Plans to transition California’s largest public ferry fleet to zero-emission vessels got a boost from a $5 million grant for charging infrastructure from the California Energy Commission.
The CEC awarded the funds Aug. 14 to the Water Emergency Transportation Authority (WETA), the agency that runs San Francisco Bay Ferry service. The funds will be used to install a “charging float” consisting of a dock, charger and battery storage.
The money was part of $87 million in grant funding the CEC voted to approve during the meeting. Much of the funding went to infrastructure projects for medium- and heavy-duty zero emission vehicles.
State’s Largest Public Fleet
With 15 vessels carrying about 3 million passengers a year across several routes, San Francisco Bay Ferry is California’s largest public ferry fleet.
The fleet runs on diesel, but WETA is planning a transition to zero-emission vessels through its Rapid Electric Emission-Free (REEF) program. The agency has set a goal of shifting half its fleet to zero emission by 2035.
Last month, the ferry service launched the MV Sea Change, a 75-passenger vessel described as the world’s first commercial passenger ferry powered completely by zero-emission hydrogen fuel cells. The California Air Resources Board funded the vessel’s development.
Owned by SWITCH Maritime, the hydrogen-powered ferry will run for a six-month demonstration period. Sponsors of the demonstration service include Chevron New Energies, United Airlines and the Golden Gate Bridge, Highway and Transportation District.
In November, the Federal Transit Administration awarded a $16 million grant to WETA for the electrification of four ferry floats. The project involves structural alterations to the passenger floats, installation of battery banks and vessel charging equipment, and grid connections.
WETA now plans to buy an electric ferry with funding from the Bay Area Toll Authority and the regional Metropolitan Transportation Commission.
Elsewhere on the West Coast, Washington State Ferries announced last month that it is partnering with ABB, a marine technology company, on the design and construction of five new hybrid-electric, 160-auto-capacity ferries. WSF, the largest ferry system in the U.S., has set a goal of running a zero-emission fleet by 2050.
Under mandates from the state legislature and governor, WSF will transition to hybrid-electric power by 2040.
Implementing Blueprints
WETA previously received CEC funding to develop a plan called a blueprint for transitioning to a zero-emission ferry fleet. The agency was one of 34 entities that completed blueprints for infrastructure to support medium- and heavy-duty zero-emission vehicles.
“To be able to move swiftly to deploy infrastructure for zero-emission vehicles, you actually have to have a plan,” Commissioner Patty Monahan said before voting for the WETA funding. “And you have to think about where you want to site it, how it fits with the grid.”
In addition to WETA’s ferry-charging project, the CEC voted Aug. 14 to approve funding for two other projects that came from the blueprints.
The city of Long Beach received $5 million for DC fast chargers and a battery backup system for the city’s medium- and heavy-duty truck fleet. Another $5 million went to Pilot Travel Centers for two rapid hydrogen dispensers and a hydrogen storage tank at a truck stop off Interstate 5 in Southern California.
The CEC awarded grant funding to an array of other projects on Aug. 14. Those include:
International Transportation Service received $3 million for hands-free EV charging stations at the Port of Long Beach, including a dynamic charging rail that can charge up to five yard tractors while they’re in operation.
Penske Truck Leasing received $7.9 million for chargers at two locations for its growing medium- and heavy-duty EV rental fleet.
Skycharger LLC received $10 million for EV chargers at the Port of San Diego for overnight and opportunity truck charging, as well as a 1.7 MW solar-powered microgrid and 1 MW battery storage system.
A major multiday energy storage project in central Maine intended to ease congestion is moving forward thanks to $147 million in federal funding.
The 85-MW battery project will be located in the town of Lincoln, Maine, and has a projected in-service date of 2028, contingent on the timeline on interconnection, permitting and community engagement.
Form Energy, the project developer, has attracted significant attention for its iron-air battery technology that it says can discharge for up to 100 hours. The early-stage company has yet to bring any large-scale projects online but expects several to be operational in 2025. The Maine battery project is its largest proposal announced to date. (See Form Energy Wants to Bring Long-duration Storage to New England.)
The federal funding stems from a $389.3 million Department of Energy grant to the New England states for the Power Up New England project, which also includes a major investment in substations in southern New England to interconnect offshore wind projects. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)
The storage project is “intended to address grid resilience and reliability throughout ISO New England,” Form CEO Mateo Jaramillo told RTO Insider. He noted that the states were particularly drawn to the battery’s ability to reduce congestion and balance the output of wind power in northern Maine.
Jaramillo noted that wind patterns often vary over multiple days, creating a need for resources that can store excess energy and balance out intermittencies over extended periods.
“Having the type of storage resource that is well matched to that period of intermittency that comes from wind is why this battery in particular [is] well suited to address the congestion challenges that come from wind,” he said.
