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November 14, 2024

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NERC Releases Final ITCS Draft Installments

In the final installments of the Interregional Transfer Capability Study (ITCS), released this week, NERC called for “a diverse and flexible approach” to meeting the future transfer needs of the U.S. electric grid.

NERC released the second and third draft ITCS installments on schedule Nov. 4. Part 1 of the study, released in draft form Aug. 28, comprised a transfer capability analysis summing up the current transfer capabilities between transmission planning regions in North America. (See NERC Examines Transfer Capability in Draft ITCS Installment.)

Part 2 includes recommendations for prudent additions to transfer capability that could strengthen grid reliability, while Part 3 lays out recommendations to meet and maintain total transfer capability. The three installments will be combined and submitted to FERC by Dec. 2 as ordered by Congress in the Fiscal Responsibility Act of 2023. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.) FERC will post the report for public comment and then submit a report to Congress along with recommendations for statutory changes.

A fourth document will follow in the first quarter of 2025, covering transfer capabilities and prudent additions from the U.S. to Canada and between Canadian provinces. While this plan goes beyond Congress’ mandate, NERC said earlier this year that the study “would be incomplete without a thorough understanding of the Canadian limits and available resources.”

“The ITCS emphasizes a balanced approach — one that identifies the unique needs of each region and determines where targeted and meaningful investments can make a real difference in ensuring reliability and resilience,” NERC Director of Reliability Assessments and Performance Analysis John Moura said in a statement. He added that NERC would continue “to ensure the [electric grid] is prepared for tomorrow’s challenges without taking a one-size-fits-all approach.”

NERC’s recommended prudent additions were based on the transfer capability analysis in Part 1, which used the transmission planning regions identified in FERC Order 1000 to create two different base cases covering summer 2024 and winter 2024/25. The model mapped existing interfaces, along with potential new interfaces that might be constructed in the coming decade, and used historical weather data to estimate load and resource availability for the future.

NERC defined “prudent additions” as “transmission enhancements … to mitigate grid reliability risks under the most challenging conditions.” Economic issues and cost-benefit analysis were not considered in the analysis.

ITCS authors selected the 2033 resource mix as the basis for their projections, even though interregional transmission projects typically need at least 10 years for construction, because “forecasting demand and resources beyond that time frame becomes increasingly speculative and uncertain.” The impact of added transfer capability during extreme events was then evaluated using a six-step process:

    • identify hours of resource deficiency through calculating available generation and storage, subtracting load and factoring in existing transfer capacity;
    • quantify maximum resource deficiency by calculating the yearly maximum resource deficiency across 12 weather years;
    • identify and prioritize constrained interfaces;
    • allocate additional transfer capability across constrained interfaces;
    • iterate incremental additions until all resource deficiencies are resolved, if possible; and
    • finalize prudent levels of transfer capability.

The authors recommended a total of 35 GW of additional transfer capability across the planning regions studied, with the greatest amount — 14,100 MW — found in ERCOT across the SPP-South connection (4,100 MW) and two entirely new connections to Front Range (5,700 MW) and MISO-South (4,300 MW). NERC noted that even with these prudent additions, it was still not possible to resolve all energy deficiencies “due to wide-area resource shortages.”

The same was true in the California-North region, where the report recommended 1,100 MW of additions on the Wasatch Front connection.

NERC described “various options” that entities can use to mitigate the risks identified in the report and address the recommended additions. Among these are the development of internal resources such as generation and storage, which can reduce the need for external transfers; building new transmission lines or increasing transfer capability with neighboring regions; and demand-side management and resilience initiatives.

“While the study highlights specific needs to improve resilience under extreme conditions, NERC encourages flexibility in meeting these needs through various pathways,” the ERO said, suggesting “enhanced collaboration with regional planning entities, careful alignment with FERC and state policies, and consistent stakeholder engagement to effectively assess, refine and execute strategies.”

In addition, NERC emphasized that “a one-size-fits-all approach may not be solely effective” in overcoming transmission constraints; in particular, the ERO said that a blanket universal transfer capability minimum across regions “could lead to inefficient investments” in areas where transmission capability is already adequate or excessive.

NERC said it hoped the ITCS would “foster collaboration between utilities, regional planning organizations and state regulators” to tackle the transmission challenges facing the grid. It also suggested revisiting the ITCS in the future to account for advances in technology and changes to the resource mix.

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Wash. Gov. Approves Controversial Wind Farm

Gov. Jay Inslee has approved a revised plan for the largest wind turbine farm in Washington, stretching across 24 miles in the Horse Heaven Hills in the southeastern part of the state. 

His approval leaves intact more than three-quarters of the originally requested number of turbines. The proposed turbine farm has drawn criticism for its possible impact on Native cultural sites and on wildlife in the area, as well as its visibility from the Tri-Cities of Richland, Kennewick and Pasco. 

The project has provoked contentious disagreement among several environmental groups, with wind and solar proponents on one side and wildlife preservationists on the other, who raise concerns about the effects on ferruginous hawk nests. 

The state’s Energy Facility Site Evaluation Council (EFSEC) approved the recommendation 4-3 in September. EFSEC posted on its website an Oct. 18 letter from Inslee (D) that said he considered “impacts on habitat, wildlife, tribal cultural resources, public safety and visual aesthetics. I believe this project is appropriately sited. … I also find that the council thoroughly and adequately responded to issues and concerns raised by tribal partners, the community and other stakeholders relating to this project.” 

Opponents of the project have until Dec. 17 to appeal the decision to the state’s courts.  

Inslee has pushed new wind turbine projects and solar panel farms as part of his campaign to trim the state’s carbon emissions. His Oct. 18 letter hinted at his impatience with the Horse Heaven Hills project taking most of 2024 to be approved. 

“We will not meet our state’s urgent clean energy needs if the path to a final recommendation from the council spans multiple years and contains conditional micro-siting process requirements that further prolong final siting approval for a significant portion of the primary project components,” Inslee wrote. “Timely and efficient action by the council is essential to our mission to mitigate the impacts of climate change and provide adequate green energy alternatives. I strongly encourage the council to identify opportunities to increase its efficiency and provide for more timely decision-making. You can expect my office to engage with you on this critical issue before the end of my administration.” 

