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December 25, 2024

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PJM PC/TEAC Briefs: April 2, 2024

Planning Committee

Stakeholders Discuss Expanding CIR Transfer Issue Charge

VALLEY FORGE, Pa. — PJM’s Planning Committee is considering a change to an issue charge framing a discussion on how capacity interconnection rights (CIRs) can be transferred from a retiring generator to a planned resource in the interconnection queue. 

The issue charge modification, brought by the East Kentucky Power Cooperative (EKPC), would allow consideration of solutions that would include planned resources sited at a different, but electrically equivalent, point of interconnection (POI) from the original generator by striking a paragraph designating such solutions as out of scope. The issue charge was proposed by EKPC and Elevate Renewables and approved by the PC on June 6. (See “Stakeholders Endorse Discussion on Deactivating Generators’ CIRs,” PJM PC/TEAC Briefs: June 6, 2023.) 

Denise Foster Cronin, EKPC’s vice president of federal and RTO regulatory affairs, said ongoing discussion at the Interconnection Process Subcommittee revealed the issue charge could prevent solutions permitting CIR transfer to a planned resource whose POI is on a different breaker, but which is otherwise electrically the same. She said the cooperative’s intent in bringing the issue charge was to ease the process of passing CIRs onto a new resource that would have minimal impacts to the grid, but that the current language ignores the realities of the grid. 

Several stakeholders said just removing the out-of-scope language would open the door to market participants creating their own interpretations of what an electrically equivalent POI could be.  

Vitol’s Jason Barker said the proposed issue charge edits would result in unbounded solution options for CIR transfers, rather than solutions that permit swift transfers at the same, or electrically equivalent, POI as originally intended. He questioned PJM about how it determines electrical equivalence in assessing CIR transfers, to which PJM said it does not have a standard measure.  

Barker expressed concern that, in the absence of agreement on the definition of electrical equivalence, eliminating consideration of expedited CIR transfers only at the same tariff-defined POI could impede the most competitive solutions. 

Independent Market Monitor Joe Bowring said a core focus should be on ensuring competition in the transmission grid and not providing undue access.

Bowring also pointed out that: “The proposal would undermine the newly revised PJM queue process by creating a bilateral queue process that could override the PJM process. CIRs are not a property right. Retiring units should not retain CIRs after the day of retirement. CIRs have value as a result of the upgrades to the transmission system paid for by all transmission customers. In addition, the proposers have failed to address whether they would even agree to offer the replacement resources into the capacity market as renewable resources and storage do not have the same must offer obligation as thermal resources.”

Paul Sotkiewicz, president of E-Cubed Policy Associates, responded that CIRs are property rights that have been paid for by the generation owner seeking to transfer them. 

Asked how PJM would define “electrically equivalent,” the RTO’s Jason Connell said the meaning has not been determined and that should be left up to stakeholders, either through the issue charge or packages to come out of it. 

Transmission Expansion Advisory Committee

PJM Preparing 2 Competitive Transmission Windows in July

PJM is shifting its timeline for running the first competitive window for the 2024 Regional Transmission Expansion Plan and the second round of transmission projects to deliver 3,742 MW of New Jersey offshore wind through the State Agreement Approach (SAA). PJM had planned to open both simultaneously during the first week of July, but Director of Transmission Planning Sami Abdulsalam said the RTO now is targeting the middle of the month and will have a gap of a few days between opening them. (See NJ Opens 2nd State Agreement Approach to Connect OSW with PJM.) 

During recent TEAC meetings, stakeholders suggested that staggering the two windows would allow proposals submitted in the second window to be informed by the projects PJM selected in the first and would avoid straining transmission owner resources in forming proposals for two concurrent solicitations. 

PJM closed the second competitive window for the 2023 RTEP on April 5 and will post window statistics by the April 30 TEAC meeting. The window sought proposals to address concentrated load growth around Columbus, Ohio, thermal violations in the PSEG transmission zone around the Hinchmans substation and the 500-kV Fentress-Yadkin line in the Dominion zone nearing its end of life. The window was shortened to 30 days due to the urgency of the thermal violations in PSEG.

Supplemental Projects

FirstEnergy presented an $18.7 million project to replace a 500/138-kV transformer at its Bedington substation in the APS transmission zone. The unit is about 47 years old and experiencing increasing maintenance issues, the utility said. The project is in the pre-engineering phase with an expected in-service date of Dec. 31, 2027. 

Inspections of three FirstEnergy 345-kV lines in the ATSI transmission zone found deteriorating wood and steel structures, as well as insulators approaching their end of life. The 19-mile Niles-Shenango line has experienced two unscheduled outages due to failed equipment since 2015, the Beaver Valley-Hanna line has had one outage and the Hanna-Mansfield line had two unscheduled outages over that period. The condition of the lines was presented as a future need. 

PPL presented a $244 million project to build a new 500-kV substation, named Bernheisel, to serve a 1,275-MW customer service request in New Kingston, Pa. The project would cut the proposed substation into the Juniata-Three Mile Island 500-kV line, rebuilding the 13.3-mile segment between the new facility and the Juniata substation in the process. The Bernheisel site would include four 500/138-kV transformers, two 138-kV capacitors, a six-bay 138-kV yard and six 138-kV lines. The new load is expected to come online in March 2026 at 40 MW, ramping up to 1 GW in 2030. 

Dominion presented a $23 million project to construct a new 230-kV substation, named Edsall, to serve a data center complex with load exceeding 100 MW in Fairfax County, Va. The new facility would be connected to the Van Dorn substation by two existing 230-kV lines between Van Dorn and the Ox and Hayfield substations. The data centers have an expected in-service date of Oct. 1, 2027.

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PJM MIC Briefs: April 3, 2024

Stakeholders Endorse Proposal on Large Load Capacity Obligations

VALLEY FORGE, Pa. — PJM’s Market Implementation Committee on April 3 endorsed a package revising how capacity obligations associated with forecast large load additions (LLAs) are assigned to electric distribution companies (EDCs).  

