Four Arizona utilities announced their plans to join SPP’s Markets+ day-ahead market, a significant win for SPP after a string of victories for CAISO’s competing Extended Day-Ahead Market (EDAM).
Arizona Public Service (APS), Salt River Project (SRP), Tucson Electric Power (TEP) and UniSource Energy Services made the announcement Nov. 25.
Markets+ is expected to save the utilities nearly $100 million while enhancing reliability and supporting the addition of renewable resources to the grid, the utilities said in a joint release.
The utilities said they plan to begin Markets+ participation as soon as 2027.
“Together with our neighboring utilities, APS plans to join Markets+ to efficiently deliver energy and bolster the resilience of our shared energy grid in Arizona and across the region,” Brian Cole, APS vice president of resource management, said in a statement.
When asked about the reasons for choosing Markets+ rather than CAISO’s EDAM, an SRP spokesperson said the primary drivers are governance and resource adequacy.
The Markets+ governance structure promotes independence, transparency, inclusivity and stakeholder-driven decision-making, the spokesperson said.
And Markets+ will adhere to a single, shared resource adequacy program — the Western Resource Adequacy Program — providing a consistent method to make sure enough resources are available to reliably serve load across the Markets+ footprint.
“It also ensures that all market participants contribute fairly to the reliability of the market footprint, preventing any participants from systemically leaning on others,” the SRP spokesperson said.
SRP expects a critical mass of entities joining Markets+ in spring 2027, and SRP will sign an implementation agreement before the market goes live.
Tariff Decision Pending
The announcement comes as SPP awaits FERC’s decision on the Markets+ tariff, which initially was filed in March. FERC issued a deficiency letter in July identifying 16 problems in the tariff. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)
SPP filed a response to the letter in September, addressing each issue and asking FERC to issue an order by Nov. 20.
But FERC isn’t required to abide by that request and will take “as much time as they need,” an SPP spokesperson told RTO Insider. SPP said previously it’s confident it can address concerns the deficiency letter raised.
In contrast, CAISO’s EDAM already has received FERC approval.
A TEP spokesperson said the company fully expects FERC to approve the Markets+ tariff, while acknowledging the approval can be an “iterative process,” a comment echoed by SRP.
“We will continue to work with FERC and SPP throughout the process in demonstrating the value this direction will bring to our customers,” the TEP spokesperson said.
FERC approval of the tariff will mark the start of a second phase of Markets+ development.
“SPP thanks all Markets+ stakeholders for their engagement and collaboration in phase one development and looks forward to their continued involvement,” Antoine Lucas, SPP vice president of markets, said in a statement provided to RTO Insider. “We eagerly anticipate receiving signed phase two commitments by the end of the year so we can continue to work together to build a market that provides benefits for all western entities.”
Footprints Taking Shape
The Arizona utilities’ announcement of their Markets+ decision is the latest step in the evolution of two day-ahead market footprints in the West. In addition to the Arizona announcement, Bonneville Power Administration has expressed a “leaning” toward Markets+ over CAISO’s EDAM. BPA is waiting for FERC’s ruling on the Markets+ tariff before deciding. (See BPA Execs Lay out Markets+ Benefits, Risks, Reasons.)
Although Powerex has not yet made a formal commitment to a day-ahead market, it has clearly signaled an intention to join Markets+ and to not join EDAM.
The Arizona announcement “is a clear indication of the value that many utilities are seeing in the Markets+ day-ahead market option,” Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), said in an email to RTO Insider.
The Portland-based PPC, a trade group representing the extensive network of Northwest publicly owned utilities that buy low-cost power from the Bonneville Power Administration, has been a consistent advocate of BPA choosing Markets+ over CAISO’s EDAM. (See Northwest Public Power Group Endorses Markets+ over EDAM.)
“As a participant in the development of Markets+, PPC has appreciated the collaboration we have had with these Arizona utilities and the shared goals we have for a well-designed, well-governed day ahead market option,” Tenney Denison said.
Meanwhile, EDAM scored its latest win this month with Public Service Company of New Mexico’s announcement of its plans to join the CAISO market. (See PNM Picks CAISO’s EDAM.)
PacifiCorp, Portland General Electric and Balancing Authority of Northern California have signed EDAM implementation agreements with CAISO and the list of entities expected to join EDAM has grown to include NV Energy, Idaho Power and Los Angeles Department of Water and Power.
In October, the Western Area Power Administration’s Desert Southwest (DSW) Region said it would cooperate with Arizona G&T Cooperatives on a study examining the potential benefits of DSW joining EDAM. DSW this year withdrew from the second phase of developing Markets+ after determining it would realize few benefits from participating in that market. (See Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study.)
After NV Energy announced its intent in May to join EDAM, Advanced Energy United issued a statement encouraging other entities, especially those in the Southwest, to join EDAM. The industry association said EDAM was becoming “the most viable day-ahead market.”
Brian Turner, who leads Advanced Energy United’s regulatory engagement in the West, said AEU is pleased that Arizona utilities are “embracing broader energy markets,” which have the potential to bring customer benefits including greater reliability and affordability.
But Turner said the Arizona announcement is “bittersweet,” as having two Western day-ahead markets will create seams and market inefficiencies.
As the market footprints are now developing, Markets+ could end up with a “big fat seam” in Northwest-Southwest trade caused by NV Energy and California entities joining EDAM, Turner said in an interview.
And the Arizona utilities are giving up known benefits of their participation in CAISO’s Western Energy Imbalance Market (WEIM) in exchange for unknown potential benefits of Markets+, he added.
But how the Western day-ahead markets ultimately take shape remains to be seen.
Members Endorse 2 Changes to Transmission Planning
ERCOT stakeholders approved a pair of protocol changes related to transmission planning as the Texas grid operator continues to grapple with connecting incoming load to its system.
During the Technical Advisory Committee’s Nov. 20 meeting, members approved NPRR1247, which uses a consumer energy cost reduction test to measure congestion cost savings when evaluating economic transmission projects. They also approved NPRR1180 and a related change to the Planning Guide (PGRR107) that incorporates a 2022 state law requiring any ERCOT reliability transmission project review to include the historical load, forecasted load growth and additional load seeking interconnection.
Several generators and retailers opposed the first protocol change, noting that congestion costs can be hedged but transmission costs can’t.
“We think basing decisions on that is probably discounting a significant value that accrues to loads,” Luminant’s Ned Bonskowski said.
The NPRR was brought forward by ERCOT staff after collaborating with the Public Utility Commission. The ISO retained Energy and Environmental Economics (E3) to identify a set of viable options and provide recommendations for the most suitable congestion cost savings test. E3 presented its work in a March 2024 analysis, recommending a system-wide energy cost reduction test as the most suitable for ERCOT.
While staff approved E3’s recommendations, Luminant said the proposed congestion cost savings test could increase costs for ratepayers when competitive market solutions could serve load less expensively. The generator suggested applying a .25 multiplier factor to the calculated system-wide consumer energy cost reduction before using it to determine a project’s economic benefits.
“We think this may be a good compromise,” Bonskowski said. “If there’s a need to move forward on something today, we certainly would also support tabling” to give stakeholders more time to “make sure that we get this right before sending it up to the board.”
The vote to table NPRR1247 fell short, 11-17, with one abstention.
Mark Bruce, speaking for Pattern Energy, said his client is concerned about an overall lack of transparency and the need for further vetting. He said Luminant lacked backing data in its comments and urged stakeholders to revisit the matter with a change to the Planning Guide to further prevent downstream effects.
“I know there’s been some pressure from above to deliver something to the board on this at their next meeting,” Bruce said. “My client’s been engaged from the get-go, from its first showing as a draft before it was even filed. We’ve been trying to understand and perfect this very important revision request.”
TAC eventually approved the measure 25-3, with one abstention. Luminant, Calpine and Shell North America all opposed the motion.