Project developer Scout Clean Energy of Boulder, Colo., originally made plans for two scenarios, calling for a maximum of 147 of the 670-foot-tall wind turbines or 222 of the 500-foot turbines along a 24-mile east-west stretch along the hills. However, EFSEC decided in February to implement two-mile buffer zones around 60 to 70 ferruginous hawk nests in that area and remove turbines along the north slopes of the hills. 

The company says those buffer zones cut Scout Clean Energy’s number of turbines by roughly half. At that time, the company said those changes would trim the projected 1,150 megawatts of wind power to 236 megawatts. 

Inslee sent the February recommendations back to EFSEC, wanting to increase the number of turbines back to the original estimates. In recent months, EFSEC trimmed some ferruginous hawk buffer zones to 0.6 mile around the nests. In 2021, the Washington Fish & Wildlife Commission changed the status of ferruginous hawks from threatened to endangered. 

The recommendations from September call for a 0.6-mile buffer around the nests, plus a 0.25-mile buffer around historic Native American fire sites, plus a one-mile buffer alongside Webber Canyon, another culturally sensitive spot for the Yakama Nation. 

If the 500-foot turbines were installed, that would trim the number of turbines by approximately 50, from 222 to roughly 172. If the 670-foot turbines were installed, that would cut the number of turbines by approximately 34, from 147 to roughly 113. More precise figures will be calculated later. 

Scout Clean Energy’s original proposal also included two 500-megawatt solar panel farms on the east and west sides of the 24-mile stretch. EFSEC ordered the eastern solar farm removed because of its proximity to sensitive Native cultural sites. 

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SPP Board/Regional State Committee Briefs: Oct. 28-29, 2024

Directors Approve 2025 Budgets, Net Revenue Requirement

LITTLE ROCK, Ark. — SPP’s Board of Directors approved the RTO’s 2025 operating and capital budgets and its net revenue requirement (NRR) on Oct. 29 following a unanimous endorsement by the Members Committee.

The budget includes $296.3 million in expenses, a 7.6% increase ($21 million) from this year’s budget. SPP’s headcount has exceeded 650 to meet an increasing workload, thanks to Western Interconnection market services and FERC orders 881 and 841.

The NRR is budgeted for $204 million, a 6.2% increase from the current $192.1 million. Staffing and related expenses account for about two-thirds of the NRR. SPP’s tariff limits the NRR to a ratio of estimated annual transmission usage, the effective administrative fee. Currently capped at 46.5 cents/MWh, SPP has filed a board-approved increase to 51.5 cents/MWh.

The capital budget was initially set around $35 million, more than doubling the 2024 allocation of $17 million. However, SPP identified projects that could be deferred or eliminated to reduce that spending to $22.1 million.

Independent Director Stuart Solomon, who chairs the Finance Committee, commended staff and the committee for putting together “one of the best budget documents” he has ever seen.

“I think you’ll agree with me that they met the goal of balancing necessary expenses with affordability and member value,” he told stakeholders during the board’s October meeting.

“We started way back in February of this year with a particular goal in mind: to try to bring greater alignment between SPP strategy, our operating plan, the identification of the necessary resources to effectuate that operating plan and, ultimately, the delivery of the budget,” CFO David Kelley said.

Kelley and Solomon both pointed to the NRR’s run rate, or the cost to operate the RTO year to year, as a metric to watch. The NRR’s budgeted run rate next year is a 4.5% increase from 2024.

“I think that’s impressive, given the increasing costs that all of us are experiencing and the amount of new work and requirements that SPP and SPP staff is dealing with,” Solomon said.

Members expressed support for the budget but cautioned SPP about not forgetting who ends up paying for the budget increase.

“We appreciate the additional focus on controlling costs in this particular budget,” Oklahoma Gas & Electric’s Emily Shuart said. “That said, I do want to be transparent about our expectations going forward, and that we don’t find the 4.5% year-over-year increases sustainable or representative of the budget constraints that members like OG&E are facing. This budget is just one cost stream associated with membership that our customers end up bearing.”

“We understand that these are real dollars that we’re asking you all to spend and they show up on ratepayer bills at the end of the day,” Kelley said. “I can assure you that everyone throughout the SPP organization understands that, and we understand that we have to keep costs as low as reasonably possible.”

Dec. 16 Key Date for Markets+

SPP’s Antoine Lucas, vice president of markets, told stakeholders that staff are targeting Dec. 16 to begin building out its Markets+ offering in the Western Interconnection.

The RTO hopes its response to FERC’s deficiency letter will have met with the commission’s approval by then and that it has also executed Phase 2 funding agreements with interested market participants. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

“With those two things, we have everything that we need to move forward with the actual development of the market and the execution of Phase 2,” Lucas said Oct. 28 during staff’s quarterly stakeholder briefings, alluding to the market’s development and delivery.

He said staff have been working “extensively” with Western stakeholders in developing the market protocols. The Markets+ Participants Executive Committee will vote on the new protocol language during its Nov. 12-13 meeting in Portland, Ore.

SPP has also filed its response to FERC’s deficiency letter for the Western expansion of its RTO. It submitted the tariff in June as it seeks to become the first grid operator with markets in both the Western and Eastern Interconnections. (See FERC Issues Deficiency Letter for SPP’s RTO West Tariff.)

Summer Ops Report

Despite summer weather that extended into October, SPP’s Bruce Rew, senior vice president of operations, said demand was high but did not reach record levels. Demand peaked at 54.39 GW in July, short of 2023’s record peak of 56.18 GW.

SPP registered 18 days with loads over 50 GW, one less than 2023 but the third straight year with double-figure 50-GW days. There were only 11 50-GW days total in 2019-2021.

The RTO issued 24 resource alerts or conservative operations calls this year, down from 40 the year before. It did issue a Level 1 energy emergency alert for two and a half hours on Aug. 26, when elevated temperatures and low wind generation resulted in high net load obligations that reached August 2023 levels. Forced outages approached 9 GW, near all-time highs. (See SPP Issues EEA 1 as Heat Scorches Midwest.)