The Dominion Energy and American Electric Power (AEP) proposal aims to prevent an LLA expected in a region participating in the Reliability Pricing Model (RPM) from increasing the capacity obligation for Fixed Resource Requirement (FRR) regions and vice versa. 

In prior MIC meetings, AEP’s Joshua Burkholder said once PJM includes an LLA on Table B-9 of its load forecast, the need to procure additional capacity is spread across that transmission zone. When a zone includes both RPM and FRR regions, an FRR entity may be required to procure more capacity than is needed to serve its customers, he said. 

The issue has become particularly prominent as evolving forms of load create pockets of high energy consumption, namely data centers and industrial customers such as steel mills or chip manufacturers, Burkholder said. 

The proposal was revised from the first read conducted at the March 6 MIC meeting to add transparency around how PJM includes LLAs in its load forecast and how they impact auction parameters. The Tariff and Manual 18 revisions would require the RTO to post LLAs and adjusted FRR and RPM scaling factors and align those postings with the pre-auction activity timeline. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,”  PJM MIC Briefs: March 6, 2024.) 

The changes also clarify that EDCs may submit LLAs to PJM, although load-serving entities, electric cooperatives and municipal power authorities may elect to submit their own forecasts instead. 

The package would revise the capacity obligation calculation to exclude any LLAs included in Table B-9 from base zonal scaling factors and add those LLAs back into the equation when determining the obligation peak load input. 

Lynn Horning, of American Municipal Power (AMP), said the transparency additions improved the proposal, but they would not resolve potential downstream issues with PJM lacking a process that ensures accuracy in identifying large load forecasts adjustments submitted by market participants. 

Independent Market Monitor Joe Bowring pointed out the proposal ignores the effect of changes in the forecasts of LLAs on customers outside the affected locational deliverability area (LDA). “If large load additions are forecast prior to the capacity auction but fail to materialize, the costs of the large load addition are spread to other LDAs. This proposal addresses only cost shifting within an LDA but not across LDAs.”

First Read of CIFP Governing Document and Manual Revisions

PJM’s Skyler Marzewski gave a first read of the first phase of governing document and Manual 18 revisions to implement capacity market changes approved by FERC following the Critical Issue Fast Path (CIFP) stakeholder process held last year. (See FERC Approves 1st PJM Proposal out of CIFP.) 

The language reworks the RTO’s resource accreditation calculations, how it models reliability risks and the inputs used to determine how much capacity must be procured in Base Residual Auctions (BRAs) and by FRR entities. The changes are effective for the 2025/26 delivery year except those related to performance testing and penalty charges for demand response resources, which are effective for the 2024/25 delivery year. 

The penalties market suppliers must pay for underperforming during emergency conditions would be reindexed to be based on BRA clearing prices rather than the net cost of new entry, effectively reducing both the hourly penalty rate and annual stop loss limit. 

Resources expected to come online between the conclusion of the auction and the start of the delivery year would be required to notify PJM of their intent to participate in the auction ahead of time. 

Marzewski said the draft governing document and manual language codifying the remainder of the changes approved in ER24-99 is expected to be brought to stakeholders after the 2025/26 Base Residual Auction in July with the aim of implementing the changes by December. 

PJM Provides Guidance on Co-located Load Configurations

PJM’s Tim Horger walked through a posting the RTO issued in March providing market participants with information about the rules around the two configurations for load co-located with generation. Horger told the MIC the guidance reflects the status quo rules and not any new interpretation of existing manual language. (See “Proposed Rules for Generation with Co-located Load Rejected,” PJM MRC Briefs: Oct. 25, 2023.) 

Much of the focus is on co-located load that does not receive network service from PJM, which is not considered FERC jurisdictional and therefore does not pay PJM fees or receive firm transmission service. Under such circumstances, the generator must reduce its capacity interconnection rights (CIRs) by the “highest expected hourly demand” for the load and have system protection facilities in place to ensure that if the generator goes offline, the load also trips and cannot receive any energy from the PJM grid. 

A portion of the resource can serve as a backup generator to the non-network load while retaining CIRs if it can continue to meet its capacity and energy must-offer requirements. The load must be reduced to zero before being served by the backup generator, which must be approved for an outage for the period it is serving the load. 

PJM’s recommended co-location configuration is for the load to receive firm transmission service from the RTO, which will study the network impact of the change and subject the load to service charges. Both the generator output and the load must be metered separately for settlement and operational security under the networked configuration, and the generator is able to retain its CIRs. 

The distinction between network and non-network load is enshrined in the generator’s PJM service agreement and is considered permanent unless the agreement is revised and necessary network upgrade studies are completed. 

The guidance comes after several proposals to rework co-located load rules failed to receive stakeholder support in October 2023. One of the core sticking points between the proposals was whether capacity resources should be permitted to retain their CIRs while serving non-network co-located load if that load could be quickly curtailed to allow the generator to meet its capacity obligation. 

PJM attorney Mark Stanisz said modifying a generator’s configuration would require re-entering the interconnection queue, but at a different point that would not place it at the back of the line like an entirely new resource. Due to the number of factors that could influence the potential network impacts, he said there is no typical timeline for how long the studies may take. 

Horger said the studies are similar to those conducted for a generation deactivation request, though they vary between specific configurations. Any costs associated with reducing CIRs would be assigned to the generator. 

Discussion of Energy Efficiency Resources Continues

Discussion of energy efficiency resources’ role in the capacity market continued after four packages were rejected by the Markets and Reliability Committee on March 20. PJM’s Pete Langbein said staff does not plan to move ahead with a proposal revising its approach to measuring and verifying the capacity offered by EE after its package was rejected alongside three stakeholder alternatives. Langbein said PJM continues to believe that EE rules need to be more robust, and it plans to continue working with stakeholders toward a compromise resulting in a FERC filing. (See “Stakeholders Reject Changes to EE Measurement, Verification,” PJM MRC/MC Briefs: March 20, 2024.) 

