have not been used since the dynamic schedule agreement with Duke Energy Progress was terminated in 2019. (See “PJM Proposes Elimination of 2 Interface Pricing Options,” PJM MIC Briefs: Aug. 7, 2024.)
VALLEY FORGE, Pa. — The first biennial test of voltage-reduction capability was a success, PJM told the Operating Committee during its Sept. 12 meeting.
Senior Dispatch Manager Kevin Hatch said the Mid-Atlantic region saw a 280-MW load reduction during its Aug. 14 test, coming out to about a 0.7% reduction in real-time load. PJM’s expectation was about 635 MW (1.6%).
The western and southern regions were tested the following day, together achieving a 360-MW (0.85%) load reduction against a 920-MW (2.2%) expectation. Hatch called the test a “good, coordinated drill.”
Conducting regular voltage-reduction testing was one of the recommendations following the December 2022 winter storm, during which an alert was issued stating that a reduction could be imminent. Following the storm, PJM told stakeholders that had a handful of additional generators tripped offline, a voltage-reduction action may have been necessary. The last time that happened was in January 2014, during the polar vortex event. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)
A PJM news release regarding the test stated that no impact to consumers was reported, and the test provided the RTO and transmission owners valuable insight into how voltage actions are conducted.
“Overall, the tests allowed PJM and its transmission owners to benefit from increased communication and understanding about the time to implement the voltage-reduction test, coordination with field personnel and evaluating the impact on the overall system,” PJM wrote. “The test also provided an opportunity to validate the operation of transmission and distribution equipment and verify equipment operating characteristics and parameters.”
Generators experienced a 1.5% drop in reactive power capability during the test, which PJM said demonstrates a need for increasing reactive reserves to ensure transfer capability remains available. The loss amounted to 3,150 MVAr in the Mid-Atlantic and 1,300 MVAr in the west and south.
Exelon’s Alex Stern said the operational performance data presented at the OC this month supported that PJM’s grid is delivering reliability, but stakeholders need to be proactive in ensuring that can be maintained.
“To me this data corroborates some of what we heard [PJM CEO Manu Asthana] talk about, which is we have a really reliable grid; we just need the generation to be there, and we need to make sure we send the signals that will get the generation built … but the grid itself is functioning well,” Stern said.
Monthly Operations Metrics
PJM’s Marcus Smith said load forecasts remained accurate through heat waves at the start of August, including a 149-GW peak on Aug. 1, though unexpectedly low temperatures during the Labor Day holiday weekend contributed to a 7% overforecast on the last day of the month.
Most of PJM’s forecast error is driven by weather, particularly temperature, cloud cover and thunderstorms. In response to stakeholder inquiries, Smith said the RTO will look at also presenting its backcasts of how significant of a factor weather has played.
August also saw three spin events, one of which exceeded the 10-minute mark that triggers penalties for underperforming resources. The Aug. 18 event began at 4:04 p.m. and went through 4:20 — 15 minutes and 51 seconds. A total of 1,417 MW of generation and 529 MW of demand response was committed to respond to the event, with respective response rates of 59 and 90%. A total of 630 MW of reserves face penalties for underperformance during the event.
PJM also declared a nine-minute, 39-second spin event Aug. 12, with 1,386 MW committed and a response rate of 75%; and a four-minute, 13-second event Aug. 26, with 2,650 MW committed and a 92% response rate.
PJM’s David Kimmel said the response rate has been low recently, which can be attributed to generation start times, as well as some resources having difficulty maintaining their committed output for the duration of the event.
A maximum generation alert was also issued Aug. 27 because of a 9.7% generation outage rate, peaking at 17,611 MW offline, and a high load forecast. Hatch said the alert was meant to put neighboring regions on notice that interchange may have to be curtailed to serve internal load. He said both MISO and SPP were operating tightly ahead of the notice and implemented load-management procedures that reduced the need for interchange.
Cybersecurity Briefing
Presenting the monthly security briefing, PJM Director of Enterprise Information Security Jim Gluck recommended that members ensure they have a plan for alerting the RTO to any cybersecurity breaches so staff are aware of any disruptions to expect and precautions that may be necessary to protect the grid.
The concern stemmed from a breach at Halliburton in which customers were notified of disruptions to oilfield operations through news reports, rather than by the company. Gluck said PJM has procedures in the manuals to notify members of any breaches on its end, and sensitive information that may need to be shared can be done so through the Electricity Information Sharing and Analysis Center.
2025 Preliminary Project Budget
PJM’s Jim Snow presented the preliminary 2025 project budget, which calls for $50 million in capital expenditures, including “historic” investments in technology.
The forecast budget for 2024 is $44 million, while $40 million was spent in 2023 and $38 million the year prior.
The largest share of the budget is $21 million for application replacements and retrofits, the largest of which are the energy management system (EMS) and model management software. Part of the increased funding request is the result of PJM identifying an off-the-shelf product that can accomplish much of the second phase of replacing its EMS software, leading expenditures to be concentrated in 2025 rather than spread out as planned.
