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November 5, 2024

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Environmental Groups Seek Rehearing of MISO Sloped Demand Curve

The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project are seeking a rehearing of MISO’s sloped demand curve in its capacity auction, arguing that it’s unreasonable for the RTO to require utilities to procure capacity beyond resource adequacy needs.   

FERC last month allowed MISO to replace the vertical demand curve it had been using since 2011 with downward-sloping demand curves. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.) 

The trio claimed in a July 29 filing that FERC’s June acceptance violates the Federal Power Act and Administrative Procedure Act by requiring load-serving entities that opt out of MISO’s voluntary capacity auction to buy more capacity than what MISO deems acceptable (ER23-2977).  

When it installs a sloped demand curve for the 2025/26 Planning Resource Auction, MISO will impose an “x% adder” on load-serving entities that decide not to participate in the capacity auction. The adder will require load-serving entities to secure more capacity than necessary to meet MISO’s planning reserve margins, which are derived from a one-day-in-10-years system reliability standard. The adder will be based on how much excess capacity is procured through the auction in previous years using the sloped demand curves.  

The Sierra Club, NRDC and the Sustainable FERC Project said use of the adder would impose “significant artificial costs” on ratepayers and distort market signals. 

“It is both arbitrary and improper to impose the excess reserve margins created by a market construct whose principal purpose is to vary reserve margins in order to mitigate extreme price fluctuations and better guide resource investment decisions back on entities who are not participating in that market,” the three argued.  

They said forcing load-serving entities to procure extra capacity undermines MISO’s “carefully measured” resource adequacy standard.  

They also said MISO put too much emphasis on using the adder to prevent non-participating load-serving entities from benefiting unfairly from potential excess capacity from other LSEs participating in the auction. Equally as important, the three argued, is the possibility that LSEs using the PRA benefit from opted-out LSEs’ obligation to meet their individual reserve margins in the years when the PRA clears below its reserve margins.  

“The adder is not about ensuring comparability but instead functions as a one-way ratchet to require excess procurement of capacity by utilities that opt out of the PRA,” they told FERC.  

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FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas

SPP’s Markets+ hit a snag July 31 after FERC issued a deficiency letter outlining 16 problems the RTO must address in the tariff it filed for the proposed Western day-ahead market in March (ER24-1658).

How significant a snag remains an open question.

The commission’s letter stipulates that SPP has 60 days to respond. Sources involved in Western market developments, but not authorized to speak for attribution, shared mixed views with RTO Insider about SPP’s ability to adequately resolve the issues on that timeline, particularly if it must consult with stakeholders on any of them.

They also wondered whether the development would shift decision timelines for entities leaning in favor of joining Markets+. They acknowledged uncertainty about the gravity of the deficiencies, but one source pointed to the seeming “structural” nature of some of FERC’s concerns.

For its part, SPP played down the significance in a statement released shortly after FERC released the letter.

“The limited scope of the commission’s requests for additional clarity indicates its broad understanding and acceptance of the Markets+ design as proposed, with a need for more detail on some specific, nuanced market characteristics,” SPP said. “The additional work necessary to respond to the commission’s questions will not negatively impact the Markets+ timeline.”

“The Markets+ development timeline has always had flexibility,” Antoine Lucas, SPP vice president of markets, said in the statement. “We allowed ourselves time expecting an extended review at FERC, and we’re prepared to spend the time necessary to assure the commission we’ve accounted for every possible contingency in the market’s operation.”

The deficiencies outlined in the commission’s letter deal with multiple subjects in the market’s rules, including treatment of transmission, integration with the Western Power Pool’s Western Resource Adequacy Program (WRAP), self-schedules, greenhouse gas pricing provisions and offers from hydroelectric resources.

Under the transmission category, the commission asked SPP to clarify provisions around when capacity is considered unavailable for use in Markets+ and explain the process and timeline for communicating unavailability to market participants.

The commission also sought clarity on how “SPP expects that transmission capacity that is opted out [of the market] but that is not otherwise scheduled will be made available for use” — and on the workings of the opt-out process.

Another deficiency relates to the tariff’s “Markets+ transmission contributors” provision, which allows participants to contribute their transmission rights to a system operated by a transmission service provider not participating in the market, a rule that prompted a protest from PacifiCorp. (See SPP Markets+ Tariff Sparks Concerns for PacifiCorp, NV Energy.)

The commission asked SPP to explain “whether SPP or the Markets+ transmission contributor will be responsible for coordinating transmission schedule changes, curtailments and other operational concerns with the nonparticipating transmission service provider and how this information will be shared, as necessary” and “whether and how ancillary service needs for contributed transmission capacity will be communicated to the Markets+ transmission contributor’s nonparticipating balancing authority.”

It also asked whether Markets+ or the transmission contributor would be responsible “for potential costs associated with usage of the nonparticipating transmission system, including redispatch costs incurred because of schedule changes.”