RSC to Engage on Order 1920

The Regional State Committee agreed during its Oct. 28 meeting to collaborate on a cost-allocation process as part of FERC Order 1920’s requirement for a six-month engagement period with relevant state entities or commissions.

The order requires transmission providers to use a 20-year horizon in planning their long-term regional needs.

SPP’s engagement period began Oct. 28 and will end May 5, when the RSC meets in Omaha, Neb. The grid operator has to make a compliance filing next August.

“The six-month engagement period … is requiring that we offer to provide a forum for negotiation of a cost-allocation methodology and/or the state agreement process,” SPP attorney Tessie Kentner said. “The order does specify that if there is an existing mechanism in place, such as the RSC, that can also be used.”

Incoming RSC President Pat O’Connell, New Mexico Public Regulation Commission | © RTO Insider LLC 

Outgoing RSC President John Tuma, a member of the Minnesota Public Utilities Commission, said SPP’s willingness to work with the states is why Minnesota joined the committee.

“You have created a culture within SPP [in which] states are equal partners in this effort and working together to accomplish good things within the RTO structure,” Tuma told SPP CEO Barbara Sugg. “Minnesota values that. We saw the value of RTOs to reduce the cost of energy and providing stable regional grid for us, and so that’s why we joined.”

The RSC also elected its officers for 2025:

    • President: Pat O’Connell, New Mexico Public Regulation Commission
    • Vice president: Chuck Hutchison, Nebraska Power Review Board
    • Secretary/treasurer: Kim David, Oklahoma Corporation Commission

“I’ve been involved in RSC for a couple years. What I’ve found is it’s always an opportunity for improvement and there’s always a new challenge, or new challenges, every year,” O’Connell said. “I’m looking forward to the challenge. Thanks to all for the trust in me and the situation we’re in now, because it looks to be a very easy job.”

Annual Membership Elections

During SPP’s annual meeting of members, the membership re-elected board Chair John Cupparo and independent Directors Susan Certoma and Ben Trowbridge to three-year board terms that begin in January.

Certoma will be serving her third term, and Cupparo and Trowbridge their second.

The membership also elected eight utility representatives to three-year terms on the 23-person Members Committee, where they will serve as proxies for their sectors:

    • Investor-owned utility sector: Tim Wilson (Liberty Utilities) and Denise Buffington (Evergy)
    • Cooperative sector: Zac Perkins (Tri-County Electric Cooperative) and Mike Wise (Golden Spread Electric Cooperative)
    • State agency sector: Robert Pick (Nebraska Public Power District)
    • Independent power producer/marketer sector: Kevin Smith (Tenaska Power Services) and Brett White (Pine Gate Renewables)
    • Public interest/alternative power sector: Christy Walsh (Natural Resources Defense Council)

Most of those elected are incumbents. Pick and Buffington are new, but Buffington is serving the remainder of former co-worker Kayla Messamore’s term before beginning her own Jan. 1. White is filling the remainder of former member Rob Janssen’s term, which ends after 2025.

The membership also approved a bylaw change brought forward by the Corporate Governance Committee that will revise the selection of Members Committee representatives. With FERC’s approval, sector members will be able to nominate committee representatives, who will then be submitted to the CGC for nomination to the membership.

The CGC said that sectors selecting their representatives on the committee would best represent the interests of each sector and would encourage greater collaboration and engagement between the sectors.

More Time to Cure RAR Obligations

The board approved a revision request (RR632), previously endorsed by the RSC and Markets and Operations Policy Committee, that gives load-responsible entities several more weeks to address deficiencies in meeting their resource adequacy requirement.

LREs would have from March 15 to May 15 (an additional 30 days) to cure summer season deficiencies and from Sept. 15 to Nov. 15 (15 extra days) to resolve winter season deficiencies.

The board’s consent agenda included SPP’s annual violation relaxation limit analysis; converting the Reliability Compliance Advisory Group to a user forum, removing the formal requirements of a chair and recorded minutes; member nominations to the Finance, Strategic Planning and Human Resources committees; and revising the SPC to mirror the sector-based composition of the Members Committee.

It also included another RR (RR649) that aims to add value to the network resource interconnection service (NRIS) product by creating an expedited process for designating new network and designated resources outside of the aggregate transmission service study process. It also revises the generator interconnection study process for new NRIS requests, defines deliverability areas and allows existing resources that meet eligibility requirements to use the expedited process.

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PJM MRC Briefs: Oct. 30, 2024

Stakeholders Endorse Issue Charges on ELCC

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Oct. 30 endorsed two issue charges sponsored by LS Power addressing the transparency and functionality of PJM’s marginal effective load-carrying capability (ELCC) accreditation methodology. 

Both were approved by acclamation. (See “LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance,” PJM MRC Briefs: Sept. 25, 2024.) 

LS Power’s Tom Hoatson outlined several design changes that could be made to the methodology, including reflecting higher potential output in the winter when awarding capacity interconnection rights (CIRs), increasing granularity to allow unit-specific accreditation and recognizing improvements made to generators that may increase their performance. 

Hoatson said that because the current approach determines a resource’s accreditation by looking at how it performed during emergency conditions, if a generation owner makes improvements to a unit that underperformed during a performance assessment interval, it could be years until its accreditation could be updated, after another emergency occurs. 

“You’re not able to improve your accreditation unless you have another Winter Storm Elliott event,” Hoatson said, referring to the December 2022 winter storm. 

There is also an incongruence between the risk modeling approach PJM implemented following the Critical Issue Fast Path process last year, which concentrated risk in the winter, and the use of summer ratings to determine the expected output for some generators, Hoatson said. While the issue charge is not seeking a sub-annual market design, he said there is potential to better align risk modeling and accreditation. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said there are circumstances beyond a generation owner’s control that result in a resource being labeled as underperforming and there should be a mechanism to allow for steps to be taken to improve accreditation following an event. 

“This is a must-have for many of us, and I think this will help PJM retain a lot of resources in the future,” he said. 

