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April 9, 2025

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FERC Approves ISO-NE Order 2023 Interconnection Proposal

FERC has accepted ISO-NE’s compliance proposal for Order 2023, setting the stage for sweeping changes to the RTO’s interconnection procedures.  

The April 4 ruling came nearly eight months after ISO-NE’s proposed effective date of Aug. 12, 2024, and followed months of stakeholder requests for rapid action to preserve the transition timeline and prevent significant delays to projects in the interconnection queue (ER24-2009, ER24-2007). 

FERC’s ruling largely accepted ISO-NE’s proposal but directed the RTO to make relatively minor changes in an additional filing.

Order 2023 and the follow-up ruling, Order 2023-A, require transmission providers to transition from serial interconnection processes to cluster study processes, in which interconnection requests will be studied simultaneously. 

ISO-NE filed its Order 2023 compliance proposal in May 2024 with the support of NEPOOL after an extensive process of stakeholder engagement and revisions. (See NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance and ISO-NE Order 2023 Compliance Proposal Fails to Pass NEPOOL TC.) 

In comments submitted to FERC, developers generally supported the filing, though several groups requested changes, such as a shorter cluster study timeline and reduced study deposit requirements. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.) 

Allco Finance had urged the commission to reject the proposal due to impacts it would have on distribution-level projects and argued ISO-NE does not have jurisdiction over state-level interconnection procedures. But FERC ruled the complaint was outside the scope of the proceeding, finding the company had not demonstrated ISO-NE failed to comply with Order 2023 or Order 2023-A.  

Despite arguments from some stakeholders that ISO-NE should adopt the 150-day cluster study timeline outlined by Order 2023, the commission accepted the RTO’s proposal for a 270-day process. ISO-NE said a 150-day timeline would be infeasible for the region. 

FERC agreed the 270-day timeline “reflects ISO-NE’s unique regional issues and the comprehensive scope of its studies, including electromagnetic transient studies for inverter-based resources.” 

The commission also approved ISO-NE’s proposal to reduce the cluster restudy timeline from 150 to 90 days, noting the RTO “will use the same base case data as the cluster study and will involve fewer interconnection requests, thereby allowing interconnection requests to proceed expeditiously through the interconnection study process.” 

FERC also accepted ISO-NE’s proposal to require a flat $250,000 deposit and a $50,000 application fee for the cluster study, writing that “extending the $250,000 deposit to smaller generators is reasonable due to regional differences because … project size is not a ready indicator of study cost or complexity for interconnection requests in New England.” 

It rejected arguments by Glenvale Solar that ISO-NE’s proposed deposit requirements are prohibitive for smaller projects participating in the process, saying the “proposed flat deposit structure reasonably approximates study costs in New England.”

The commission also approved ISO-NE’s proposal for a $500,000 initial commercial readiness deposit, writing that the amount will help deter speculative interconnection requests. Order 2023 requires commercial readiness deposits to be twice the size of study deposits. 

“While higher than the pro forma [Large Generator Interconnection Procedures], we find the variation is justified because the $500,000 amount reflects historically high network upgrade costs in ISO-NE,” FERC wrote.  

Optimism Around Transitional CNR Study

FERC also accepted ISO-NE’s initial prohibition of using surety bonds for deposits, despite Order 2023’s direction to do so, saying the RTO demonstrated it needs more time to develop the procedures for accepting the bonds. The order directed the RTO to submit more information about when it will begin accepting surety bonds for commercial readiness and study deposits. 

ISO-NE’s transition process for adopting the changes also largely complies with Order 2023, FERC wrote. The commission wrote that the creation of a transitional capacity network resource (CNR) group study helps to appropriately balance “the need to move expeditiously to the new cluster study process with the need to respect the investments and expectations of interconnection customers at an advanced stage in the existing interconnection process.” 

The transitional CNR group study is intended to allow projects with complete system impact studies to gain capacity interconnection rights without needing to go through the full cluster study. Going forward, interconnection customers will achieve capacity interconnection rights through the cluster studies.  

In recent months, project developers have raised alarms that FERC’s inaction on ISO-NE’s compliance proposal could threaten the ability to align the transitional CNR study with the qualification activities for ISO-NE’s 2025 reconfiguration auction (RA). (See New England Generators Remain in Limbo on Interconnection Reform.) 

ISO-NE had said it would need a ruling by March 31 to align the transitional CNR group study with the 2025 RA qualification process due to a show-of-interest submission deadline at the end of April. On March 31, FERC took the unusual step of informing ISO-NE and stakeholders that it planned to issue an order in the coming days. (See FERC Announces Impending Order on ISO-NE Order 2023 Compliance.) 

Alex Lawton of Advanced Energy United, who has been vocal about the importance of the transitional CNR study, said he’s optimistic FERC’s ruling will enable ISO-NE to proceed with the study.  

A representative of ISO-NE said the RTO “is reviewing the April 4, 2025, order in detail and assessing next steps.” 

The ruling also accepted independent entity variations related to site control requirements, the opportunity to reduce project size prior to a cluster restudy, energy storage modeling and the evaluation of alternative transmission technologies. 

FERC directed ISO-NE to make a series of relatively minor changes to its proposal within 60 days, including to correct multiple “unexplained deviations” from the pro forma language, and to add pro forma language that was omitted. The commission also found the proposal did not comply with Order 2023’s ride-through requirements. 

The commission accepted ISO-NE’s proposed Aug. 12, 2024, effective date and the June 13, 2024, deadline for interconnection customers to have a valid interconnection request to be eligible to participate in the first cluster study. While the RTO briefly reopened its interconnection queue April 1, requests submitted after this date will not be eligible to participate in the transitional cluster study. (See ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC.) 

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Groups Ask FERC to Axe Languishing Proposal to Cut Transmission Incentives

The Edison Electric Institute, GridWise Alliance and WIRES asked FERC on April 3 to end a proceeding that has been open for five years to consider cuts to transmission incentives (RM20-10). 