The committee approved NPRR1180 25-0, with four abstentions, two from consumer interests.
The Office of Public Utility Counsel’s Nabaraj Pokharel said he supported the rule’s legislative intent but stressed the importance of ensuring load projections used for planning “are as accurate as possible.”
“There is a risk of unintended consequences, particularly if load studies are not thorough or accurate,” he said. “While building transmission to meet actual load is necessary, [it] could result in unnecessary cost that would ultimately be borne by residential consumers.”
To remedy that concern, Mark Dreyfus, speaking for a coalition of cities, suggested approving the protocol change and filing a follow-up revision request that drills down into the load-projection’s validation process.
“There’s a lot of projects waiting to have this process in place and we need to get moving on those projects,” he said.
Texas Competitive Power Advocates Executive Director Michele Richmond said several meetings with Oncor and other wires companies have resulted in a draft proposal for another NPRR that would address the process’ transparency and standardization.
“I think we are very comfortable with moving this forward, given that commitment and the really good discussions that we have been having,” Richmond said.
Large Loads Need a Segment Home
TAC discussed with staff potential changes to the committee’s segment makeup, driven by the growing influence of data centers and cryptocurrency miners that don’t fit neatly into either the industrial consumer or large commercial segments.
ERCOT membership has risen from 257 members in 2021 to 356 this year, mostly because of large flexible loads. Staff has asked entities with large loads to register in the industrial segment when making their membership applications for 2025.
The grid operator’s seven segments are used to fill out the 30-person TAC. Any changes to the representation would require an amendment to the bylaws and PUC approval.
“Things have changed a lot,” Engie’s Bob Helton said, alluding to a TAC segmentation that has been static since 2014. “Every time we talk about this, we have to be careful of balance. Anything we do is going to be a long, drawn-out deal to make sure that that balance remains in place and that no segment or group has a heavier weight than any other one in trying to approve things.”
Staff said ERCOT now has just over 62 GW of large loads in its interconnection queue. It has added another gig of new standalone and co-located projects since October.
West Texas Project Endorsed
TAC members endorsed ERCOT’s recommended $202.2 million Oncor project that addresses reliability issues in West Texas, placing it on the combination ballot.
The project stems from the 2019 Delaware Basin Load Integration Study. The region has significant oil and natural gas load and ERCOT’s highest peak demand growth rate percentage in recent years.
The Regional Planning Group approved Oncor plans to upgrade an existing capacitor station, build 22 miles of double-circuit 345-kV lines, convert 41 miles of 138-kV lines to 345-kV, build 41 miles of new 138-kV lines, and install six 5000-A, 345-kV circuit breakers. The project is expected to be completed in 2027.
Because the project cost more than $100 million, making it a Tier 1 project, it must be approved by ERCOT’s Board of Directors.
Co-chair Martin to Step Away
The meeting was the last as TAC’s co-chair for Collin Martin, Oncor vice president of grid operations. Martin told his fellow members he is stepping away “partially” to focus on potential transmission projects in the Permian Basin.
“I appreciate everybody’s confidence in being able to be seated to this on the table,” he said. “It’s been a great year. I learned a lot.”
“I learned a lot from Collin,” said TAC Chair Caitlin Smith, with Jupiter Power. “He brought a wide range of knowledge to TAC leadership, and not just the engineering side. He knows a lot about the market side and the systems and everything. I think having him here to add his perspective has been very valuable.”
Fellow Oncor employee Martha Henson has been proposed as Martin’s replacement. Smith will continue as chair.
HDL Override Change Tabled
TAC again tabled a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. Members directed their Wholesale Market Subcommittee to provide remarks on the change back to the Protocol Revision Subcommittee before they take it up again in January.
The change was approved by TAC in June. However, the board remanded it back to TAC in October over the consumer segment’s concerns that the NPRR would reward overscheduling of power that cannot be delivered. Members of that segment say that will force consumers to subsidize insufficient hedging by other market participants in the face of changing grid conditions. (See “2025 AS Methodology OK’d,” ERCOT Board of Directors Briefs: Oct. 9-10, 2024.)
Reliant Energy Retail Services’ Bill Barnes said he has discussed this with Eric Goff, who represents residential consumers but was unable to attend the meeting, and floated a concept from their conversation. He said it acknowledges consumer concerns about a situation where HDL overrides become a “dominant component” of the market.
“We would be more dependent on these out-of-market payments. That’s not the goal of 1190. That’s not the goal for any of us,” he said.
Barnes said an annual settlement trigger, should ERCOT find itself in a situation where it hits a threshold amount of HDL payments, would lead to a review of the protocol’s language. That would tighten the contracts eligible for some participants, he said.
Members unanimously endorsed a combo ballot that included four NPRRs and related changes to the Planning Guide (PGRR) and Nodal Operating Guide (NOGRR) and an Other Binding Document request that will do the following if approved by ERCOT’s board:
NPRR1239, NOGRR266: move reports that don’t contain ERCOT critical energy infrastructure information (ECEII) from the market information system secure area to the public ERCOT website.
NPRR1240, NOGRR267, PGRR116: move reports that don’t contain ERCOT ECEII information from the market information system secure area to the public ERCOT website. The change also conforms rules with current posting practices, including those for maintaining ECEII lists of equipment in the outage scheduler; for making the annual planning model data submittal schedule available in the model-on-demand (MOD) application; and for posting weekly demand forecasts, demand analyses for 36 months and beyond, metrics of forecast error, and assessments of chronic congestion on the website.
NPRR1246, NOGRR268, OBDRR052, PGRR118: insert terminology associated with energy storage resources (ESRs) into the protocols, aligning the ESRs’ provisions and requirements with those for generation resources and controllable load resources. The change applies to ESRs in the future single-model era and should be implemented simultaneously with NPRR1014 (BESTF-4 Energy Storage Resource Single Model).
NPRR1254: require resource entities to submit the initial resource registration data for a generator interconnection or modification (GIM) project four months prior to target inclusion in the ERCOT network operations model. This gives ERCOT and the entities one month to address errors or deficiencies.
NERC’s recently submitted Interregional Transfer Capability Study (ITCS) is “a phenomenal first step,” according to participants in a webinar hosted by the American Council on Renewable Energy and Americans for a Clean Energy Grid — but there’s still much work ahead to address the U.S. grid’s mounting reliability challenges.
Speakers at the Nov. 25 webinar included former FERC Commissioner Allison Clements; Robert Taylor, vice president for transmission and new markets at Invenergy; Michael Goggin, vice president at Grid Strategies; and Cy McGeady, a fellow for energy security and climate change at the Center for Strategic and International Studies (CSIS). ACORE and ACEG hosted the forum to discuss the implications of the ITCS and potential future steps for FERC, Congress and other stakeholders.
The ERO worked with the regional entities and transmitting utilities for 18 months to develop the three-part report, which FERC will post for public comment. A final installment focused on transmission between the U.S. and Canada, and between Canada’s provinces, is planned to be released in early 2025.
In the ITCS, NERC recommended 35 GW of additional transfer capability across transmission planning regions in North America to strengthen grid reliability, including two new connections between ERCOT and neighboring regions. (See NERC Releases Final ITCS Draft Installments.) The report’s authors emphasized the analysis did not account for economic issues and cost-benefit analysis, and that even with the recommended additions it would not be possible to resolve all energy deficiencies due to chronic “wide-area resource shortages.”
In ACORE’s webinar, McGeady called the ITCS an “excellent starting point” and a “baseline” for future studies. Similarly, Goggin said NERC and its collaborators “did a great job in really tight time constraints and with the pretty narrow scope that Congress gave them.”
At the same time, attendees said the narrow scope meant that NERC ended up performing a conservative analysis. Goggin said the 35 GW recommendation represents “a floor, in my view, of what you should be thinking about in terms of an optimal transmission expansion.” He noted that FERC tasked the ERO only with identifying “prudent” transmission additions to improve reliability, which meant the study understandably did not take some important factors into consideration.