The issue charge aims to file a proposal with FERC in the first quarter of 2025 to be implemented to whichever auction may be held in December of that year, Hoatson said, noting that PJM has requested a delay of the 2026/27 Base Residual Auction (BRA) and several to follow. 

PJM’s Adam Keech said that for any changes to be implementable for an auction conducted in December 2025, a filing would need to be submitted in March or April. While that timeline is doable, he said it’s important that stakeholders keep the tight turnaround in mind. 

“There’s not much time to get changes in for that auction; we are happy to move through this in an expedited fashion,” he said. 

The second issue charge seeks to add transparency to the ELCC process by encouraging more data sharing with generation owners, publishing assumptions underlying class ratings and establishing a date certain for the posting of planning parameters associated with ELCC assumptions. It also envisions a model that stakeholders could use to estimate accreditation of resources they own or representative stand-ins, as well as the ability to modify assumptions to create accreditation sensitivities. 

“Given the large adjustments recently announced to near-term load growth expectations and continued retirement declarations, it has become increasingly important to determine whether and how the accreditation approach as currently implemented will incent needed investment in new and existing resources to maintain resource adequacy,” the issue charge states. 

Vote on Issue Charge to Establish SATA Rules Deferred

Stakeholders deferred action on an issue charge brought by PJM to explore rules to govern battery storage as a transmission asset (SATA) after several argued that members may be inundated with other issues over the coming months. (See “PJM Proposes Reopening Discussion of Storage as a Transmission Asset,” PJM MRC Briefs: Sept. 25, 2024.) 

The motion made by Adrien Ford, Constellation Energy director of wholesale market development, delays action on the issue charge any earlier than February and requires completion of education on the subject at the Operating Committee as well. Ford said stakeholders are being asked to consider numerous issue charges at once and it’s important that the issue charge is written correctly to avoid having to go back to the drawing board, which requires education before moving forward. 

Delaying action was broached by Erik Heinle of Vistra, who noted that stakeholders are also juggling PJM’s Reliability Resource Initiative — which would create a special application window for high-capacity factor resources to enter the second transitional interconnection queue — and a possible Federal Power Act Section 205 filing to revise aspects of the capacity market. 

“When I look around at the most burning issues right now, we’re at a place where we’re trying to put the fires out … and I don’t know that this fits in, so I’m wondering if it makes sense to push this back six months,” he said. 

PJM Director of Stakeholder Affairs Dave Anders said the issue charge sought to delegate the work to the OC in an effort to avoid adding to the workload of other committees already working on other major topics. Heinle responded that members tend to have the same staff working on issues across PJM’s working groups, and, regardless of the venue, another issue charge would add to their responsibilities. 

The RTO also opted to avoid discussion of dual use for storage assets — allowing them to simultaneously act as both transmission and market resources — because of the extensive stakeholder engagement that may entail. 

“Dealing with that dual-use aspect will probably be more time consuming, and we would like to move forward with the operational aspect of it,” Anders said. 

Independent Market Monitor Joe Bowring stated that “there is no logical difference between storage as a transmission asset and a generating unit as a transmission asset. Storage is a competitive market resource in PJM. The MMU opposes the inclusion of competitive market resources in transmission owner rate base because it creates a slippery slope towards rate base rate of return regulation which some are already promoting more broadly.” 

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said advocates broadly support expanding implementation of storage, and while there are some who are frustrated that the issue charge precluded dual use, they support it. He said some advocates may seek further changes to the rules for market-oriented storage resources through the Public Interest and Environmental Organization User Group. 

Calpine’s David “Scarp” Scarpignato said he is concerned about the prospect of creating a class of regulated transmission assets that could be dispatched to address transmission constraints and the impact that could have on PJM’s markets. He questioned how it could be determined which type of resource would be dispatched under various circumstances. 

“You can’t have somewhat regulated resources being paid for and then expect competitive resources to jump in or participate,” he said. 

CIR Transfer Proposal Discussed

The MRC discussed a proposal to create an expedited process for studying resource interconnection requests that would be using CIRs from deactivating generators.  

A page turn of draft tariff language is scheduled to be conducted during a special session of the MRC on Nov. 14. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.) 

The package is the continuation of the stakeholder coalition endorsed by the Planning Committee on Oct. 8, which won out over proposals from PJM and the Monitor. 

The defining feature relative to the PJM approach is permitting any resource type to receive CIRs and take advantage of the expedited process; the RTO would have categorically excluded storage resources and applied a material adverse impact standard, which opponents argued would effectively limit it to resources of the same fuel type. The process would be limited to projects sited at the same substation and at same voltage as the retiring unit. 

Donnie Bielak, PJM director of interconnection planning, said the RTO’s primary concerns with the coalition package were addressed by the inclusion of a wider set of studies that would be conducted on the impacts a project may have on the grid. Projects’ significant network upgrades would be bounced to the standard interconnection queue, while those with minor upgrades or none at all would be permitted to proceed in the parallel queue. 

The studies would be conducted on the latest phase 2 or 3 model in the wider queue, which Bielak said would result in minimal disruption to the processing timeline for other projects. 

Bowring said allowing bilateral trading of CIRs would create market power for retiring resource owners and could slow resource replacement by allowing those rights to be held for a year before they are transferred. He added that there would be no consideration of the reliability value of the replacement resource nor a requirement that it offer into the capacity market. The Monitor’s proposal would have allowed resources to move to the front of the queue if they resolved a reliability issue and committed to a specific in-service date and being a capacity resource. 

The Monitor’s proposal would have created a PJM-administered process where generation owners could propose new projects to mitigate any transmission violations prompted by a resource deactivation. Any CIRs not transferred through that process would be made available to others in the interconnection queue. 

Elevate Renewables’ Tonja Wicks said this would not be a process where generation owners are handing CIRs over to the highest bidders. Instead, they would be intending to replace their resources with new units at the same location to bring new assets online as quickly as possible. 

PJM Revives Proposal to Sunset Clean Attribute Procurement STF

Clean Attribute Procurement Senior Task Force (CAPSTF) facilitator Scott Baker, PJM business solutions engineer, presented a proposal to sunset the group as states gravitate toward a clean attribute trading program outside of FERC jurisdiction. 

