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March 17, 2026

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PJM Stakeholders Endorse Penalties for Pre-emergency Load Management

The PJM Market Implementation Committee endorsed an RTO proposal to establish penalties for load management and price-responsive demand (PRD) resources that underperform during pre-emergency deployments.

Penalties are being considered after six pre-emergency load management events during the summer of 2025 saw a weighted average performance of 67%. (See PJM Stakeholders Considering Load Management Performance Penalties.)

The penalty would be set at half the rate levied against resources that don’t meet their capacity obligation during a performance assessment interval (PAI), which amounts to about $1,150/MWh based on capacity prices for the 2027/28 delivery year. The formula mirrors the calculation for PAI penalties but doubles the number of expected deployment hours each year to 60. They would count toward the annual stop-loss for Capacity Performance penalties.

PJM’s Pete Langbein said the lower rate reflects that pre-emergency deployments are less severe than PAIs.

Penalty revenues would be awarded to overperforming curtailment service providers (CSPs) if the fleet-wide response meets or exceeds the amount committed. If demand-side resources under-respond, a pro-rated share of the revenues would be allocated to load-serving entities.

The PJM proposal received 86.1% support, while an alternative offered by Voltus received 39.3% and two packages from the Independent Market Monitor received 25.7% and 14.4%.

Voltus

Voltus adopted a similar formula to PJM, but it added a 50% derate to account for the diminished reliability risk associated with pre-emergency events and increased the number of expected deployment hours to 90. The resulting penalty would have been 16.7% of the PAI rate, or about $383/MWh.

Revenues would have been allocated to overperforming demand-side resources at 120% of the penalty rate, pro-rated for the amount they exceeded their assignment. The 20% adder is intended to create an incentive to overperform without allowing a windfall if the bulk of the response is from a small number of CSPs. Any excess would be provided to LSEs.

If the number of pre-emergency load management hours exceeded expectations, the package would have increased the overperformance bonus to 150% to counteract potential fatigue. The possibility of load management deployments becoming more regular as reserve margins tighten has become a frequent subject for stakeholders concerned it could drive away participation.

Monitor

The Monitor’s proposals would have required demand-side resources to curtail according to PJM instructions. Rather than a set penalty rate, it would have withheld daily capacity payments from the latter of the start of the delivery year or their last successful performance or test, spanning to the next successful performance or test. The amount withheld would have been based on resources’ shortfall and the revenues would be entirely allocated to loads rather than to other demand-side resources.

“Load pays for these resources, and load should receive the penalty revenue when the resource fails to perform,” Monitor Joe Bowring said in an email to RTO Insider.

The Monitor’s alternative proposal would have measured performance for each registration and prevented CSPs from netting performance across sites.

David Mabry, representing the PJM Industrial Customer Coalition, argued the Monitor was misconstruing what load management and PRD resources are expected to provide. Rather than provide a set reduction in load, they must maintain their load below a pre-defined level when dispatched.

Bowring said the Monitor’s proposals would prevent resources from being paid for being capable of curtailing when they do not do so when requested.

Pamela Wildstein, a market analyst with the Monitor, said the requirement is to reduce demand when dispatched and cited the tariff provision that states the requirement.

The alternative package was introduced during the meeting to define the performance obligations of demand-side resources with the intention of clarifying what the penalties are for. Bowring said there are several key weaknesses in how PJM defines the obligations of demand resources as capacity resources. Those include “not actually requiring a reduction in load when called to respond by PJM; not measuring the current load and therefore not accurately measuring reductions in load by the resources; simply ignoring actual increases in load by demand resources when called to respond; and allowing aggregation across hours and resources rather than calculating penalties by hour and by individual registration.”

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PJM PC/TEAC Briefs: March 10, 2026

Planning Committee

Stakeholders Endorse Quick Fix to Include Batteries in Planning Models

VALLEY FORGE, Pa. — The PJM Planning Committee on March 10 endorsed by acclamation a quick-fix proposal to include battery storage dispatch in the RTO’s planning models.

The revisions to Manual 14B: PJM Region Transmission Planning Process would model storage availability by season to reflect the longer duration of winter events. Batteries are currently modeled as offline in the Regional Transmission Expansion Plan (RTEP) base cases, but they are included in generation deliverability studies.

