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August 13, 2024

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PJM PC/TEAC Briefs: Aug. 6, 2024

Planning Committee

PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year

PJM could see a growing capacity shortfall starting with the 2029/30 delivery year, the RTO found after running its effective load carrying capability (ELCC) model on a generation mix forecast through the 2034/35 DY, PJM’s Patricio Rocha-Garrido told the PJM Planning Committee during its Aug. 6 meeting. 

Garrido said adjustments to resource accreditation drive a declining forecast pool requirement (FPR) in the analysis, leading to the forecast peak load surpassing the solved peak load.  

In other words, the resources PJM expects to come onto the grid will have a declining marginal capacity contribution each year that, paired with generation deactivations, may lead to accredited capacity falling below forecast peak loads. 

Garrido cautioned that the analysis should not be seen as a forecast and is instead the result of applying its ELCC modeling to a resource mix forecast supplied by a PJM vendor, which carries “significant uncertainty.” While the vendor’s assumed resource mix cannot be released publicly, Garrido said it can be supplied to individuals upon request. 

“We’re getting lower reliability value of the additions,” Garrido said, adding that the declining capacity value is the driving factor “rather than demand-side adjustments.” 

If peak loads were driving the imbalance, Garrido said the FPR would be trending up in the analysis. 

PJM analysis found a potential capacity shortfall beginning in the 2029/30 delivery year based on projected resource accreditation ratings and a vendor’s forecast generation mix. | PJM

PJM received deactivation requests for combustion turbines that led to a higher CT rating in the 2026/27 Reserve Requirement Study (RRS) after the analysis was initiated, so they are not reflected in the assumed resource mix. (See PJM Presents Revised Reserve Requirement Study Values.) 

Garrido said a decline in the capacity contribution of demand response resources is due to risk modeling concentrating expected unserved energy (EUE) in winter hours outside the DR availability window. 

Paul Sotkiewicz, president of E-cubed Policy Associates, questioned whether the vendor would readjust the resource mix forecast given the spike in capacity prices in the 2025/26 Base Residual Auction. He said it could make sense for generators to undergo retrofits rather than retire, given the possibility of higher capacity revenues, particularly for coal units that could see upgrades to comply with coal combustion residuals (CCR) requirements becoming economically viable. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

Several stakeholders questioned the accuracy of the resource mix forecast and urged PJM to conduct additional sensitivities. Garrido said more sensitivities would be helpful, but staff did not have time for this analysis while preparing the 2026/27 RRS parameters. 

Stakeholders Endorse LAS Charter Revisions

The PC endorsed revisions to the load analysis subcommittee (LAS) charter aimed at reflecting a shift in the group’s function toward reviewing the load forecasts produced by PJM and soliciting stakeholder comments on the forecast inputs. 

PJM’s Andrew Gledhill said much of the status quo charter language is a holdover from when transmission owners presented their own forecasts to PJM and stakeholders through the LAS. The proposed changes were approved by the LAS on July 29. 

Calpine’s David “Scarp” Scarpignato said stakeholders’ role at the LAS goes beyond reviewing PJM’s load forecasts, which he said was the focus of the original proposed charter revisions. He proposed that PJM’s language be amended to reflect that stakeholders provide substantive comments on how the forecast is prepared. 

Gledhill said language in the “responsibilities” section of the charter was intended to reflect stakeholder comments and noted that members do not vote on or approve PJM’s forecasts. He accepted a friendly amendment to the revisions from Scarp to add “and is responsible for soliciting stakeholder input and providing review of PJM reports” to the charter’s mission statement. 

Monitor Presents CIR Transfer Proposal

The Independent Market Monitor presented its proposal for an expedited process for transferring capacity interconnection rights (CIRs) held by deactivating generators to planned resources in the interconnection queue. (See “Elevate Reviews CIR Transfer Proposal,” PJM PC/TEAC Briefs: July 9, 2024.) 