Regarding the day-ahead market’s integration with WRAP, FERC asked SPP to cite the tariff provisions describing “how Markets+ would ensure that WRAP-related exports, imports or wheel-through transactions’ firm transmission priorities would be treated and/or retained in the Markets+ framework, and how ‘high priority within the market clearing processes’ would ensure preservation of a WRAP-related transaction’s associated transmission priority.”

‘Full Confidence’

The deficiency letter additionally seeks clarity on rules related to the treatment of hydroelectric resources, provisions important to Canada-based Powerex and federal power agency Bonneville Power Administration — whose staff in March recommended the agency choose Markets+ over CAISO’s Extended Day-Ahead Market. (See BPA Staff Recommends Markets+ over EDAM.)

FERC’s concerns centered around the calculation of the seasonal hydroelectric offer curve (SHOC), which is designed to estimate the opportunity costs for hydroelectric resources so those costs can be factored into their market offers.

FERC’s deficiency letter comes a week after all four U.S. senators from Oregon and Washington sent a letter to BPA Administrator John Hairston urging the agency to delay its decision on joining a day-ahead market until more developments play out around Markets+ and EDAM. (See NW Senators Urge BPA to Delay Day-ahead Market Decision.)

“The SPP Markets+ tariff was filed at FERC in April and is still under review,” the senators wrote. “FERC has a new slate of commissioners, and it remains unclear whether the tariff, as submitted, will be approved or found deficient. Indeed, deficiency letters for novel filings are common and require additional time and effort to resolve.”

“The innovative and complex market structure of Markets+ is proposed under a standalone tariff,” SPP’s Lucas said in the RTO’s statement. “We’ve always anticipated that a deficiency letter from FERC was a possibility given the intricacies of the market structure. We have full confidence we can quickly and effectively address FERC’s request.”

CAISO’s EDAM tariff won relatively clean approval from FERC last December, with the commission only rejecting a “separable” and temporary measure designed to ensure interim compensation for transmission providers that suffer financial losses during their transition into the new market. The commission approved the ISO’s revised version of that measure in June. (See FERC Approves EDAM Tx Revenue Recovery Plan.)

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NERC Planning Task Force on EV Grid Impacts

NERC’s Reliability and Security Technical Committee (RSTC) hopes to approve the formation of a task force examining the impact of electric vehicles on grid reliability by the end of this week, ERO staff said. 

Speaking to the System Planning Impacts of Distributed Energy Resources (SPIDER) Working Group on July 31, JP Skeath, NERC senior engineer for bulk power system security and grid transformation, said the RSTC is holding an electronic vote to allow the task force to begin work before the committee’s next formal meeting, which is not scheduled until September. 

Skeath said RSTC Secretary Stephen Crutchfield told him that day the online vote, which ends on Aug. 2, had yet to reach a quorum. However, he said the 17 votes in favor received so far made staff “assume the vote is going to be” successful. If so, Skeath continued, the committee will start forming the task force right away, with recruitment targeting EV manufacturers among other stakeholders. 

The EV task force would report directly to the RSTC rather than to any of its subcommittees or working groups, Skeath said. However, he added that “part of the expected scope is to be able to characterize specific types of risks and potentially reassign future work … a year or so” after work begins. The task force may tap specific groups to study further mitigation of the risks identified. 

ERO stakeholders have become increasingly concerned about the impact of EVs on the grid, with their rate of adoption in North America rising significantly over the past several years. According to data collected by the California Energy Commission last year — which Skeath shared in his presentation — cumulative national EV sales since 2010 reached more than 3.25 million in the last quarter of 2022, with nearly 250,000 of those sales occurring in just that quarter. 

“We’re starting to see the exponential [growth] part … of that type of adoption curve,” Skeath said. “The cumulative and instant sales are just growing in the last few years, where EVs are starting to become a … larger market share in … light-duty vehicles.” 

The growing EV deployment also has led to expanding loads for grid planners to deal with, he continued. In a 2022 analysis, National Grid examined current EV charging sites, including locations like parking garages with one or two chargers, mixed-use retail sites and large locations like truck stops.  

While most of the sites analyzed accounted for less than 5 MW of load in 2022, National Grid projected that by 2045, a smaller site could require 10 MW to 20 MW — between an outdoor stadium and a small town — while the largest locations could exceed 40 MW, the same as a large industrial plant. 

“That started the idea of [asking] what type of load will be friendly to the rest of the grid, and what type of load will be unfriendly to the rest of the grid?” Skeath said. 

The ERO has contributed to several previous studies on EVs’ grid reliability impacts. In April 2023, NERC, WECC and the California Mobility Center released a report identifying “grid-friendly” and “grid-unfriendly” behavior — meaning, respectively, electric applications that support stable operation of the grid, and those that aim to maintain a constant current or power level despite the effect it might have on a weakened system. (See NERC, WECC Outline EV Charging Reliability Impacts.) 