In presenting the second read of the proposal, Lead Engineer Julia Spatafore said including storage in the RTEP analysis would increase the resources available for transmission reliability, as well as better align regional planning with state policies and the determination of network upgrades for projects in the interconnection queue.

When modeling the system for the summer, the battery availability would be set at the lesser of its effective nameplate capacity (ENC) or the ENC multiplied by the resource’s duration, then dividing that value by 4 and multiplying the quotient by the fleet effective equivalent demand forced outage rate. The 4 in the equation represents the expected duration of summer events; for the winter, it would be replaced with an 8.

Director of Transmission Planning Sami Abdulsalam told RTO Insider that the reliability challenges presented by summer events tend to center around a single peak, while in the winter they tend to span the period between the morning and evening peaks.

He told the committee the change is a “kick start” to the RTO’s effort to use batteries for reliability.

Paul Sotkiewicz, president of E-Cubed Policy Associates, argued the change is too significant to proceed under the quick-fix process, which allows an issue charge, problem statement and proposed solution to be voted on together.

PJM intends to seek endorsement from the Markets and Reliability Committee at its meeting April 22. If approved, the changes would be implemented immediately.

Transmission Expansion Advisory Committee

Supplemental Projects

UGI Utilities presented a $94 million project to serve a 200-MW customer seeking to come online adjacent to the Hunlock Creek substation in Pennsylvania in 2027.

The customer would initially interconnect with 100 MW to be served by upgrades to the 66-kV bus at the Mountain substation. The second half of the load would come online in 2029 following the construction of a 230/66-kV substation named Newport, which would cut into the 230-kV Susquehanna-T10 line and connect to a switching station to serve the customer with two 66-kV lines. The project is in the engineering phase with a projected in-service date of Sept. 30, 2029.

UGI canceled a $33 million project to serve a 384-MW customer near Nanticoke, Pa., because the customer canceled the project. The upgrades would have included constructing a 230-kV substation, which would have cut into two 230-kV lines between Mountain and Susquehanna.

PPL presented four new service requests to serve large loads in Pennsylvania, each exceeding 1 GW. The requests seek to:

    • bring a 200-MW load to Washingtonville in 2028 and ramp to 1,500 MW by 2032;
    • site a 100-MW load in Archbald in 2028 and ramp to 1,200 MW by 2033;
    • construct a 75-MW load in Berwick in 2028 and grow to 1,500 MW by 2033; and
    • develop a 60-MW load in Nescopeck in 2028 and ramp to 1,350 MW by 2032.

PPL’s Robin Lafayette said direct connection costs, such as new substation equipment and lines to serve the new load, are currently fully allocated to the customer, while the costs of upgrades to existing facilities are assigned to the transmission zone in which the load is located.

Dominion Energy presented a $115 million project to address a 300-MW load drop violation identified in a 2029 do-no-harm analysis. The project would tear down and rebuild the 19-mile, 230-kV lines between the Gordonsville, Louisa CT, South Anna, Desper and Foxbrook Lane substations in Virginia. A parallel line would be constructed connecting Gordonsville directly to the Wesbey Drive substation, bypassing the other substations. The project is in the planning phase with a projected in-service date of March 1, 2029.

The utility also presented a $26 million project to serve a 300-MW customer in Ashland, Va. A 230-kV substation would be installed on the 230-kV Four Rivers-Hanover line, with about a half-mile of new line required.

Exelon presented a pair of $44 million projects to rebuild two 230-kV lines between the Plymouth Meeting and Whitpain substations in the PECO zone. The conductor on the 5.12-mile lines is about 65 years old, and the tower bolts and paint coatings are 95. The projects are in the engineering phase with one expected to be complete in July 2029 and the other in December 2029.

An additional $54 million project in the PECO zone would replace the 98-year-old Buxmont-Whitpain line. It’s in the engineering phase with a projected in-service date of Dec. 31, 2028.

The utility also presented a need to address limited operational flexibility around transmission outages because of a single 500/230-kV transformer bank being in place at the Limerick substation.

Finally, Exelon presented a $41.5 million project to serve a new service request in the ComEd zone. The customer is expected to bring about 30 MW to the Minooka, Ill., area in June 2028, which could grow to 588 MW by 2036. The project would construct a 345-kV substation, named Wildy Road, with two 345-kV lines to the Kendall County E.C. facility. Five double-circuit lines would feed the customer. The project is in the conceptual phase with a projected in-service date of July 1, 2027.