The biggest distinction between the Monitor’s concept and the four competing designs is that CIRs would not be bilaterally traded between market participants but would instead be made available to the next planned resources that could take advantage of the underlying transmission capability. If PJM identified that a deactivating resource would create transmission violations that would require offering the owner a reliability-must-run (RMR) agreement to keep the plant in operation, PJM would initiate an expedited process where it would assign the CIRs to the next resource in the queue that could address the violations. 

If PJM did not identify projects within the interconnection queue that could resolve the transmission violations, it would conduct an auction, or a solicitation could be held for project designs. 

Scarp questioned what guarantees can be provided to ensure that generation projects selected by PJM through the expedited process are built if they are meant to replace an RMR contract and constitute reliability projects. 

“If you’re doing it for RMR purposes, I’m wondering if you need more of a solid commitment more than what is already in the generator interconnection process,” he said. 

PJM, Gabel Associates, MN8 Energy and Elevate Renewables have also sponsored packages, differentiated by the resources that would be eligible to receive transferred CIRs, how potential impacts to the grid would be studied and the standard that would disqualify replacement resources from using transferred CIRs due to identified grid upgrades. 

PJM’s Becky Carroll said the proposals are slated to go for first reads and an endorsement during the Sept. 10 PC meeting, but voting could be deferred to the Oct. 8 meeting if substantial changes are made over the next month.  

Manual 14B Revisions Include Change to Light Load Model

Stakeholders endorsed revisions to Manual 14B: Region Transmission Planning Process to rework the inputs to PJM’s light load case, which is used in the Regional Transmission Expansion Process (RTEP) load forecast to reflect the growth of load with flat profiles unaffected by weather and season.  

The light load case is designed to create an accurate representation of shoulder periods by scaling load down to 50% of the summer forecast peak using bus-level data provided by transmission owners. PJM’s Stan Sliwa said that practice has been challenged by the growth of non-scalable load, such as data centers. The revisions would remove non-scalable load from the light load case.  

The Manual 14B changes also expand the NERC TPL standards examined during generator deliverability analysis to match current practice, updating the system operating limit (SOL) definition and adding new standards created by NERC. 

The language is set to go before the Markets and Reliability Committee for a first read Aug. 21 and an endorsement vote Sept. 25. 

Transmission Expansion Advisory Committee

PJM Presents Results of 8-year RTEP Model

PJM has updated the needs in its 2024 RTEP Window 1 solicitation to include a longer 8-year model designed to capture issues that might take longer than the typical 5-year cycle to resolve. 

The additional three years capture the remainder of the New Jersey offshore wind being interconnection through the state agreement approach (SAA), the completion of the Coastal Virginia Offshore Wind (CVOW) project and the 1 GW Chesterfield gas generator near Richmond, Va.  

Despite the additions, load growth and resource deactivations are expected to cause Dominion and the West regions to each lose over 1 GW of dispatchable energy in the summer, while the capability in MAAC would grow by 2 GW over the 2029 model. Dominion would lose 2 GW in the winter case, while MAAC and West would both gain around 1 GW. Both MAAC and the West would both likely export energy as demand grows in Dominion.  

PJM’s Sami Abdulsalam said a conservative approach is taken when considering which planned resources are expected to be available in the RTEP analysis. Both Chesterfield and CVOW have advanced queue positions that provide a strong certainty of them coming online, while the NJ SAA projects have commitments to PJM from a state backer. 

Over 100 new thermal overloads were identified in the longer model, 76 of which were in the summer, 48 in the winter and 40 in the light load case. Abdulsalam said the analysis is meant to allow transmission owners submitting RTEP solutions to right-size their projects to meet the needs identified in the 5-year model with an eye toward long-term needs. 

The solicitation window opened July 15 and is set to close Sept. 13, but Abdulsalam noted that the new analysis was released after the window opened  

Several ratepayers in Northern Virginia called for alternatives to the series of transmission projects built or that are planned to crisscross the region to supply rapid load growth, with residents particularly interested in the concept of an undergrounded DC line. They also questioned whether higher capacity prices will lead to generation development that could reduce the need for transmission projects. 