The commission opened the rulemaking in March 2020 and supplemented it a year later to propose eliminating the existing RTO membership transmission incentive for utilities that have been participating in an organized market for more than three years. The proposal would have focused project-specific incentives on the benefits to customers from transmission investment. 

“The commission’s current transmission incentives policy is working to the benefit of customers, transmission owners and the public interest,” they said in a joint filing. “With the rising demand for electricity, the commission’s existing transmission incentives policy has become even more essential.” 

A lot has changed since the rulemaking launch, they said, including a rapid and unforeseen return to demand growth because of large data centers, reshoring of industry and general electrification pressures. The COVID-19 pandemic led to an economic slowdown and uncertainties in the economic forecasts on which the industry relies. 

FERC also issued Orders 1920 and 1920-A, which are intended to identify considerable new transmission portfolios that might also introduce new risks to development because of the selection of larger and more complex projects, the groups argued. The world also is entering into a period of greater geopolitical tensions and competition, in which promoting domestic energy independence and security is considered a heightened priority. 

While the three trade groups want FERC to abandon the rulemaking, they argued even if the commission wants to go forward, it should take more comments so parties can update the record for the changes over the past half decade. 

President Donald Trump has declared a national energy emergency, in which he emphasized the urgent need to revamp and expand the grid to meet growing demand and ensure reliable supply, they noted. 

“This infrastructure is not only essential for accommodating the increasing power demands from various sectors, but also for maintaining and enhancing the overall resilience and efficiency of the nation’s energy system, which itself underlies the broader economy,” they said. “A reliable, resilient and efficient energy delivery system is the foundation to providing cost-effective electric service to customers of all kinds, thereby aligning with the administration’s broader goals of fostering economic growth and energy security.” 

The incentives date back to the Energy Policy Act of 2005, which acknowledged that increased levels of transmission infrastructure were needed to keep costs reasonable and the system reliable. FERC implemented them in 2006 with Order 679, which established tailored incentives to address risks and challenges associated with transmission development. 

“After nearly two decades, it is undeniable that the commission’s transmission incentives policy has provided the signal and support for transmission investments that ultimately benefit electric customers,” the groups said. As FERC considers changing the incentive policy, it has to weigh whether this would disrupt expectations, create uncertainty and possibly chill investment by eliminating rate treatments that cut risk and aid in lower financing costs to benefit consumers, they said. 

FERC’s proposed change would treat the RTO adder as an incentive to join an organized market, but the groups argued that was not Congress’ intent. 

“The commission is, ultimately, ‘a creature of statute and has only those authorities delegated to it by … Congress,’” they said. “Any action that would restrict eligibility for this incentive beyond the requirement that a transmission owner join an RTO is ultra vires [beyond its legal authority].” 

RTO membership requires TOs to transfer operational control of their facilities to the grid operators, which perform functions like planning, marketing and congestion management. The grid operators can require TOs to make investments in high-risk transmission projects, with the RTO adder helping to offset that risk. 

“Transmission owners in RTOs must also comply with a more expansive set of federal regulations, such as Order Nos. 719, 745, 841 and 2222, which significantly and disproportionally impact RTO regions,” the groups said. “Through these actions, the commission has fundamentally altered the business model, exposed certain future capital investments of transmission owners to competition, increased the potential that investments will be delayed and deprive customers of the benefits, and created significant uncertainty and related regulatory risk.” 

The RTO adder offsets risks incurred in delivering the benefits of RTO membership to customers such as access to cheaper power, efficient dispatch over a wide area and enhanced reliability, which together far outweigh the cost of the adder, they argued. 

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PJM TEAC Briefs: April 1, 2025

PJM Presents Scope Change to RTEP Projects

PJM presented a $97 million increase to a project included in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3. The change would remove two 230-kV lines between the Mars substation and Sojourner and Shellhorn facilities and reroute them to terminate at the south side of Mars to avoid intersecting with new lines being planned. The original scope is to build a 500-kV line between Mars and Golden and a 230-kV line from Mars to Lockridge and terminating at Golden. The changes bring the total cost to $439.9 million.

Projects included in the 2022 RTEP Window 3 also have obviated the need for two prior projects totaling $7.5 million. The rebuilding of a line between Loudoun and Morrisville will supplant a $4.5 million project to rebuild a 1.3-mile segment of that facility. A $3 million project to replace breakers at the Ox 500-kV substation also is being canceled as the same work is included in baseline projects.

Supplemental Projects

FirstEnergy presented a pair of projects amounting to $37.6 million to replace two 500/138-kV transformers and disconnect switches at its Pruntytown Substation in the APS zone due to the assets nearing end of life and experiencing maintenance issues. The projects are in the conceptual phase with in-service dates of Dec. 13, 2030, and June 13, 2031.

The replacement of another aging 500/345-kV transformer at Wylie Ridge is expected to cost $20 million with a projected in-service date of Dec. 13, 2030. The transformer has increased hydrogen and ethylene readings, moisture buildup and low dielectric strength, according to FirstEnergy.

American Electric Power presented a $50.4 million project to build a new 345-kV substation, to be named Navistar, in the AEP zone to serve a new customer bringing 437 MW of load to the New Carlisle, Ind., area. The facility would be cut into the Dumont-New Prairie 345-kV double circuit lines and would be configured as a breaker and a half with 11 345-kV breakers and two bus ties to the customer. The project is in the scoping phase with a projected in-service date of March 15, 2027.

Dayton Power and Light presented a $480 million project to serve two new customers located near Jeffersonville and Wilmington, Ohio, by expanding several 345-kV substations and linking the Clinton, Fayette and Atlanta facilities with new 345-kV lines. The Fayette and Atlanta substations would be expanded to breaker-and-a-half configurations to accommodate a 25-mile double circuit between the two sites, as well as two customer feeds from Fayette.

The Clinton facility would be expanded with equipment for a new 27-mile line to Fayette and two 345-kV customer feeds. The project is in the conceptual phase with a projected in-service date in January 2031. The Jeffersonville load is expected to come online in September 2026 and ramp up to 1.5 GW of load by 2031, while the Wilmington customer is expected to come on in 2028 and grow to 500 MW.