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PJM Eyeing Tight Deadline to Eliminate De Minimis Exception, Rebill Decade of Tx Rates

PJM updated stakeholders on how it plans to act on a FERC order requiring it to rework how it determines transmission rates and recalculate rates going back to June 2015.

The March 6 order rejected a settlement between several transmission owners and PJM to resolve a complaint filed by Neptune Regional Transmission System and Long Island Power Authority (LIPA), which challenged the de minimis exception (EL15-18).

The decision instead requires the parties to revise PJM’s tariff to eliminate the exception and recalculate over a decade of rates within 90 days. The exception zeroes out the cost assignment for any zone responsible for less than 1% of the flow modeled on a transmission upgrade. The change is not applicable to costs allocated through the load-ratio share basis.

PJM Associate General Counsel Jessica Lynch said the RTO may request additional time to recalculate costs without the de minimis exception, as the order provides only 90 days to rerun over a decade of billing. The RTO is working to identify the baseline reliability projects affected by the order and what will be needed to recalculate their cost assignment.

To submit a commentary on this topic, email forum@rtoinsider.com.

Solution-based distribution factors (DFAX) are used to determine the full cost for projects less than $5 million and under 500 kV, while for higher-cost and higher-voltage projects, the calculation is split evenly between the load-ratio share basis and solution-based DFAX. Different methods are used if a project is needed to resolve stability violations.

The order denied a second prong of the Neptune/LIPA complaint, which argued PJM’s practice of netting counterflows, paired with the de minimis exception, distorts how the benefits of a project are accounted for when setting cost allocation. The commission also established a paper hearing to explore whether solution-based DFAX should be used when a project is needed to resolve short circuit violations.

Paul Sotkiewicz, president of E-Cubed Policy Associates, ask what implications the rebilling might have on credit and default risk for PJM members.

PJM General Counsel Chris O’Hara said staff does not have a sense of the scale of the rebilling and that it would be inappropriate to speculate on default risk at this time.

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PJM MIC Briefs: March 11, 2026

Constellation deferred on asking the Market Implementation Committee to vote on a quick-fix proposal to account for any downtime dual-fuel gas generators may require when switching fuels. The process allows for a problem statement, issue charge and solution to be considered concurrently.

Director of Wholesale Market Development Erik Heinle said the company is working to incorporate amendments offered by PJM to ensure the reliability value of dual-fuel units is not compromised if they switch to their alternative fuel when gas prices are high. Resources still would be required to be capable of operating for at least 16 hours on alternate fuels.

The proposal would revise the dual-fuel definition in PJM Manual 11: Energy & Ancillary Services Market Operations to reflect “limitations or restrictions resulting from fuel switching time modeling within PJM’s software platforms.” The current definition requires dual-fuel units offer schedules for both their primary and alternate fuels, while respecting limits stemming from “energy or environmental limitations imposed on the generating unit by applicable laws and regulations.”

While Heinle said PJM’s amendment can be included without significantly disrupting the company’s goal of having the changes implemented before the 2026/27 winter, Constellation is wary of expanding the scope to address other issues.

Manual Revisions Sought to Clarify VOM and Opportunity Costs

PJM presented revisions to Manual 15: Cost Development Guidelines drafted through the document’s biennial review that center on clarifying the variable operating and maintenance (VOM) adder and opportunity cost calculator. Endorsement will be sought at the April 8 MIC meeting.

Language would be added to specify that the format of operating costs can be changed only at the time of submission and once every calendar year thereafter.

The opportunity cost calculator section would be expanded to state that the dispatch will be between resources’ economic minimum and maximum parameters. A paragraph would be added to detail how the opportunity cost adder interacts with environmental and operational limits.

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PJM OC Briefs: March 12, 2026

Stakeholders Discuss SATA Proposals

PJM, Constellation and the Independent Market Monitor plan to bring competing proposals to define rules for operating battery storage as a transmission asset (SATA).

The PJM and Constellation packages would allow batteries to be brought as solutions to transmission violations, while differing on how they would be compensated. The Monitor plans to bring a proposal to explicitly prohibit storage from being defined as transmission.