PJM’s Susan McGill said the RTO’s role is to identify needs and it’s up to developers to propose transmission or generation solutions through the RTEP or interconnection queue. 

Supplemental Projects

PPL presented a project to interconnect a 1,980-MW load sited near Hazleton, Pa., for $196.55 million. The customer would be supplied by a new 230-kV switchyard named Tomhicken, which would be cut into the Susquehanna-Harwood double circuit 230-kV line, as well as a new Nescopeck 230-kV switchyard. 

Tomhicken would be configured as a six-bay, breaker-and-a-half facility with a 125-MVAR capacitor bank for $45 million, and Nescopeck would be configured as a three-bay breaker and a half switchyard for $29.5 million. Nescopeck would be cut into the Susquehanna-Sunbury 230-kV line with a partial rebuild of the portion between the new facility and Susquehanna to upgrade it to be double circuit for that portion. Additional 230-kV lines would be constructed between Nescopeck, Tomhicken and Harwood. 

The customer is expected to come online in 2026 starting with a load of 240 MW, growing to 720 MW in two years, 1,440 MW by 2031 and reaching its full consumption in 2033. The project is in the conceptual phase, with a projected in-service date of June 1, 2027. 

Exelon presented a $158 million project to provide service to a customer seeking to bring 378 MW of load to the Elk Grove area in its ComEd zone. The customer would be served by a new 138-kV substation with 16 circuit breakers and in a double ring bus configuration and five 138/34-kV transformers. The facility would be cut into the Elk Grove-Schaumburg line.  

The project would require a new 345-kV bus in a breaker-and-a-half configuration to be installed at the Elk Grove substation, including 12 new 345-kV circuit breakers. The bus would be cut into the Des Plaines-Lombard 345-kV double circuit line. Two 345/138-kV autotransformers would also be installed. 

The customer expects to bring 117 MW of load in December 2026 and reach 333 MW in 2028. The project is in the conceptual phase, with a projected in-service date of Dec. 31, 2026. 

Exelon presented an additional $40.6 million project to serve a customer in the Elk Grove region with 260 MW of load. A new 138-kV substation would be built with 15 circuit breakers in a double ring bus configuration with six 138/34-kV transformers. It would be connected to the Elk Grove East substation with new 1.7-mile, 138-kV lines. 

Two 345/138-kV autotransformers would be required at the Itasca substation, as well as two 345-kV and two 138-kV circuit breakers. 

The customer anticipates 25 MW of load in June 2027, 87 MW in 2028, growing ultimately to 260 MW. The projected in-service date for the transmission upgrades is Dec. 31, 2027. 

FirstEnergy presented a $38.7 million project to replace steel H-frame structures along its Perry-Ashtabula-Erie West 345-kV line, reconductor 7.2 miles of the 20-mile line and replace insulators and related equipment. The line is around 60 years old, and the insulators, H-frames and guying are corroded. The line has experienced seven scheduled outages for repairs and four due to equipment failure since 2014. The project is in the conceptual phase, with a possible in-service date of April 9, 2027. 

The utility also presented two projects amounting to $15.5 million to replace obsolete and misoperating relay equipment at its Doubs, Ringgold, Lime Kiln and Montgomery 230-kV substations in the APS zone. The work is in the engineering phase, with an estimated in-service date of Oct. 31, 2026, for Lime Kiln and Montgomery and Dec. 31, 2026, for Doubs and Ringgold. 

Dominion presented a $180 million project to address reliability violations along its Fredericksburg-Possum Point 230-kV line, as 3 GW of load is expected to come online served by 13 new substations along its length. 

A new Allman switching station would be built north of the Fredericksburg substation, with 10 230-kV line terminals in a breaker-and-a-half configuration. It would cut into 230-kV lines between Fredericksburg and the Cranes Corner, Aquia Harbour and Birchwood substations  

About 4.5 miles of the line from Allman to Cranes Corner and 0.7 miles of line from Allman to Hospital Junction would be rebuilt with double circuit structures. The Cranes Corner substation would be expanded to support line realignment. The line to Aquia Harbour would be upgraded to double circuit and rebuilt with vacant arm positions to host two additional 230-kV lines to run from Allman, past Aquia and onto Possum Point on a new 7.1-mile double circuit pole line. 