PPL presented a $101 million project to expand the proposed Tresckow 230-kV substation to include a four-bay breaker and a half 69-kV yard to serve a customer expected to bring 300 MW of load to Hauto, Pa., in 2028. Four 230/69-kV transformers also would be installed, as well as two 69-kV double circuit lines connecting Tresckow to the Frac-Tres 69-kV No. 1 and No. 2 lines. The project is in the conceptual phase with a projected in-service date of May 30, 2028.

Duke presented a $49 million project to build a new 345-kV substation, to be named Gold Finch, along the Silver Grove-Red Bank 345-kV line to serve a new customer seeking to interconnect 300 MW in Clermont County, Ohio. Gold Finch would be configured as a ring bus with four 345-kV breakers and a control building. The project is in the scoping phase with an in-service date of June 1, 2028.

Dominion presented a $450 million project to upgrade several lines and transformers to address load drop and thermal violations on the Ladysmith CT-Fredericksburg and Ladysmith CT-Four Rivers 230-kV lines. The violations were identified in the 2025 do no harm analysis. The project is in the conceptual phase with an in-service date of July 1, 2029.

Phase 1 of the project, expected to be complete in January 2028, includes rebuilding 6.5 miles of the Summit DP-Fredericksburg Sub 230-kV line with higher capacity conductor; reconductoring 7.3 miles of the Ladysmith-Ladysmith CT line; adding two 500-kV capacitor banks to Ladysmith; and building a new 230-kV line running between Ladysmith, New Post, Lee’s Hill and Allman using a mix of new structure and vacant arms.

Phase 2 would go online in July 2029 to expand the Kraken 500-kV switching station to cut into the Summit DP-Fredericksburg Sub 230-kV line, the St. Johns-Four Rivers 230-kV line and the planned Ladysmith-Allman 230-kV line. The St. Johns-Four Rivers and Four Rivers-Elmont lines also would be rebuilt. The 115-kV lines from Fredericksburg-Four Rivers, Pinewood-Four Rivers, Four Rivers-Elmont, and Pinewood-N. Doswell lines would be “wrecked” and a new double circuit 230-kV line would be built from Kraken to Allman, along with a single circuit line from Kraken to Elmont.

Several additional Dominion projects would serve new service requests across its footprint. A $10.1 million project would construct a 230-kV ring bus with four breakers at its Trabue substation; two new 230-kV substations, Ruther Glen and Carmel Church, would be added to the Ladysmith CT-Four Rivers line for $87 million; and two new 230-kV substations, New Post and Lee’s Hill, would be built along the Fredericksburg-Ladysmith CT line for $43 million.

The Wabash Valley Power Alliance presented an $80 million project to construct a 15-mile, 345-kV line between AEP’s Elderberry substation and NIPSCO’s Stillwell substation. The line will be operated by MISO and is being submitted to PJM’s supplemental planning process to allow study coordination.

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PJM MIC Briefs: April 2, 2025

Stakeholders Narrowly Endorse Uplift Changes

VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a joint PJM and Independent Market Monitor proposal to rework how uplift and deviation charges are calculated for market sellers depending on how they respond to market signals and dispatch instructions. It passed with 53.3% support and is set to go for a first read at the Markets and Reliability Committee on May 21. (See “First Read on Proposal to Overhaul Uplift,” PJM MIC Briefs: March 5, 2025.) 

The changes would establish a new tracking ramp-limited MW desired (TRLD) metric to replace the three existing MW desired metrics used in calculating balancing operating reserve (BOR) credits and deviation charges. The TRLD would follow how a unit responds to instructions over time, rather than focusing on individual five-minute intervals as the ramp-limited desired, dispatch and locational marginal pricing-desired metrics do. 

PJM’s Lisa Morelli said that would address scenarios where a unit ignoring dispatch and keeping its output steady can avoid deviation charges. 

The TRLD would account for any dispatch instructions arising from ancillary services a market seller is responding to as well, such as regulation or sync reserve, allowing corresponding automatic exemptions from deviation to be eliminated. 

In past meetings, Morelli gave the example of a unit operating at 100 MW being dispatched down to 95 MW in accordance with its ramp rate. If that unit ignored the signal and stayed at 100 MW, it would not exceed the 10% margin that defines when a unit is deviating from dispatch under the status quo. Additionally, because dispatch is limited by ramp rates in the next interval, PJM could bring it down only to 95 MW in the following interval. 

The proposal also would rework the BOR credit formula by taking the lesser of real-time output or the TRLD and adjusting for ramp parameters for each interval, which Morelli said would simplify the equation. The start and end points for uplift eligibility would be revised to align with when a market seller’s commitment began and to run through either the end of that commitment or the unit’s minimum run time. 

Morelli said PJM’s goal is not to reduce uplift and the changes are likely to be a net benefit for many participants, as they also address scenarios where generators are undercompensated in some scenarios. 

If endorsed by the Members Committee in July, Morelli said PJM would aim to file tariff revisions at FERC in September. The changes would be implemented in two phases, starting with simulated results in market settlements reporting system (MSRS) reports before affecting actual settlements in late 2026 or early 2027.  

Responding to stakeholders questioning how PJM could respond to any gaps or unintended consequences identified during the soft launch, Morelli said the intention is to have enough detail in the tariff language to give direction to how the TRLD would function, with finer detail spelled out in the manuals. Any edge cases stakeholders are concerned about could be addressed by adjusting the manuals without needing to make additional FERC filings. The governing document language likely would empower PJM to adjust the TRLD if there are instances where SCED would dispatch a unit inconsistent with locational marginal pricing or the unit’s offers. 

Committee Endorses Manual 11 Periodic Review

Stakeholders endorsed revisions to Manual 11: Energy & Ancillary Services Market Operations drafted through the document’s periodic review. The changes were deferred during the committee’s March 5 meeting after concerns were raised with the language designating data centers as plug load. (See “Periodic Review of Manual 11 Deferred,” PJM MIC Briefs: March 5, 2025.) 