NERC built on 2023’s study with a 2024 white paper recommending EV and charger manufacturers improve their collaboration with electric utilities and that transmission planners incorporate charger performance into their planning criteria. (See NERC Addresses Growing EV Risks in White Paper.) 

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FERC Approves CAISO Request to Lift Soft Offer Cap for Hydro, Storage

FERC on July 31 accepted CAISO’s proposal to allow for storage resources to bid above the ISO’s $1,000/MWh soft offer cap in the real-time market to account for their intraday opportunity costs (ER24-2168).

The approved tariff revisions also remove the requirement that scheduling coordinators submit reference level adjustment requests (RLCR) to raise their default energy bids (DEBs) above $1,000/MWh when their DEBs would, by their own calculations, rise above $1,000/MWh.

The proposal is the result of work by CAISO’s Price Formation Enhancements Working Group and the Storage Bid Cost Recovery and Default Energy Bids initiative. It revises the process under FERC Order 831 by which the ISO verifies a unit’s cost-based offers in the energy market. (See CAISO Moves for Expedited Change to Soft Offer Cap.)

Issued in 2016, Order 831 set a “soft” cap on energy bids of $1,000 that could be exceeded, up to a “hard” cap of $2,000, to reflect a resource’s verifiable costs. Each grid operator was required to propose a process for verifying offers over the soft cap.

CAISO, however, found that the new paradigm, approved in 2020, inhibited storage and hydroelectric resources, two types vital to maintaining adequate supply during the summer.

“For resources that operate based on finite resources like reservoir levels or state-of-charge, supplying energy earlier in the day often means that they cannot supply energy later at the time of higher demand,” FERC said in its order. “CAISO states that this is a significant concern because if these resources are depleted earlier in the day, CAISO must depend on a more limited pool of resources to meet its later net peak demand.”

Removing the RLCR restriction will enable cost-justified bidding, promoting more efficient dispatch on constrained days, FERC said. “The artificial restriction to cap DEBs at $1,000/MWh is unnecessary and counterproductive to using DEBs for cost-verification.”

CAISO’s Department of Market Monitoring agreed, having argued that requiring scheduling coordinators to submit RLCRs is unnecessary because the formulas used to calculate DEBs are well established and reflect the marginal cost of a resource. The department also agreed the cap should be removed for energy-limited resources because of the technical limitations they face. Portland General Electric and the California Energy Storage Alliance also supported the proposal.

While the DMM generally supported the tariff revisions, it also said the proposed changes should not apply to the entire day because a static bid cap cannot target specific hours when intraday opportunity costs are most likely to exceed $1,000/MWh.

The California Public Utilities Commission also argued that the proposed changes are not targeted enough to address the intraday opportunity costs of hydro resources. Lifting the cap in the day-ahead market is not necessary because the market is already able to optimize resource schedules, it said.

“DMM and CPUC assert that the bid cap proposed by CAISO would allow energy storage resources to bid substantially in excess of their intraday opportunity costs during high priced hours when the system is tight and the opportunity cost is known to approach zero,” FERC summarized.

The department also raised concerns about the tariff revisions’ potential to exacerbate existing flaws in bid cost recovery, an issue being addressed in the ISO’s bid cost recovery initiative. (See CAISO Kicks Off Storage Bid Cost Recovery Stakeholder Initiative.)

The CPUC also argued that the hydro DEB formula was not designed for above-cap bidding and therefore does not result in values that satisfy Order 831 cost justification requirements.

CAISO responded by reiterating its belief that artificially capping any resource’s DEB at $1,000/MWh in the day-ahead market could lead to inefficient scheduling. CPUC’s arguments regarding the hydro DEB formula were outside the scope of the proceeding, the ISO argued, and neither it nor the DMM provided evidence that proposing a static bid cap throughout the day rather than targeting specific hours was unreasonable.

FERC disagreed with the DMM’s and CPUC’s arguments.

“We find that CAISO’s proposal will help to ensure that energy-limited resources are able to reflect their opportunity costs in their cost verified bids, similar to other resources,” FERC stated. “We find that accounting for these opportunity costs will enable CAISO to more optimally manage these resources’ energy limitations over the day, and thereby improve CAISO’s ability to reliably and economically meet its net peak demand.”

The tariff revisions become effective Aug. 1. Commissioners Lindsay See and Judy Chang did not participate in the order.

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Maryland PSC Approves Grid Upgrades for New Data Center

Maryland is setting itself up to compete with Northern Virginia’s Data Center Alley with a 2,100-acre data center campus in Frederick County, and on July 31, the Maryland Public Service Commission granted a waiver for Potomac Edison Co. to install two 230-kV lines to help connect four data centers from the campus to a new substation. 