Congestion costs in New England are relatively low because of transmission investments made over the past two decades; ISO-NE’s External Market Monitor noted in its 2023 report that “congestion levels per MWh of load in the other RTOs were six to 11 times higher than in New England based.”
However, the RTO’s Internal Market Monitor has indicated that northern Maine is the part of the region where generation is most limited by transmission constraints, affecting the development of new renewable resources in the area. As electricity demand increases and renewables proliferate, transmission constraints likely will become a greater issue. ISO-NE estimates that transmission upgrades needed by 2050 could cost up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)
While this project is centered around onshore wind, offshore wind is likely to face significant transmission constraints as it scales up. ISO-NE’s 2050 Transmission Study found a high likelihood of overloads on north-south transmission lines during periods of high offshore wind generation, although the extent of overloads is dependent on where offshore wind projects interconnect. (See ISO-NE Analysis Shows Benefits of Shifting OSW Interconnection Points.)
Form has not announced other projects in New England, but Jaramillo said the company is working to bring other projects online in the region.
“I don’t at all expect this to be the only project in New England in the next few years,” Jaramillo said. “This is certainly on the larger side of what we expect, but there’s other clear opportunities that we’re pursuing on the same time horizon.”
While the project is supported by a mix of federal and private funding, Jaramillo said it is “still to be determined how much of the funds to cover the investment will come from the market.”
ISO-NE is in the middle of an extended effort to update how it values different resource types in its capacity market, aiming to better align capacity awards with reliability benefits. The RTO plans to implement the reforms for the 2028/29 capacity commitment period. (See ISO-NE Outlines ‘Straw Scope’ of Capacity Market Reforms.)
The new accreditation process likely will increase the financial incentives for longer-duration energy storage resources. Existing capacity market rules provide little incentive for storage resources to increase their duration beyond two hours. (See ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.)
“Form will be the owner of the asset, and so we’re very interested in making sure that the right market products are there in the ISO to compensate for the value that we bring,” Jaramillo said.
As the region’s winter risk increases, long-duration batteries would help boost winter grid reliability by balancing wind resources, which often perform better with lower temperatures, Jaramillo said.
“What we’re bringing is a new type of asset,” Jaramillo said. “An integrated system that has this type of asset in the end is a more reliable system.”
A new report finds that the percentage of renewable energy generation additions associated with renewables portfolio standards (RPS) has declined since this century began as development increased.
The 2024 edition of the report by the Lawrence Berkeley National Laboratory indicates most of the 29 states with an RPS have met their targets in recent years but most clean electricity standards (CES) targets are not yet in force.
“U.S. State Renewables Portfolio & Clean Electricity Standards: 2024 Status Update” also summarizes recent legislative revisions, key policy design features, compliance with interim targets, impacts on clean electricity development and compliance costs.
This chart shows regional progress toward goals set in renewables portfolio standards. | Lawrence Berkeley National Laboratory
The report’s accompanying spreadsheets drill down to more granular detail in individual states, including demand projections, nominal percentage targets and retail electricity sales projections.
The report offers a broad perspective on aspects of the clean energy transition and the role RPS and CES policies play in it.
Among the details:
Twenty-nine states and the District of Columbia have RPS policies; 16 of those have final targets of at least 50% retail sales, and four have a 100% RPS.
Sixteen states have a 100% CES; all but one of those also have an RPS.
While RPS-related capacity additions have increased over time, they have shrunk as a percentage of new renewable energy construction — 35% in 2023, compared with 60 to 70% per year 10 to 15 years earlier.
The authors acknowledge the difficulty of attributing growth of renewable energy to one factor, but they say RPS policies have been a key driver; nonhydro renewable generation increased by 648 TWh from 2000 through 2023, but RPS and CES policies required only 280 TWh of growth.
Aggregate RPS requirements rise from 450 TWh in 2024 to 930 TWh in 2050; CES requirements begin to ratchet up in 2030 and reach 770 TWh by 2050.
New interregional transmission could reduce resource needs for both RPS and CES; retirements of nuclear, large hydro and other existing assets would increase those resource needs.
A total of 35 GW of renewable capacity was added in 2023; the largest off-taker was load-serving entities, at 39%, but retail off-takers continue to grow, accounting for 29% of new capacity in 2023.
The voluntary market — targets adopted or imposed beyond RPS and CES — might absorb a larger portion of new generation than assumed in the report.
In 2023 and the first quarter of this year, 112 pieces of RPS- and CPS-related legislation were introduced, but only 13 were enacted into state law; 24 of the proposals would have weakened the standards, but none were signed into law.
This chart shows where new U.S. renewable energy generation capacity is going as it comes online. | Lawrence Berkeley National Laboratory
The report concludes that the future impacts of state RPS and CES programs will depend on multiple factors, including:
whether states decide to expand and broaden their programs;
the types of implementation and enforcement mechanisms established;
efficacy of federal policy in stimulating new clean electricity supplies and transmission;
efforts to address issues surrounding renewable energy integration, permitting and interconnection; and
the price trajectories of renewable energy construction and renewable energy certificates.