“Basically, it’s just keeping the lights on. It’s not looking at the opportunity to reduce consumer costs by giving them cheaper power,” Goggin said. “More importantly, even on the resource adequacy side, it’s not looking at how transmission can help you share generating capacity. … The NERC study did look at this, but they didn’t look at how you could economically save on building power plant capacity by tapping into” neighboring regions’ generation.
McGeady added that the figures NERC used to estimate demand were based on the ERO’s 2023 Long-Term Reliability Assessment. He said the projections in this year’s LTRA likely were to be “profoundly larger, like significantly upward revisions.” This means the ITCS’ recommendations could turn out to be even more conservative than Goggin and other panelists thought.
Moderator Elise Caplan of ACORE suggested these concerns could be taken up by respondents when FERC opens comments on the study, along with how to meet the additional unmet needs that NERC identified.
Asked what actions FERC could take to improve reliability through interregional transmission ties, Clements said she believes the commission can play a significant role. She called on FERC to take the lead on interregional planning and on the cost allocation process.
“I think if you’re really, genuinely trying to get to reliability at this moment in time, across the systems that constitute this nation’s electricity systems, we need to be looking at all the tools in the toolbox,” Clements said. “When it comes to reliability, there’s often a quick jump to say you can’t retire the uneconomic thermal units that want to retire. … I think it’s imperative on the commission to say what are the quick, easy, fast ways to do that.”
“I wasn’t a champion of transmission just because I think transmission is great. In fact, it would be a lot easier if we didn’t have to build it,” Clements added. “I’m a champion of transmission because it is a way to get to cost-effective reliability for customers.”
VALLEY FORGE, Pa. — Stakeholder opinions were sharply divided at the PJM Members Committee’s meeting Nov. 21 regarding RTO proposals to allow high capacity factor resources to be sped through the interconnection queue and revise aspects of the capacity market.
The Reliability Resource Initiative (RRI) would advance 50 interconnection requests to Transition Cycle 2 (TC2) — an interim group of queues established as part of PJM’s interconnection process overhaul that began in 2023 — in an effort to address a possible resource adequacy gap identified in the 2029/30 delivery year. The proposal would require tariff changes to be approved by the PJM Board of Managers and FERC. (See Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation.)
Presenting the RRI, PJM Director of Interconnection Planning Donnie Bielak said the proposal is being brought to address “unique circumstances” and would be a one-time measure to allow uprates and resources that can quickly come online to be expedited through the queue to address a reliability need.
If more than 50 projects are submitted, selection would be based on a scoring formula that awards up to 35 points to projects based on their unforced capacity (UCAP); 35 points for the viability of being in service by June 1, 2029, or sooner; 20 points for higher effective load-carrying capability ratings; and 10 points for site location. The only hard eligibility requirements would be that a project must have a UCAP above 10 MW and that they are not part of a project under FERC Order 1000’s State Agreement Approach.
Resources not already subject to the requirement that they participate in the capacity market would be compelled to offer for at least 10 delivery years. Bielak said developers would have the choice of accepting a must-offer requirement for a project they are truly certain can be rapidly brought to market or wait to be sorted into TC1.
TC2 was open to projects sorted into the AG2 and AH1 queues, the latter of which closed in September 2021. Studies on projects submitted after that date are not likely to initiate until 2026.
Responding to stakeholder questions regarding the scale of the impact the RRI could have on TC2 cost allocation, Bielak said PJM does not know which projects will be submitted, and there are hundreds of projects that dropped out of the interconnection process that could be resubmitted. Potential cost allocation impacts vary significantly depending on which projects are submitted and ultimately selected by PJM.
Criticisms and Alternatives
Several renewable developers objected to the proposal, arguing it would constitute queue jumping and disrupt network upgrade cost allocation for projects that have been waiting in the queue for years.
Rahul Kalaskar, AES senior director of regulatory affairs, offered an alternative from AES Clean Energy and REV Renewables to run TC2 and RRI projects in separate cycles. The RRI projects would be added to the separate cycle, which starts after Decision Point 2 of the TC2 cycle and runs all the studies in one condensed process. Doing so would keep the network upgrades for the TC2 and RRI projects in two different buckets.
Kalaskar said that if PJM’s RRI design were to proceed, transmission headroom could be consumed, increasing the costs assigned to TC2 projects and possibly causing some to drop out of the queue.
Steve Lieberman, vice president of transmission and regulatory affairs for American Municipal Power, said his organization conditionally supports RRI if changes are made to the scoring weights to prioritize project size and viability; projects that would be part of fixed resource requirement (FRR) plans are excluded; and developers are prohibited from buying out of their obligations.
Tonja Wicks, vice president of regulatory affairs for Elevate Renewables, said “project viability” and the “in-service date” should account for at least half of the project weighting, as it gets to the core issue that PJM is trying to resolve with the RRI: getting capacity that has the most certainty to come online by a set date. Otherwise it risks selecting projects that promise to bring a large amount of power, but with no firm site control or demonstration that they can meet milestones.
Independent Market Monitor Joe Bowring said the RRI should be preserved as a permanent option that PJM can deploy when it identifies reliability needs that can be resolved by expediting new development. Because projects are being fast-tracked to resolve capacity needs, he said the 10-year must-offer requirement should be expanded to the lifespan of the asset.
Mike Cocco, senior director of RTO and regulatory affairs at Old Dominion Electric Cooperative, said data center loads in northern Virginia are accelerating rapidly, and the RRI is necessary to ensure PJM can continue to meet demand. He said ODEC intends to submit projects to be studied under the RRI, possibly including combustion turbine generators, and he encouraged PJM to consider how the milestone deadlines for RRI projects could conflict with timelines for air quality regulations and other requirements.
“We’re in a position to bring generation online with the timeline that you’re looking for,” he said.
Grant Glazer, MN8 Energy’s manager of regulatory and market affairs, highlighted that projects in TC2 will be studied under a new generation deliverability test, which he said could identify violations prompted by projects in TC1. The status quo rules would assign those network upgrades to TC2 clusters, increasing their cost allocations for up to two-thirds of projects in the cycle. Instead, he encouraged PJM to revise the Regional Transmission Expansion Plan to capture those upgrades.
SIS Eligibility
Along with the RRI proposal, the filing with FERC would include tariff revisions to expand eligibility for projects seeking surplus interconnection service (SIS) by striking language prohibiting projects that could impact the network upgrades for new service customers in the queue.
Stakeholders argue the language is overly prohibitive and prevents developers from co-locating thermal resources with renewables and storage.
Sarah Toth Kotwis, RMI senior associate, said SIS is the fastest process available for bringing new resources online. Storage co-locating with existing resources can come online within 2.5 years of receiving an interconnection agreement, about half the time for adding new generation.
Wicks said PJM stands alone among RTOs in studying open-loop batteries as discharging in light load cases and using those outcomes to determine whether projects would consume headroom that could be used by other queue projects.
“With short duration times for construction and energizing, batteries are the types of resources FERC’s SIS directive envisioned utilizing excess capacity — a.k.a. surplus — at existing facilities to meet resource shortfalls and enhance reliability,” Wicks said.
PJM CEO Manu Asthana said RTO staff are open to revisiting the light load case test for storage, but that needs to be a discussion in the stakeholder process to ensure there are no unintended consequences. The tariff changes would remove barriers to allow that conversation to proceed.
Asthana said his read on stakeholder impressions on the proposed SIS changes is that PJM is on the cusp of resolving their core concerns about the service. He said PJM is taking that feedback and plans to continue pursuing changes.
“The door is not closed: We want to hear how we can make that work,” he said.
Bruce Grabow — a partner in Sheppard, Mullin, Richter & Hampton — urged PJM to take more time to vet the proposal through the stakeholder process, noting that stakeholders had only a few minutes to make their comments during the meeting, with some rushing to include all of their arguments. That is not how the stakeholder process is supposed to occur, he said.