The 3-1 vote on the waiver allows Potomac Edison to begin construction on the lines in September without first requesting a certificate of public convenience and necessity (CPCN), a much longer and more expensive process.  

Commissioner Bonnie Suchman cast the single no vote, arguing the waiver could open the door for more waiver requests for similar line additions for more data centers, with other customers picking up the bill. 

Potomac Edison’s customers in Frederick County don’t need the upgrades at present, Suchman said. “Upgrades are only coming because of this new data center. … You’re going to get more data centers coming in, and more data centers are going to put more burdens on the system, and then you’re going to come to us for a waiver, and we’re going to sort of rush all this stuff through. 

“The data center may come or not, but the one thing I am seeing is an increase in the cost for the network that’s going to be borne by the ratepayer,” she said. 

According to commission staff, however, the project meets specific legal standards in the state’s public utilities code that require the PSC to grant the waiver: The new lines won’t require the utility to secure new property or rights-of-ways or to install bigger or taller structures for increased voltage or larger conductors. 

The Potomac Edison lines will be “loop lines” that run from an existing 230-kV line to a new substation to be built for the data center and then back to the main line. Each line will be 1,100 feet long and use the same type of wires as the existing line, and will include eight new poles, none of which will be taller than existing poles.  

The staff report also said the new lines and other system upgrades, including a switching station expansion, will mitigate potential thermal overloads and voltage violations the new data centers could cause on the main line, as identified by PJM. 

“PJM did that specifically for reliability reasons … not only to take into consideration [the data center’s] anticipated load, but the other load currently being served and to be served in that area, altogether about 1,350 MW,” said Joey Tsu-Yi Chen, corporate counsel for Potomac Edison. “We do not want to see a situation, in fact, cannot, where we have no more than 300 MW of load that would be interrupted by any particular criteria.” 

However, PJM spokesperson Jeff Shields said the RTO neither planned nor approved the two lines. Rather, FirstEnergy, which owns Potomac Edison, included the project in a supplemental filing to the RTO’s Transmission Expansion Advisory Committee in October 2023. 

Data Center Alley North?

Reliability aside, Chen told the commission the waiver was needed so the new lines could be built to meet the data center’s timeline. A full CPCN review would not meet “their timing needs for their project,” he said ― underlining the disconnect between digital and regulatory time frames, and Suchman’s concern Potomac Edison’s waiver request could be the first of many. 

Maryland has been promoting itself as a nearby, attractive alternative to Northern Virginia, home to hundreds of data centers and skyrocketing power demand. Gov. Wes Moore (D) rolled out the welcome mat in May when he signed the Critical Infrastructure Streamlining Act of 2024 (S.B. 474), waiving the need for data centers to get CPCNs for their fossil fuel-powered backup generators.  

The Frederick County data centers could provide a glimpse of what’s to come. The developer for the project is Rowan Digital Infrastructure, which provides “turnkey data center campus solutions” with “de-risked development timelines,” according to the company website. 

The data centers will cover about 145 acres in the larger, 2,100-acre Quantum Frederick data center campus being planned by developer Quantum Loophole. Rowan’s website describes its project as a multi-building facility with 300 MW of power to start and the potential to expand to 450 MW. 

The Frederick County site offers “near-term power interconnection dates [and] competitive power pricing … [and can] deliver the initial 300 MW by late 2025, providing a high-value alternative to the congested Ashburn corridor” in Northern Virginia. 

Quantum also has big plans for the site, which it intends to connect to its data center hub in Northern Virginia with a 40-mile fiber optic network ring. 

“At full capacity, the 34 conduits will hold more than 235,000 strands of fiber to transmit data between the two hubs in under one millisecond Round Trip Time (RTT),” a company press release said.  

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Opposing Sides Want to Speed, Slow NY Cap-and-invest

Dueling visions for New York’s proposed cap-and-invest system are being offered as state officials continue the lengthy process of codifying its details.

Environmental advocates, alarmed by the state’s lagging progress toward its decarbonization goals, are calling for a robust scheme to be put in place as soon as possible.

Business, labor and industry representatives, alarmed by the escalating, yet still unknown costs of those decarbonization efforts, are calling for a pause to assess what realistically is possible and affordable in New York.

Both statements were issued July 30 and are keyed to the fifth anniversary of the state’s landmark Climate Leadership and Community Protection Act, signed into law in 2019.

The CLCPA mandates a 40% reduction of greenhouse gas emissions by 2030 over 1990 levels and an 85% reduction by 2050. Cap-and-invest is intended to incentivize carbon-emitting industries to reduce their emissions.

The CLCPA scoping plan finalized in December 2022 recommended the cap-and-invest system as one way to help achieve those goals.

Gov. Kathy Hochul (D) announced details of a cap-and-invest concept in early 2023.