The PJM proposal would define payment and cost allocation for SATA projects through the transmission enhancement credits language, with payments made through energy settlements according to injection and withdrawal. The RTO would establish when the storage can be charged or discharged and the owner would be required to maintain the state of charge and submit offer schedules. The voltage would be set by reliability studies conducted by planning staff.

Constellation underscored that SATA should be limited to being operated to resolve transmission violations and would compensate owners through cost-of-service mechanisms. The battery would be prohibited from entering the interconnection queue.

Monitor Joe Bowring said allowing SATA would be a step back toward regulated markets, arguing the logic used by SATA supporters for putting batteries in a transmission owner’s rate base also could justify rate-basing combustion turbines. He pushed back on comments that the proposals from PJM and Constellation would gate the batteries to being used as transmission, unlike other RTOs, by stating that PJM cannot be compared to regions where most of the generation are cost-of-service assets.

The Monitor had sought to bring a proposal that simply stated batteries cannot be transmission assets but was told that would not be a valid package. The Monitor will bring a proposal opposing the SATA treatment of batteries as part of a transmission owner’s rate base.

“It is a slippery slope towards reregulation which some transmission owners are already advocating for all types of generation,” he said in an email to RTO Insider. “Once batteries are in a rate base, there is nothing stopping the transmission owners from arguing they should be allowed to operate as market assets. In fact, some have already made that argument.”

Stakeholders responded that batteries could be used as a temporary transmission solution, as the units can be installed quickly and moved between sites in a way that generation cannot.

Bowring said there is nothing about the actual functionality of a battery requiring it to be a regulated transmission asset, rather than a market asset.

“SATA means putting batteries in a regulated transmission company’s rate base with a guaranteed capital recovery and rate of return. The issue is not whether a battery or a generator can contribute to resolving issues on the grid. The issue is whether PJM will continue to rely on markets. Batteries are market assets in PJM now, and more batteries are in the generation queue and scheduled to go into service soon,” Bowring said in an email. “SATA is not about how batteries are used. SATA is about who owns batteries and how they are paid.”

February Operating Report

PJM saw an average hourly forecast error rate of 1.76% and slightly lower 1.71% error rate for peak hours across February, according to PJM’s monthly operating report. Four days exceeded the RTO’s 3% peak forecast error benchmark: Warm temperatures pushed the peak load on Feb. 3 down by 3.21% and on Feb. 4 by 4.12%. Cold temperatures led to the Feb. 17 peak being 3.06% under-forecast and 3.38% below target for Feb. 20.

There were two spin events, three shared reserve events, one conservative operations alert, two cold weather alerts, 34 shortage cases and 20 post contingency local load relief warnings issued. A dozen shortage cases Feb. 9 were attributed to higher-than-expected temperatures pushing the morning peak higher than forecast, with a similar dynamic at play behind nine cases on the morning of Feb. 2 and six on the morning and evening of Feb. 6.

A spin event was initiated at 11:49 a.m. Feb. 3 and lasted 4 minutes, 24 seconds; 1,969 MW of generation was assigned, with a 32% response rate, and 292 MW of demand response (DR) assigned, 62% of which responded. The second spin event was at 2:06 a.m. Feb 23 and lasted 6 minutes, 52 seconds. It saw 2,305 MW of generation assigned, with a 61% response rate, and 452 MW of DR assigned and 32% responding.

Security Report

PJM Senior Director of Cybersecurity Jim Gluck said the Cybersecurity and Infrastructure Security Agency is recommending utilities review their infrastructure and remove devices that have software no longer being supported by the manufacturer. The request comes in the wake of a cyberattack that disrupted communications on the Polish electric system. The infiltration was possible due to vulnerabilities in software that no longer is being patched.

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SPP’s Consolidated Planning Process a ‘Bold Step,’ FERC Says

FERC conditionally approved SPP’s streamlined generator interconnection and long-term planning processes in what the commission said is a “bold step” in addressing the needs of the electric system.

The commission found in its March 13 order that SPP’s Consolidated Planning Process (CPP) complies with FERC Order 1000’s regional transmission planning and cost-allocation requirements and that its generator interconnection (GI) procedures satisfy the independent entity variation standard for deviations from Order 2003 (ER26-414).

However, it directed the grid operator to submit a compliance filing by April 14 addressing several errors outlined in a December 2025 deficiency letter. FERC also ordered SPP to clarify that some interconnection customers may be directly assigned network upgrade costs for upgrades with a nominal operating voltage of 100 kV or below.