PJM had broached terminating the group during the MRC’s October 2023 meeting, stating that the task force had run its course when its three proposals were rejected without a clear path forward. PJM dropped its recommendation to sunset at the next meeting, and the committee voted against a motion to close the task force. (See “Vote to Close Clean Attribute Group Fails,” PJM MRC/MC Briefs: Nov. 15, 2023.) 

The task force was formed in April 2022 following MRC approval of an issue charge to consider changes to PJM market design to facilitate the creation of a regional, voluntary market for trading clean resource attributes. The discussions yielded three packages, all of which failed to receive majority support in a poll conducted in May 2023. Following that poll, several states formed the Forward Energy Attribute Market (FEAM) Working Group to discuss possible market design and jurisdictional issues. Though the working group was not affiliated with PJM or the Organization of PJM States Inc. (OPSI), its meeting documents can be found on the latter’s website. 

According to a legal and jurisdictional analysis consensus report presented in May 2024, both state-defined renewable energy credits and clean energy attribute credits could be sourced from any qualifying resource and traded among voluntary buyers, such as companies and municipalities with clean energy targets. 

The report states that the credits would not be bundled with the sale of energy and therefore would not fall under FERC’s jurisdiction. It would also not require that states recognize each other’s definitions for qualifying credits, nor would it transfer one state’s authority to another — thereby not requiring congressional approval to establish. Instead, it might take the form of a designated contracts market subject to the U.S. Commodity Futures Trading Commission. 

1st Read on 3rd Phase of Hybrid Resource Rules

PJM’s Maria Belenky presented a package of governing document revisions to expand the RTO’s rules for hybrid resources to include non-inverter-based generation paired with storage.  

The Market Implementation Committee endorsed the revisions Oct. 9. (See “Third Phase of Market Rules for Hybrid Resources Endorsed,” PJM MIC Briefs: Oct. 9, 2024.) 

The hybrid rules would not be applicable to combinations of non-inverter and intermittent generation units, which would be classified as co-located resources. Belenky said PJM is not foreclosing a future pathway for an additional stakeholder discussion on creating a hybrid model for such resources. The rules for non-inverter-based hybrid participation in the energy and ancillary services markets would be based on the Energy Storage Resource Participation Model detailed in Manual 11. 

The revisions would also specify that a hybrid with any component that is subject to the requirement that resources offer into the capacity market would also be subject to the must-offer rule. Hybrids with no component subject to the rule would not be mandated to participate in the market. 

They would also make clarifications to the existing hybrid rules and align language across the governing documents and manuals. That includes defining how generation owners may determine whether the storage component of a hybrid would be offered as a closed loop, incapable of charging from the grid, or an open loop. Belenky said that if the battery is physically or contractually able to charge from the grid, it must be offered as open loop, but there may be circumstances in which the resource owner may wish to operationally limit it to closed-loop usage. 

The revisions would allow generation owners to change loop classification according to the existing technology change rules. A capacity resource is permitted to change its ELCC class once every five years with a request submitted by Aug. 1 of the year prior to the relevant BRA. Energy-only resources can make such a change every year with a request made by May 30 of the previous calendar year. 

Other MRC Business

PJM’s Michele Greening presented a first read on tariff and Reliability Assurance Agreement revisions drafted by the Governing Document Enhancement and Clarification Subcommittee. The changes include removing sunset terms and obsolete references, correcting drafting errors and clarifying instructions. 

PJM presented revisions to manuals 3 and 10 drafted through the documents’ periodic review. The changes to Manual 3: Transmission Operations would update links and references, clarify the process for revising timely transmission outages, and reflect existing practices on facility ratings. The Manual 10: Prescheduling Operations revisions would clarify how outages for inverter-based resources are reported in eDART, specify that work on forced outages must be completed before planned outages can start and correct an exhibit showing the time the day-ahead market closes. 

PJM’s Suzanne Coyne gave a first read on revisions to Manual 28: Operating Agreement Accounting to expand the lost opportunity cost (LOC) formula to hybrid, storage and solar resources. The formula currently only applies to wind resources. 

The committee endorsed tariff revisions to make PJM’s creditworthiness review of bilateral capacity transactions more proactive. The revisions would require that auction-specific and locational unforced capacity transactions be submitted to PJM in advance for credit review and advance approval. PJM would be expected to approve transactions submitted prior by 1 p.m. by the end of the next business day; submissions made after 1 p.m. would be complete within two days. The credit risk of all parties to the transaction and its potential market impact would be considered in the review. The proposal was added to the Members Committee’s consent agenda by acclamation following the MRC meeting.

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NCUC Approves Latest Duke ‘Carbon Plan’ to Expand Renewable, Nuclear and Gas Generation

The North Carolina Utilities Commission issued an order Nov. 1 approving Duke Energy’s consolidated Carbon Plan and Integrated Resource Plan (CPIRP), which is meant to meet state-mandated carbon emission cuts and improve system reliability.

The plan was the first biennial CPIRP since NCUC approved the initial one at the end of 2022. Determining the least-cost path to cutting carbon emissions while maintaining system reliability is a complex and iterative process, the regulator said.

NCUC has directed Duke to pursue every opportunity, including tax incentives and federal funding, to cut costs for consumers. Duke has delivered electricity at rates below the national average for decades, and the regulator said it would work to ensure that record is maintained.

The order waived the requirement to model a 70% carbon cut by 2030, agreeing to extend that to 2032 and telling Duke to pursue 70% carbon cuts by the earliest date possible.

The order approves a settlement between Duke and the commission’s Public Staff, which is the state’s consumer advocate. The settlement also was agreed to by Walmart and the Carolinas Clean Energy Business Association.

“We believe this is a constructive outcome that allows us to deploy increasingly clean energy resources at a pace that protects affordability and reliability for our customers,” Duke said in a statement on the CPIRP. “The order confirms the importance of a diverse, ‘all of the above’ approach that is essential for long-term resource planning and helps us meet the energy needs of our region’s growing economy.”

