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 advisor, 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 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 and 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 in 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 advocates at PJM, FERC and state commissions for the reliable expansion of the grid for renewable resources.
Protecting the public interest while implementing the Extended Day-Ahead Market (EDAM) and expanding the Western footprint was central to the discussion in a West-Wide Governance Pathways Initiative workshop Aug. 15.
“How are we going to continue to serve the public interest with an expanded footprint and with alternative, different governance?” Alice Reynolds, president of the California Public Utilities Commission, asked.
Members of the launch committee sought feedback on a combination of tools that could protect the public interest across the footprint of the regional organization (RO) the Pathways Initiative seeks to establish.
Beyond regulation by FERC, members discussed five main components that could be integrated into the structure of a new RO, including a stakeholder process, an independent market monitor, consumer advocate engagement, a states committee and an RO board.
In the implementation of an RO board, members emphasized public interest protection language in the articles of incorporation and the charter provisions. Also deemed important: a commitment to expand public benefits by attracting new participants, protecting individual state and local generation preferences and climate policies, holding open meetings and adhering to open records requirements.
Board members should have a history of protecting the public interest in their official roles, said Ben Otto, consultant with NW Energy Coalition and a launch committee member.
“There can be standards of duty for the board that are incorporated, like they have to act to protect public interest, and that is then their obligation when they’re acting as a board member, to follow those requirements and not their own wishes,” Otto said.
The RO also could establish a states committee that would maintain the current Western Energy Imbalance Market Body of State Regulators structure with a charter requiring protection of the public interest. Under this structure, states individually or through the committee could continue to submit 206 pleadings at FERC.
Other aspects of the committee would be having access to market monitor data, having the power to originate a stakeholder initiative with support from half of the participating states or half the load, having a seat on the RO board, and having veto rights over RO board nominations with a two-thirds vote of states and load. A subset of the committee representing one-quarter of states or load could vote to trigger a requirement for a supermajority vote on a particular topic.
Consumer advocates also could play a role by participating in stakeholder processes, having access to market monitor data and obtaining a seat on the RO board.
“This is absolutely necessary to ensure that the board is well informed on consumer issues. Being informed on consumer issues, we think, is key to fulfilling the public interest mission that we’ve laid out here in Pathways,” said Michele Beck, director at the Utah Office of Consumer Services and a member of the launch committee.
Individual consumer advocate offices aren’t resourced enough to participate in these processes, Beck said, creating the need for a central consumer advocate organization that could maintain interaction with RO processes. Launch committee members suggested the creation of a 501(c)(3) organization that could facilitate consumer advocate participation. Beck highlighted the Consumer Advocates of the PJM States (CAPS) program as an example worth replicating.
Launch committee members also highlighted other existing structures within the CAISO model that could be carried forth in the new RO, including the ISO’s Department of Market Monitoring and Market Surveillance Committee.
Additional ‘Tools in the Toolbox’
Stakeholders provided additional ideas for protecting the public interest.
“One other tool that we should have in the toolbox for protecting the public interest is really allowing and enabling the public to participate in our decision making to the extent that it’s appropriate,” said Mark Specht, Western states energy manager at the Union of Concerned Scientists and a member of the launch committee. “Things we might consider would be creating some sort of office of public engagement that would really serve as a resource for folks who are interested in participating and having their voices heard in our decision making.”
Preserving state and local autonomy within regions also was a primary point of conversation given the different laws, policies and preferences within each state.
“We’ve really been thinking about, how do we create a system that explicitly acknowledges and protects the ability for states to keep that authority in place and enables states to really develop their own vision of what the public interest is?” said Kathleen Staks, executive director of Western Freedom and co-chair of the Pathways Initiative. “What tools holistically across the entire regional organization ensure that the regional organization protects the public interest in lieu of a single state statutory requirement like we have with the CAISO today?”
Commissioner John Hammond of the Idaho Public Utilities Commission echoed concern over the challenge of defining the public interest given the array of different players.
“There are obviously common interests in keeping costs low and in reliability, but I worry about when we start getting into policy areas and what impacts that might have on the individual states that have different policies,” Hammond said. “My fear is you start incorporating too many things in the toolbox, you might get a reaction legislatively from particular states … so I think it’s very important that we define exactly what public interest we are trying to protect.”
The NYISO Operating Committee has approved two study reports and one study scope, all of which involve load projects in northern New York.
The SDC St. Lawrence interconnection study modeled the impact of the 120-MW load project on the local system. NYISO staff found that the project would cause thermal overload that could not be mitigated with adjustment. In sensitivity scenarios, the project caused voltage violations and voltage transfer degradation.