The CPP will replace the grid operator’s separate interconnection requests and annual Integrated Transmission Plan (ITP) with an “innovative approach” to regional planning that forecasts overall needs and takes all grid requirements into account. SPP said it will provide more certainty to investors in planning their budgets, and a revamped funding structure to address the region’s historic load growth and challenges interconnecting generation and load in a timely manner.

“FERC’s approval of SPP’s CPP filing marks a defining moment, further demonstrating the value of a regional transmission organization,” Casey Cathey, SPP’s vice president of engineering, said in a statement. “The CPP unlocks the ability to plan and build the grid at a scale and speed the future demands. It’s a powerful step toward a more reliable, resilient and valuable system that can meet unprecedented load growth and connect the next generation of resources.”

Commissioner Judy Chang concurred with SPP’s “bold step” and encouraged other grid operators to “explore comparable reforms.” She said the RTO’s proposal addresses upgrade cost uncertainties, the “core issue that has been delaying the interconnection of new generation.”

“Facing rapid load growth and the need for new resources, we must meet this moment, and proposals like SPP’s put us on the path to do so,” Chang wrote.

‘At the Forefront’

Commissioner David Rosner issued a separate concurrence with the order, calling the CPP a “major step forward” in improving speed and efficiency in the GI and planning processes that “promises to deliver the electrons our country so badly needs.”

“Faced with electric demand growth at levels not seen in 25 years, SPP and its stakeholders have risen to the occasion with one of the most innovative, common-sense proposals presented to the commission since the inception of open-access transmission service,” he said. “This proposal will get transmission built smarter and connect new generation faster, helping to make energy more reliable and affordable in the SPP region.”

Rosner noted the CPP won unanimous support for both SPP’s member states and stakeholders. In an emailed statement to RTO Insider, the Sierra Club and Natural Resources Defense Council said the “historic level of consensus” reached during the stakeholder process sets a “high standard for future SPP policy initiatives.”

“Today’s decision places SPP at the forefront of ongoing efforts across the country to address over-burdened resource interconnection queues that have held back the clean energy transition our country so desperately needs for over a decade,” Sierra Club Senior Attorney Greg Wannier said. “CPP is a gamechanger and we encourage other grid operators across the country to take note as this process moves forward.”

“By breaking down siloed processes, CPP will cut years of wait time to get clean energy on to the power grid and ensure transmission planning drives optimal, long-term, high-value transmission projects,” Annie Minondo, a sustainable FERC Project advocate at NRDC, said.

Under the proposed CPP framework, SPP will conduct a long-term transmission assessment over a 20-year horizon, with a focus on both EHV (300-kV and above) and high voltage (above 100-kV and below 300-kV) facilities, and a 10-year assessment in the planning cycle’s first year. The grid operator will also conduct annual CPP-10 assessments in the second and third years of each planning cycle.

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Mass. Gov. Healey Issues Order to Procure 10 GW of Power by 2035

Amid uncertainty about how New England will meet rising demand in the coming decades, Massachusetts Gov. Maura Healey (D) issued an executive order to procure 10 GW of new power and 5 GW of energy storage by 2035.

In the announcement of the order on March 16, the administration claimed the procurement would save customers $10 billion and bashed President Donald Trump’s “costly war and his failed energy policies.”

While the state has set ambitious clean energy targets and invested heavily in its offshore wind supply chain and infrastructure, the Trump administration’s attacks on offshore wind have left the industry in a precarious position with an unclear long-term outlook.

In the days leading up to the order, Revolution Wind announced first power and Vineyard Wind 1 installed the final turbine on its long-delayed project. (See Vineyard Completes Construction, Revolution Starts Generation.) But the next wave of large projects has been sidetracked for the foreseeable future and policymakers have been forced to look elsewhere for sources of power to meet growing demand.

Possibilities for this next wave of supply could include onshore wind in northern Maine, offshore wind in Nova Scotia, and advanced nuclear. While pipeline constraints limit the region’s ability to add large amounts of gas-fired generation, gas plants could look to add dual-fuel capabilities enabling them to burn oil in the winter when pipelines are constrained.