Because of the lack of discussion, along with his assertion that PJM still had not provided data to stakeholders supporting the need for expedition, the RTO risks protests at FERC and in court, Grabow argued. He asked questions about the weighting system PJM intended to apply to determine which new generation projects would be winners and losers and whether the scoring means would be transparent; when PJM did not provide further detail, Grabow argued that meant the criteria would be subjectively applied, which does not comport with FERC standards of transparency, non-discrimination and preference.
Asthana said there is a need for as many TC2 projects as possible — ideally all of them — to be interconnected. He encouraged members to submit written comments by email, with directions provided in a communication to members. Comments will be accepted through Nov. 27, with staff aiming to submit a filing to FERC about Dec. 9, if the board approves the proposal.
“It felt like people had more to say, and we do want to hear what you have to say,” Asthana said.
Proposal to Modify Capacity Market Components
PJM also consulted with the MC at the meeting on a separate proposal that would revise the capacity market to include the output of some resources operating on reliability-must-run (RMR) contracts as supply, revert the reference resource to a dual-fuel CT, and remove the reactive compensation component of the energy and ancillary service (EAS) offset. (See “Insight into Upcoming Filing,” FERC Approves PJM Capacity Auction Delay.)
The 2026/27 Base Residual Auction (BRA) would be the first to use a combined cycle generator as the reference resource, a change that was made in the most recent Quadrennial Review. The higher EAS revenues for CC generators over a combustion turbine unit pushed the net cost of new entry (CONE) value to zero, affecting several parameters derived from net CONE. The variable resource rate (VRR) curve, which defines the slope of the demand curve defining auction clearing prices, would become substantially steeper, and the Capacity Performance penalty rate would fall to zero. (See “Price Cap Increases in 2026/2027 BRA Planning Parameters,” PJM MIC Briefs: Sept. 11, 2024.)
Even with the change, PJM’s Adam Keech said some locational deliverability areas (LDAs) still could see a $0 penalty rate because of the forward price estimates showing a widening spread between gas and electric prices, increasing EAS revenues for all categories of gas generation. The final net CONE will not be known until PJM completes the process of posting the revised planning parameters.
The proposal aims to address those regional impacts by replacing zonal nonperformance charge rates with a uniform penalty derived from the RTO-wide net CONE. Keech said doing so would also reflect the regional emergency capacity deployments PJM tends to experience.
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if PJM has examples of dual-fuel CTs being built in the RTO’s footprint within the past five years, adding that the necessary air quality permits to run the backup fuel would be almost impossible to get in many areas, particularly in the regions capacity is needed most.
The reference resource has “to be a resource that can be realistically built,” he said.
Keech said PJM considered several restrictions that would affect the viability of virtually all technologies and looked for the lowest-cost resource that viably can be built. If it were entirely impossible to build a dual-fuel CT across the RTO, the technology would not qualify to be the reference resource, but staff believe there are enough regions where such a unit could be sited to proceed.
Vistra’s Erik Heinle, also speaking for Calpine and LS Power, said a single-fuel CT would be more appropriate as the reference resource by virtue of being viable to build in a wider range of locations.
Constellation Director of Wholesale Market Development Adrien Ford said CTs are “the pure capacity resource,” and setting it as the reference resource would reduce the impact of higher energy revenues on the capacity market.
The inclusion of expected output of generators operating on RMR agreements is aimed at Talen Energy’s 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators outside Baltimore. It would pertain only to agreements accepted by FERC by Feb. 6, 2025, and require that the units be able to operate for the entire delivery year; have sufficient run hours to address transmission violations and capacity emergencies; have deliverable CIRs; and be available for dispatch under emergency conditions unless on outage. The changes would be effective for the 2026/27 and 2027/28 delivery years while stakeholders pursue a more permanent approach to how RMR units interact with the capacity market.
Keech said it is not clear that Brandon Shores would be able to operate in accordance with those requirements because of an agreement with the Sierra Club that mandates that the plant cease coal combustion by the end of 2025, with no plans apparent to convert to alternative fuels. Wagner Unit 3 likely meets all of the criteria, but the RTO still is investigating whether Unit 4 has sufficient run hours to address the transmission needs and be available as capacity.
The RMR units would not be required to take a capacity obligation or enter into BRAs and therefore would not be subject to CP penalties nor included in the balancing ratio. Rather than paying the RMR units as if they had taken a capacity obligation, the proposal would collect capacity revenues and allocate them as credits to consumers assigned a portion of the costs associated with the RMR agreement.
LS Power Vice President of Wholesale Market Policy Dan Pierpont said PJM should ensure that it is considering how the run hours for each of the Talen units may interact. If Brandon Shores cannot operate because of the Sierra Club agreement and Wagner then needs to run more often to resolve transmission violations, that would affect its ability to meet the requirements to be modeled as supply. Keech responded that PJM would address any such interactions.
ACES Power Executive Director of Regulatory Strategy John Rohrbach said PJM is in a bind where it’s likely the Talen units will run through some avenue — either through a modification to the Sierra Club agreement or an emergency order from the U.S. Department of Energy under Federal Power Act 202(c) — but it does not have concrete knowledge of how the generators will be available. He said if PJM believes the RMR units will run one way or another, their output should be modeled.
The third prong of PJM’s proposal — to remove compensation for generators providing reactive service from the EAS offset — is in line with a FERC order finding that consumers cannot be charged for reactive service within a standard range (RM22-2). The commission’s Oct. 17 order provided PJM with more time to submit a compliance filing to determine a transition mechanism to eliminate reactive service, but it also required a separate filing to address how it is reflected in the EAS offset.
The proposed change would be a severable component of the filing, allowing FERC to approve or deny it separately from how it rules on other aspects of the proposal. (See “PJM Details Path Forward on Reactive Power,” PJM MIC Briefs: Nov. 8, 2024.)
BALTIMORE — Getting storage online in Maryland could be a critical piece of the solutions needed to address the sky-high capacity prices PJM recorded in its most recent auction, according to a panelist at a solar and storage conference.
“This is a hands-on-deck moment for Maryland to get these technologies on board,” said Joel Harrington, director of government affairs for REV Renewables, a solar, wind and storage developer. “Sitting in the PJM queue right now, just for transmission-connected storage, are 17 projects … [that] can come online in the next few years.”
Totaling 1.6 GW, those projects represent only the queued-up storage that would be located in Maryland, Harrington said, and getting them online, while not a panacea for PJM’s capacity market problems, is essential. What state regulators, the industry and other stakeholders need to figure out is “what’s going to attract, what’s going to send appropriate price signals” to developers, he said.
PJM capacity prices increased nearly tenfold in the 2025/26 Base Residual Auction in July, jumping to $269.92/MW-day, far above the $28.92/MW-day for the 2024/25 auction. Prices in some parts of Maryland and Virginia hit $466.35/MW-day and $444.26/MW-day, respectively. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)
Harrington and other panelists at the Chesapeake Solar and Storage Association’s Solar Focus 2024 on Nov. 20 debated the options for accelerating deployment of residential and both distribution- and transmission-tied storage, as outlined in a recent report from a Maryland Public Service Commission “workgroup.”
With the passage of H.B. 910 in 2023, Maryland set ambitious targets for getting new energy storage on its electric system — 750 MW by mid-2028; 1,500 MW by mid-2031 and 3,000 MW by mid-2034 — with the goal of creating a “robust and cost-effective” storage market in the state.
The Maryland Energy Storage Initiative (MESI) Workgroup Phase 1 report is aimed at kick-starting the state market to hit the first 750-MW target. Plans for phases 2 and 3 will be developed in subsequent reports.
The workgroup recommends a multipronged approach to market development with a potential mix of utility and third-party owned storage both behind and in front of the meter, including rooftop residential and distribution- and transmission-tied projects.