The state Department of Environmental Conservation and the New York State Energy Research and Development Authority are developing the proposal. It still is a pre-proposal, having reached Stage 4 of an eight-step process that already has generated nearly 5,000 public comments.

Meanwhile, the clock is ticking.

NYSERDA and the state Public Service Commission on July 1 issued a draft report saying the state would miss the CLCPA target of 70% renewable energy by 2030, perhaps by a wide margin, thanks to a variety of factors both local and global. (See NY Expects to Miss 2030 Renewable Energy Target.)

An audit released July 17 by the Office of State Comptroller made the same point, and faulted the state for offering no estimate of what the overall effort would cost, or how much of that cost would fall on utility customers who already have some of the highest rates in the country. (See Audit Faults NY on Climate Act Progress.)

These delays and costs were cited in the competing wish lists issued July 30.

The Environmental Defense Fund and 28 like-minded organizations urged Hochul to advance an ambitious set of regulations as soon as possible:

“The health and safety of our communities and of future generations depends on bold leadership and meaningful action to implement and fund our nation-leading climate law. Our organizations call on Governor Hochul to propose draft regulations for a cap-and-invest program that delivers on the promise and requirements of the CLCPA without further delay.”

Kate Courtin, senior manager of New York’s climate policy and strategy team, told NetZero Insider that “the pre-proposal is a helpful first step,” but advocates want a formal rulemaking to be put in place.

She said the cost concerns raised by opponents and skeptics miss the point — the cap-and-invest program should be viewed not in terms of its costs but the larger savings it will yield in the short and long term.

Cap-and-invest would provide economywide market signals and give the state money it could invest in the clean-energy transition, Courtin said.

“The reality right now is we’re just not investing enough,” she said.

Preliminary state analysis shows cap-and-invest would yield $6 billion to $12 billion a year in revenue. That would come from the industries generating the emissions, which presumably would pass the cost along to New Yorkers.

Hochul recently took a controversial step to cushion New Yorkers from the cost of the state’s climate-protection efforts, placing an indefinite pause on a congestion-pricing system meant to limit vehicle traffic in New York City.

Courtin said the call for expedited action by the environmental advocates was not in concern that a similar pause is in the works for cap-and-invest, but because the new program is taking too long to devise. Hochul’s initial proposal called for the regulations to be in place by the end of 2023.

But such a time-out is exactly what the Business Council of New York State would like to see. It and 61 other business, union and industrial organizations called on the state to make mid-course corrections to its implementation of the CLCPA, based on the significant economic and market changes seen since it became law.

The Business Council wrote:

“Since the start of the CLCPA implementation efforts five years ago, many have called for a more comprehensive, publicly accessible assessment of implementation costs, the comparative costs of policy alternative programs and the impact of new policies on residential and business energy consumers. We are renewing those demands today.”

It clarified that it is not criticizing the goals of the CLCPA.

“We are not opposing further state investments in emission reductions, renewable generation and energy efficiency, nor are we opposing the adoption of a ‘cap and invest’ program. However, the state needs to ensure that its push toward emission reductions and the electrification of major sectors are technically and economically achievable.”

The vision for cap-and-invest in New York goes beyond greenhouse gas emissions.

Its architects are charged with designing a program that simultaneously targets benefits to disadvantaged communities, channels money to New Yorkers to defray the higher costs that would accompany the program, invests in industries of the future and supports the transition to a less carbon-intensive economy.

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Manchin-Barrasso Permitting Bill Easily Clears Committee

The Senate Energy and Natural Resources Committee voted 15-4 on July 31 to advance the Energy Permitting Reform Act of 2024 to the floor. 

The bill, S.4753, was backed by committee Chair Joe Manchin (I-W.Va.) and Ranking Member John Barrasso (R-Wyo.) and includes changes to transmission siting and planning, mining, oil and gas drilling, and judicial review. 

The committee worked on the legislation over the course of this congressional session, holding many hearings on permitting and related issues, Manchin said at the committee’s business meeting. 

“I think the need for permitting reform has come up in almost every hearing that we’ve had this Congress,” Manchin said. “No matter what side of the fence you may be on, everyone knows it can’t happen unless we reform our permitting — how we do things. So, the time to act is now.” 

While the bill awaits a potential vote on the floor, the Senate’s actual working days left this Congress are dwindling as lawmakers will take extended time off for the election this fall. The Senate leaves for summer break at the end of this week and is scheduled to be in session for only three more weeks before the election, with five weeks of a lame duck session on the schedule. 

Numerous amendments were offered during the business meeting, but only one on forest restoration from Sen. Steve Daines (R-Mont.) passed. The committee voted down several others, including ones offered by Sen. Ron Wyden (D-Ore.) and Sen. Angus King (I-Maine) to ban offshore drilling off the West Coast and New England. 