Bowring presented on the pathway that led to EE being included in the market, documenting that it was a response to PJM’s load forecasting method that reflected energy efficiency with a four-year lag. When the RTO began including the effect of EE in the forecast without a lag, he pointed out, the explicit tariff language required the removal of EE from the capacity market. While PJM did remove EE from the capacity market, PJM created a convoluted process that continued to pay EE the clearing price despite the fact EE is not a capacity resource under the tariff. PJM’s approach recognizes EE does not help meet the reliability requirement for a given BRA, but nonetheless pays EE the auction clearing prices. Bowring explained the details of the addback mechanism.

Affirmed Energy’s Luke Fishback said the EIA figures capture some of the incentives provided by both states and wholesale market revenues, but according to EIA, results should be interpreted not as predictions of EE, but projections of what EE would be under existing laws and regulations. He asked the IMM and PJM whether and by how much the removal of capacity revenues would reduce the amount of EE projected in the load forecast.

Langbein argued that PJM’s forecasting now accounts for EE and that capacity market revenues being paid to EE providers are not incentivizing program growth or increased energy-saving equipment installation. He pointed to a steady rise in EE participation in RPM even as capacity prices have fallen. 

Other MIC Business

    • Stakeholders closed an issue charge to explore creating an alternative capacity compliance construct for weather-sensitive demand response and price-responsive demand. The discussion was held at the Distributed Resources Subcommittee (DISRS), where package formation has stalled since the only proposal was withdrawn last year, subcommittee Chair Ilyana Dropkin told the MIC. 
    • The committee endorsed a PJM proposal adding synchronous condenser market parameter definitions to its governing documents and manuals. The language would codify existing practices around condense startup costs, condense energy use and condense-to-generate costs. 

Stakeholders questioned the approach the DISRS is taking in drafting potential changes to the rules around solar-battery hybrid resources, arguing that including a broader set of storage resources in any proposal would go beyond the intended scope of the issue charge. MIC Facilitator Foluso Afelumo said an agenda item will be added on the issue charge’s scope for the May 1 MIC meeting. 

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Pro-competition Group Plans to Sue if FERC Reinstates Federal ROFR

FERC has yet to issue a final rule on transmission planning, but supporters of competition for transmission development have said they will appeal it to court if it reimposes a federal right of first refusal (ROFR). 

Order 1000 opened up FERC-jurisdictional, regional transmission lines to competition. The commission’s pending Notice of Proposed Rulemaking would pare that back by granting a ROFR as long as an incumbent partners with another firm on a transmission project. FERC also proposed another ROFR for “right-sizing,” which would apply when an ISO or RTO determines it would make sense to increase the capacity on a transmission line rather than just replace it with new infrastructure at the same capacity. 

“If they proceed to reinstate these two federal ROFRs, then consumers, without question, will take legal action to oppose [them],” Electricity Transmission Competition Coalition (ETCC) Chair Paul Cicio said in an interview. 

ETCC supports expanding transmission infrastructure, but the costs associated with the buildout contemplated by the NOPR’s biggest supporters would be huge, with Cicio saying it could result “in the largest increase in electricity rates in the history of the country.” 

“We support competitively bidding all regionally planned transmission projects to lower costs,” Cicio said. “It’s just that simple.” 

While ETCC and others, including the Federal Trade Commission and the California Public Utilities Commission, support keeping competition in place, many incumbent transmission owners and their trade groups like the Edison Electric Institute and WIRES argue the policy has not played out as expected in Order 1000 and needs reform to actually build out the grid. 

“It was clear after the proposed rule came out that the issue of competitive transmission, and possible restoring rights of first refusal, was highly contentious,” WIRES Executive Director Larry Gasteiger said in an interview. “That follows the history of this competitive transmission process from the get-go from Order 1000. So, I think in a sense, none of that has changed, and the positions over time have probably hardened.” 

The two sides of the argument mean FERC cannot possibly satisfy everyone involved, he added.  

The debate has led to dueling studies, with one side arguing that opening up transmission to competition saves money, while the other argued that those savings do not always come to fruition and that competition can prevent the kind of collaboration that expands the grid. (See Big Savings for Tx Competition Claimed as FERC Considers a New ROFR.) 

For FERC to reimpose the ROFRs, it should have to go through a Section 206 proceeding under the Federal Power Act, in which it must show that it is not working, Cicio said. 

“We think that’s going to be hard to do because there’s ample evidence [that] competitively bid projects, regionally planned, have shown substantial reductions of up to 40% in costs and just and reasonable rates,” he added. 

The transmission and distribution side of the average customer bill has already grown significantly, Cicio argued: Overall bills have gone up 12.5% annually over the past decade when demand growth was generally flat and, more often than not, natural gas was fairly cheap. The wires part of the average bill has gone from 8% to nearly 30% over the past decade, he said. 

“Almost the entire increase in the cost of electricity that consumers are paying is because of a substantial increase and spending in transmission that has not been competitively bid,” Cicio said. He pointed to PJM’s supplemental projects in its transmission planning process, in which projects needed to address local transmission owner needs, such as degrading infrastructure, are not subject to competitive bidding, as they are not regionally planned. 

Gasteiger said the experience with competitive transmission has led to more antagonism in the development process. He also noted that cost savings are not always forthcoming. 

“It’s actually created an environment where you have a bunch of perverse incentives now,” Gasteiger said. “And the whole goal is to see who can come up with or construct the cheapest bid in order to win the ability to build a project. And what we’re finding is in the aftermath of that, they’re using all kinds of escape clauses to recover cost overruns when they go to build the projects.” 