The second-largest funding area is current applications and system reliability at $18 million, including upgrades to PJM’s Dispatcher Application and Reporting Tool (DART), data analytics, credit and risk enhancements, and cybersecurity measures. The budget proposal also calls for $8 million in funding for facilities and technology infrastructure, $2 million for new products and services, and $1 million on interregional coordination.
Snow said several items were considered for inclusion in the budget, but staff feel comfortable deferring action to avoid a larger spending increase in 2025. That includes spending approximately half a million on developing energy market incentives supporting reserve certainty and about $400,000 on expanding credit surveillance of market participants.
The Finance Committee is scheduled to deliver a recommendation letter to the Board of Managers on Sept. 23, with board action on the budget expected in October.
The Massachusetts Supreme Judicial Court (SJC) on Sept. 11 upheld the Energy Facilities Siting Board’s (EFSB’s) approval of a controversial substation in East Boston, likely concluding the 10-year fight over the project.
The court ruled that the petitioners, the Conservation Law Foundation (CLF) and GreenRoots, did not meet the heavy burden of proof required to overturn the EFSB’s approval of the project.
“We conclude that the board’s decision is lawful, was supported by substantial evidence, and was not arbitrary, capricious or otherwise an abuse of the board’s discretion,” the SJC found.
The project, currently under construction, is sited on the bank of the Chelsea Creek near a public park, homes and a new police station.
Eversource Energy, the electric distribution company responsible for the project, had argued the substation is needed to meet load growth in the area and preserve electric reliability.
However, the project was met with significant opposition by residents and environmental advocacy organizations, which argued it will add to the significant burden of pollution already facing the neighborhood. The surrounding area is classified by the state as an environmental justice neighborhood, meeting the definition’s criteria for income, minority population and language isolation.
In a non-binding 2022 ballot question, 83% of Boston voters opposed the project at the selected site, while politicians including Boston Mayor Michelle Wu (D) and U.S. Sen. Ed Markey (D) have voiced their opposition to the project.
In challenging the EFSB’s approval, CLF and GreenRoots argued the board did not adequately weigh the project’s environmental burdens with its benefits to the community and said the board improperly pre-empted the review processes of two local agencies.
The groups also took issue with the substation’s designation as a water-dependent facility when granting its tidelands license.
The court was not persuaded by these arguments, finding “no error in the board’s considerations of environmental protection, public health and public safety.”
The project’s opponents expressed disappointment with the court’s ruling, arguing it is a failure to protect residents of the environmental justice neighborhood.
“East Boston residents endure major pollution and other environmental hazards that threaten their health and safety, and this project was poorly sited in a flood-prone area,” said Anxhela Mile of the Conservation Law Foundation. Mile added that the decision underscores the “need to reform how the commonwealth permits energy infrastructure and assesses the cumulative environmental and health risks a community faces.
“GreenRoots and the East Boston community affected by the Eversource project are disappointed with the MA SJC’s decision to allow the project to move forward, but honestly we’re not surprised,” said John Walkey of GreenRoots. “The siting and permitting process is broken from any perspective you look at it.”
He noted that the fight over the substation was an important factor in passing environmental justice protections into state law in 2021, and in centering environmental justice protections in recent efforts to pass permitting reforms in the state.
“We have also seen Eversource itself change its own approach to engaging communities in their recently proposed substation in the Hyde Park neighborhood in Boston,” Walkey added, noting that the company engaged the community before filing with the EFSB and “brought up the question of Community Benefits Agreements right out of the gate.”
“However, this is cold comfort for an already environmentally over-burdened East Boston community now saddled with additional poorly and unjustly sited industrial infrastructure,” Walkey said.
Eversource spokesperson William Hinkle said the court’s decision affirms the substation “is critically needed to address local capacity constraints, support a rapid growth in electric use and reliably serve our customers in East Boston and Chelsea.”
“We cannot leave any customers or communities behind in the clean energy transition and achieving decarbonization and electrification goals while ensuring that all customers have access to clean energy opportunities will require a significant amount of new electric infrastructure,” he added.
The Massachusetts Department of Public Utilities recently approved the electric sector modernization plans of the state’s three investor-owned electric utilities, establishing the framework for major new investments in electric infrastructure across the state. (See Mass. DPU Approves 1st Round of Utility Grid Modernization Plans.)
Meanwhile, in a proposed supplemental budget bill, Gov. Maura Healey (D) included reforms to streamline and expedite the state’s clean energy permitting and siting processes. The proposal would reduce the timeline for reviewing infrastructure projects — including substations — while requiring a cumulative impact analysis to account for existing pollution sources and public health burdens, a requirement that was not in place for the review of the East Boston substation. (See Mass. Gov. Healey Includes Permitting Reform in Budget Proposal.)
Hinkle noted the company has completed about 75% of the work on the station foundations, with construction expected to extend through the third quarter of 2025. The company expects the substation to come online in late 2025.
The company estimated in late 2022 the project will cost about $103 million, compared to the initial $66 million estimate presented to the EFSB. Eversource attributed this increase to construction delays and higher costs of materials and labor.