PJM’s Joseph Tutino said the proposal was changed since the first read to include data centers and crypto mining as “business segment” load following feedback that plus load typically includes smaller devices, such as household appliances. He said the remaining changes are mainly typographical. 

PJM’s Maria Belenky told the committee in March that data centers are considered plug load for the purpose of curtailment service providers (CSPs) reporting load enrolled in demand response. 

First Reads on Manual Revisions

PJM presented a first read on revisions to Manuals 6, 11, 28 and 29 to conform with FERC’s May 2023 order accepting a PJM proposal on how it proceeds with settlement under a market suspension. PJM’s transmittal letter states that a market suspension never has occurred but could result from “extraordinary circumstances such as a failure of computer systems.” (See “Market Suspension,” PJM Market Implementation Committee Briefs: June 8, 2022.) 

The filing stated that the tariff has no way of determining energy and ancillary service prices when zonal dispatch rates cannot be calculated by software. Three different sets of rules are included for determining real-time prices when suspensions last less than six hours, between six and 24, or for longer. Shorter suspensions would use the average real-time prices for each hour prior to and following the outage; for moderate duration events, day-ahead prices would be used if available, otherwise real-time prices would be used; and for suspensions exceeding a day, an aggregate supply curve would be developed (ER23-1431).  

The proposed Manual 28 language would use actual output for calculating energy offers during real-time energy market suspensions. Lost opportunity costs (LOC) would not be included for suspensions longer than one day, and BOR charges would be allocated to real-time load plus exports if a suspension exceeds one hour. 

PJM also gave a first read on revisions to Manual 18 to conform with FERC orders granting several changes PJM sought to make to its capacity market in recent months (ER25-682, ER25-785, ER24-2995). 

The bulk of the changes arise from FERC’s Feb. 14 order granting a host of capacity market changes meant to address tightening supply and demand. The corresponding manual revisions would codify delayed Base Residual Auction (BRA) dates; model resources operating on reliability-must-run (RMR) agreements as capacity; continue the use of a combustion turbine generator as the reference resource; and clarify that market sellers do not hold “safe harbor” from claims of market power exercise by holding a categorical exemption from the requirement that all resources holding capacity interconnection rights (CIRs) must offer into the capacity market. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

It also includes the elimination of must-offer exemptions for intermittent, storage and hybrid resources, requiring market sellers to offer those units into capacity auctions starting with the 2026/27 BRA scheduled to be conducted in July. Stakeholders and intervenors argued the exemption artificially increased auction clearing prices, while many generation owners argued the existing and proposed market rules do not allow them to reflect the risk exempt resources would take on with a capacity obligation. 

The final change would be to memorialize the removal of the energy efficiency addback and eliminate the resource class outright following the 2025/26 delivery year. PJM argued to the commission that the addback was a holdover from a prior set of rules and no longer was needed, as EE was captured in its load forecast. Removing capacity status for EE was sought as the RTO argued that it could not be demonstrated that capacity market revenues were used to reduce load. (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.) 

Stakeholders Discuss Pseudo-tied Resources

The committee continued its discussions on how pseudo-tied generators are assigned to locational deliverability areas for the purpose of determining clearing prices and the amount of local capacity PJM models as available within a zone. The subject was brought up by the North Carolina Electric Membership Corp. (NCEMC) to explore whether a load-serving entity seeking to self-supply with pseudo-tied generation should receive the clearing price for an LDA or the RTO-wide clearing price, with the latter being the status quo. 

PJM’s Nebiat Tesfa said pseudo-tied resources are those that have an indirect connection to PJM, hold firm transmission service and are studied to ensure deliverability akin to internal resources. Those studies do not, however, determine whether any particular resource is deliverable to a specific LDA; to ensure the right to inject to an LDA, either incremental capacity transfer rights (ICTRs) or investment in qualifying transmission upgrades (QTUs) must be obtained. In some cases, modeling the flow from a pseudo-tied resource can use the reliability requirement for an LDA to increase, she said. 

PJM’s Tim Horger said the RTO’s priority going into the topic is ensuring there are no inconsistencies between internal and pseudo-tied resources when modeling congestion or transmission. 

In its own presentation, NCEMC said there were circumstances in the 2025/26 BRA where LSEs were exposed to price separation within their LDAs and were prevented from using their own resources adjacent to that zone and which they believe are electrically serving that load. It said analysis of dispatch data shows that those units are providing congestion management in Mid-Atlantic Dominion. 

Horger said PJM and stakeholders have to be careful when considering changes down the path of using distribution factor (DFAX) analysis to determine whether a given resource is helping a specific LDA. 

Carl Johnson, representing the PJM Public Power Coalition, said if resources are tied to an LDA, especially when it’s the same organization trying to serve load with its own resources, there should be a way of recognizing that the cost shouldn’t be different just because an LDA separates. 

PJM’s Jonathan Kern said the CETL study is agnostic about which capacity resource is supplying an LDA, so there’s going to be some association with the CETL and generation outside the LDA but not associated with any particular resource. 

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PJM OC Briefs: April 3, 2025

Stakeholders Endorse Manual Revisions

VALLEY FORGE, Pa. — The Operating Committee endorsed a pair of revisions to Manual 1: Control Center & Data Exchange Requirements and Manual 37: Reliability Coordination. 

The changes to Manual 1 would align with NERC standards IRO-010, TOP-003 and EOP-008 and include updating the Generation Scheduling Service table with generation periodic eDART and Cold Weather Checklist data requests. 

The periodic review of Manual 37 led to recommendations to update references throughout the document and remove the 3 p.m. posting deadline for next day reliability analyses. 

March Operating Metrics

PJM’s Marcus Smith presented the forecast error and operating metrics for March, which saw a 1.47% hourly forecast error and three days exceeding the 3% peak error benchmark. 

Warmer-than-expected temperatures March 4 led to load coming in lower than expected, pushing the peak error to 3.05%, while the hourly rate was 1.63%. March 6 saw cooler temperatures corresponding to peak loads being 4.14% lower than forecast. A similar dynamic was seen March 15, when the peak was 5.01% lower than forecast.  