He cited Maine’s experience with the competitively bid Aroostook Renewable Gateway Project to bring onshore wind to market in ISO-NE. The state’s Public Utilities Commission canceled a contract for the project after LS Power said it could no longer build it for its original cost estimate. 

FERC has used competition in the generation space for decades, Gasteiger said. While market rules change frequently, competition is a settled issue, he said. 

“Electrons are fungible, right?” Gasteiger said. “So, it doesn’t matter what the generation source is for creating electrons. And the structure of that portion of the industry lends itself more towards competition.” 

Transmission involves adding new lines to the existing grid, and it helps to be familiar with the local geography, how a new line would fit into the existing system and where existing rights of way are located, he added. 

For Cicio, the difference between the two sides of the industry’s experiences with competition comes down to enforcement. 

“FERC has not enforced Order 1000,” Cicio said. “No. 1, utilities have taken action to avoid it by doing supplemental projects. And No. 2, they have gone to their state legislatures to put in place ROFRs that thence prevents transmission competition.”

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Regulators Approve PNM IRP Despite Staff Criticism

New Mexico regulators have voted to accept Public Service Company of New Mexico’s 2023 integrated resource plan, despite concerns about an escalation in costs and resources since the utility’s 2020 IRP. 

The New Mexico Public Regulation Commission (PRC) voted 3-0 on April 4 to accept PNM’s IRP — even though PRC utility division staff had several criticisms of the plan, including its “incredibly expensive” capacity additions. 

PNM could reduce costs by keeping two gas peaker plants in its resource mix for longer than proposed, staff said. 

Commissioners noted that their approval of the IRP was “narrow,” merely finding that the document’s statement of need and action plan were compliant with IRP rules. The vote did not approve resource acquisitions or costs or determine prudency, steps that will come later. 

“Staff brought up some extremely important points,” Commission Chair Pat O’Connell said before the vote. 

PNM said in its plan that the 2023 IRP “lays out an aggressive plan to achieve a carbon-free portfolio by 2040.” 

“The sustained, rapid pace of new capacity additions needed to meet environmental goals and ensure reliability is unprecedented in PNM’s history,” the IRP stated. 

In a report filed March 14, PRC staff recommended that the commission reject PNM’s plan, saying it did not meet the key objectives of an IRP, namely reliability, environmental compliance and affordability. 

“In the three years since the 2020 IRP, PNM’s net load has not changed significantly and it has not filed a notice of material change with the commission,” staff said in its report. “Yet PNM’s 2023 IRP requires an increase in resources over the 2020 IRP of 2,690 MW at an additional cost of $2.7 billion!” 

Even if adjusted for removal of 300 MW of existing resources and a 500-MW increase in the load forecast for 2042, the increase in capacity additions is 1,890 MW, the report said. 

The increase in resources in the 2023 IRP is because the utility postponed the addition of 480 MW of hydrogen-ready combustion turbines to the 2031-2042 time frame, according to the report. 

As a substitute for the delayed hydrogen-ready turbines, PNM is planning additional solar and battery storage — 800 MW and 905 MW more, respectively, compared to its 2020 plan. 

“PNM represents that it takes over three times as much new solar and storage to provide the same equivalent capacity as hydrogen CT capacity,” PRC staff said in the report. 

According to the IRP, the hydrogen-ready turbines may run on natural gas until PNM transitions to a carbon-free portfolio in 2040. 

The PRC staff report said the four-hour battery storage proposed in the IRP is “overbuilt,” creating a risk of stranded costs when longer-duration storage becomes available. 

In addition, the report said, PNM uses an “island” rather than “integrated” approach to its planning, “by its very limited consideration of regional energy markets and an expanded transmission network.” 

Longer Life for Peakers

The report identified a potential solution to some of the issues it raised: extending the Valencia and Reeves gas peaker plants.  

PNM receives about 155 MW of peaking capacity from the Valencia power plant under a 20-year power purchase agreement ending May 2028. Reeves Generating Station, which the utility owns, is scheduled for retirement in 2031.  

“Extending the lives of the Valencia and Reeves gas-peaking facilities prevents overbuilding [and] out-of-control rate hikes and allows time for the development of long-duration storage,” the PRC staff report said. 

O’Connell said much of what staff said in its report “would have benefited from having a response from PNM.” PNM in February filed a response to issues raised by stakeholders, but the staff report was filed in mid-March, just a few weeks before the commission’s vote. 

O’Connell also cautioned against taking “as fact” the resources detailed in the IRP’s most cost-effective portfolio, particularly in later years. For example, geothermal energy could develop into a more prominent resource in New Mexico. 

“It’s something that could play out over 20 years,” O’Connell said of PNM’s future resource mix.  

“The truth of it is the bids that will be received in the [request for proposals] is what’s going to determine the next resources.” 

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Climate Activists Urge FERC to Reject Results of ISO-NE FCA 18

Climate activists from New England are calling on FERC to reject the results of ISO-NE’s Forward Capacity Auction (FCA) 18, arguing the auction disproportionately favored fossil fuel resources. 

FCA 18 was held in early February and applies to capacity for the 2027/2028 capacity commitment period. The auction procured 31,556 MW of capacity for about $1.3 billion. (See Prices, Renewables Rise in New England Capacity Auction.) 

The auction saw some gains for clean energy resources: Battery storage increased from about 3.5 to 6% of the total capacity procured compared to FCA 17, while solar increased from 3 to 4%. For the second auction in a row, no coal resources gained a capacity commitment, foreshadowing the announcement in March that Granite Shore Power will retire the region’s last coal plant by 2028. (See Last Remaining Coal Resources in New England Set to Retire.) 

However, the majority of the capacity commitments awarded in FCA 18 still went to fossil resources. Natural gas resources accounted for about 44% of the capacity, while oil generators accounted for about 11%.  