In front of the meter, utilities might develop their own distribution- or transmission-tied storage or procure projects from third-party developers, the report says. The behind-the-meter market might get a boost from other state programs being developed under other laws, such as the Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B. 1256), which promotes the aggregation of renewables and storage in virtual power plants.
Another new law, H.B. 864, allows behind-the-meter energy storage to be integrated into utility demand response programs as part of a state energy conservation program.
The report stresses the integral role of aggregation in market development, not only within but also across different programs and storage sectors.
“While the financial, environmental and equity-related benefits and costs of individual storage deployments and programs should not be ignored, it is important to focus on designing an energy storage market that maximizes the aggregate value of all energy storage deployments and the entire portfolio of MESI programs for the grid, ratepayers and the state’s policy goals,” the report says. “Some benefits that storage can provide can only be realized through the aggregate behavior of many devices, and therefore these benefits can be difficult to measure at an individual project or program level.”
Non-monetizable Benefits
The MESI Phase 1 report was submitted to the PSC on Oct. 1, kicking off a comment period that ended Nov. 7. The commission is reviewing the comments and will issue an order, though no time frame has been mentioned, according to an email from a PSC spokesperson.
The panelists agreed that a core challenge for state regulators will be setting up market structures that allow storage projects to be fairly compensated for the full range of services they can provide to cut costs for consumers.
The workgroup report recommends upfront incentives in some instances, which could be critical in the residential market, said Jamie Charles, manager for grid services policy at Sunnova, a residential developer.
While cost savings are the main motivation for homeowners to install solar, “storage is really developed for resilience,” Charles said. “So, by providing these upfront incentives and providing these proposals for these grid services programs and these virtual power plant programs, that’s going to really reduce that barrier to entry.”
The report sees either the Maryland Energy Administration or individual utilities setting and distributing such incentives, which could provide a “strong foundation” for the expansion of the residential storage market in Maryland, Charles said.
Kavita Ravi, senior vice president at BlueWave Energy, a solar and storage developer of distribution-level projects, argued commercial projects should not have to pay demand charges that commercial generation projects typically pay.
“There are several benefits that storage can provide that are non-monetizable, so it’s kind of an unfair market overall,” Ravi said. “In order to allow storage to take off in the electric distribution grid, we think it is important to not levy demand charges during charging.”
Utility demand charges usually are based on specific times of highest demand; for example, when extra power is needed on cold winter days or hot summer afternoons. But for storage, demand charges often are based on the assumption that a project always will charge at its maximum capacity, which the industry has argued is not realistic.
Ravi pointed to the concept of a “wholesale distribution tariff” being developed in the Northeast specifically for storage, which “will fairly apportion the transmission costs and then the charging costs as well, which is more thoughtful and fair for storage.”
For transmission-tied storage, Harrington wants multiple options as well, including full- and partial-toll contracts and upfront incentives. A full-toll option “would be a power purchase agreement or long-term contract where you would contract for energy, ancillary services and capacity, so all three of the attributes would be a fixed price,” he said.
A partial toll would be a fixed-price contract for capacity only, with developers free to bid into either energy or ancillary services markets.
Balancing State and Local Control
Flexibility will be critical going forward, Harrington said. “Our markets [are] changing. The uncertainty around the [Inflation Reduction Act] is really making us question, how do we monetize these assets in the next four or five years? So, we need to be nimble.”
All the different procurement and contract options will “attract energy storage at some level,” Harrington said. “Every business is going to have a different option as to which one is going to attract the best investment for their business.”
The panel also talked about the need to streamline interconnection and for state standards on permitting and siting, while still allowing some flexibility for local control.
While developers will continue to look for project sites that are “non-conflict prone,” Harrington called for “the state establishing specific standards, instead of this patchwork of a developer going into each community, each town [where} they have their own set of rules and ways of regulating and permitting projects.
“The balance is being cognizant of local control, respectful of local control … but having siting standards, ordinance standards that communities can at least follow as a base,” he said.
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Nov. 21 endorsed a proposal to create an expedited process to study interconnection requests that would reuse the capacity interconnection rights (CIRs) of a deactivating resource.
The tariff revisions, proposed by East Kentucky Power Cooperative and Elevate Renewable Energy, were approved with 77% sector-weighted support and added to the Members Committee’s consent agenda, which also passed during the committee’s meeting later that day. (See “CIR Transfer Proposal Discussed,” PJM MRC Briefs: Oct. 30, 2024.)
Under the proposal, PJM would study replacement resource requests in parallel with projects sorted into the standard interconnection queue with the aim of offering developers an interconnection agreement on an eight- to 10-month timeline. To minimize impacts on queue timelines, CIR transfers would be studied using the most recent phase 2 or 3 grid model developed for queue clusters.
The process could be initiated within one year of a formal deactivation notice being received. The replacement resource would be required to interconnect at the same substation and voltage as the original resource, though it could be physically located elsewhere so long as it ties in at the same point. The maximum facility output and CIRs would have to be equal to or lesser than the deactivating generator.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said the proposal would allow developers to take advantage of transformers and other infrastructure already in place to avoid supply chain issues causing delays to construction across the U.S.
“This is something that helps avoid some of the supply chain issues to get resources on quicker,” he said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said his members were divided on the motion, with some supporting it as an improvement that would speed development. Others are concerned that interconnection would remain too slow, in part because of the ability for generation owners to wait a year before transferring CIRs, and preferred a design the Independent Market Monitor offered during deliberations at the Planning Committee. If the MRC had not endorsed the proposal, Poulos said some advocates intended to move the Monitor’s proposal as an alternative.
The Monitor’s package would have prohibited bilateral exchange of CIRs and instead created a PJM-administered process to shift headroom from retiring resources to any project in the queue or proposed by a developer that could resolve transmission violations associated with that deactivation.
A third proposal sponsored by PJM at the PC was closer to the endorsed proposal — allowing CIRs to be traded after a deactivation — but would have imposed tighter eligibility limits, including outright barring storage, and required that any replacement resources that prompted network upgrades or would consume available headroom be removed from the expedited process and directed to submit an application to be studied under the wider queue.
The language endorsed by the MRC and MC would allow projects with network upgrades to proceed so long as they cover associated costs. Developers also would be permitted to reduce the scope of a project to avoid network upgrades before proceeding.
The EKPC-Elevate proposal received 51.8% support at the PC during the Oct. 8 vote, while PJM’s design received 40.6% and the Monitor’s received 11.1%.
Monitor Joe Bowring said he does not believe the expedited process would be an improvement, and PJM would continue to face challenges attracting new entry. He suggested it should expand its Reliability Resource Initiative to be retained as a long-term tool to speed interconnections when reliability issues are identified. The initiative — an in-development, interim accelerated interconnection process — would open 50 slots for high capacity factor projects to be added to Transition Cycle 2, allowing them to be studied in advance of projects that have yet to receive a queue position.
He argued that a private, bilateral CIR trading process would introduce delays and create market power for holders of existing CIRs. Owners of deactivating assets would be able to pick the highest bidder for the replacement resource, rather than PJM being able to select the projects that would have the highest impact. Intermittent and storage replacement resources also would not be required to offer into the capacity market, meaning they may not provide the reliability benefit PJM is seeking through the process.
Third Phase of Hybrid Resource Rules Endorsed
Stakeholders endorsed by acclamation a proposal to implement the third phase of PJM’s hybrid resource rules, expanding the model to include non-inverter-based generation paired with storage.
The language is slated to be voted on by the MC on Dec. 18. (See “1st Read on 3rd Phase of Hybrid Resource Rules,” PJM MRC Briefs: Oct. 30, 2024.)
Participation in the energy and ancillary service markets would be along the lines of the Energy Storage Resource Participation Model detailed in Manual 11; capacity accreditation would focus on the storage element of the resource while taking into account the availability of the generation component.