Three shared reserve events, one high system voltage action, seven post-contingency local load relief warnings and six shortage cases were issued. Two of the shortage cases were on March 15 due to lines tripping. Four were on March 19 and were attributed to load increases and reduced reserves being available. 

Update on Regulation Market Design

PJM’s Damon Fereshetian presented an update on the implementation of PJM’s regulation market redesign, the first phase of which is set to go live Oct. 1, 2025. The second phase is scheduled to roll out a year later. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

Phase 1 includes consolidating the RegA and RegD signals into one bidirectional signal, shifting to 30-minute clearing from hourly, eliminating the accuracy and delay components of performance scoping to focus only on precision, and changes to opportunity costs and the regulation requirement. The RegD product provides fast response, while RegA is used for long deployments. 

Training on the changes is set to begin in May. Sandbox testing software will launch either that month or in June. PJM targets endorsement of manual language codifying the changes in August, with education sessions Aug. 12 and Sept. 5. 

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NJ Lawmakers Sound Energy Supply Alarm

New Jersey lawmakers pushed back on the state’s all-electricity, clean-energy strategy at a heated committee hearing, urging an all-the-above approach as PJM faced criticism for failing to foresee a dramatic hike in demand that helped trigger a 20% rise in the average customer’s bill.

Facing predictions that electricity demand could rise by more than 60% by 2050, driven in part by the expected arrival of data centers, greater electric vehicle use and the state’s shift toward building electrification, lawmakers said the state needs to consider all options that could rapidly boost generation capacity. (See NJ Releases Electrification-focused Energy Master Plan.)

The turbulent, five-hour meeting convened March 28 by a Select Committee of Senators and the Assembly Telecommunications and Utilities Committee underscored the severity of the potential power shortfall facing New Jersey and its likely impact in further pushing up rates.

The two Democratic co-chairs of the meeting suggested the state needs to look beyond Gov. Phil Murphy’s (D) tight focus on renewable energy. During his seven years in office, Murphy has championed EVs, building electrification and a now largely stalled effort to create an offshore wind sector able to generate at least 11 GW.

“The storms are going to keep coming, and we need to look at renewable energies,” said Sen. Paul Sarlo (D), one of the co-chairs. “But we can’t just sit idle for the next five to seven years and not open our eyes to other concepts.”

That was the “loud and clear” message of the committee members, he said. He asked Christine Guhl-Sadovy, president of the New Jersey Board of Public Utilities (BPU) and a Murphy appointee, if her agency would agree to “go forward with repurposing an existing plan for clean natural gas” while also pursuing renewable energy. Under prodding, she replied only that “we need to explore all options.”

Assemblymember Wayne DeAngelo (D), the second co-chair, said the state needs a “well diversified energy generation portfolio” that includes wind, battery storage, nuclear and natural gas. Plans to go from gas heating to heat pumps would require a major, potentially burdensome residential infrastructure upgrade, he said.

“Seventy-five percent of our homes in New Jersey are heated with natural gas. Sixty-five percent of our businesses are heated with natural gas,” he said. “And we haven’t even talked about our data centers, which are popping up all over the place.”

Republicans, who have called for the state to adopt a broader portfolio, blamed Murphy’s policies for the state’s dilemma.

“I can’t help but get the impression today that we’re here because all of a sudden the rates went up, and people are like, ‘Wow!’ … like it wasn’t foreseen or couldn’t have been predicted,” Sen. Anthony M. Bucco (R) said. “Experts have said the same thing: that we’re just not going to be able to produce enough [electricity]. … We’ve all been saying that; you can’t completely electrify the state in such a short period of time.”

PJM Criticized for Perceived Flaws

But some of the most vigorous criticism was directed at PJM and its capacity market. In written testimony delivered at the hearing, Brian O. Lipman, director of New Jersey’s Division of Rate Counsel, said that “clearly PJM is the easiest target in the room, and not without reason.”

“PJM and its markets are a significant factor as to how we got to this problem,” he said. “Everyone saw the pending retirements of generators. The issue did not come to a head because PJM was able to mask the problem with excessive available generation. The system is broken. The capacity auctions are not doing their job. The generation queue is not doing its job.”

Legislators convened the hearing to address concerns about a 17 to 20% hike in the average electricity bill that will begin June 1 as a result of a basic generation service (BSG) auction in February.

Those BSG bid prices were shaped by PJM’s capacity market auction in July, which set capacity prices at record levels, about 10 times as high as the previous auction. The auction sets the wholesale prices in the region that help shape bids in the BPU’s auction. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

BPU officials say they believe the bids were inflated by PJM demand forecasts that failed to properly include all the clean capacity expected to come online.

In a March 25 letter to PJM discussed at the hearing, Guhl-Sadovy said the BPU had “serious concerns” about PJM’s plan to reduce the “recognized capacity value of generation resources” in its upcoming auction because it used the same “flawed reliability modeling” that produced the high prices. She said PJM’s Independent Market Monitor calculated the prices would have been half as high if not for those “flaws” that “severely undercounted available supply.”

“The cost of PJM’s mistakes to New Jersey consumers in the July 2024 capacity auction alone will be at least $800 million,” Guhl-Sadovy wrote. “PJM should therefore be working to ensure that no critical flaws remain in its capacity market design.”

Calculating Generator Capacity

PJM says the pending supply shortage is in part because of decarbonization efforts that have shut down older, fossil fuel-fired plants faster than new plants have come online. The RTO has been criticized for the slow pace of approvals for new generating sources, in particular renewables, although it says its new queue system will speed up the process.

Asim Haque, senior vice president for PJM, disputed the suggestion the RTO should have anticipated the “major uptick in demand.” For years demand across the system was flat. That changed recently because of data centers, electrification and onshoring of the U.S. manufacturing industry.

“The market is essentially holding a mirror and reflecting the reality of the supply-demand challenge,” he said. “And unfortunately, consumers are now seeing that on the bill side.