In response to these results, activists with the organization No Coal No Gas have submitted comments to FERC arguing the results should be rejected because the auction does not take into account the climate or public health consequences of burning fossil fuels (ER24-1290). 

As the states work to rapidly shift away from fossil fuel generation, “a key barrier we face is ISO-NE’s continued reliance upon outdated modes of decision-making that prioritize short-term financial calculus at the expense of long-term strategic thinking,” said Sonja Birthisel, a member of ISO-NE’s Consumer Liaison Group (CLG) and an environmental scientist associated with the University of Maine. 

The activists also argued that fossil resources often “don’t perform as advertised” during grid stress events. Nathan Phillips, a professor of ecology at Boston University who also is an elected member of the CLG, pointed to ISO-NE’s findings that 36 generators in New England experienced some form of unplanned outage during Winter Storm Elliott, resulting in 2,277 MW of capacity reductions. 

Phillips also wrote that ISO-NE has not tapped into the full potential of demand response resources, which could reduce the need for fossil peaker plants. 

“Demand response is the simplest, most cost-effective and reliable solution to peak demand, which ISO-NE ignores with increasingly deafening silence,” Phillips said, adding that demand reductions could help limit need for additional transmission capacity. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

Responding to the protests, ISO-NE spokesperson Matt Kakley noted more than 2,600 MW of demand resources cleared the auction.  

“Demand response can and does participate in all of our wholesale markets,” Kakley said. “Additional participation at the residential level will need to be driven at the state/retail level,” he added, highlighting a New England Conference of Public Utilities Commissioners working group that’s investigating the role of demand response on the grid. 

Regarding emissions, Kakley said ISO-NE “has no jurisdiction by which to assess the environmental attributes of different resources.” 

He added that ISO-NE has “long recommended carbon pricing as a way to account for environmental factors within the wholesale markets,” but said the RTO would need support from the states to have a chance of FERC approval.  

“Thus far, there has not been state support for carbon pricing in the wholesale markets,” Kakley said. 

Environmental organizations made similar arguments in 2023 in opposition to the previous FCA. FERC ultimately sided with ISO-NE and approved the results, writing that the protests were “outside the scope of this proceeding because they do not bear on the sole question here — namely, whether ISO-NE conducted FCA 17 in accordance with its own tariff rules” (ER23-1435). (See FERC Accepts Results of ISO-NE FCA 17.) 

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NERC Answers IRC Cold Weather Standard Objections

In comments submitted to FERC on April 4, NERC pushed back on the ISO/RTO Council’s objections to its proposed cold weather standard, urging the commission to deny the IRC’s “extraordinary requests” and approve the standard “without further delay.” 

EOP-012-2 (Extreme cold weather preparedness and operations) is under consideration by FERC, having been submitted by NERC on Feb. 16 after its approval by the ERO’s Board of Trustees (RD24-5). If approved, it will replace EOP-012-1, which FERC approved in 2023 with the caveat that NERC must submit a successor within a year to address numerous “undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods” before the standard takes effect in October. (See FERC Orders New Reliability Standards in Response to Uri.) 

The IRC submitted a petition March 21 expressing its members’ “united opposition” to approving the standard as currently written. Despite expressing support for the prevention of cold weather-related outages such as those experienced during winter storms Elliott and Uri, the IRC said the ERO’s standard drafting team had left its “most significant concerns … unaddressed” and approving the standard could lead to more reliability issues, additional work for FERC, and great costs for generator owners and the public.  

It asked the commission to remand the standard to NERC and direct the ERO to submit revisions addressing the IRC’s issues within 120 days. (See IRC Urges FERC to Remand NERC Cold Weather Standard.) 

IRC Called Standard Too Generous

In its filing, NERC summarized each of the IRC’s objections and explained why they did not justify remanding the standard.  

A common theme expressed by the IRC was that the proposed standard gave too much latitude to industry on its implementation, which could create auditing difficulties. For example, the standard would specify that freeze protection measures would not “be limited to optimum practices, methods or technologies,” but could include measures “generally implemented … in areas that experience similar weather conditions.” The IRC suggested revising the standard to require measures “that would reasonably be expected to result in effective … performance.” 

Another concern the IRC identified was that GOs could claim an exemption to implementing some freeze protection measures if doing so would “require prohibitively expensive modifications or significant expenditures on equipment with minimal remaining life.” The council said cost issues were outside the scope of reliability standards and the proposed requirement could “invite a ‘race to the bottom’ as [GOs] face economic incentives to keep their compliance costs lower than those of their competitors.” 

NERC said in its response that while the standard drafting team’s priority was to “provide a high bar for generators that operate in cold weather,” members had to balance this with concerns that high costs or technical limitations might cause generators to choose not to operate in cold weather, leading to increased reliability risks. The SDT also felt that GOs should neither be required to adopt “unproven technologies” nor discouraged from implementing “new freeze protection methods as they are developed.” 

“The commission is not being asked in this proceeding to choose among the ‘best’ or most just and reasonable of all potential options, only to assess whether NERC’s proposed definition is just and reasonable,” NERC said.  

The IRC also objected to excluding generators that do not normally operate in freezing conditions from implementing freeze protection measures, arguing that they may be called on to operate during emergency situations, including in cold weather. It asked FERC to order that all units “that may be committed to operate” in freezing temperatures be required to use freeze protection measures. 

NERC replied that “avoiding undue burden on those generating units that are not expected to operate in cold weather,” even though they may be needed in an emergency, is “a fundamental premise of the EOP-012 standard.” The ERO further observed that FERC’s directive approving EOP-012-1 and ordering a new standard specifically quoted the language exempting those units not typically used during freezing weather — along with the fact that they could be used in emergency conditions — and did not demand any changes to it. 

In addition, the IRC criticized NERC on the time provided for freeze protection measures’ implementation in EOP-012-2— which the IRC wanted to shorten from as little as 24 months to a minimum of 12 months — and for required inspections and maintenance, for which the standard does not provide a time requirement.  