NYISO estimated the cost to build the attachment facility for the interconnection is $55 million, plus or minus 50%, and it would take about 54 months to complete. The cost to mitigate the thermal overload issues and the voltage transfer degradation issues were $33.6 million and $37.5 million. Voltage violations would cost an estimated $2.5 million to mitigate. An additional estimated $39 million would be needed to mitigate thermal issues at the transformer.
The customer asked if there was a different software package that could be used to help reassess costs.
“We can take it back and consider it, but I don’t believe the additional capability of the distributed model at St. Lawrence would resolve these overloads” or alleviate upgrade costs, said Aaron Markham, vice president of operations for NYISO.
In the study report for the Massena Green Hydrogen project, a 110-MW hydrogen electrolysis plant, no adverse impacts to the grid were found. NYISO found that interconnection would be feasible with the construction of a new three-breaker and bus substation. The estimated cost for the interconnection would be about $27.7 million, and the project would take two to three years to complete.
The Cayuga Compute 150-MW data center scoping study was discussed and approved. The study will perform reliability and cost-estimation analysis similar to the reports listed above.
Other Business
The Operating Committee also heard the July 2024 Operations Performance Report. Peak load was 28,990 MW, which set the new summer 2024 peak. Markham said this was because of higher-than-average temperatures.
He noted that NYISO also had to call on the Emergency Response Demand Program and Special Case Resources during the evenings of July 15-16. Markham said they hit scarcity pricing on both days.
“On the 16th of July, a number of severe thunderstorms, including 10 confirmed tornadoes, occurred in the state as the remnants of Beryl passed through,” Markham said. He said that caused simultaneous outages for about 275,000 customers.
“There was a tornado in Buffalo early last week, and from what I saw, that broke the [record for the] number of tornadoes that occurred in the state,” Markham said. “That was 25 back in 1992; we are up to 26 this year.”
The committee also reviewed and approved supplemental manual updates for constraint-specific transmission shortage pricing. These updates to the day-ahead scheduling manual and transmission dispatch operations manual are described here. Drafts may be seen here and here.
Eds: A previous version of this article incorrectly referred to the SDC St. Lawrence as the North Country Data Center.
NYISO staff have presented tariff revisions that may be deployed as early as the first quarter of 2026 to account for the uncertainty of wind and solar energy forecasts. The filing date with FERC has yet to be determined.
If accepted by FERC, the revisions would add two new items to the tariff, uncertainty reserve requirements and scarcity pricing in 30-minute reserves for the New York Control Area and several downstate zones. These requirements would add a stepwise demand curve to the market.
“Uncertainty reserve requirements for operating reserves are here to account for the forecast uncertainty of node wind and solar energy forecasts,” Vijay Kaki, market design specialist for NYISO, said at the Installed Capacity Working Group meeting Aug. 13.
Kaki explained the uncertainty reserve requirements would be calculated for, and apply to, the day-ahead and real-time markets. For the day-ahead market, the uncertainty reserve would apply only to the 30-minute reserve product. In the real-time market, these new reserves would be calculated for both 10- and 30-minute reserve products.
For the day-ahead market, the reserves would be calculated for each hour of the day, before the day-ahead market run.
“It’s a daily change,” said Kaki, explaining this was based on annual forecast data. “The annual metrics are calculated once a year, and those metrics will be applied to the day and market forecast data on a daily basis.”
The NYISO price scheme is intended to encourage generators to respond quickly to requests for energy to meet reliability requirements. The market would pay more for generators who activate when operating reserves and uncertainty reserves are low.
Revisions to the tariff, along with a consumer impact analysis, are expected to be done by the end of the third quarter.
Winter Reliability Enhancements
After discussing the tariff revisions, NYISO presented the winter reliability capacity enhancement project that tentatively is scheduled for 2025. The idea is to ensure the capacity market provides the correct price signals all year to ensure reliability as New York transitions to a winter-peaking system.
“We’re looking at this project to consider what would be the process for setting winter CAFs [capacity accreditation factors] and would they be any different,” said Michael Swider, senior market design specialist for NYISO.
Swider said the market needed to be evaluated to look for elements that are more affected by a more seasonally differentiated capacity market. Currently there is one installed capacity requirement that is applied to an entire year that is forecasted based on annual peak load, which occurs in summer.
NYISO projects the system will transition to a winter-peak in the 2030s. The RTO has stated its concerns about fuel constraints occurring in winter, particularly if the system is winter peaking. (See NYISO Braces for the Coming Winter.) Because the current ICAP is calculated based on summer load, NYISO staff worry the current system may cause reliability and market issues.