Hybrids with any component subject to the requirement that resources offer into the capacity market also would be subject to the must-offer rule. Hybrids with no component subject to the rule, such as intermittent generation or storage, would not be mandated to participate in the market.
PJM’s Maria Belenky said a friendly amendment was offered following the first read in November to align the binding notice of intent requirement for hybrids with other resource classifications. She said stakeholders pointed out that a different timeline would exist for hybrids than all other planned resources under the original tariff language drafted.
First Read on Quick Fix for Revising Load Drop Estimate Inputs
PJM’s Andrew Gledhill presented a proposal to grant PJM more flexibility to reflect errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast.
The revisions to PJM Manual 19: Load Forecasting and Analysis are being brought as a quick fix — allowing the issue charge and solution to be voted on concurrently — in an effort to have the changes effective for the 2025 load forecast.
Gledhill said the change is intended to account for instances when load management deployments occur at times that participants are operating below their peak load, which would reduce the estimated load drop PJM is likely to receive. That includes holidays when industrial consumers are likely to be offline.
If starting with the premise of peak load contribution rather than what the actual loads would be at that time, Gledhill said it’s likely inaccurate information would be included in the forecast.
PJM’s Pete Langbein said that historically, peak loads were concentrated on hot summer days, but the RTO’s risk modeling has shifted the focus toward winter deployments, when the energy reduction capability can vary more significantly. Load drop estimates are used to calculate unrestricted load for forecasting, capacity compliance and the addback reported to the utility for the following year. The hourly forecasts also are an input into the effective load-carrying capability models used in resource accreditation.
Manual Revisions to Clarify DASR Calculation for 30-minute Reserves
PJM’s Kevin Hatch presented revisions to Manual 13 to document how the day-ahead scheduling reserve (DASR) is used to determine when the 30-minute reserve requirement may be insufficient for procuring adequate reserves.
The Operating Committee endorsed the language as a quick-fix proposal during its Nov. 8 meeting. (See “Stakeholders Endorse Quick Fix Solution on Day Ahead Scheduling Reserve Calculation,” PJM OC Briefs: Nov 8, 2024.)
The 30-minute reserve is set at the greater of 3,000 MW, the primary reserve requirement or the largest active gas contingency, which Hatch said does not reflect the full range of operational risks dispatchers must account for when determining necessary reserves. The DASR calculation accounts for load forecast error and forced outage rates, both of which were factors that PJM sought to include in a dynamic 30-minute reserve formula stakeholders rejected in July. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)
Hatch said the revisions reflect an existing practice and no changes are being made to PJM processes.
Manual 14D Periodic Review
PJM’s Madalin How presented a package of revisions to Manual 14D drafted through the document’s periodic review. The changes would correct grammatical errors and typos, and update communication protocols, including adding a new email address.
The manual also would be updated to document that generators must provide reactive capability curves to PJM before they can come online and that reactive testing must be completed within 90 days of initiating commercial operations.
Members Committee
Comment Period Opens on Cost Allocation Tariff Revisions
PJM told the MC that the Transmission Owners Agreement Administrative Committee had opened a 30-day consultation period on revisions to tariff Schedule 12, which details the solution-based distribution factor (SBDFAX) process for allocating the costs of Regional Transmission Expansion Plan projects (EL21-39, ER22-1606).
The revisions would address a FERC order granting a complaint from the Long Island Power Authority and Neptune Regional Transmission System regarding components of the SBDFAX method.
Merchant transmission facilities would be considered “responsible customers” within the zone they are interconnected to be assigned a portion of the transmission enhancement charges associated with RTEP projects. If material modifications are made to the boundary of that transmission zone, merchant transmission owners would have the option to have the DFAX analysis separated from that zone.
Required transmission enhancements approved by the PJM Board of Managers prior to Dec. 11, 2023, will be located in the zone of the relevant TO, while enhancements approved after that date would be located in the zone where the physical enhancements are sited.
Constellation Energy filed a complaint against PJM at FERC on Nov. 22, opening up another regulatory front in the debate over co-locating data centers at existing nuclear plants (EL25-20).
Constellation alleges that PJM’s tariff is unfair because it does not contain rules for interconnected generators to follow when seeking to provide service to fully isolated, co-located load.
“While nothing in the tariff suggests any prohibition of fully isolated co-located load, some local utilities are taking advantage of the lack of tariff rules to thwart competition to serve large end use loads, thereby delaying by several years and significantly increasing costs to serve data centers that are critical to national security, economic development and other national priorities,” Constellation’s complaint said. “This lack of tariff rules is allowing transmission owners across the PJM system to treat generators seeking to serve fully isolated co-located load differently.”
PJM released guidance for the issue in April 2024, which explains how the RTO has been reviewing co-location. The complaint said that should be included in the tariff. FERC might decide that it has to weigh in on other issues, but those could be dealt with in a paper hearing.
The complaint argues that rules are needed so market participants understand what they have to do to enter into generator co-location deals. They also would ensure utilities understand the FERC jurisdictional rules applicable to fully isolated, co-located load and “cease exercising their monopoly power to thwart competition.”
“It is necessary to establish consistency across the PJM footprint and avoid the current circumstance of each of the transmission owners in PJM deciding whether and to what extent they will follow PJM’s guidance,” the complaint said. “Otherwise, we will be left with a mishmash of co-location rules at the federal level that are driven by the self-interests of each of the transmission utilities.”
That mishmash already is starting to happen based on how different Exelon’s pending rules would treat co-located demand compared to how PPL Electric Utilities dealt with the 300-MW data center co-located at the Susquehanna nuclear plant.
Data centers are a national security priority due to the new technologies driving them, such as artificial intelligence. Their increasing size has made them difficult to connect to the grid, as that often requires new transmission. Building out the required lines takes several years and leads to higher costs for other consumers, the complaint said.
“As a matter of simple engineering, it is more efficient to locate large loads next to large generation, when possible,” Constellation said. “One longstanding option that has been available to any load since the beginning of open access has been to connect directly to a generator either fully independent of the network grid or with a reduced reliance on the grid.”
Data centers have pursued contracts for fully isolated, co-located load, “networked co-located load” where they rely partly on the grid and partly on a nearby power plant, and a “networked load” configuration that relies entirely on the grid. The last two have formal rules in PJM’s tariff, but fully isolated co-located load lacks formal rules, with the tariff also saying nothing that indicates the configuration is inconsistent with the RTO’s rules.
The issue of the less formal guidance on co-location came up when FERC recently rejected the expansion of a co-located data center at the Susquehanna nuclear plant. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) The amendments to the Susquehanna deal were proposed in large part so PJM’s guidance would be binding on the parties.
FERC rejected them in part because it questioned whether the RTO planned to offer interconnection services on equivalent terms to all similarly situated interconnection customers. FERC’s order acknowledged the guidance was “not part of the PJM tariff, has not been approved by the commission and was not before the commission in the instant filing.”
The complaint notes that PJM has completed studies for potential co-located loads at three Constellation generation sites, which indicated none of those would have been able to draw power from the grid.
Exelon reviewed the deal at Constellation’s LaSalle Clean Energy Center in Illinois, but then refused to do so at the other two units, insisting that the generation owner or its customer first must apply for retail service and designate what sort of wholesale transmission service it would take from Exelon. The utility holding company then stopped working with the data center at the LaSalle plant, the complaint said.
Connecting a major data center to the grid can take five to 10 years, and in a global race for new technology, any delay is harmful to the national interest, the complaint said.
“This interconnection delay imposes unquantifiable risks and costs to the national economy and security and advances in AI,” the complaint said. “Each year that hyperscale data centers await interconnection to the grid risks another year of losing ground to competing nations.”