NERC said the freeze protection implementation timelines provided are “based on a reasonable and measured consideration of all relevant factors” and that shortening the default timelines could result in additional administrative burdens from entities requesting deadline extensions. The ERO also asked that FERC delay any move to require specific timelines on inspection and maintenance until data is available on the standard’s overall effectiveness. 

“Should NERC’s experience monitoring the implementation of the standard provide factual support for revising the standard, NERC will promptly initiate its standard development process to make any needed changes and to use all the reliability authorities at its disposal to ensure reliability in the interim,” NERC said. “In the interest of reliability, however, entities must begin to implement the important protections this standard will provide without further delay.” 

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FERC’s Christie: Transmission Can’t be Built Without State Support

The surest way to ensure that transmission is not expanded is to usurp states’ authority, FERC Commissioner Mark Christie said April 4 at WIRES’ Spring Member Meeting in Chicago. 

With the Infrastructure Investment and Jobs Act, Congress directed FERC and the Department of Energy to update their processes on designating National Interest Electric Transmission Corridors (NIETCs) after a federal court curtailed the commission’s backstop siting authority from the Energy Policy Act of 2005. A NIETC designation allows the commission to overrule states that reject lines proposed in the specified area. 

The commission will implement that law because it is a creature of statute, Christie said. But he predicted the changes would have little practical effect. (See DOE Lays out Plans for Designating Transmission Corridors.) 

“The backstop siting authority will last until the point when FERC actually imposes a backstop siting authority on a state that just had a proceeding and found that it was not needed,” Christie said. “That’s as long as it’s going to last because the political blowback is going to be off the charts.” 

While he was on Virginia’s State Corporation Commission, Christie voted to approve more than 100 certificates for transmission lines, from small “wreck and rebuild” lines to the Trans-Allegheny Interstate Line (TrAIL) project, which was the longest regional project built in PJM. That project went through three states, including high-value real estate in Virginia’s Horse Country, where owners did not want it to spoil views of their “10,000-acre” estates, Christie said. 

The opposition was well funded and vociferous, but the line was needed to maintain reliability, he said. 

“And because of the process that we followed and giving the public the opportunity to come in front of their own state body, I think that played a big part in why Virginia politicians didn’t come out in opposition to it,” Christie said. 

If FERC were to overrule a state’s rejection of such a project, all its senior politicians, including its congressional delegation, would oppose it.

“You cannot get stuff built without state buy-in,” Christie said. 

Christie extended the same basic argument to the commission’s Notice of Proposed Rulemaking on transmission planning, the final rule of which FERC could vote on in the coming months. 

“There’s a lot of people running around Congress, ghostwriting letters for congressmen to send to us saying, ‘Well, don’t let the state stand in the way,’” Christie said. “You know, don’t let the states be an obstacle. FERC should just do it. FERC should just impose the cost allocation.” 

He recalled that two of the early, important cases he sat on during his SCC tenure were Dominion Resources’ and American Electric Power’s requests to join PJM. 

“We approved them because we thought regional planning could give us, occasionally, a regional reliability project that would be more efficient than a local project if the facts were there,” Christie said. “And we were willing to let PJM plan those regional projects, but they’re reliability projects.”

The facts are easy to prove for reliability projects, he said; the same can be said for economic projects that make sense as long the benefits outweigh the costs. However, the NOPR (and Order 1000 before it) contemplates a third category: public policy. That is where Christie has some concerns. 

“A public policy project is planned by politicians; [it is] fundamentally different,” Christie said. 

They work in single-state markets, but in RTOs, with multiple states that often have divergent policies, they can lead to problems. 

“If politicians in one state want 100% green energy, that’s fine,” Christie said. “If they want to pay for it. If they’re willing to accept the reliability consequences. That’s fine. But don’t make consumers in another state pay for it, unless they agree.” 

It does not make sense to throw those three categories into a regulatory blender and allocate every type of line across an entire RTO footprint, he added. 

“Even a policy project has reliability benefits,” Christie said. “Well, tangentially it may. You can build a line almost anywhere and get some congestion relief. That doesn’t mean it’s the optimal solution.” 

The way to build transmission projects is to have states buy into them, even when they are incredibly controversial like TrAIL, which is on the same scale of transmission that the NOPR’s supporters most want to see get built. Getting FERC to impose cost allocation on the states if they cannot independently come to an agreement will not work, Christie said. 

“I think that’s a pipe dream,” he added. “I think that’s just totally unrealistic the way things work in America.” 

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PSEG Plans for 80-year Nuclear Generation in NJ

PSEG subsidiary PSEG Nuclear has told the Nuclear Regulatory Commission it plans to request operating license extensions for its three South Jersey nuclear plants, which would enable the oldest plant to continue running until 2056 and the newest until 2066. 

With NRC approval, the plants, which are central to New Jersey’s clean energy goals, would operate until they are 80 years old — almost double the 42 years that is the average age of U.S. nuclear plants. 

The utility told the NRC in a March 28 letter it expects to seek license renewal for the plants — Salem Generating Station Units 1 and 2 and Hope Creek Generating Station — in the second quarter of 2027. The application would trigger a two-year review and approval process for the plants, which generate 3,468 MW of energy, PSEG said in a statement.   

“This early notification is intended to provide the NRC with time to ensure resource availability when the formal applications are submitted in 2027,” the company said. 

The three plants generated 42% of the electricity produced in the state in 2022 and are key to Gov. Phil Murphy’s (D) goal of reaching 100% clean energy by 2035. Solar projects account for about 8% of New Jersey’s in-state production, and construction has yet to start on any offshore wind projects, so nuclear-generated electricity will be essential to the state’s ability to produce clean energy and cut emissions for years to come. 

The state’s Energy Master Plan says nuclear plants will need to be “retained past current licenses” and predicts that in 2050, nuclear plants will produce 16% of the state’s electricity, compared to 34% generated by solar and 23% produced by offshore wind. 