The project is in the conceptual phase, with a possible in-service date of June 1, 2029. 

Dominion also presented a $30 million project to power a data center customer in Stafford, Va., with a projected summer 2029 load of 136 MW. A new Centreport switching station in a 4-breaker ring bus configuration would be cut into the Spartan-Cranes Corner line with 2.5 miles of new double circuit line. 

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Vineyard Wind, GE Vernova Release Action Plan Following Blade Failure

Vineyard Wind and GE Vernova on Aug. 9 released an overview of their action plan for cleaning up debris and eventually resuming construction on the Vineyard Wind 1 project in the wake of the blade failure and collapse on July 13. (See Blade Failure Brings Vineyard Wind 1 to Halt.)

According to blade maker GE Vernova, the failure was caused by an isolated “manufacturing deviation” at the factory. (See GE Vernova Finds Defect in Vineyard Wind Blade.) Construction and power production have been paused following the incident due to a suspension order from the U.S. Bureau of Safety and Environmental Enforcement.

“Vineyard Wind and GE Vernova are committed to safely removing the damaged blade, monitoring for and collecting any debris, assessing any environmental impacts, inspecting all of the other project blades and safely restarting the project,” the companies said in a statement.

While no personal injuries related to the blade collapse have been reported, foam, wood and fiberglass pieces of the blade have washed up on local beaches over the past month, temporarily closing several beaches. The action plan noted that the “primary risk of the debris is physical contact with fiberglass.”

The companies said they are working with Resolve Marine to prevent additional debris from falling into the ocean, remove the broken blade and clean up seabed debris.

To ensure manufacturing issues do not affect any other blades, the companies said they are reviewing ultrasounds from the manufacturing process of the blades to identify any abnormalities. They are also conducting an internal inspection using “advanced remote-controlled robots,” or “crawlers.”

The action plan also indicated that GE is developing an algorithm to better detect and avoid similar issues, which will “provide advanced warnings or automatic, safe turbine shutdown when required.”

Looking ahead to the eventual resumption of activities on the project, the companies said they will first resume tower and nacelle installations, followed by blade installations and finally move on to power production. The companies said they are “working with the Federal Interagency to ensure all operations are in compliance with all applicable orders, permits, regulations and laws.”

Despite relatively minimal local environmental impacts, the blade failure has drawn significant national attention. At the time of the failure, Vineyard Wind 1 was the largest operating offshore wind farm in the country.

Offshore wind opponents, including fishing industry organizations and conservative think tanks, have pointed to the blade collapse as evidence that the industry is a bad investment of public resources and a danger to the environment.

“Offshore wind is just another of the Biden-Harris administration’s sinking policies,” said the Texas Public Policy Foundation, which called on the courts to strike down the project’s regulatory approvals. Attorneys for the foundation are representing fishing industry opponents to the project in a federal appeal of its approval.

Meanwhile, environmental advocates have expressed concern about the blade failures, but have emphasized that environmental impacts must be viewed in context, and that offshore oil spills are far more damaging to local communities and ecosystems.

“We must all work to ensure that the failure of a single turbine blade does not adversely impact the emergence of offshore wind as a critical solution for reducing dependence on fossil fuels and addressing the climate crisis,” said Nancy Pyne of the Sierra Club in a statement.

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PJM OC Briefs: Aug. 8, 2024

PJM Presents Operations Road Map

VALLEY FORGE, Pa. — The Operating Committee discussed PJM’s timeline for addressing technological and operational challenges the RTO plans to address over the next four years.

The document is one in a series of outlines PJM has formed to track the various stakeholder and internal staff efforts to address reliability issues identified in its Ensuring a Reliable Energy Transition analyses. The market-oriented road map was presented during the July 10 Market Implementation Committee meeting, while its planning sibling remains under design as staff works to incorporate FERC’s Order 1920. (See “PJM Presents Road Map of Market Design Changes,” PJM MIC Briefs: July 10, 2024.)