“I believe in an all-of-the-above approach to energy — that means solar, wind, gas, nuclear and hydro,” Healey said in a statement. “While the president is taking American-built energy sources off the table, in Massachusetts, we are saying yes to more supply from more sources of energy.”

The executive order stipulates that 4 GW of the procurement should be solar power and 3.5 GW should be demand management. The final 2.5 GW could include New England-based generation and imports to the region.

The executive action includes a list of high-level directives to state agencies aimed at promoting clean energy technologies including solar, wind, geothermal, nuclear and demand response.

It explicitly references the expiring Inflation Reduction Act tax credits for wind and solar and the need to move quickly to meet the deadlines. Projects must begin construction by July 4, 2026, or come online by the end of 2027 to receive the federal incentives.

The order also directs the Department of Public Utilities (DPU) to review the state’s natural gas and oil storage and delivery capabilities, and “identify whether additional, strategically located storage capacity or delivery capabilities could provide reliability and affordability benefits to all ratepayers and align with existing regulations.”

However, it does not call for the expansion of fossil fuel systems — such as pipeline infrastructure — into the state.

The wide-ranging order:

    • Directs the Executive Office of Energy and Environmental Affairs to “review and expedite” existing initiatives to promote the development of renewables and storage; address barriers to interconnection; and expedite regulatory proceedings affecting solar development.
    • Directs the Department of Energy Resources to conduct a review of existing demand management programs.
    • Promotes efforts to develop next-generation nuclear resources and directs the EEA to accelerate efforts to support existing nuclear resources:
    • Directs the EEA to “accelerate deployment of geothermal and other non-fossil thermal energy systems” by reducing administrative and regulatory barriers, increasing worker training and collaborating with companies and unions to address supply chain constraints.
    • Requires utilities to submit plans to manage increased interconnection requests as developers push projects to meet federal tax credits deadlines.
    • Directs utilities to establish flexible interconnection programs.
    • Directs the DPU to “expedite the review of proposals that can unlock the benefits of time-of-use electricity rates, distributed energy resources, energy efficiency, and virtual power plants.”

Reactions

While right wing groups in the state have frequently derided the Healey administration for favoritism toward renewable resources, the administration has tended to emphasize stakeholder consensus when developing energy policy. The announcement of the order included testimonials from a range of business, clean energy, labor and environmental organizations.

“Action like this is exactly what the Commonwealth needs to ensure we remain a place where everyone can afford to live,” said Brooke Thomson, CEO of the Associated Industries of Massachusetts.

“Setting clear targets to bring 10 gigawatts of new energy online, along with major new investments in storage, will help strengthen reliability and ensure the region has the power it needs to meet growing demand,” said Valessa Souter-Kline of Advanced Energy United.

“Massachusetts needs more reliable energy and more union jobs — and we need them quickly,” said Chrissy Lynch, president of the Massachusetts AFL-CIO. “Working families shouldn’t have to purchase energy from billionaire oil tycoons and foreign governments.”

“We applaud Gov. Healey’s focus on lowering energy costs and her long-held principle that customers shouldn’t be forced to subsidize costly and polluting fossil fuel infrastructure,” said Caitlin Peale Sloan of the Conservation Law Foundation.

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Vineyard Completes Construction, Revolution Starts Generation

One New England offshore wind farm has completed construction, and another has begun sending electricity ashore as it finishes construction.

With a combined nameplate capacity of 1,510 MW, Vineyard Wind and Revolution Wind are expected to provide an important boost to the ISO-NE grid.

But both projects have faced delays and interference reaching their respective milestones, including two federal stop-work orders each — one from equipment problems, and three as part of the Trump administration’s ongoing campaign against offshore wind development. Whether the administration might take steps against completed wind farms remains to be seen.

Vineyard announced installation of the final turbine blades the evening of March 13, marking the completion of offshore construction.

Also on March 13, Revolution announced it had begun delivering electricity. Coincidentally, that date was the deadline for the Trump administration to appeal a federal judge’s Jan. 12 stay of a Bureau of Ocean Energy Management stop-work order against Revolution. BOEM did not appeal.

Vineyard put its first steel in the water in June 2023 and exported its first electricity to Massachusetts in January 2024. But the 806-MW project took a sharp turn for the worse later that year when a blade disintegrated, showering debris into the oceans and then onto beaches. An investigation revealed manufacturing flaws; work was slowed or halted while replacement blades were installed.