Charles (Chaz) McFeaters, president of PSEG Nuclear, said the company has “safely generated reliable, always-on carbon-free energy” for five decades. 

“Seeking to renew our licenses signifies our commitment to continuing to contribute to New Jersey’s clean energy future and serving as a vital economic engine for the local community,” he said. 

Aging Plant Inspections

There were 54 commercially operating nuclear power plants in the U.S. in 2023, with 93 reactors in 28 states, according to the U.S. Energy Information Administration.  

U.S. nuclear plants initially are licensed for 40 years and can submit an application to the NRC to renew the licenses 20 years at a time. The NRC has completed 61 applications to extend a license from 40 to 60 years, known as initial license renewals, but has completed just three applications to extend a license from 60 to 80 years, known as subsequent license renewal. 

PSEG’s plan follows the announcement in March that Michigan’s 800-MW Palisades nuclear power plant, which was opened in 1971 and decommissioned in 2022, could become the first nuclear plant in the U.S. to be restarted, helped by a $1.52 billion loan from the federal Department of Energy’s Loan Programs Office (LPO). (See LPO Announces $1.52B Loan to Restart Palisades Nuclear Plant.) 

Diane Screnci, a spokeswoman for the NRC, said the agency’s extensive research on nuclear plant aging concluded that “most nuclear plant aging issues are manageable and do not pose technical issues that would prevent them [from] … operating [for] additional years beyond their original 40-year license period.” 

Each reactor is licensed based on a specific set of requirements, called the plant’s “licensing basis,” she said. “The license renewal review process provides continued assurance that the current licensing basis will maintain an acceptable level of safety for the period of extended operation. The renewed license requires ‘aging management programs’ to monitor and manage the effects of continued operation on certain structures, systems and components.” 

The agency conducts an extensive inspection and oversight program at every plant throughout its life, she said.  

Chizi Odidika, media relations manager for the Nuclear Energy Institute, said planned life extensions for nuclear plants are not unusual. 

“Over 90% of our current nuclear fleet intends to pursue operation for at least 80 years,” she said, adding that “extending their lifespan involves significant considerations and investments, including the development of robust monitoring programs to track the aging of key structures and systems.”  

Federal Nuclear Subsidies

PSEG is the sole owner and operator of the Hope Creek plant and the operator and majority co-owner of Salem 1 and Salem 2 plants, with Constellation Energy the minority co-owner. 

The company’s oldest nuclear plant, Salem Unit 1, came online in 1976 and in 2011 was granted a license extension to continue operating beyond the initial expiration in 2016 to 2036. The utility now plans to ask for an extension to operate until 2056.  

Salem Unit 2, which came online in 1980, obtained an extension to operate beyond 2020 to 2040, and approval of the planned request would continue operations there until 2060. Hope Creek came online in 1986 and obtained an extension to operate until 2046. PSEG will seek a license to operate the plant until 2066. 

PSEG’s announcement comes as the Inflation Reduction Act (IRA) this year begins offering nuclear production tax credits (PTC) to nuclear plant operators. PTCs create a credit of $15/mWh for electricity produced by existing nuclear plants. 

PSEG in November told the New Jersey Board of Public Utilities (BPU) the utility would withdraw from the state zero emission certificate (ZEC) program to pursue the federal tax credits. The New Jersey program provides subsidies to nuclear power plants at risk of closure so they can remain open to generate carbon-free power. It paid $10/MWh. 

The BPU twice awarded ZECs totaling $300 million a year to PSEG, in 2019 and 2022, and the company had filed a notice of intent to seek incentives in the next period, which would run from 2026 to 2029. But the BPU shut down the program after PSEG’s withdrawal because there were no remaining applicants. (See NJ Closes Nuclear Subsidy Process as PSEG Looks to Feds.) 

The ZEC process became contentious in the last period, with the New Jersey Division of Rate Counsel, the state’s consumer advocate, and environmental activists arguing PSEG exploited its market dominance to extract an unnecessarily large payoff and didn’t need the maximum ZEC to keep the plants operating. 

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Nev. RTO Effort Turns Focus to NV Energy Day-ahead Studies

In studies predicting NV Energy would benefit more from joining CAISO’s Extended Day-Ahead Market than SPP’s Markets+, a key factor is the benefits the utility would lose by leaving the Western Energy Imbalance Market, a consultant said. 

If NV Energy joins Markets+, it would drop out of the WEIM, the real-time market run by CAISO, and join SPP’s Western Energy Imbalance Service (WEIS). 

Leaving the WEIM would create a loss of nearly $100 million for NV Energy, according to John Tsoukalis with the Brattle Group, which conducted the market analysis for NV Energy.  

“So even when you replace that with the gains you see from joining Markets+ and the gains you see by the Markets+ real-time market … it’s not as beneficial as the EDAM cases you see,” Tsoukalis said during a Public Utilities Commission of Nevada (PUCN) workshop April 3. 

Leaving the WEIM would reduce NV Energy’s access to excess renewables from CAISO in real time, and the utility’s prices for real-time sales would fall, according to the study. 

Other WEIM participants also might feel an impact if NV Energy leaves CAISO’s real-time market, Tsoukalis told RTO Insider, although he noted Brattle hadn’t done calculations for other utilities. 

“I would assume the breaking apart of the WEIM would have a negative impact on the other current WEIM [participants],” he said in an email. 

Market Choice Evaluation

The PUCN opened a docket last year to explore ways to evaluate a utility’s choice of a regional market or RTO. (See Nev. Regulators to Weigh Approaches to RTO Membership and RTO, Day-ahead Choice Closely Linked, Nev. Effort Shows.) 

The April 3 workshop focused on cost-benefit studies for market participation; a workshop to discuss different market designs is slated for April 10 at 10 a.m. 