Members of the Southeast Energy Exchange Market (SEEM) told FERC in a filing that, contrary to what SEEM’s opponents claim, the market “is bringing savings to customers and should be allowed to continue” (ER21-1111, et al.).
Participants in the Aug. 13 filing included Southern Co., Dominion Energy, Duke Energy and Louisville Gas & Electric, all of which were among the founding utilities that first proposed SEEM in 2021. They aimed to answer questions commissioners posed in a June 14 filing seeking information on whether SEEM qualifies as a loose power pool under FERC Order 888 and whether the market’s requirements that entities transacting in it have a source and sink inside its footprint violate Order 888. (See FERC Requests Briefings on SEEM After DC Circuit Order.)
FERC ordered the briefing as a step toward satisfying last year’s order by the D.C. Circuit Court of Appeals that remanded the commission’s approval of the market — which occurred by default when the commission split 2-2 when the deadline for approval arrived. (See DC Circuit Sends SEEM Back to FERC.)
The court also found FERC failed to explain why SEEM should not be considered a loose power pool. Opponents argued the market’s nonfirm energy exchange transmission service (NFEETS) made SEEM a loose power pool, which under FERC’s rules must be open to nonmembers.
FERC provided a series of questions for SEEM members, including whether it is a loose power pool and, if so, whether and how it meets or exceeds Order 888’s open-access requirements for power pools and, if not, whether it is consistent with the pro forma open access transmission tariff (OATT). The commission also asked whether NFEETS should be considered a non-pancaked rate and whether entities with a source or sink outside of SEEM’s territory could conform with the technical requirements of the market’s matching platform.
In their response, SEEM members argued that SEEM does not quality as a loose power pool because “the commission has already found that NFEETS is neither a discount not a special rate” and that the D.C. Circuit did not find fault with FERC’s reasoning on that point.
Members claimed the court instead was concerned about a possible inconsistency because it read part of Order 888 to “equate a discount with a non-pancaked rate.” The filing countered this by claiming that NFEETS is pancaked because charges for losses and imbalances are cumulative across balancing authorities (BA). In addition, members asserted that NFEETS is “available to everyone, including SEEM members, on the same terms and conditions, and at the same price, under the [OATT] (or equivalent) of each member.”
The respondents confirmed that owning a source or sink connected to a SEEM transmission provider is necessary for SEEM to be technically feasible, explaining that SEEM was never intended to be a “fundamental, ground-up reconstruction of the market design in the Southeast,” quoting the initial SEEM filing.
However, they argued the requirement is not “unduly discriminatory to entities outside the SEEM territory” because there are other ways loads and resources outside the SEEM territory can participate in the market. Members held up pseudo-ties — which are used to represent interconnections between two BAs where no physical connection exists between the load or generation and the power system network — as one possible means of participation by outside entities.
Finally, members urged FERC to maintain SEEM as the best choice currently available for Southeastern ratepayers, claiming that despite their technical arguments, the market’s opponents have an overarching motive for their objections.
“At the outset of this litigation, petitioners made their real objective clear: They want a different kind of market for the Southeast,” members said. “But … every prior effort at increased coordination in the Southeast has failed. More importantly, SEEM benefits customers, and those customers should not become victims of petitioners’ ulterior objective. SEEM is the proposal on the table now and must be evaluated on its own merits. And it passes the test easily.”
The nation’s first-ever floating offshore wind research lease has been issued to Maine.
The U.S. Bureau of Ocean Energy Management announced the decision Aug. 19, paving the way for placement of up to 12 floating turbines with a combined rating of up to 144 MW.
Construction is not expected to start for several years. The state first must draw up a research activities plan, then BOEM must perform an environmental analysis on it.
Offshore wind turbines have been built for more than 30 years on foundations affixed to the seabed in shallow water but only now are turbines on floating towers beginning to be deployed in deeper waters, and the design of the towers and anchoring systems is a work in progress.
Maine aspires to be a leader in the floating wind sector. Much of the Gulf of Maine is too deep for fixed-bottom turbine foundations.
The University of Maine has been working for years to refine floating foundation designs.
For commercial purposes, BOEM sold five floating wind leases off the California coast in a December 2022 auction and plans to offer eight in the Gulf of Maine in an auction in late 2024. But the lease announced Aug. 19 was the first for the purpose of researching floating wind.
Maine has designated Pine Tree Offshore Wind LLC, an affiliate of New England Aqua Ventus LLC, as the operator for the research lease. Aqua Ventus began utility power purchase agreement negotiations before the Maine Public Utilities Commission (Case 2022-00100) in April 2022.
Maine Gov. Janet Mills (D) said in a prepared statement Aug. 19 that the research array, as proposed, will use floating platform technology development by the University of Maine and deployed by its development partner, Diamond Offshore Wind.