PJM Senior Director of Market Design Rebecca Carroll said the road maps are meant to be updated as new efforts begin or are completed, with the aim of ensuring none of the working areas fall through the cracks.

The operations road map includes:

    • Enhancing forecasting of intermittent resources, behind-the-meter generation and changing load behavior.
    • Implementing the Control Room 2030 plan to build dispatcher tools to facilitate the deployment of large volumes of intermittent, distributed and storage resources.
    • Continuing upgrades to PJM’s suite of energy management system (EMS) software, focusing on network application, training system and model management tools.
    • Developing risk-based operations approaches that account for variance in forecast error, generator outage performance and time of year considerations. That could impact reserve and regulation procurement or other operational decisions.
    • Continuing gas-electric coordination efforts to incorporate information about the gas pipeline and generation fleet into PJM operations.
    • Incorporating intermittent forecasting into the transmission outage analysis and approval process.
    • Ensuring any changes to reserve market structures remain aligned with operational needs.

PJM’s Chris Pilong said the number of risks the grid faces is increasing, challenging the ability for operators to schedule the appropriate generation with optimal lead times. Some of the initiatives likely will require the focus of stakeholders and the RTO indefinitely, such as the electric-gas coordination efforts that have been ongoing for a decade and are likely to continue as the gas industry evolves with shifting economics and policies.

Several stakeholders recommended PJM publish the three roadmaps and their related materials in one place for easy retrieval and provide more insight into which forums each issue will be discussed.

Paul Sotkiewicz, president of E-cubed Policy Associates, said all of the items on PJM’s road map are interrelated topics, and he’s concerned that if they’re addressed in siloes, holistic solutions may remain out of reach.

Pilong said staff are coordinating across departments and when topics are brought to stakeholders PJM wants to make sure they’re brought to the correct working group.

Sotkiewicz also argued it’s inappropriate for the RTO to include the facilitating of decarbonization policies reliably in its three “Pillars of Strategy” guiding the focus of the road map. Instead, he said the focus should remain locked in on reliability amid changes external to PJM.

Voltage Reduction Action Test Planned

PJM plans to conduct a voltage reduction test Aug. 14 and 15 to validate a capability the RTO has not used for more than a decade.

Senior Dispatch Manager Kevin Hatch said the test is one of the recommendations in a PJM report on the performance of the grid in the wake of the December 2022 Winter Storm Elliott, when a voltage reduction warning was issued, and one additional generator trip could have required an action. The previous voltage reduction action PJM issued was in January 2014. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)

The Mid-Atlantic region will undergo testing on Aug. 14 at 2 p.m. EST, followed by the western and southern regions the following day at the same hour. If the test cannot be conducted as scheduled, Aug. 28 and 29 have been identified as alternatives. The test is scheduled to run for half an hour.

The test will simulate a 5% voltage reduction on a load level above the seasonal upper quartile.

Hatch said the goals of the test are to determine whether changes in the characteristics of PJM load have led to any shifts in the efficacy of voltage reduction actions, to examine the functionality of updated procedures and to provide training for staff and members. PJM does not have a regular voltage reduction testing regimen, but Hatch said ISO-NE and other regions conduct tests twice a year.

Operating Error Metrics Improve in July, 153 GW Monthly Peak Load

July 16 saw one of the highest peaks for the month in PJM’s history at 153 GW. Presenting the month’s load forecast error, PJM’s Marcus Smith said the month as a whole averaged 5 GW higher than an average July.

PJM’s average peak and hourly forecast error rates for July both fell squarely at their 25-month averages of 1.64% and 1.52%, respectively.

The day-ahead forecast error did exceed PJM’s 3% target on a handful of days. July 13 saw a 5% under forecast as temperatures came in hotter than expected, while the following day was over forecast by about 6.5% due to storms bringing temperatures 15 degrees cooler than anticipated.

Eight shared reserve events, three spin events and eight hot weather alerts were issued across the month. Generator trips led to two shortage cases on July 28 and one on July 8.