The 65-turbine, 704-MW Revolution Wind began construction in 2023 but ran into cascading delays even before President Donald Trump returned to office. Then late in 2025, as the project was nearing completion, BOEM shut it down along with the four other projects under active construction in U.S. waters.

One by one, judges lifted all of those stop-work orders. (See With Sunrise Wind Ruling, OSW Industry now 5-0 Against Trump Admin.)

Now that electrons have begun flowing to Connecticut and Rhode Island, Revolution will be scaling up generation in the days and weeks to come, an Ørsted spokesperson said March 16.

An ISO-NE spokesperson said March 16 that Revolution is one more asset for a region that needs new power resources: “Last week, Revolution Wind delivered power to New England’s regional grid, as part of the commissioning and testing process. Through the wholesale markets administered by the ISO, Revolution Wind has committed to helping meet New England’s demand for electricity, which is forecasted to grow approximately 11% over the next decade.”

Vineyard and Revolution would not say how much electricity they are sending ashore, and ISO-NE said it could not, citing confidentiality rules. An industry advocate previously said Vineyard sent as much as 600 MW to the strained New England grid during a major winter storm in January.

As of 5 p.m. March 16, the RTO’s ISO Express dashboard indicated wind turbines were producing a total of 1,066 MW, or 66% of the renewable resource mix. System load was 14,473 MW.

Natural gas (6,735 MW) and nuclear (3,358 MW) accounted for the bulk of resources. Net imports (1,623 MW) were a bit ahead of wind power, and hydro (982 MW) was a bit behind.

In 2025, wind provided 4,618 GWh of electricity to the ISO-NE grid, which was 4.1% of generation and 3.9% of net energy for load. Solar was slightly higher: 4,836 GWh, 4.3% and 4.1%, respectively.

U.S. Sen. Sheldon Whitehouse (D-R.I.) was among those cheering the news about Revolution powering up.

“When Rhode Island families pay their utility bills, they will be grateful to Ørsted and the resilient union workers who got this project over the finish line,” said Whitehouse, who brought a union apprentice electrician helping build Revolution to Trump’s 2026 State of the Union Address. “Power from Revolution Wind will make our grid more reliable in the winter and reduce Rhode Islanders’ energy costs for years to come.”

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APS to Seek Palo Verde Extension through 2067

Arizona Public Service has notified the U.S. Nuclear Regulatory Commission that it plans to seek operating license renewals for all three units at Palo Verde Generating Station, potentially extending operations through the mid-2060s.

APS filed a notice of intent with the NRC on March 13, saying it will submit a Subsequent License Renewal application in late 2027. The renewal would allow Palo Verde units 1, 2 and 3 to run through 2065, 2066 and 2067 respectively.

NRC approval would extend the units’ life to a total of 80 years. APS noted that the NRC so far has renewed licenses for 80 years of operation to 10 nuclear plants across the U.S.

The three Palo Verde units, with a combined capacity of 4.2 GW, are a key piece of APS’s long-term energy strategy and central to Arizona’s grid reliability, the company said in a release.

To submit a commentary on this topic, email forum@rtoinsider.com.

“Our notice to the NRC is another step in ensuring Arizonans and the region continue to benefit from this critical resource for many more years to come.” APS CEO Ted Geisler said in a statement.

Units 1, 2 and 3 received their initial 40-year operating licenses from the NRC in 1985, 1986 and 1987, respectively. In 2011, the NRC approved APS’ request to extend the operating licenses for 20 years, through the mid-2040s.

Palo Verde is operated by APS and supplies electricity to Arizona, Texas, New Mexico and Southern California. It is owned by seven utilities: APS, El Paso Electric, Los Angeles Department of Water and Power, Public Service Company of New Mexico, Salt River Project, Southern California Edison and Southern California Public Power Authority.

Through its “subsequent license renewal” (SLR) process, the NRC conducts safety and environmental reviews for extending nuclear power plant operations for up to 80 years of operation. Public meetings are part of the process.

In addition to approved applications, the NRC is reviewing three SLR applications. Those include units 1 and 2 of Florida Power & Light’s St. Lucie plant; Unit 2 of Duke Energy’s H.B. Robinson power plant in South Carolina; and units 1 and 2 of the Edwin I. Hatch nuclear plant in Georgia. NRC also has a pipeline of notices of intent to file SLR applications.