“This lease between the state and BOEM to support the nation’s first research array devoted to floating offshore wind technology is the result of extensive engagement with stakeholders and communities across our state to establish Maine as a leader in responsible offshore wind, in balance with our state’s marine economy and environment,” she said.
BOEM in its news release said the research project goes beyond Maine’s ambitions, allowing the wind energy industry, fishing community, wildlife experts, governments and others to evaluate floating wind as a renewable energy source in the Northeast, and to evaluate its impacts.
Maine first requested a research lease in October 2021, and the request went through revisions during the review process. The awarded lease area totals nearly 15,000 acres, about 28 nautical miles southeast of Portland.
The upper limits specified in the floating research lease — 12 turbines and 144 MW — potentially put the project on the scale of the first completed wind farm in U.S. waters: South Fork Wind, a fixed-bottom project whose 12 turbines are rated at 132 MW.
It’s been six weeks since Hurricane Beryl, a Category 1 storm, blasted through the heavily wooded Houston area, toppling trees into distribution lines and knocking out power to nearly 3 million residents.
Electricity has been restored after weeks of recovery efforts, but lawmakers and regulators still are trying to figure out how a puny Cat 1 storm could have caused the devastation that led to long-term outages.
Houston utility CenterPoint Energy has borne the brunt of the scrutiny. Entergy lost several hundred thousand of its own customers in its Texas footprint; however, it had better communications with its customers and an outage tracker that worked.
Texas Attorney General Ken Paxton (R) became just the latest to probe the beleaguered company when he launched an investigation on Aug. 12 over allegations of CenterPoint fraud, waste and “improper use of taxpayer-provided funds” following Beryl. He said any unlawful activity his office uncovers will be met “with the full force of the law.”
Texas Gov. Greg Abbott (R), who said in 2021 just four months after the disastrous winter storm that ERCOT’s grid “is better today than it’s ever been,” has taken a hands-on approach with CenterPoint. He ordered the utility to file a plan outlining its preparation and response practices for the next storm, threatening to cut rates if the response was insufficient. After meeting with CenterPoint executives at the July 31 deadline, he called the plan “inadequate” and said “more must be done [and] faster.”
Abbott also has directed the Public Utility Commission, whose members he appoints, to conduct a “rigorous” study to determine why severe weather events lead to “repeated … power failures” in the Houston area. The PUC brought first-year CEO Jason Wells and other CenterPoint executives in for one hearing and is receiving regular updates from the utility. It plans to report its findings to the legislature by Dec. 1 (56822).
Both of Texas’ legislative houses have joined in the fun and conducted public floggings of the utility’s executives, with most of the ire coming from Houston senators. Wells was asked by Sen. Paul Bettencourt (R) whether he would heed calls for his resignation during a special Senate committee’s July 29 hearing. Noting CenterPoint has laid out 40 actions to immediately begin regaining community trust, Wells said, “I think if I resign today, we lose momentum on the things that are going to have the best possible impact for the greater Houston region.”
Some lawmakers were shocked — shocked — to learn during the hearing that CenterPoint’s regulated business model allows it to recover storm-restoration, vegetation management, line maintenance and other costs in its rate cases, while earning a 9.4% return on capital investments. They called for more accountability from the utility, threatening it with clawing back profits, trimming rates, shrinking its service territory and implementing performance-based ratemaking.
“It’s a pretty amazing business model,” Sen. Lois Kolkhorst (R) told CenterPoint execs. “Most of us that run a business, we don’t get reimbursements for our expenses.”
However, it’s CenterPoint’s $800 million lease agreement for 15 large (32 MW) mobile generators and several smaller ones in 2021 that has attracted much of the politicians’ focus. The utility said the larger generators could support restoration efforts after power outages. However, they sat unused after Beryl, as they have since being leased. The large units are so heavy they need permits to be transported and take days to set up.
Senators derided the generators as “quasi-mobile.” Wells defended the lease agreement, which may have relied on personal relationships, saying the generators are necessary when there is another load shed event as occurred during the 2021 winter storm.
“I find it troubling that you’ve been using the rate of return on something that you’re not using,” said Sen. Charles Schwertner (R), the committee’s chair. “It doesn’t smell good at all.”
“That’s fraud!” Bettencourt charged, threatening to claw back rates related to the lease agreement.
As the senators piled on Wells, Jason Ryan, CenterPoint’s executive vice president of regulatory services and government affairs, took to social media to say the large generators are a necessary tool in the toolbox to avoid a repeat of Winter Storm Uri.
CenterPoint CEO Jason Wells gathers his thoughts during a pause in the Senate hearing after a technical glitch. | Texas Senate
“Like our own toolboxes at home, not every tool is used in every situation, and not every emergency generation asset in our fleet is likely to be used in any one event,” he wrote on X, formerly known as Twitter. Ryan’s account no longer exists.