The latest workshop featured presentations on an Energy+Environmental Economics (E3) cost-benefit analysis that was part of the wider Western Markets Exploratory Group (WMEG) study and Brattle’s study for NV Energy, which the utility released last month. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

The Brattle Group study found that joining EDAM would grant NV Energy $62 million to $149 million in annual benefits. Results of the company joining Markets+ would range from a $17 million loss to a $16 million benefit. The study looked at two scenarios in which it joins EDAM and three in which it joins Markets+, calculating benefits expected in 2032. 

In a scenario that Brattle calls the EDAM bookend case, NV Energy and almost all other Western Electricity Coordinating Council (WECC) utilities join EDAM. 

NV Energy’s trading volumes would nearly double in that case, as the utility would serve as a central hub for trading between California and the Southwest and facilitate transfer of low-cost generation from California and the Southwest into Idaho Power and PacifiCorp East. NV Energy’s annual benefit in the EDAM bookend is estimated at $62 million. 

But the utility’s annual benefit would be even higher — an estimated $149 million — in a scenario called Middle View 1. 

That scenario assumes NV Energy, Idaho Power and Seattle City Light join EDAM, along with entities that have announced an EDAM choice, which now includes Portland General Electric. (See CAISO’s EDAM Scores Key Wins in Contested Northwest.) 

In Middle View 1, the Bonneville Power Administration and most of the Northwest’s publicly owned utilities, Puget Sound Energy, and all Arizona BAAs would join Markets+. 

Middle View 1 gives NV Energy access to more resources that are “bottled up” in a smaller EDAM footprint, Tsoukalis said. 

“[During] midday hours in most of the year, you can actually buy power when you need it at almost no cost,” he said. “Whereas in the EDAM bookend case, you kind of have to share that with the Southwest and the Pacific Northwest.” 

Markets+ Scenarios

If NV Energy joined Markets+ rather than EDAM, NV Energy’s generation costs from EDAM participants would rise and trading with those entities would decrease. Instead, the utility would do more trading with Northwest and Southwest BAAs under a Markets+ bookend case. It would gain $16 million annually in that scenario.

If NV Energy joined Markets+ but Idaho Power went with EDAM — in a scenario Brattle called Middle View 2 — NV Energy would lose $17 million annually, as the scenario cuts off a major Northwest-Southwest artery for Markets+. 

“Being in the WEIM alone with almost the full WECC in that footprint is more beneficial for NV Energy specifically than this kind of bifurcated case,” Tsoukalis said. 

Brattle also calculated WECC-wide results for different NV Energy scenarios. 

The greatest WECC-wide benefit, $985 million, was seen in the EDAM bookend case. The least benefit was $682 million in the Middle View 2 case, in which NV Energy chooses Markets+ but Idaho Power goes with EDAM. 

“All of these cases do create for the West as a whole a benefit,” Tsoukalis said. “Even in the cases where things are bifurcated and you get multiple day-ahead markets, the presence of those day-ahead markets does create customer savings relative to the business-as-usual case.” 

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NEPOOL PC Supports Additional Delay of FCA 19

The NEPOOL Participants Committee voted April 4 to support an additional two-year delay of ISO-NE’s Forward Capacity Auction 19 to buy time for the RTO to develop and implement resource capacity accreditation (RCA) changes and shift the overall timeline of capacity auctions. 

FCA 19 will procure capacity for the 2028/2029 capacity commitment period (CCP), and initially was scheduled for February 2025. The auction previously was delayed by a year in a filing approved by FERC in early January. (See FERC Approves ISO-NE’s One-Year Delay of FCA 19.) The additional delay would push the auction to February 2028, with the related CCP set to begin in June of that year. 

This February, ISO-NE endorsed a major redesign of its forward capacity market. While auctions historically have been held more than three years prior to each yearlong CCP, ISO-NE hopes to adopt a “prompt/seasonal” capacity market, with auctions held just months prior to the CCP, which would be broken up into distinct seasonal periods. (See NEPOOL MC Backs Further Forward Capacity Auction Delay, ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.)  

Meanwhile, the RTO is continuing work on its RCA updates, which are intended to better align the capacity values assigned to different resources with the actual reliability benefits the resources provide. (See NEPOOL Markets Committee Briefs: March 13, 2024, NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

The vote on the additional delay passed with broad support from the PC, though some stakeholders have expressed concern the delay could hurt the development of new resources that rely on capacity market revenues.  

To help mitigate these impacts, ISO-NE will allow new resources expected to be operational by June 2028 but that lack capacity supply obligations to qualify for reconfiguration auctions. 

Extended-term/Longer-term Transmission Planning Phase 2

The PC also voted to support a proposal from ISO-NE and the New England States Committee on Electricity (NESCOE) to create a new process for transmission investments to address long-term transmission needs.  

The process would allow ISO-NE to issue a request for proposals targeting long-term transmission needs at the direction of the states. ISO-NE then would select a preferred solution out of the proposals received, while giving the states the option to proceed with this preferred solution. (See NEPOOL TC Approves Process for States’ Transmission Needs.) 

The costs of selected projects would be regionalized among the states unless NESCOE proposes an alternative cost allocation methodology. For a project to be eligible for selection, expected quantified benefits must outweigh costs.  

The PC also passed a supplemental process that would allow the states to select a proposal even if no project passed the cost/benefit threshold. In this supplemental process, one or more states could agree to cover the costs that exceed the benefits, while the rest of the costs would be regionalized.   

Operations Updates

ISO-NE COO Vamsi Chadalavada said overall demand in March was lower than historical levels due to mild temperatures and increasing behind-the-meter solar production. The monthly peak load was 15,692 MW, which occurred on the evening of March 21. 

Chadalavada noted that ISO-NE expects the eclipse on April 8 to cut solar generation by about 3,600 MW but said the RTO “has simulated this event, and our operators are ready.”