Social Manipulation Attacks a Rising Cybersecurity Threat

Artificial intelligence increasingly is being used in social manipulation cyberattacks, PJM’s Jim Gluck said, warning stakeholders that critical infrastructure is experiencing attacks at a higher rate than the economy as a whole.

He pointed to a software company that was targeted recently through its hiring process by attackers impersonating a prospective employee. Four video interviews, validation of credentials and background checks failed to identify that a stolen identity was being used and profile images augmented with AI. Once the individual was hired for the position, a company computer was mailed out, malicious software was installed on it and a breach was attempted. The company identified the attack and revoked the computer’s access before systems could be compromised.

Attackers also have taken advantage of widespread disruption caused by an issue with antivirus software developed by CrowdStrike. Individuals have impersonated CrowdStrike employees offering assistance with recovery to gain access to Microsoft systems.

“We’ve got to make sure we’ve got the processes in place to detect these kinds of situations wherever they are,” Gluck said.

Implementing multi-factor authentication, patching software regularly and staying vigilant for phishing attacks can reduce the risk of attacks being successful, he said.

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PJM MIC Briefs: Aug. 7, 2024

PJM not Planning to Refile Components of Rejected CIFP Proposal

VALLEY FORGE, Pa. — PJM has scuttled plans to refile several components of its proposed capacity market redesign that was rejected by FERC in February (ER24-98).

Drafted through the Critical Issue Fast Path (CIFP) process conducted last year, the filing sought to rework the market seller offer cap (MSOC) and Capacity Performance (CP) structure, and establish a forward-looking energy and ancillary service (EAS) offset for the MSOC and minimum offer price rule (MOPR). The filing was one of two arising from the CIFP process last year; the other was approved by the commission in January and focused on risk modeling and generation accreditation. (See FERC Rejects Changes to PJM Capacity Performance Penalties.)

During the MIC’s meeting June 5, Chief Economist Walter Graf said PJM was considering refiling components that the commission either seemed supportive of or did not comment on in its rejection order. That included “clarifying revisions” to the definition of Capacity Performance quantified risk (CPQR), MSOC values for planned generation based on net cost of new entry, segmented offer caps and the forward-looking EAS offset. (See “PJM to Refile Portions of Rejected CIFP Proposal,” PJM MIC Briefs: June 5, 2024.)

But last week, PJM Lead Market Design Specialist Pat Bruno said the decision to not refile was made following mixed stakeholder feedback during the June meeting, as well as outreach to members over the past two months. He said the overall sentiment seemed to be that there is not a major imperative to refile at this time, particularly given the Quadrennial Review and second phase of the capacity market redesign, both expected to begin next year. Those two forums may be where PJM seeks to propose the items it intended to refile. (See “PJM Presents Road Map of Market Design Changes,” PJM MIC Briefs: July 10, 2024.)

The RTO envisions the phase 2 discussion to center around a seasonal or sub-annual capacity construct, Bruno said.

PJM’s proposal did not subject intermittent resources to the must-offer requirement, but the RTO had considered doing so as part of a sub-annual market design while forming its proposals. A sub-annual design would allow for greater alignment of intermittent resource performance expectations and accreditation, he said.

Stakeholders Endorse FTR Manual Revisions

The MIC endorsed revisions to Manual 6: Financial Transmission Rights to conform with three FERC orders on storage, hybrid resources and bilateral trade agreements (ER19-469, ER22-1420 and ER24-374).

The revisions state that transmission customers using firm service to deliver energy for charging storage or open-loop hybrid resources cannot receive auction revenue right allocations. (See RTOs Move Closer to Full Order 841 Implementation.)

They also require reporting bilateral trades to PJM, including confirming that the seller has no continuing interests in the FTR once it has been transacted.

The revisions are set to go before the Markets and Reliability Committee for a first read on Aug. 21 and move to an endorsement vote on Sept. 25.

PJM Proposes Elimination of 2 Interface Pricing Options

PJM presented a quick-fix proposal to remove its high/low and marginal cost proxy interface pricing options because of lacking utilization. The quick fix process allows for an issue charge and proposed solution to be voted on concurrently.