Sen. Phil King (R), who wrote the legislation that cleared the way for regulated wires provider CenterPoint to acquire generation, apologized to the committee after Wells’ testimony.
“The intent was to simply allow there to be very mobile storm response generation,” he said. “It was never intended, at least by me, to allow it to be used for large generation of the nature we’ve talked about today. I feel like I’ve been taken advantage of, to be honest. We will fix that going forward.”
Following the hearing, Lt. Gov. Dan Patrick (R), who essentially runs the Senate, sent a letter to the PUC urging it to claw back the $800 million to ensure ratepayers do not pay for CenterPoint’s “mismanagement.” Schwertner promised lawmakers “will hold CenterPoint accountable for lining its pockets at the expense of its customers” in the coming months.
Apparently, renegotiating the generators’ contract is not an option. Ryan told the PUC during its Aug. 15 open meeting that CenterPoint can’t break the contract unless the vendor, Life Cycle Power, fails to meet its obligations. That left the commissioners incredulous.
“You entered into a contract you can’t terminate unless there’s vendor non-performance,” Commissioner Lori Cobos told Ryan. “It just seems like we’re in this circular place where you all are coming across like your hands are tied to this contract.”
Energy consultant Alison Silverstein, a former PUC and FERC adviser, said the easiest way for Texas regulators to punish CenterPoint would be to reopen the mobile generation case and assess whether CenterPoint provided “accurate or misleading” information about the generation assets and their intended purpose.
“This could be a pretty fast proceeding and could look like enough of a spanking to make customers and politicians happy,” Silverstein told RTO Insider.
She dispelled the notion that a new wires provider could be handed the franchise for the nation’s fourth-largest city.
“Outside of Florida, no utilities are doing a competent job dealing with hurricane-heavy service geographies,” Silverstein said.
Performance-based ratemaking could be one option, she said, by aligning all utility incentives (profits, cost recovery, executive compensation) with reliability, resilience and affordability. At the same time, Silverstein doubted the PUC would revise the state’s ratemaking rules on its own.
“This would be a long and boring process that won’t have the speed, bloodletting and circus elements or assured outcome that would make local and state politicians happy,” she said.
“I think we need a comprehensive look at how we fund utilities, how they prepare for storms,” PUC Chair Thomas Gleeson said during the Senate hearing.
The day after that hearing, CenterPoint held its quarterly earnings call with financial analysts and reported a 93.2% increase in earnings. It said it planned to ask the PUC to recover between $1.5 billion and $1.7 billion in Beryl storm costs.
“That dog won’t hunt,” Sen. Carol Alvarado (D) said on X.
Two days later, CenterPoint withdrew both its $2.3 billion resiliency plan filed in April (56548) and its rate-increase request to recover $6 billion of investments made since its last rate proceeding in 2019 and expand its return-on-equity (56211). The utility had been negotiating settlements in both dockets.
However, on Aug. 16, the state Office of Administrative Hearings rejected the rate case’s withdrawal. The court said the withdrawal would conflict with state law requiring investor-owned utilities in the ERCOT region to file a comprehensive rate review within 48 months of their most recent rate proceeding.
Since then, CenterPoint has continued to try to make amends. The utility rolled out its Greater Houston Resilience Initiative that tracks its progress in substituting composite poles for wood structures and its vegetation management program; unveiling a new cloud-based outage map to replace its locally hosted version that crashed during a derecho in May; fired its senior vice president of electric business; beefed up its social media presence, with more than a dozen posts on X on Aug. 17-18 alone; and held the first of 16 community open houses through September.
PUC staff is attending each of the open houses and will lead a public work session in Houston Oct. 5. The commission also created a web tool to gather feedback from Houston residents.
“What was good enough 15 years ago is not good enough anymore,” Gleeson told the Senate committee. “We have not held them to a standard that is sufficient. I think we need a comprehensive look at how we fund utilities and how they prepare for storms.”
The Maryland Office of People’s Counsel (OPC) has published a report on how a spike in capacity prices and generator deactivations will affect state ratepayers, finding monthly costs could increase by as much as 24% for some.
The largest share of the impact is due to the significant jump in Base Residual Auction clearing prices seen in the 2025/26 auction results released last month, which saw prices across the RTO reach $269.92/MW-day from $28.92/MW-day the year prior. The Baltimore Gas and Electric (BGE) region surged higher to $466.35/MW-day due to a lack of internal generation, and transmission constraints. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
At the same time, ratepayers are expected to cover the cost of a reliability-must-run (RMR) agreement to pay Talen Energy to keep its Brandon Shores and H.A. Wagner generators operational while transmission upgrades are built to accommodate the plants’ deactivations. Talen has requested $774 million in a pending FERC filing to keep the generators online (ER24-1787, ER24-1790). (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)
The cost of those transmission upgrades also likely will fall squarely on Maryland ratepayers: Of the $726 million in upgrades required before the Talen generators can retire, 81%, or $630 million, is estimated to be allocated to the state. (See FERC Approves PJM RTEP Projects over State Protests.)