BOSTON — Energy leaders from the U.S. and Canada grappled with the challenges of balancing decarbonization and affordability at the New England-Canada Business Council’s (NECBC’s) Executive Energy Conference on Nov. 20-21, discussing how collaboration could lower the cost of the clean energy transition on both sides of the border.
Retail electricity rates in New England are rising faster than nearly all other regions in the U.S., while Hydro-Québec plans to spend billions of dollars to meet demand growth, which it expects to put “upward pressure on electricity rates.”
To juggle major investments preparing for load growth, upgrading aging infrastructure, and incorporating and balancing intermittent renewables, “there needs to be a different way to look at how the investment is funded,” said Nicola Medalova, COO of National Grid’s New England electric business.
Central Maine Power CEO Joseph Purington echoed Medalova’s concerns, saying the increase of public policy costs in electric rates is “not sustainable.”
“We have to start thinking about public policies and the public policy component of the bill,” Purington said. He wondered if some of those costs should be “spread across as a tax instead of as a part of your electric bill.”
The potential loss of federal clean energy funding with the incoming Trump administration likely will add a layer of difficulty for states looking to meet their climate goals without overburdening ratepayers.
Electricity bills can be a regressive funding mechanism to support public policy initiatives: Rising energy costs disproportionately affect low-income individuals, who often are forced to choose between paying energy bills and covering other essential needs like food and health care.
Discount rates can do only so much to mitigate the issue, Medalova said, adding that rate pressures can drive up economy-wide living costs. “Whenever you give a discount, somebody else is picking up the weight of that bill.”
North of the border, political uncertainty in Canada similarly threatens the availability of federal funding, said Monica Gattinger, a political studies professor at the University of Ottawa. Gattinger said public opinion shows climate change has been “dropping like a stone” in the public’s list of priorities, adding that a conservative government “would likely reverse many, if not all, of these policies.”
Competing Priorities
Speakers at the conference discussed a wide range of solutions to help balance the often competing priorities of affordability, reliability and decarbonization.
Medalova and Purington both emphasized the need to unlock retail demand flexibility, a sentiment that was echoed by several other speakers throughout the conference.
ISO-NE CEO Gordon van Welie highlighted the RTO’s finding from its 2050 Transmission Study that a 10% reduction in the 2050 peak load could reduce the required transmission buildout by about a third.
Winston Morton, CEO of Climative, said there is a large amount of remaining potential in energy-efficiency upgrades. He added that these gains have been constrained by the limited scale of state energy-efficiency programs and the gap in capital needed to finance building retrofits.
“We’ve got to attract private capital into the market as quickly as we can,” Morton said, noting that he sees “a positive return on investment for every retrofit.”
Along with transmission needs, load growth also will pose significant resource adequacy challenges for the Northeast.
“We’ve got to figure out how to balance load growth and electrification efforts with reliability,” said NERC CEO Jim Robb, adding that he is “a big advocate of natural gas generation, because it’s so flexible and it can help meet the afternoon ramp.”
Natural gas is the dominant source of electricity generation in New England, and gas-fired generation has been increasing steadily in recent years.
“There is a critical need for gas throughout the year,” said Richard Levitan, president of energy management consultancy Levitan & Associates.
Toby Rice, CEO of EQT, one of the largest U.S. gas producers, pitched attendees on the need to increase natural gas pipeline capacity into the region.
“We’ve hit a wall,” Rice said. “We just need more infrastructure to connect markets.”
Rice chided environmentalists for opposing pipeline projects and argued that additional gas infrastructure would help reduce emissions by displacing coal or oil.
“They should be supporting pipelines because of their concern for climate,” he said.
While replacing coal or oil with natural gas can bring some emissions reductions depending on how much methane is leaked from the system, coal and oil make up only a small fraction of the generation mix in New England, Québec and the Maritime provinces, apart from Nova Scotia.
Increased gas generation has caused greater power system emissions in New England in the past year, and a long-term rise in gas consumption would likely undermine the climate goals set by New England states. Massachusetts state law includes sector-specific emissions limits with increasingly stringent decarbonization targets through 2050.
Rice also argued that increasing LNG export capacity would drive down global emissions, although the climate case for exported LNG is murky. One peer-reviewed study published in October found exported LNG to have a 33% larger carbon footprint than coal over a 20-year period.
Van Welie expressed skepticism that New England would see new pipelines, citing a lack of customers. However, he stressed that existing resources must not be retired faster than new renewables are deployed, especially with anticipated load growth. An ISO-NE study on deep decarbonization published in October found a significant need for clean, dispatchable resources to balance renewables. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.) The study singled out small modular nuclear reactors (SMRs), synthetic natural gas and multiday energy storage as potential solutions to help meet these needs.
Rudy Cuzzetto, a member of the Legislative Assembly of Ontario, discussed the province’s work to help commercialize SMRs. Ontario likely will have the world’s first full-scale SMR — with a capacity of 300 MW — in operation by 2029, he said.
“The world is looking at Ontario right now,” Cuzzetto said. “We are going to be a powerhouse in Ontario [and] be able to export electricity across the world.”
Québec’s vast hydropower resources also could help to fill the need for dispatchable power, said Serge Abergel, COO for Hydro-Québec Energy Services.
Despite a drop in exports in 2023 from low reservoir levels, Hydro-Québec has indicated that long-term changes to the role that its hydroelectric resources play on the grid could bring savings across the Northeast. (See Québec, New England See Shifting Role for Canadian Hydropower.)
“We are interested in optimizing our grid for our neighbors,” Abergel said. “Let’s have a conversation on regional planning for the long term. Maybe we can save some ratepayer money.”
In theory, increased bilateral transmission capacity between the two countries could provide significant benefits when paired with a surplus of renewables on the New England grid. This would allow New England to export cheap power during periods of excess renewable generation, while enabling Québec to conserve hydropower and send power back to the U.S. during renewable lulls.
Abergel said the company sees “significant savings, especially when you start looking at 2040 and onward.”
Responding to Abergel’s pitch, van Welie said this dynamic would require agreements to provide “a reciprocal benefit” between regions and to ensure Hydro-Québec sells the power back to New England at a reasonable price during periods of low renewable generation.
California regulators approved a $35 million package of clean transportation incentives for fiscal 2024/25, a steep drop in funding that is raising concerns about the fate of programs not funded by the package.
The California Air Resources Board approved a funding plan Nov. 21 that divides the money among three programs:
$15 million for the Clean Off-Road Equipment project (CORE), which provides incentives for the purchase of zero-emission off-road equipment such as forklifts and cargo loaders.
$15 million for the Innovative Small e-Fleet (ISEF) project, which offers incentives for medium- and heavy-duty ZEVs for fleets of 20 or fewer vehicles. There’s also funding for “innovative solutions” such as truck sharing.
$5 million for the Zero-Emission Truck Loan pilot project to help fleets buy zero-emission medium- and heavy-duty trucks.
This year’s $35 million in clean transportation funding compares to a $624 million incentive package approved in 2023, a record-breaking $2.6 billion in incentives in 2022 and a $1.5 billion package in 2021.
“This year’s state budget was a challenging one, with reductions across the board to many key state agencies and programs,” CARB Chair Liane Randolph said. “Funding allocations for air quality and climate change programs were unfortunately no different.”
While last year’s incentive packages were funded by a variety of sources, including cap-and-trade dollars and the state general fund, this year’s funding came only from the state’s Air Quality Improvement Fund.
CARB Executive Officer Steven Cliff said the funding package is aimed at small fleets and small businesses and seeks to benefit disadvantaged communities. The CORE and ISEF programs historically have had more demand than available funds, said Cliff, adding that though the funding is less this year, it’s “certainly meaningful.”
Programs Left Out
CARB’s approval of allocations to only three programs means other incentive programs will go without additional funding this fiscal year. That includes the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), which has helped fund the purchase of more than 14,000 medium- and heavy-duty clean vehicles since it launched in 2009.