“If we’re all being very truthful with one another, nobody saw this coming,” he said. “We certainly saw the supply-demand imbalance sort of changing many years ago … but the demand increase, in particular, this uptick, is something that is a newer phenomenon.”

Addressing criticism of the RTO’s rules, Haque said PJM is constantly receiving stakeholder input, but it can’t change them without FERC approval.

One complication in trying to calculate supply is the variable output of some clean resources. A group of solar resources totaling 200,000 MW of capacity, for example, results in only about 20,000 MW of actual power because PJM calculates it operates at only 10% of capacity, he said.

New Jersey’s Picture

In New Jersey, which imports 35% of its electricity, the RTO predicts demand will increase by 2.8 to 4.7% over the next 10 years, Haque said. The state planned to meet that increase in large part through wind generation: Of the state’s 16,000 MW in PJM’s queue, about 12,000 MW are OSW, he said. “As we sit here right now, those projects have not materialized.”

Guhl-Sadovy said New Jersey has 79 projects in the PJM queue, mainly solar and storage that are “waiting for interconnection review to get connected to provide electricity.” She said clean energy projects could be among the fastest to start generating energy once approved, adding that the federal government disrupted that process by halting wind projects.

“The fact of the matter is that thousands of megawatts of generation were going to come online in New Jersey to support New Jersey and the PJM grid between 2029 and 2032,” she said.

Under questioning, Guhl-Sadovy acknowledged her agency suspects one reason for the RTO’s slow approval process of clean energy projects is that “PJM has made decisions that lean toward fossil fuel generation and the states that have large-scale fossil fuel generation.”

Data Center Reality?

Sen. Bob Smith (D) questioned the veracity of the claim that power-hungry data centers are driving the power imbalance. He said the U.S. Energy Information Administration has reported the state’s electric load dropped from 75.4 TW to 71.1 TW in 2023.

“You mentioned the projected increase: Our history has not been out-of-the-box demand in New Jersey, but actually, at least recently, declining demand,” he said to Guhl-Sadovy. “Do you actually have data center AI in the queue at BPU? … How do we know any of this is true?”

He said PJM does not know if the proposed AI data centers are “real or phony-baloney” and called for the RTO’s policies to be investigated, saying the specter of data center demand is a “preemptive rate increase with no basis in fact.”

Guhl-Sadovy said the question is a “great point,” adding the utilities have said they have interconnection requests from data centers and her agency is waiting for details.

Haque acknowledged that on the demand side, the industry is “legitimately struggling with sort of what is real on these data center forecasts.” One solution already adopted by some states is to put “gating criteria” on data centers that submit connection applications, requiring them to “put money down up front,” he said.

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CEC Report Shows High Ocean Energy Potential in Northern Calif., Less Down South

California has a significant amount of marine energy potential in the northern part of the state but much less in the south, a new California Energy Commission report has found. 

The report, a requirement of California Senate Bill 605, evaluated two forms of ocean energy: wave and tidal energy. Both are renewable energy resources that could provide support for intermittent renewable resources like wind and solar power, CEC staff said in an April 2 workshop on the subject.  

The report separated the state into three regions: Northern, Central and Southern California.  

Northern California, defined as the region from Bodega Bay north to the Oregon border, contains substantial areas of moderate to high wave energy within 6 miles of shore. But the region has a lower population than other parts of the California coast. 

Central California has a medium level of wave energy potential and the highest tidal energy potential, due to the large tidal inlets in the region, such as the San Francisco Bay and the San Pablo Bay. But the region has many constraints and conflicts to access its marine energy due to higher populations and ports.  

Southern California has low to no tidal energy potential due to the lack of large tidal inlets, yet has high energy demand and substantial energy infrastructure, the report says.  

Each of the three regions contains constraints, such as already being assigned as U.S. Bureau of Ocean Energy Management wind lease areas or oil and gas planning and lease areas, or being far from onshore electrical infrastructure. 

Due to these constraints, a more realistic use of ocean energy could be for non-grid-connected applications, such as equipment in ports and harbors, marine aquaculture and scientific research equipment, the report says. The economic and societal barriers to entry are much lower in these application areas than on commercial-scale sites where developments must reach a certain size to compete economically with alternative power generation methods, the report says.  

Another possible approach to kickstarting ocean energy projects in California could be building them with offshore wind projects. The land and nearshore components of marine energy and wind energy operations could be used together, potentially reducing the overall spatial and visual impact of that supporting infrastructure, the report says.  

The report also outlined some other, more unusual, ways to use wave energy. One of those is to power underwater charging stations for autonomous vehicles.  

Next, the CEC will submit a summary report of these findings to the California legislature and Gov. Gavin Newsom. The agency also plans to engage more key stakeholders in the process because the marine renewable energy industry “is still emerging with few commercial-scale projects in operation, so the public’s knowledge on these topics is limited,” the report says. 

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Demand Curve Reset Tops NYISO Priorities in Capacity Market Review

After months of conversations with stakeholders, NYISO presented the Installed Capacity Working Group with its priorities for the Capacity Market Structure Review, with improving the demand curve reset (DCR) process and methodology topping the list.

Also on the list are winter reliability capacity enhancements; attribute-based pricing for transmission security; improving capacity accreditation and resource adequacy modeling; and redesigning the capacity zones.

Of the listed priorities, the winter reliability enhancements are ongoing as a standalone project. Brendan Long, capacity market design specialist for NYISO, said that they were occurring in parallel with the review.

Much of the morning of the all-day April 1 meeting was dominated by conversation about how NYISO would reexamine the DCR, the process by which it sets the proxy unit’s cost of new entry into the market, which in turn helps set capacity prices for the next four years. The ISO just completed the most recent reset last year.

“This effort would look to examine alternative methodologies and processes for establishing the ICAP demand curves with the goal of reducing the complexity and resource intensity of the DCR,” said Maddy Mohrman, senior market design specialist with NYISO.