In an announcement of the report, Maryland People’s Counsel David Lapp said the same resource deactivations are hitting Maryland ratepayers on multiple fronts, raising capacity costs and saddling them with high transmission upgrade and RMR costs while those plants are paid to remain idle, but not contributing capacity.
“Customers are facing massive rate increases from potential retirements of old and uneconomic fossil fuel power plants — potential retirements that were entirely foreseeable and that PJM should have planned for,” Lapp said. “Customers will bear the brunt of PJM’s planning failures and other dysfunctional market rules, while generation companies will walk away with record profits.”
Conducted by Synapse Energy Economics on behalf of the OPC, the analysis estimates that BGE rates could increase by 5% to cover the RMR costs and an additional 14% due to the higher capacity costs, which amounts to an additional $21 for the average residential customer. The capacity market impacts also will be felt in the APS, DPL-S and Pepco zones, which could see rates increase by 24, 2 and 11%, respectively.
Taking Brandon Shores and Wagner out of the capacity market had a significant impact on prices in the BGE zone, Synapse wrote, stating that in the years running up to the 2025/26 auction, about a third of the capacity consumed in the region was produced locally. Removing the two generators brought that figure down to about 10%. The report estimated that if Brandon Shores and Wagner had remained in the capacity market, the BGE zone would not have seen price separation from the rest of the RTO, which would have seen the clearing price halved to $163.46/MW-day.
“At that price, electric customers across the RTO would save over $5 billion in that delivery year. Further, comparing this counterfactual analysis to the actual results of the capacity market and Talen’s proposed RMR, we found that Talen’s revenues for the 2025-2026 delivery year are $360 million higher than what they would have been had Talen’s units participated in the capacity market,” the report said.
Lapp said a small number of deactivations are causing an outsized spike in rates.
“The fact that the retirement of such a relatively small amount of generation could cause capacity market price spikes that cost customers across PJM more than $5 billion shows … PJM’s market is stacked against the customers that pay the bills,” Lapp said.
Market Changes and Queue Backlog Contributing to Higher Prices
The report notes that several changes to the capacity market structure were implemented in the 2025/26 BRA, including using a marginal effective load carrying capability (ELCC) approach to accrediting resources and risk modeling that shifted the riskiest hours toward the winter. Those redesigns had the effect of shifting the variable resource rate (VRR) curve to the left, reducing available supply and likely increasing costs. Forecast peak loads also increased by over 3 GW in the 2025/26 delivery year, increasing demand. (See FERC Approves 1st PJM Proposal out of CIFP.)
The report also argues that PJM has left customers vulnerable to high prices by delaying capacity auctions while rule changes are implemented, compressing the auction schedule and leaving little time for generators to be planned to take advantage of high prices and to increase available supply. Under the current schedule, the 2026/27 BRA is scheduled to be conducted in December, 1.5 years before that delivery year begins. Paired with a backlogged interconnection queue, it says it’s unlikely any large generators will come online before Brandon Shores and Wagner are set to deactivate in 2028, potentially leaving high prices in place for years.
“Thus, the strong price signal sent by the high-capacity market prices in the BGE LDA (and the RTO as a whole) may not induce timely new generation into service within the LDA before the completion of the transmission lines that end the need for these RMRs (or to help alleviate prices seen across the region). Instead, the clogged queue could lock in a windfall for the existing generating units continuing to operate in the BGE LDA and across the PJM region generally,” the report says.
There are 13 projects pending in the interconnection queue that would be sited in the BGE zone, amounting to about 1.2 GW of capacity. Construction on those projects could begin in mid-2025, according to PJM’s queue timeline, to begin mitigating capacity prices in 2026/27. The amount of time needed for construction, though, could result in many units coming online after that auction. Historical completion rates also suggest a share of those projects will be canceled, the report says.
The report states there’s a great deal of uncertainty on the transmission side, stating that 3.5 years to complete the upgrades necessary to allow the Talen generators to retire without issue could prove to be too short. If more time is needed, the RMR agreement could be extended.
“If the transmission projects are not complete by the end of 2028, and/or the continued operation of the RMR units are required beyond December of that year, the RMR costs for electric customers would necessarily increase,” the report said.
Deputy People’s Counsel William Fields told RTO Insider he doubts there will be time for the price signal sent in the 2025/26 auction to lead to new resources coming online ahead of future auctions. The interaction of a backlogged interconnection queue and compressed auction schedule leaves ratepayers with the worst of both worlds: paying generators to remain online without them being in the capacity supply stack to offset auction prices.
“A price signal without an ability to respond to it doesn’t accomplish much other than customers paying more money,” he said.