Since their implementation in 2009, the options have only been used once, when Duke Energy Progress received FERC approval of a dynamic schedule with PJM, according to the RTO’s problem statement. That agreement was terminated in 2019, and the options have not been used since.

“PJM and its stakeholders have the opportunity to retire the aforementioned processes associated with the development of interface pricing points for non-market entities,” the problem statement reads. “There is an opportunity to simplify the existing language to remove outdated processes no longer used and better align with the existing language for the current interface pricing process in use.”

PJM’s Phil D’Antonio said the marginal cost proxy option required a congestion management agreement to be reached, but the RTO removed the management process in 2021.

Updated Guidance for Entering Dual-fuel Units into Markets Gateway

PJM’s Joseph Tutino reviewed the RTO’s updated guidance for how dual-fuel generators should reflect their fuel availability in Markets Gateway.

Resources assigned a cost schedule through the day-ahead or real-time markets are unable to subsequently switch their schedules, so dual-fuel generators that intend to switch the fuel they are operating on should update their schedule to state the fuel they will be consuming and the associated price, Tutino said.

If a gas-fired dual-fuel unit is committed to run on gas and then becomes unavailable later in the operating day, its gas cost schedule, incremental offer curve and no-load cost should be updated to reflect the cost of oil. The “reference schedule” field should also be updated to reflect the cost schedule ID of the alternative fuel.

PJM Presents Data on DR Availability

PJM analysis of demand response availability during the 10 days in 2022 and 2023 that comprised the top five weather load days for each year suggests that actual metered load reductions required to meet winter curtailment obligations were below the effective load-carrying capability (ELCC) rating assumptions for the resource class during the winter availability window hours. (See “Voltus Discusses DR Market Issues,” PJM MIC Briefs: July 10, 2024.)

The data were presented as part of a stakeholder discussion on whether the window in which DR resources are considered available to supply capacity should be expanded during the wintertime hours to reflect changes to PJM risk modeling that shifted focus to the evening.

Bruno said the ELCC analysis assumes that there is zero reduction capability outside the availability window of 6 a.m. to 9 p.m., which curtailment service providers argue undervalues the capacity they could offer. Bruno said the other side of the coin is that the data suggest that capability within the window is lower than ELCC ratings expect, and performance falls off even more outside the window.

Dave Mabry, of the PJM Industrial Customer Coalition, said the December 2022 data are skewed by emergency conditions overlapping with a holiday weekend, as PJM data for Dec. 23, a Friday, show many DR participants shutting down ahead of the holiday weekend starting as early as the morning prior to the load management event that occurred later in the evening hours.

Calpine’s David “Scarp” Scarpignato said the difference between thermal generation’s winter and summer capability is also not well captured in ELCC ratings. He said it would be more efficient for stakeholders to focus on overall ELCC improvements rather than having several complex stakeholder processes focused on the construct.

Several Corrections to Formulas Included in Proposed Manual 15 Revisions

PJM’s Jennifer Warner-Freeman presented a package of revisions to Manual 15: Cost Development Guidelines drafted through the document’s biennial review. The changes mainly focus on correcting formulas throughout the manual.

The revisions would also remove a table displaying variable operations and maintenance costs to prevent any confusion about which values should be used. Freeman said the costs are updated annually to account for inflation, and staff are concerned that members may believe the manual values are static. The updated values are posted to the PJM website.

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NYISO Previews Work on Compliance with FERC Order 1920

NYISO last week began gathering stakeholder input on its FERC Order 1920 compliance plan, which it expects to file on time without any need for delay. 

The ISO gave an overview of the 1,300-page order, issued in May, to the Transmission Planning Advisory Subcommittee. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

“What I am reviewing here, from NYISO’s perspective, are the highlights,” said Yachi Lin, the ISO’s director of systems planning. “But absolutely please do your own review, bring back your points, and we can start a discussion.” 

The rule requires regional transmission planners to plan on a 20-year horizon with several benefits. Cost allocation plans for projects must ensure only customers who receive those benefits pay for projects. 