The CPIRP requires Duke to retire its remaining coal plants, which total more than 8,000 MW, by 2036.

Duke will conduct two competitive solar procurements in the next two years, targeting 3,460 MW of new solar generation that can be placed into service by 2031. It also will procure 1,100 MW of battery storage, which includes 475 MW of standalone storage and 625 MW paired with solar, to come online by 2031.

The order calls for Duke to procure 1,200 MW of onshore wind to come online by 2033, including at least 300 MW targeted for commercial operation by 2031.

NCUC approved new natural gas capacity as well, with 900 MW of combustion turbines to be developed by 2030 and 2,720 MW of combined cycle capacity coming online by 2031.

Duke will try to build 1,834 MW of pumped storage hydropower at the Bad Creek Hydroelectric station in South Carolina, which would be placed into service by 2034.

The order authorized early development of 300 MW of advanced nuclear generation to go into service by 2034 and an additional 300 MW for the next year. Duke also was authorized to work on extending its operating licenses for its existing nuclear plants.

For offshore wind, the CPIRP authorizes Duke to start gathering information regarding the development of up to 2,400 MW off the North Carolina coast to be in commercial operation by 2035.

The order also requires Duke to continue planning for a 1% load reduction through demand-side management and energy efficiency. It calls on Duke to work with large customers to manage load for the benefit of all customers.

Commissioner Jeffrey Hughes filed a concurrence saying that while the order will lead to benefits, the NCUC could have spent more time analyzing the potential costs associated with climate change.

“I would have liked to see more acknowledgement that producing carbon emissions, whether directly through the combustion of gas or coal or indirectly through the production and delivery of those fuels, carries a significant economic cost in terms of climate change,” Hughes said.

The order was criticized by those who want the state and Duke to move faster to cut emissions. The nonprofit Ceres, which encourages investors to address climate change, welcomed the required clean energy procurements but objected to the timeframe.

“Leading businesses across North Carolina have supported the state’s plan to reduce power sector emissions by 70% by 2030, both to reduce their own exposure to climate risk and to experience the economic benefits of clean energy investment,” said Ceres Director of State Policy Mel Mackin. “This decision not only delays that goal, but it also sets a worrying precedent.”

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SPP, AECI Release Draft Joint Study to Stakeholders

SPP and Associated Electric Cooperative Inc. (AECI) have given stakeholders until Nov. 15 to review a draft study that has identified potential joint transmission projects mutually beneficial to the grid operators. 

The 2024 Joint and Coordinated System Planning (JCSP) study found several projects of interest to SPP and AECI. Several of the projects also are in SPP’s 2024 Integrated Transmission Plan (ITP) portfolio that recently was approved by the RTO’s board. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.) 

“Some of these projects may look very familiar,” SPP’s Clint Savoy, manager of interregional strategy and engagement, said during a Nov. 1 meeting of the AECI-SPP Interregional Planning Stakeholder Advisory Committee. “We tried to cast a wide net with this study.” 

Savoy said it was unlikely any of the projects in the report would replace any from the ITP, but that staff were looking for projects with “even the smallest potential for cost sharing.” 

The 2024 JCSP study horizon included modeling the transmission system for the next 10 years, which will provide lead time so appropriate approvals may be obtained, and project owners can begin work promptly. 

The grid operators plan to review the feedback and issue a final report. They will continue to filter through the list of projects and determine which ones, if any, meet the qualifications for sharing costs. 

The AECI-SPP joint operating agreement requires staff to conduct a JCSP study every other year to ensure the reliable, efficient, effective planning and operation of the transmission system along the grid operators’ seam.  

MMU Releases Summer Report

SPP’s Marketing Monitoring Unit has released its quarterly State of the Market Report for the 2024 summer. The report, covering June through August, indicates day-ahead and real-time prices dropped during the season, driven predominantly by lower gas prices. 

Day-ahead prices decreased 17%, from $35/MWh in 2023 to $29/MWh in 2024. Real-time prices also fell 17%, from an average of $32/MWh in 2023 to $27/MWh in 2024. 

The system’s average hourly load was 3% above 2023, while the peak hourly load was down 3% compared to 2023. 

Wind resources accounted for 30% of SPP’s total generation during the summer. A year ago, wind was 24% of the generation mix. Coal generation fell from 34 to 28%. 

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Data Center Opportunity is Strong, Expanding, PSEG CEO Says

The FERC ruling that blocked the proposed expansion of a data center in Pennsylvania isn’t a hindrance to developing data centers in New Jersey, Public Service Enterprise Group CEO Ralph A. LaRossa said in a third-quarter earnings call Nov. 4. 

LaRossa said PSEG has received a surge in project inquiries and proposals and is well positioned due in part to its spare nuclear generating capacity and a state tax-break program enacted in July. 

On Nov. 1, FERC rejected an amendment to Talen Energy’s interconnection service agreement (ISA) with PJM and PPL for a proposed expansion of Amazon Web Services’ 300-MW data center in Pennsylvania. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

“We are aware of the FERC technical conference and decision on Friday,” LaRossa said, adding that “we will continue to look for clarity on this issue going forward. That said, we believe that data center demand will continue to grow.” 

PSEG is the sole owner and operator of the Hope Creek nuclear plant in Salem, N.J., and the operator and majority co-owner of two adjacent nuclear plants, Salem 1 and Salem 2, with Constellation Energy the minority co-owner. The company considers the three plants key to its ability to meet the future needs of data centers and artificial intelligence development projects, which the state’s economic development planners also are courting. (See PSEG Plans for 80-year Nuclear Generation in NJ.) 

LaRossa called the FERC ruling on the Talen Energy project a “very narrow decision” that was “specific” only to the facts put forward by the parties involved in the Pennsylvania case.  

“It has not slowed us down, and will not slow us down, from trying to help the state of New Jersey meet their economic development goals,” he said. “We continue to pursue contracting of our nuclear output at long-term, attractive pricing with low execution risk that can also help attract new technology-based businesses to New Jersey.” 