Sen. Josh Hawley (R-Mo.) offered the day’s only amendment on transmission, which the main bill would give FERC authority to site. Hawley’s amendment would have required any lines the commission sites to go through a regional planning process. Manchin said the language would threaten the existing backstop siting FERC implemented with Order 1977 and the committee rejected the amendment. 

Other amendments, including one offered by Sen. Lisa Murkowski (R-Alaska) to make it easier for remote communities in her state to use small-scale hydroelectric and hydrokinetic generation, were withdrawn with promises from Manchin that changes could be made on the floor. 

“After more than a year of bipartisan negotiations with Chairman Manchin, we are now one step closer to getting the bipartisan Energy Permitting Reform Act signed into law,” Barrasso said. “Our bill is a true, all-of-the-above energy policy — targeted, timely and good for all Americans.” 

American Clean Power Association CEO Jason Grumet welcomed the bill, which he said would increase the resilience of the power sector and accelerate the deployment of clean energy. 

“The leadership from the Senate Energy and Natural Resources Committee is critical to ensure that our nation can meet rapidly growing electricity demand,” Grumet said. “The legislation is both bold and balanced, creating an effective policy framework for building new high-voltage transmission. Building out new transmission will help ensure affordable, reliable energy for American businesses and consumers.” 

The transmission language in the bill includes some language backed by Democrats and even environmentalists, with the House Sustainable Energy and Environmental Coalition’s Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.) welcoming those provisions. The two have introduced the Clean Electricity and Transmission Acceleration Act, which includes similar transmission reforms. 

“While there are aspects of the bill that can be improved upon and provisions that we have concerns about, we are eager to continue the critical discussion on permitting reform as we strive to enact a law that will equitably accelerate adoption of clean energy and transmission,” Casten and Levin said in a statement. 

The Sierra Club found its opposition to the offshore drilling language and changes to permitting on federal law outweighed whatever benefits the transmission language would bring, saying it preferred the Casten-Levin legislation in the House. 

“There are existing proposals that would offer real solutions to accelerate the deployment of clean energy without sacrificing the climate and public health for fossil fuel executives’ profits,” Sierra Club Beyond Fossil Fuels Policy Director Mahyar Sorour said in a statement. “It is possible, and necessary, to unleash renewable energy and supercharge the clean economy without undermining bedrock environmental laws. Congress must see through this ruse to give handouts to polluters and reject the Dirty Deal.” 

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PSEG Planning for EV, Data Center Growth

Public Service Enterprise Group is seeing “slow but steady” electric vehicle growth in New Jersey but has yet to turn down any interconnection requests for EV chargers to handle the increase, CEO Ralph LaRossa said in the utility’s second-quarter earnings call July 30.

“We have the capacity,” he said. “But we’re upgrading that last mile. So that’s really playing out exactly the way we expected it to.”

Because of the unique “condensed nature of our housing and our commutes” in New Jersey, he said, EVs “have not had the same challenges and pressure that maybe the rest of the country has seen as far as the expansion that was expected.”

New Jersey last year put an additional 62,426 new EVs on the road, a 68% increase over 2022, which has prompted some advocates to suggest the state is in reach of its goal of having 330,000 EVs in the state by 2025. The rise occurred as some analysts say EV uptake elsewhere around the nation is slowing.

The New Jersey Coalition of Automotive Retailers says the state’s affluent population is less bothered than drivers in some states by the higher price of an EV, but the organization is skeptical the target can be reached. (See NJ EV Incentives Target Low-income Buyers.)

LaRossa said the rise in EV charging, along with growing interest from developers in putting data centers in the state, “is expected to drive load growth and system investment in these in the future.” Responding to a question from an analyst, he said he sees little risk in investing for continued EV growth, even if former President Donald Trump is re-elected.

“The only question, and we’ve talked about this before, is will you have 100% EVs by 2035, or will we get a 50% on that test?” he said. “And a 50 on that test is still going to be quite a bit of market penetration for the electric vehicle industry here.”

Data Centers

LaRossa said the utility is heavily focused on positioning itself to take advantage of interest from data centers in locating in the state, and especially those interested in co-locating next to the three nuclear plants owned and operated by PSEG in South Jersey.

He said the utility has “experienced an increase in new business requests and feasibility studies from potential data center customers across our service area compared with 2023 activity, which, combined with increased electric vehicle charging, is expected to drive load growth and system investment in these in the future.”

PSEG takes proposals seriously once the developer has moved beyond the engineering phase, he said. He added that “we’re seeing several hundred megawatts of data centers that are moving into that scenario here in New Jersey,” and two or three times as many projects that are in earlier stages.

LaRossa noted that Gov. Phil Murphy (D) on July 25 signed a law (S3432/A4558) creating a $500 million program to offer tax credits to encourage artificial intelligence companies to locate in the state.

He said a co-located data center has two benefits for the state’s economic development ambitions.