Mohrman said this could include changing the demand curve shape and slope, using “empirical net cost of new entry” to set a reference price and leveraging existing publications of resource costs. But before she could proceed into detail on the ISO’s options, stakeholders immediately began asking for things to be included under the scope of the DCR review. A representative of the Long Island Power Authority asked that examining the definition of the proxy unit be included. Another stakeholder asked whether the ISO would consider adding the annual update process.

Mohrman said the ISO could look at the proxy unit definition and that the annual update process was something it would be examining as part of the review regardless.

“Nothing’s really off the table for this,” she said. “We just want to highlight some of the alternatives we’ve already identified.”

Leveraging Outside Cost Estimates

Currently the ISO hires a consultant to estimate the capital costs of each potential type of peaker plant using bottom-up engineering assessments. The assumptions used for those assessments have historically been the subject of considerable stakeholder debate. Rather than go through that process every four years, the ISO would use peaker plant cost estimates developed by external entities.

“Two organizations we could look to potentially leverage are [the National Renewable Energy Laboratory] and the [U.S. Energy Information Administration],” Mohrman said. “They regularly publish estimates of capital costs. We’re looking into that further, and that could also be used, potentially, to help the annual update process as well.”

Howard Fromer of Bayonne Energy Center said that the capital costs in New York are very different from national estimates and that costs within the state vary significantly by region. Using estimates that don’t capture New York’s realities could generate an inaccurate CONE.

Mark Younger of Hudson Energy Economics said that using external sources could waste time and effort if ISO staff ended up having to substantially adjust the external cost estimates to make them fit in New York.

Is the Demand Curve Working?

Several stakeholders questioned whether the demand curve and the CONE were appropriate market mechanisms at all. One stakeholder argued that the demand curve mechanism only worked to incentivize capacity retention and buildout if prices continued to rise. Another stakeholder representing New York City said that if the market is designed only to function upward, then it isn’t a market because it would incentivize overpaying and not price correction.

A third stakeholder, representing the transmission sector, said that in the past, the high price signals sent by the ICAP market would have incentivized new builds and eventual price competition. Currently, the price signal is high, but the vast majority of new generation is being built through state-level processes.

“We don’t have confidence that new entry will occur outside of [renewable energy certificates] and state-sponsored resources, and we don’t know what the accreditation factor change on those resources will be,” they said. “High prices could be sustained without a true competitive process capable of disciplining them. We need to make sure we don’t end up in that conundrum.”

Mohrman steered the discussion back to NYISO’s proposed solutions. She said the ISO was considering changing the shape of the demand curve. The curve has been linear since it was put in place in 2003.

“Alternative shapes and slopes may more accurately value resources according to their contribution to reliability, compared to this linear curve,” she said. “This may also address some stakeholder concerns that the current demand curve structure may result in wealth transfers to incumbent resources.”

Younger said that going with a steeper curve would result in more uncertain revenues and could possibly result in out-of-market actions, which may increase risk. Another stakeholder agreed, saying the steeper the curve, the greater price volatility.

Reliability Attribute-based Capacity Pricing

Michael Ferrari, a market design specialist for NYISO, took over to present the ISO’s proposal for valuing resources’ contributions to reliability via transmission security. He said the ISO is open to calculating separate resource adequacy and transmission security requirements for each locality, which would be traded separately as two different ICAP market products. This might mean creating a transmission security demand curve, transmission security capacity accreditation methods and new auction structures to solve both products.

“Potentially, as a secondary effort, we could leverage a framework to co-optimize with additional attributes in addition to transmission security,” Ferrari said. “These attributes may include … ramping inertia, voltage stability and quick cycling.”

Ferrari said NYISO would work with stakeholders to identify which additional attributes could be co-optimized with the ICAP market. He said it was possible that some attributes would be inappropriate and not work well as part of the market.

He said the purpose of all of this was to build more support for system reliability into the market.

Rezoning

NYISO divides New York into 11 capacity zones, labeled A to K approximately northwest to southeast. A is the Buffalo area, while J and K are New York City and Long Island, respectively.

The ISO wants to explore alternate ways to determine zone boundaries. This might mean exploring alternatives to the “New Capacity Zone” study, which examined deliverability across major transmission interfaces using a static set of system assumptions and conditions. The ISO is considering a probabilistic approach to identify system constraints and set zone boundaries.

The ISO is also considering increasing how frequently new zones can be considered for addition. The ISO lacks a mechanism to remove a zone and would explore whether having such a mechanism would improve price signals.

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NEMA Report Forecasts 50% Electric Demand Growth by 2050

Electricity demand will grow by 50% over the next 25 years, according to a report released April 7 by the National Electrical Manufacturers Association (NEMA). 

Data center demand is expected to grow by 300% over the next 10 years, with most of that happening in ERCOT and PJM, the study says. That represents 32% of the 1,323 TWh of forecast growth through 2037, while electrification of transportation makes up 24%. 

For the 1,360 TWh between 2038 and 2050, transportation makes up 51% of the forecast, followed by industrial demand at 28%, while data centers represent just 1%. 

The overall projected growth works out to 2% per year and follows years of low load growth across most of the U.S. as energy efficiency offset new sources of demand, NEMA CEO Debra Phillips said on a call with reporters April 4. 

“This 50% growth that we’re looking at over the next 25 years is fairly remarkable, and our grid wasn’t designed really to meet that,” Phillips said. “So, we’re going to have to get creative around the technology and policy solutions that are going to help us meet the demand.” 

The new growth will require new generation, transmission and other infrastructure, but Phillips said the industry would need to do more to maintain reliability. 

“We’ve grown more efficient over time,” Phillips said. “It’s been key to us keeping that demand curve flat in recent years, and we’re going to continue to get better in that efficiency space. And so that, I think, is the real difference maker in our study versus others, is that we’re really leaning into that concept of efficiency, and our products really enable that.” 

NEMA represents manufacturers of the grid’s backbone infrastructure, including lighting, motors, wire and cable, she said. 

While demand is forecast to grow the fastest in PJM and ERCOT in the first half of the forecast, the shift to EVs in the second means the West and Northeast should see the highest rates of growth, Phillips said. Between now and 2050, electricity is expected to grow from 21% of final energy use to 32%. 