The utility’s nuclear fleet has room for expansion and the utility is “pursuing thermal inefficiency upgrades” that could increase the output of the three Salem units by 200 MW, LaRossa said. 

Co-location Factors

LaRossa said the utility recently updated the load study, part of an annual submission to PJM, which reflects the interest in putting data centers in the territory served by the utility. 

“Our existing data center peak load currently stands at approximately 350 MW, and these sites are expected to expand by about 170 MW over the next 10 years,” he said. “We have also received formal applications to initiate nearly 400 MW of new data center load and inquiries over 1,200 MW of data center feasibility studies in new business.  

“These amounts do not represent firm commitments, but they provide an indication of the increase in interest,” he said. He cited the example of an announcement by Roseland, N.J.-based CoreWeave that it had signed a lease to convert a 280,000-square-foot former laboratory and manufacturing building into a $1.25 billion data center. 

“New Jersey has numerous locations that can be re-utilized in a similar fashion, and the state’s economic development efforts are focused on replicating this activity throughout the state,” he said. Potential developers are likely to be swayed in varying amounts by three factors, he said: to what extent a project represents “additionality,” or the creation of new renewable energy; the time it will take to get the project up and running; and the reliability of the energy source. 

“We believe we’re in pretty good shape on all three of those factors,” he said. “And that’s why we haven’t indicated at all that we’re backing down.” 

He said the utility is open to co-locating a data center next to one of the nuclear plants, for which potential clients typically would look at factors such as how much the utility charges for the energy and the transmission, and at the level of taxes. Those factors will determine whether the state can attract a “hyperscaler,” or large-scale data center, to the area, he said, noting that Gov. Phil Murphy (D) in July signed a law that would allocate $500 million a year in tax breaks to artificial intelligence data centers.   

In a separate issue, LaRossa said PSEG has submitted a proposal to the New Jersey Board of Public Utilities (BPU) offshore infrastructure solicitation, the results of which are expected to be released by the end of 2024. (See NJ Offshore Infrastructure Plans Spark Electromagnetic Fears.)  

The utility also submitted bids to PJM’s 2024 Regional Transmission Expansion Plan Window 1, LaRossa said. The solicitation seeks proposals to meet the RTO’s needs stemming from ongoing load growth.  

PSEG’s third-quarter results for 2024 exceeded those in 2023. The company reported net income of $520 million ($1.04/share), compared with $139 million ($0.27/share). Non-GAAP operating earnings for Q3 2024 were $448 million ($0.90/share), compared with $425 million ($0.85/share) in the same period in 2023. 

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NYISO Management Committee Passes 2024 Reliability Needs Assessment

The NYISO Management Committee on Oct. 31 passed the draft Reliability Needs Assessment and recommended that the Board of Directors approve it at its next meeting.

The assessment has identified a reliability need in New York City starting in summer 2033 and “continues to demonstrate a very concerning decline in statewide resources margins such that by 2034 no surplus power would remain without further resource development,” according to the executive summary.

The committee passed the assessment unanimously via secret, emailed ballot. Some stakeholders abstained from the motion, according to the final writeup of the results.

The New York City need is driven by increased peak demand, limited additional supply and the assumed retirement of the New York Power Authority’s small gas plants based on compliance with state climate legislation, NYISO found. Additional generators were also assumed to be unavailable because of the Department of Environmental Conservation’s peaker rule.

Consolidated Edison, the transmission owner and local utility, also identified reliability violations in the 138-kV Greenwood transmission load area, but because these reliability violations occur on the non-bulk power transmission facilities, they are not actionable under NYISO’s assessment. The ISO wrote that these issues are being brought up so that developers can address both needs holistically.

NYISO was facing a statewide reliability need until it revised some of the incoming large loads, representing about 1,200 MW of cryptocurrency miners and hydrogen plants, to be “flexible.” (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.)

Stakeholders raised concerns about this finding similar to those in prior meetings.

“There’s no requirement that’s imposed on these [crypto miners]. There’s no certification from a CEO, as we have in many other instances. There’s no filings. There’s no commitments. There’s nothing in writing at all. It’s simply that we don’t think they’re going to be there” said Kevin Lang, representing New York City. “If Bitcoin goes through the roof, and now it’s cost-justified to be running those cryptocurrency mining operations 24/7, what is going to prevent them from doing that? Nothing.”

Lang went on to say that he knew this wasn’t going to change how the RNA would go, or how the vote would go, but that he wanted to register a large concern. He wasn’t the only stakeholder to voice this concern. Others mentioned the potential for cryptocurrency miners to pivot to AI.

“Yes, we are making an assumption here,” NYISO’s Zach Smith said. “We think it’s based on a good amount of information that we’ve gotten directly from these loads. … Without question this is an assumption we’re going to continue to revisit time and time again.”

Other Committee Actions

National Grid’s Transmission Control Center director, Matthew Antonio, was elected vice chair of the committee.

The committee also unanimously passed a motion to ask the board to approve the proposed $1.306/MWh Rate Schedule 1 for the 2025 budget year. The recommendations include a 2025 revenue requirement of $202 million. The committee further recommended that spending underruns and overcollections of RS1 be used to pay down debt or reduce anticipated debt.

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Constellation Pushes Ahead on Co-located Data Centers

Constellation Energy remains bullish on data centers co-located with nuclear power plants despite FERC rejecting terms for the expansion of one such agreement in a high-profile ruling. 

Data centers are critical to the economy and national security of the United States, and co-location is among the best ways to get them built quickly, CEO Joe Dominguez said Nov. 4 during a call with financial analysts. 

The nation’s largest nuclear power plant operator is working to restart the reactor it owns at the former Three Mile Island station to help meet the projected rise in power demand. 

Constellation already has signed a power purchase agreement with Microsoft for the zero-carbon output from the reactor, which has been renamed the Crane Clean Energy Center. 

Dominguez noted the company could boost its nuclear generation an additional 1 GW or more through uprating the facilities and said customers have expressed interest in contracting for that output. 