“It’s not necessarily just that it’s co-located,” he said. “It’s the fact that it’s a hyperscale data center. It’s going to provide a clear signal to AI companies that are looking to locate here in New Jersey and in the region, that the infrastructure is here up and running and ready to go for their businesses to thrive,” he said.

Talen Controversy

LaRossa said his attitude has not changed in response to the recent controversy over Talen Energy’s deal to divert capacity from its Susquehanna Nuclear Plant to serve a data center on the same site.

The project, which Talen developed next to its northeastern Pennsylvania plant and sold to Amazon Web Services, has drawn protests at FERC from parties who argue that it could siphon power meant for other clients, shifting costs and threatening reliability. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

“That’s not shifting us in any way, shape or form,” LaRossa said, adding the utility will be guided by its commitment to supporting Murphy’s economic development plans.

“I will say this to you. I’m a little bit concerned about co-located load as it impacts other industries,” he said. “If you really think about co-located load, that doesn’t just apply to data centers. That’s for combined-heat-and-power plants; it’s for cogeneration units.

“So, depending upon where this goes, while I’m concerned about data centers, I’m just as concerned about everything from rooftop solar behind the meter to cogeneration that might be taking place.”

Still, he added in response to a question from an analyst, whatever outcome emerges from the Talen case would not affect, or even delay, any proposal that might emerge for co-locating a facility next to PSEG’s three nuclear plants.

“Every deal is going to be very specific. I think the way our nuclear facilities are configured will be different than a nuclear facility down the street.” he said. “So, each one of those will be looked at differently, whether it’s by PJM, in its current rules that coexist for co-located load, or FERC when they come out with some sort of a process, if they do under the current challenge that’s there.”

PSEG’s second-quarter results this year fell short of those in 2023. The company reported net income of $434 million ($0.87/share), compared with $591 million ($1.18/share). It brought in about $2.4 billion in total revenue during the quarter, a slight increase over last year.

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PJM Capacity Prices Spike 10-fold in 2025/26 Auction

PJM capacity prices increased nearly tenfold in the 2025/26 Base Residual Auction (BRA) as a trifecta of load growth, generation deactivations and changes to risk modeling shrank reserve margins. 

The clearing price for most of the RTO jumped to $269.92/MW-day, far above the $28.92/MW-day for the 2024/25 auction. Two regions surged to their price caps, reaching $466.35/MW-day in the Baltimore Gas and Electric (BGE) zone and $444.26/MW-day in the Dominion zone. (See PJM Capacity Prices Jump in 5 Regions.) 

“The significantly higher prices in this auction confirm our concerns that the supply/demand balance is tightening across the RTO. The market is sending a price signal that should incent investment in resources,” PJM CEO Manu Asthana said in a July 30 announcement of the BRA results. 

PJM forecasts a peak load of 153,883 MW for the 2025/26 delivery year, up 3,243 MW from the previous year. The auction procured 135,684 MW of capacity at a record $14.7 billion to serve that load, with an additional 10,886 MW supplied through fixed resource requirement (FRR) plans. 

The total installed capacity was around 182 GW, resulting in an 18.5% reserve margin, just over the 17.8% installed reserve margin (IRM) target. The Dominion and BGE zones landed just under their reserve requirement and are transmission-constrained, causing prices to jump to the zonal cap. 

PJM Executive Vice President of Market Services and Strategy Stu Bresler said the auction procured adequate supply and sent a signal that investments in capacity are needed for future delivery years. He cautioned that capacity costs remain just one component of consumers’ bills and the results should not be read as causing a multifold increase in retail rates. 

“Auction prices were significantly higher in this auction and those steep increases, we believe, do signal the need for investments,” he said during a press conference July 30. 

The auction followed a yearslong trend of declining supply, with around 6.6 GW retiring or being approved for a must-offer exemption, which signals their intent to deactivate. Bresler said the tension between supply and demand demonstrates the reliability concerns the RTO highlighted in a February 2023 Energy Transition in PJM white paper. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.) 

Bresler said PJM is searching for solutions to speed the generation interconnection process to facilitate new resource development; however, 38 GW of resources have cleared the generation interconnection process but have yet to enter commercial operation. 

“Interconnection process reform is proceeding, but hurdles remain for many projects outside of our process,” Bresler said in the announcement accompanying the auction results. “We are considering ways to accelerate those who can successfully overcome those challenges and build.”  

In addition to tighter supply and demand, Bresler said the cost increase was driven by a shift in how PJM models reliability risks and matches them with resources accreditation (ER24-99). (See FERC Approves 1st PJM Proposal out of CIFP.) 

The changes use PJM’s marginal effective load-carrying capability (ELCC) framework to accredit all resources, except energy efficiency, and rely on its hourly probabilistic modeling to calculate capacity needs through the reserve requirement study. The new approach concentrated reliability risk into the winter and led to several resource classes seeing reduced accreditation. (See “Revised Reserve Requirement Study Values Endorsed,” PJM MRC/MC Briefs: March 20, 2024.) 