As of Nov. 21, the HVIP website said the standard voucher portion of the program was out of money. The program still had funds available in certain set-asides, including those for transit and drayage trucks.
Tim McRae, vice president for public affairs at the California Hydrogen Business Council, said the HVIP funding shortfall comes at a “pivotal point” for the fuel cell electric vehicle industry. New manufacturers and new products are entering the market, giving truck buyers more choices, he said.
“We must have incentives in the next six to eight months to get these platforms off the ground. Otherwise, the whole industry, including customers and end users, will suffer,” McRae said during the CARB board meeting.
In contrast to HVIP, McRae said, the ISEF program has less of a track record, and the CORE program targets vehicles that generally don’t emit as much pollution as the heavy-duty trucks that HVIP targets for replacement.
Among the newly available fuel cell electric vehicles is a zero-emission garbage truck that is being tried out in California. The garbage truck was developed by Hyzon in partnership with New Way Trucks.
In a trial with Mt. Diablo Resource Recovery, the fuel cell trucks demonstrated consistent power over a range of at least 125 miles, including at least 1,300 cart lifts, with greater fuel efficiency than traditional diesel trucks, Hyzon said in an announcement this month.
Nick Barrett with Hyzon said the company was on the verge of closing several large orders for the fuel cell trucks.
“HVIP is absolutely required to complete these sales and get these trucks on the road,” Barrett told the board.
Low-income Programs
The funding shortfall also pits two low-income, zero-emission vehicle incentive programs against each other.
CARB’s Clean Cars for All (CC4A) program has been run for several years by air districts in different parts of the state. More recently, at the direction of the legislature, CARB launched a statewide incentive program for residents living outside of the participating air districts.
CARB announced in September the launch of the statewide program, called the Driving Clean Assistance Program, with $242 million of funding. The program allows low-income participants to scrap their old vehicle in exchange for a grant of up to $12,000 to buy a new or used zero-emission car, motorcycle or e-bike.
Now CARB is struggling to balance the funding needs of DCAP, which brings the low-income ZEV incentive to regions where it previously wasn’t available, and the air district’s CC4A programs, which have a track record of bringing incentives to hard-to-reach populations.
Neither received any funding in the new incentive package. But $14 million recently was shifted from DCAP to the San Joaquin Valley CC4A program.
“Unfortunately, we are basically talking about scraps,” said Randolph, the CARB chair. “We are talking about inadequate funding for getting vehicles to residents that could not otherwise afford cleaner vehicles.”
Randolph said she would work with CARB staff on ways to optimize funding among the DCAP and CC4A programs.
ERCOT says it will recommend that its Board of Directors approve a reliability-must-run (RMR) contract for one of three aging CPS Energy gas units, set for retirement, to maintain reliability in the San Antonio area.
The grid operator also told the Texas Public Utility Commission during its Nov. 21 open meeting that it is working with CPS and CenterPoint Energy to determine whether the latter’s controversial $800 million mobile generators could be moved to San Antonio as an alternative.
“I think this is an elegant solution to a number of issues that we’re facing,” PUC Chair Thomas Gleeson said in response.
ERCOT General Counsel Chad Seely told the PUC that grid operator staff, the two utilities and Life Cycle Power, the generators’ owner and operator, have been discussing moving the larger units and their 480 MW of capacity to the San Antonio area. He said the 15 large generators are the equivalent of two of the retiring plants, Braunig Power Station’s Units 1 and 2, and would provide greater reliability than CPS’ forced outage-prone assets.
That comes from “mainly the diversity of where those units can be located versus having two larger units that have the susceptibility of higher forced outages,” he said. “These are dual-fuel-capable units. They could be located in San Antonio with a higher shift factor. And obviously their start time is about 10 to 15 minutes, versus a longer lead time for Units 1 and 2.”
CenterPoint said in an emailed statement that its “top priority is finding a Texas-driven solution that helps address the growing energy needs of Texans and our strong economy.”
“We are optimistic that we will find a constructive solution that best serves our customers and Texas,” the utility said.
San Antonio’s municipal utility told ERCOT earlier this year that it planned to retire the three Braunig units, which date back to the 1960s, in March 2025. However, ERCOT said the resources, with a combined summer seasonal net maximum sustainable rating of 859 MW, were needed for reliability reasons and issued a request for RMR proposals in July. (See ERCOT, CPS Energy Negotiating RMR, MRA Options for Retiring Units.)
In the meantime, Seely said ERCOT will urge its board to approve an RMR agreement for Braunig Unit 3, the newest (1970) and largest (412-MW maximum summer rating) of the three units. It will ask the directors to defer any decision on the other two units so staff can continue to work on the feasibility of the mobile generators’ move. The board meets Dec. 2-3.
CPS has said each unit must be inspected and repaired — consecutively, not concurrently — if it is to operate beyond its retirement date. The utility has moved the unit’s suspension date up to March 2, allowing time for inspection and repairs that it says will take at least 60 days.
“If the board moves forward with an RMR agreement, that will allow us to move forward with that inspection work at the beginning of March in trying to get that unit back for the summer of 2025,” Seely said. “A lot of work has been done on the technical side. We do believe it is technically feasible to move those 15 units into the San Antonio area.”
“There are many factors being evaluated by ERCOT and the companies involved,” CPS spokesperson Miguel Vargas told RTO Insider in an email. “We remain engaged in ERCOT’s efforts to evaluate this alternative proposal.”
ERCOT says the RMR units will be important in addressing the South Texas export interconnection reliability operating limits staff established this year that will eventually be resolved by transmission projects underway. Their analysis revealed that under certain conditions, such as when high system demand coincides with an outage of a major transmission line or one or more generation units, lines that deliver power from South Texas into San Antonio could be overloaded and possibly lead to cascading outages.
ERCOT’s solicitation for must-run alternatives to Braunig’s retiring units resulted in one response. A 200-MW multi-hour energy storage resource responded within minutes of an Oct. 7 deadline, proposing to start in the summer of 2026 and end March 1, 2027.
The RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. It ended in 2017, thanks partly to transmission facilities that increased imports into the region.
New Rules for Crypto Miners
The PUC approved a new rule requiring virtual currency mining facilities in ERCOT to annually provide information related to their electricity demand, location and ownership, giving the grid operator more transparency into the market (56962).
Under the rule, cryptocurrency miners with a total load above 75 MW will have to register with the PUC as a large flexible load, capable of adjusting their power consumption in response to prices. The facilities must file a five-year projection of expected peak load for each year, including the percentage of load that meets the definition as interruptible. The rolling five-year projection will be repeated each year.
“I think it’s really important that, as we’re looking at [Texas’] load growth, that this help us give ERCOT and the market an understanding of what those actual projections are from the cryptocurrencies’ standpoint,” Commissioner Jimmy Glotfelty said. “Having them look five years out every year is a really important component of this for reliability.”
The rule was mandated by state law as demand associated with virtual currency mining operations has grown rapidly in recent years, according to the U.S. Energy Information Administration.
PUC Completes Beryl Investigation
The commission approved several reports, including its investigation into two major weather events that hit the Houston area: a derecho in May and Hurricane Beryl in July.
At Gov. Greg Abbott’s directive, the PUC assessed local utilities’ emergency preparedness and their response to the two events (56822).
The PUC team made a number of recommendations to reduce the length and effect of power outages, including annual hurricane and storm drills between utilities, new performance standards and heavier fines, and a legal right to restoration timelines.
The investigation’s summary will be added as an addendum to the broader report that all state agencies are required to file ahead of Texas’ biennial legislative sessions. The 2025 session begins Jan. 14.
The PUC also approved:
ERCOT’s biennial report on the operating reserve demand curve, which will eventually be replaced by individual ancillary service demand curves under real-time co-optimization (55999); and
an order finding ERCOT’s proposed ancillary service methodology for 2025 is appropriate and necessary for the market’s proper functioning (54445).