The Nov. 4 conference call was intended to provide details and take questions on Constellation’s third-quarter financials, but Dominguez immediately launched into his thoughts on FERC rejecting terms of the deal to expand Amazon’s data center co-located at Talen’s nuclear plant (ER24-2172) after a Nov. 1 technical conference. (See related stories, FERC Dives into Data Center Co-location Debate at Technical Conference and FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

Nearly 10 minutes into the call, Dominguez switched to Constellation’s quarterly financials, which once again were strong: GAAP net income was $3.82 per share and adjusted operating earnings were $2.74 per share, up from $2.26 and $2.13 respectively in the third quarter of 2023. 

The company again bumped its 2024 earnings projection higher and said it would grow its earnings per share by at least 13% through 2030. 

Despite this, Constellation Energy stock closed 12.5% lower in heavy trading Nov. 4, a plunge widely presented as fallout from the FERC ruling. 

Dominguez downplayed the significance of the ruling in his opening remarks and again during the Q&A with financial analysts. 

It was a very narrow decision on the proposed interconnection service agreement, he noted. 

“In Constellation’s view, the 2-1 ruling rejecting Talen’s ISA by a fraction of the commission is not the final word from FERC on co-location,” Dominguez said. “We believe that all of the commissioners, including the two who recused themselves from Friday’s decision, understand the critical importance of providing additional guidance.” 

The steps that will allow for co-location could come from FERC, from RTOs or from the private sector parties pursuing the deals, he said. 

Dominguez rejected criticism that co-located behind-the-meter data centers would not pay their share of costs to build and maintain grid capacity and would create capacity problems by diverting so much generation off the grid. 

The data centers still would pay to support the grid, he said, and the nuclear reactors would switch their output back to the grid in times of emergency. Also, he said, if a co-located load had backup power, it could offer that power to the grid. 

“These issues should be brought together and advanced at FERC,” Dominguez said. “Frankly, I think part of the issue with the ISA proceeding is that it did not bring these issues together, and understandably, some of the commissioners want to see the complete package. We will pursue this regulatory clarity while simultaneously pursuing commercial strategies for co-location that are permitted under existing rules.” 

An analyst asked whether Constellation is broadening its strategy in the wake of the ruling. 

“Our foot is on the accelerator, pressed all the way down on deals, whether they’re front- or behind-the-meter,” Dominguez replied. “Speed to market is very clearly the most important thing for customers, and so that’s going to depend on the transmission configuration in different places, and certain places are going to be, frankly, more attractive [than] others for the data economy customers, and we’re going to follow where they need to go.” 

An analyst asked what sort of timeline Dominguez expects for gaining regulatory clarity on co-located loads. 

Dominguez did not know — the FERC decision was not yet 72 hours old by that point, and most of those hours were weekend days.  

“I probably would agree with you that there’s not a quick fix,” he said. “It’s not going to happen tomorrow, but there are a lot of parties interested in moving this forward.” 

Dominguez added: “I think a bigger development wasn’t the ISA, which was a narrow thing, but how do we deal with the comments that came out of the tech conference and craft something globally that addresses those comments?” 

Another analyst asked whether hyperscalers would vote with their feet and look to build their facilities elsewhere, given slow movement in PJM. 

“Where are they going to go? Right? It’s not like it’s a lot better anywhere else than PJM,” Dominguez replied. “They’re not slowing the pace of their investment, but what they’re seeing is that there’s no nirvana out there. There’s no place where you could easily hook up the amount of energy that they’re looking to hook up.” 

He added: “I’ll tell you what won’t be the solution, and I know this with absolute certainty: They’re not going to wait around for 10 years until somebody builds a power plant, transmission lines, to power the data economy. If that’s the U.S. plan, then we’ve got bigger problems than picking the right RTO.” 

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New York DPS Recommends New Method for Determining Peak Hours

The New York Department of Public Service presented a proposal for updating the method by which NYISO determines peak load hours to the ISO’s Installed Capacity Working Group on Oct. 29.

The change would not affect the capacity market load forecast or installed reserve margin and is only being proposed for transmission owners’ capacity obligations to load-serving entities.

Chris Graves, chief of utility programs for the DPS Office of Regulatory Economics, explained that the department was recommending using the top 10 New York Control Area coincident peak load hours on non-holiday weekdays in July and August. This approach would provide a better allocation of capacity costs to LSEs and a more representative rate for retail customers, he argued.

“I want the demand side of the market to understand what hours are important so they can make decisions on how much capacity they want to be buying,” Graves said.

In most years, based on historic data, the top 10 hours will occur on three or more days. In situations where the top 10 hours occur in two days, all zones tend to peak at the same time. Graves said that if the ISO is forced to always use the top three days, rather than just the top 10 hours, the weight of the peak would be diluted, and the peak hours might not be representative.

The effort to identify more peak load hours dates back to at least 2021 when NYISO was considering expanding to more peak load hours so that TOs could use the information when allocating load obligations to generators and other LSEs in the capacity market.

Current practice only identifies the peak hour using reconstituted load data. This means that capacity resources that are not visible to NYISO in the real-time market are added back into the peak load hour as part of the load forecasting process.

Graves said that there is currently no adjustment to add back generation from resources not participating in the wholesale market, like rooftop solar or municipal generators.

In July 2021, NYISO recommended using the coincident peak load from the highest hour of the top three unique peak load days on non-holiday weekdays in July and August using actual load data.

Stakeholders, squinting at dense slides, voiced some skepticism. One stakeholder asked whether this was just making determination of peak hours more complex than necessary.

“Wouldn’t incentives be better if we set capacity accreditation factors in advance so people know what they are? If we set the weighting factors in advance, wouldn’t that improve incentives for load?” they asked.

Graves said it could improve incentives, but he wasn’t sure if it was cost-causative because the weightings change depending on the load shape.

Amanda De Vito Trinsey of Couch White, representing the large customer association Multiple Intervenors, said the group was “fiercely opposed” to the proposal.

Another stakeholder said that a straight average of 10 hours of load would “destroy the incentive to care about the actual peak” because averaging of that length of time would dilute the load.

“We got this yesterday morning, and we’ve been talking a bit, trying to noodle through this … but it seems like more work needs to be done,” they said.