Auction Conducted After Several Delays

The timing of the auction has been repeatedly delayed from the original May 2022 schedule to implement several market changes, including reversing an order establishing a forward-looking energy and ancillary services (EAS) offset, followed by the Critical Issue Fast Path changes. (See FERC Approves PJM Capacity Auction Date Changes.) 

An additional delay approved in February pushed the opening of the auction from June 12 to July 17 to grant market participants more time to understand how the RTO will calculate effective load-carrying capability (ELCC) ratings to accredit the capacity resources can provide. (See FERC Approves PJM Capacity Auction Delay.) 

EPSA Says Increased Prices Reflect Increased Risks, Manufacturers Skeptical

Electric Power Supply Association (EPSA) CEO Todd Snitchler said the increased capacity prices are an encouraging first step in meeting the mounting reliability risks PJM has identified. 

“While there is still work to be done, these price signals recognize the situation PJM faces and should begin to incentivize the investment needed to deliver a reliable system in PJM and in other U.S. markets,” Snitchler said in a statement. “Reliability watchdogs, regulators, policymakers and PJM itself have been sounding the alarm that the misalignment of power resource retirements and additions poses a serious reliability risk to the grid — especially in the face of rising demand spurred by data center and manufacturing growth among other factors like electrification, extreme weather and policy choices.” 

Ryan Augsburger, president of the Ohio Manufacturers’ Association, said in a statement that auction delays will translate to higher capacity costs for consumers. 

“Markets work — but after years of delay of PJM’s critical capacity auction, prices are rising to attract generation in a hurry. PJM’s capacity auction will yield billions more for generators that locate in its territory to serve healthy customer electric load, but customers will bear the brunt of PJM’s costly auction delays,” he said. 

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WEIM Yields $365M in Q2 Benefits with Hot Start to Summer

CAISO’s Western Energy Imbalance Market (WEIM) provided its 22 participants with $365.04 million in economic benefits from April to June this year, down 4% from the same period a year ago. 

Cumulative benefits since the 2014 launch of the real-time market have hit $5.85 billion, according to CAISO’s second-quarter WEIM benefits report, released July 30. 

June saw an extremely hot start to summer for most of the West. During that month, the solar-heavy CAISO area was the WEIM’s leading net exporter, sending more than 1.1 million MWh of energy to other market participants, up 7% from June 2023. In the WEIM, a net export represents the difference between total exports and total imports for a balancing authority area during a particular real-time interval. 

“The transfers helped balance supply and demand when some of the WEIM entities were experiencing higher electricity usage due to a heat wave that saw temperatures climb 7 to 16 degrees above normal for several days across the West,” CAISO said in a press release accompanying the report. 

The ISO also was the biggest net exporter over the full quarter at 2.86 million MWh, followed by PacifiCorp’s East and West BAAs’ combined exports of 584,555 MWh, NV Energy at 464,133 MWh and Salt River Project at 395,542 MWh. 

The largest net importers were Powerex (965,287 MWh), the Balancing Authority of Northern California (BANC) (534,382 MWh) and SRP (473,319 MWh). 

CAISO also was the location of the largest volume of wheel-through transfers during the quarter at 736,433 MWh, followed by Arizona Public Service (508,707 MWh), the Western Area Power Administration’s Desert Southwest Region (DSW) (430,880 MWh) and PacifiCorp-West (419,025 MWh). WEIM participants currently receive no financial benefits from facilitating wheel-throughs through the market, with only the source and sink of the transfers benefiting, although stakeholders have discussed the possibility of changing that in the future. 

“More recently, subsequent to the June 30 closing of the second quarter, the real-time market also provided an important platform for energy trading during the record-setting heat wave in July that caused triple-digit temperatures across much of California and the West,” the ISO said. “Market participants provided similar assistance with robust energy transfers throughout the region.” 

DSW, which joined the WEIM in 2023, reaped the greatest economic benefit during the second quarter, at $50.57 million. DSW this year withdrew from participating in the second phase of developing SPP’s Markets+ — a potential competitor to the WEIM — after finding it would see few benefits from participating in either Markets+ or CAISO’s Extended Day-Ahead Market. (See WAPA DSW Cites Lack of Benefits in Markets+ Withdrawal.) 

BANC realized the second-largest share of benefits ($49.9 million), followed by CAISO ($36.02 million), NV Energy ($33.65 million) and the Los Angeles Department of Water and Power ($30.52 million). 

CAISO’s report said WEIM operations in the third quarter also helped market participants avoid 55,921 metric tons of greenhouse gas emissions through reduced curtailments of emissions-free resources. The market has prevented over 1 million MT of emissions since 2015, the ISO estimates.