He said concerns about the auction outcome were mounting ahead of the posting of the results, leading the OPC to commission the report. While the spike in prices will have a significant impact, he said transmission costs have been steadily making up an increasing share of consumers’ rates. Some of those new projects could lead to reduced congestion, but whether that will come to pass is not yet apparent.
Stakeholders Discussing Changes to RMR Rules
PJM stakeholders are considering changing several areas of how RMR agreements function, including the timeline generators must provide PJM ahead of their desired deactivation date, how the compensation rate is determined and possible alternatives to the RMR structure. The Deactivation Enhancement Senior Task Force met Aug. 19 to discuss proposals from the Independent Market Monitor and PJM that would seek to use actual incurred costs to be the basis of RMR compensation.
The OPC sought a wider scope for the task force, including education on transmission technologies, such as energy storage or grid-enhancing technologies (GETs), that can provide an alternative to traditional upgrades, comparable structures RTOs employ to keep resources online when they are needed for transmission reliability and cost-effective alternatives to RMRs. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.)
The office also has advocated for proposals that require RMR resources to participate in the capacity market, which both the Monitor and PJM have declined to include. In a May protest of Talen’s RMR filing, the OPC argued the agreement would not subject the generators to the same performance requirements resources participating in the capacity market are held to, raising the question of whether they would be capable of responding to a PJM deployment. (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)
The Planning Committee also is considering proposals on how revising capacity interconnection rights (CIRs) can be transferred from a deactivating generator to a new resource. One aim would be reducing the need for RMR agreements by creating an expedited process for planned resources that could resolve identified transmission violations. The five packages are slated to be voted on during the Sept. 10 PC meeting. That could, however, be delayed to October if the components are changed substantially. (See “Manual 14B Revisions Include Change to Light Load Model,” PJM PC/TEAC Briefs: Aug. 6, 2024.)
Kevin Pytel, NYISO director of product and project management, presented the ISO’s initial 2025 budget recommendations Aug. 13 to the Budget and Priorities Working Group.
If approved, the 2025 budget for projects would be about $42.1 million. More than half of that would be spent on labor and professional services to execute projects.
The projects selected for initial inclusion include:
capacity market structure review: a look at whether changes are needed to send accurate price signals in the capacity market.
engaging the demand side: a project that would let behind-the-meter solar supply energy to wholesale markets.
balancing intermittency: an attempt to maintain reliability with intermittent, zero-emissions power via potential market rule changes.
winter reliability capacity enhancements: a project intended to address the looming challenge of a winter peaking system to the ICAP market.
winter fuel constraint study: a look at how extreme winter weather could affect the fuel available to natural gas generators and how fuel constraints could change over the next decade.
“We’re really trying to maximize the value of the markets with this proposal and pay attention to stakeholder scores to ensure that we’re choosing projects that have stakeholder support,” Pytel said.
“We recognize that there are a lot of high-priority projects that were scored that were not selected in the initial recommendation,” Pytel said. “If there are projects that you feel should be in the recommendations, which projects would you like to see come out to accommodate those?”
Kevin Lang of Couch White drew attention to the operating reserves performance project that was cut. “There was one in particular that piqued our interest that isn’t about maximizing value; it’s about protecting people and making sure that we’re not giving certain market participants windfall profits that didn’t make your list,” Lang said.
The operating reserves performance project would ensure that energy suppliers’ stated operating reserves were accurate and that suppliers were compensated to reflect actual performance.
Pytel said all feedback would be shared with NYISO executives. He said NYISO’s CEO was available to speak with stakeholders who felt strongly about some particular project or other.
This is the second-to-last phase of developing the budget before NYISO proposes its initial 2025 budget in September. NYISO will take feedback and return to stakeholders with revisions Aug. 27. The 2025 budget is scheduled to be finalized by Nov. 19.
Pytel highlighted several high-priority projects that were not selected due to resource constraints. The hybrid aggregation model project, which would broaden the number of resources that could use on-site energy storage and share the same interconnection, was put on hold until 2026.
A project to develop an operating protocol to integrate Champlain Hudson Power Express (CHPE) also was removed from the proposed budget. CHPE is a high-voltage connection between Hydro-Quebec and NYISO that’s expected to come online in 2026.
Several continuing projects have been delayed until 2026, including the hybrid aggregation model project, which would allow for more generation and storage facilities to exist on the same site.
“The hybrid aggregation model, it’s disappointing to see this getting delayed a year,” said Chris Hall of the New York State Energy Research and Development Authority. “On top of that … it’s a little bit surprising that we’re taking continuing projects and pushing them back.”
Pytel said projects being pushed back weren’t being canceled, but deprioritized. He pointed to a data center project at NYISO headquarters that’s being slowed down to free up some money so NYISO can finish other projects.