In terms of new generation, the report forecasts its capacity will grow by 43% to 1,761 GW nationally, with most of the growth in renewables and storage as fossil generation declines slightly. NEMA’s forecast has 409 GW of gas running by 2043, while the U.S. Energy Information Administration expects the gas fleet to total just 126 GW by 2050 and a National Renewable Energy Laboratory study has it falling to 189 GW by 2050. 

NEMA is releasing the study after President Donald Trump announced wide-ranging tariffs, which will impact manufacturing supply chains around the globe, include the group’s members. Since 2018, NEMA members have invested $185 billion in domestic manufacturing, and its goal of reshoring some industry aligns with Trump’s goals, Phillips said. 

“Another aspect of the trade world that the electrical industry finds itself in is an ecosystem that’s very connected in North America,” Phillips said. “So, trade with our Mexican and Canadian partners is really important.” 

The three largest North American countries have designed their entire power systems together, so NEMA values certainty and predictability around the trading rules and tariff rates between them, she added. 

Predictability is important to the future of that continental trading relationship, ABB Executive Vice President Michael Plaster told reporters on the NEMA call. 

“We have a switch gear plant in Mebane, N.C.,” Plaster said. “We have a switch gear plant in Mexico, and they make the same thing. And to be able to flex when there is a crisis is really important, without having to wonder how much is it going to cost us to flex like that.” 

Predictability is important, but the tariffs are going to have cost implications because going back to a world where everything is made for domestic consumption in each country is not cost effective, S&C Electric CEO Anders Sjoelin said on the call. 

“There will be a cost adder,” Sjoelin said. “And we’re going through that because some of the components and parts that [go] into your product [are] hard to make yourself because [they’re] not part of your core. … I’m discussing that today with my team.” 

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NERC Board Approves Cold Weather Standard

NERC’s Board of Trustees on April 4 approved the ERO’s new cold weather reliability standard, bringing to a close a development that saw the board use its special authority to streamline the normal stakeholder process for the second time.

The board unanimously found that EOP-012-3 (Extreme cold weather preparedness and operations) is “just, reasonable, not unduly discriminatory or preferential, and in the public interest.” The standard will be submitted to FERC for final approval.

In her presentation to the board, Soo Jin Kim, NERC vice president of engineering and standards, reviewed the sometimes unorthodox process that brought EOP-012-3 to its final state. FERC kicked off the chain of events in June 2024 by approving the standard’s predecessor EOP-012-2 while ordering a set of “targeted modifications” to be completed by March 27.

NERC first approached the project through its normal standards development process, assigning the task to Project 2024-03 (Revisions to EOP-012-2). But the draft standards created by the team failed to meet the two-thirds, segment-weighted approval of stakeholders, required for passage, in two formal ballot rounds by December 2024, leaving the ERO’s management concerned about being able to satisfy FERC’s directive.

With the commission’s deadline looming, the board agreed in January to invoke Section 321 of NERC’s Rules of Procedure for the second time in five months. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.) The board ordered NERC’s Standards Committee to work with stakeholders and ERO staff to prepare a standard that satisfies FERC’s order, post it for a 45-day public comment period and then submit it to the board after revising it in response to stakeholder feedback. Additional formal ballots were not required under the board’s directive.

The SC formed a group of volunteers, including some members of the 2024-03 drafting team, to revise EOP-012-2. After completing their work, they posted a draft of EOP-012-3 for comment in January; the comment period ended March 12. This left only 15 days before the standard was due to FERC, and NERC formally requested the commission to extend its deadline to April 14, which FERC granted on March 20 (RD24-5). (See NERC: Cold Weather Standards Now Expected in April.)

Kim identified several themes in industry responses to the draft, which the SC addressed in the final standard. First, the team revised the proposed definition of “generator cold weather constraint” — a condition that precludes generator owners from implementing freeze protection measures — to “clarify the scope of … measures that may be precluded by a constraint.” In addition, the final standard will require GOs submitting constraint declarations to add an attestation signed by a company officer.

Commenters also raised concerns about the standard’s requirement that corrective action plans (CAPs) addressing cold weather reliability events be implemented by the start of the next winter season after the event — a mandate that stakeholders said could place unfair pressure on utilities that experienced events late in the season. Kim said the team responded to this concern by clarifying the criteria for “early season CAPs,” without specifying what changes were implemented.

Kim added that the final standard provides for a “compliance abeyance period.” This measure provides a two-year window during which regional entities will not take action against utilities for failing to comply with requirements concerning generating units’ extreme cold weather temperature — defined as the lowest 0.2 percentile of a unit’s winter temperatures since 2000 — as long as the utility is “acting in good faith to comply with the standard in accordance with the implementation plan.”

Board Chair Suzanne Keenan noted this will be the first standard to have such an abeyance period, one of “a lot of firsts” that the project entailed. These include the first time requesting an extension from FERC, the first time approving a standard without a successful stakeholder ballot and the first time holding an open board meeting on “such a difficult topic” without a closed meeting beforehand.

Keenan emphasized that “the board doesn’t take lightly the action before us,” adding that “if this were easy, we wouldn’t be here now.” She also referred to NERC’s Modernization of Standards Processes and Procedures Task Force, which the board created at its previous meeting in February, and expressed hope that the group could “reimagine how we get [standards] done to avoid this in the future.”

Trustee Sue Kelly, the board’s liaison to the SC, praised the committee’s work under pressure, first to create the new standard and then to revise it after the comment period. She said NERC was “in a much better place than we otherwise would have been” without the committee’s work.

Trustee Ken DeFontes, who was chair both times the board invoked Section 321, echoed Keenan’s thanks for the SC’s efforts while reiterating his belief that the special action was necessary to satisfy the commission’s order.

“It’s clear to me that we have been as reasonable and thoughtful as we can possibly be to make sure that we’ve considered all the feedback from the stakeholders, and I think we have found the right place to balance those concerns while still assuring that we have a standard that will address the risks that we understand are real,” DeFontes said.