Among the 10 nuclear plants that have been approved for 80 years of operation are Florida Power & Light’s Turkey Point units 3 and 4. The approval, received in 2024, allows the units to run through 2052 and 2053.

Units 2 and 3 of Peach Bottom Atomic Power Station, co-owned and operated by Constellation Energy Generation in York County, Pennsylvania, received approval to operate through 2033 and 2034.

Arizona’s Nuclear Future

Besides seeking license extensions for Palo Verde, APS has teamed up with two other Arizona utilities — Salt River Project and Tucson Electric Power — to explore additional nuclear generation in the state. In 2025, they applied for a U.S. Department of Energy grant to evaluate potential nuclear sites. (See Arizona Electric Utilities Team Up to Pursue Nuclear.)

The funding is available through the Generation III+ Small Modular Reactor program in the DOE’s Office of Clean Energy Demonstrations. The utilities are applying for funding in the “fast follower” category, which will provide up to $100 million to address hurdles the U.S. nuclear industry has faced in areas such as design, licensing, supply chain and site preparation. Awardees must match the DOE funding.

Tier 1 award recipients were announced in November 2025. (See DOE Awards Holtec, TVA $800M to Build Pioneering SMRs.)

Tier 2 applicants, including APS, are still waiting to hear if they’ll receive funding. But initial project planning has begun, including the hiring of a project manager, APS Senior Director Brad Berles told the Arizona Corporation Commission during a February workshop on nuclear power.

APS continues to evaluate nuclear technologies and hasn’t yet settled on a specific option.

“We know there’s a large demand growth that we need to meet,” Berles said.

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EV Capacity More Than Battery Storage in California, CEC Finds

California’s historic battery storage boom over the past five years has not kept up with the state’s electric vehicle capacity growth — and now officials want to send idle EV electrons back to buildings, homes and the grid through new bidirectional chargers.

At the end of 2025, EV capacity in California reached 18.5 GW, which is more than a third of the historical peak load recorded in CAISO, Vincent Weyl, CEC principal of fuels and transportation, said at a March 12 CEC voting meeting. That figure also exceeds the state’s total stationary storage capacity of about 17 GW, including behind-the-meter storage and utility-scale storage, Weyl said.

“The opportunity and potential of bidirectional [charging] is massive and presents benefits to EV owners, grid operators and ratepayers,” Weyl said. “Of course, this resource can only be accessed when the vehicle is not driving and when the vehicle is located where bidirectional charging is possible.”

EVs could serve about 10% of California’s total residential load, he added.

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The CEC has funded 200 bidirectional charging stations to date and is developing a program that could fund up to 18,000 new bidirectional chargers, Weyl said.

The CEC’s bidirectional charging research project is the first time a state agency has assessed the benefits of bidirectional charging for the grid, the driver and electricity consumers, CEC Commissioner Nancy Skinner said at the meeting. But much more work needs to happen for these chargers to proliferate, she said.

Many changes to rate structures and how equipment connects to the grid are needed to “compensate someone for using their EV to send power to the grid,” Skinner said.

More than half the EVs studied could participate at least weekly in a discharge event during peak hours, CEC staff found in their research. This charging frequency would reduce EV owners’ electricity bills an average of $260 to $320 from June to September.

“It is incredible how much power we have roaming around on our streets,” Commissioner Andrew McAllister said at the meeting. “If we can take advantage of even a small percentage of that at the margin, that is going to make a huge difference in our reliability profile.”

But the concept of connecting EVs to the grid has been around for more than 10 years at California’s energy agencies. In 2014, CAISO published a vehicle-to-grid road map report with support from the CEC and the California Public Utilities Commission. More recently, in February 2026, the CPUC in a resolution asked Pacific Gas and Electric to demonstrate how bidirectional EVs and electric vehicle supply equipment can provide community resiliency benefits during grid outages.

At the voting meeting, the CEC also approved Riverside Public Utilities’ (RPU) integrated resource plan. The city of Riverside plans to procure its electricity from only zero-carbon sources by 2040 and retire its gas-fired plants by the same year. Currently, about 30% of RPU’s electricity is generated by geothermal resources.

RPU’s annual demand is expected to increase from about 2,300 GWh in 2025 to more than 3,250 GWh in 2045.