Pytel said some of the projects were dropped because of newly discovered resource constraints. One project, storage as transmission, was found to be more resource-intensive than NYISO initially estimated. A stakeholder pointed out that NYISO was working to comply with FERC Order 1920, which calls for incorporating non-transmission solutions into the transmission planning process. The dropped project could be rolled into the compliance process. Pytel said he would need to discuss that more with NYISO staff.
FERC has accepted SPP’s revisions to its Western Energy Imbalance Service (WEIS) market’s tariff related to the residual supply index (RSI) and ensuring that affiliated market participants’ resources are evaluated together (ER24-2208).
In its Aug. 15 letter order, the commission found the revisions will help identify and address structural market power in the WEIS market by ensuring a market participant affiliate’s online resource capacity is evaluated in the RSI calculation. It said the proposed revisions modify the market’s existing definition of “affiliate” by incorporating FERC’s regulations and require market participants to affirmatively identify affiliates when they register in the WEIS market and on an ongoing basis.
SPP’s Market Monitoring Unit determined in 2020 that the WEIS market had a high level of structural market power when viewed through the RSI, or the ratio of residual supply to total market demand. The RTO said that under the calculation, affiliated market participants’ total capacity is not evaluated together and creates a situation in which an entity can split its fleet of resources into multiple market participant registrations to avoid any one of the market participants failing the RSI calculation.
The grid operator’s proposal addressed FERC’s concerns when it rejected SPP’s first attempt in December. The commission found that allowing the MMU to exclude affiliated capacity from the RSI calculation if the monitor determined there were sufficient safeguards and corporate controls was not just and reasonable. The MMU, which supported SPP’s revisions, now can exclude affiliated capacity from the RSI calculation.
The RTO still must make an informational filing notifying FERC of the revisions’ actual effective date no less than 30 days prior to their implementation.
SPP has administered the WEIS market on a contract basis since February 2021. It serves 12 participants.
Battery storage facilities and data centers added to existing generator locations have a lot in common, with both supply and demand on a single interconnection. Yet despite the similarities, PJM is refusing FERC Order 2023 requirements regarding flexibility on charging battery storage while offering data center co-location projects those same provisions.
Mike Jacobs
PJM treats storage interconnection requests as an unavoidable driver of peak demand, while Order 2023 provides the option to assume the opposite. The PJM framing of interconnection causes batteries to appear to exacerbate transmission problems from plant retirement and require additional transmission upgrades, rather than meeting the system need caused by retirement.
(PJM’s claims of unsolved problems with providing storage developers the ability to define operational limits are on Page 27 of Answer to Protests filed in July 2024.)
This is in direct opposition to the Order 2023 directive (starting at paragraph 1,448) that allows energy storage projects to define their interconnection operational limits on charging.
PJM claims that storage asset owner commitments, real-time monitoring equipment and system protection controls are all insufficient and incapable of limiting battery charging operations throughout its interconnection rulemaking comments and initial Order 2023 compliance filing.
Simultaneously, PJM developed guidelines and interconnection agreements for data centers co-located with generation, allowing those asset owner commitments, real-time monitoring equipment and system protection controls to limit data centers from creating transmission system demand.
In March, PJM published guidelines for co-located load with a new or existing generation facility. PJM includes data center loads as an example of a more sophisticated and flexible treatment of both a supply and a demand at a single point of interconnection. PJM now provides an interconnection agreement for such co-located facilities after study of their proposal.
Meanwhile, PJM simultaneously argues it cannot modify interconnection manuals’ treatment of energy storage facilities as inflexible loads. This accommodation of co-located load illustrates PJM’s ability to establish sensible requirements through interconnection agreements that could allow both data centers and energy storage assets to contribute to the economy without undue obstacles.
Neither the co-location guidelines nor the interconnection manuals have been filed at FERC, but the efforts by PJM to continue discriminating against storage interconnection were expressly rejected by FERC in Order 2023.
PJM’s effort seeking reconsideration of this practice also was rejected by FERC. A third attempt by PJM to avoid compliance with the provision that storage be able to request to be limited from charging on peak, which is recognized elsewhere in the U.S., is included in FERC’s current refusal to accept PJM’s compliance filing for Order 2023.
FERC has given PJM until late October to once again explain why its noncompliant load deliverability tests for storage interconnection requests, which also disqualify storage from surplus interconnection and CIR transfer opportunities, should be permitted.
PJM’s refusal to comply with Order 2023 is a disservice to the millions of people who rely on the interconnection process to address supply needs and provide just and reasonable rates.
FERC’s directive more accurately reflects a wholesale market where storage assets can arbitrage between charging in low-price, off-peak hours and selling only in peak periods. PJM’s disparate treatment of energy storage load is not based on science or engineering.
Just as they negotiated provisions for data centers, they must do the same for storage. The RTO’s next Order 2023 compliance filing is the time to make this change.
Mike Jacobs, of the Union of Concerned Scientists, advocates at PJM, FERC and state commissions for the reliable expansion of the grid for renewable resources.