“You’re going to hear these terms repeated over and over again throughout the order: ‘sufficiently long-term,’ ‘forward-looking,’ ‘comprehensive,’” Lin said. 

The order went into effect Aug. 12. Lin said NYISO needs to submit its compliance filing with the regional planning requirements to FERC by June 12, 2025. Interregional planning requirements are due later in August. 

Between October and December of this year, NYISO will be drafting a straw proposal to comply with the order, followed by tariff revisions during the first six months of 2025. 

NYISO will be required to develop three long-term scenarios that project out 20 years based on seven factors prescribed by FERC. Once projects have been winnowed down to the selected projects, the reasons for the selections and rejections will be explained to stakeholders. 

One TPAS member pointed out that the process looked similar to parts of NYISO’s extant three-pronged process and wondered how much this would change the ISO’s existing process. 

“That is the question we are very much interested in hearing your opinion on,” Lin said. She went into detail on the NYISO planning process and then asked whether it was better to expand the existing process or build an additional tracker on top to comply with the order. “I don’t have an answer to tell you. What we really need to do is hear from you.” 

One stakeholder said it was unclear to him whether NYISO was the “transmission provider” under the rule or whether that was the New York Public Service Commission.  

“The transmission provider has an affirmative obligation to determine the need,” Lin said. “The relevant state entity does have a role to play in providing the input for how the scenario is developed, how the need is established. So there’s also an affirmative role for the relevant state entity to play.” 

Lin also noted the four technologies that were specified as grid-enhancing technologies, which under the order must be considered for efficiency and cost-effectiveness against new facilities or upgrades that do not incorporate them. They are dynamic line ratings, advanced power control devices, advanced conductors and transmission switching. 

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FERC Approves Two Enforcement Orders Related to Battery Storage

FERC approved two enforcement orders requiring several battery storage operators to pay more than $1 million in fines and remit nearly $1.9 million back to CAISO.  

In the first order, issued Aug. 6, the commission found that Vista Energy Storage submitted bids into CAISO that overstated the availability and capability of its Vista Battery (IN24-11). The misrepresented bids occurred for over a month during the summer of 2022. As a result, Vista will pay $1 million in fines and disgorge $1,670,000 in profits to CAISO.  

Vista is a subsidiary of REV, a renewable power company formed by LS Power in 2021 that operates about 2.8 GW in generation assets. The Vista Battery’s maximum storage capacity is 40 MWh, and it offers both energy and ancillary services into the CAISO market.  

During a 33-day period in 2022, Vista each day told CAISO that it forecast the battery’s initial state of charge the following day to be at or below 4 MWh even though the battery had a 36 MW or larger regulation up award for the final hour of that day.  

“Vista knew, or should have known, that because of that regulation up award, the ancillary services state of charge constraint would ensure that Vista’s actual state of charge would be around 20 MWh during the final hour that day,” the order reads.  

Vista received 40 MW regulation down awards for the first hour of the next day due to its 4 MWh lower initial states of charge. It would not have received these awards in the first hour of the day if it had submitted an initial state of charge value of 20 MWh. The lower values also enabled the company to earn awards of 40 MW of regulation down for several hours after the first hour.  

“Because the battery was actually at a state of charge around 20 MWh at the beginning of each of the 33 days within the relevant period, there was a conflict between operation of the regulation down product (which seeks to charge the battery to adjust frequency on the grid) and the ancillary service state of charge constraint,” FERC stated.  

To resolve the conflict, the ancillary service state of charge constraint frequently discharged the battery to make Vista’s regulation down awards feasible.  

As a result, Vista received approximately $1,485,000 in bid cost recovery payments because of regulation down awards it would not have obtained if it had submitted accurate initial state of charge values. 

NextEra Order

The second order, issued Aug. 8, involved Arlington Energy Center III, Blythe Solar 110, Blythe Solar III, Blythe Solar IV, Desert Sunlight 250, Sunlight Storage and McCoy Solar (IN24-10).  

The companies are all indirect subsidies of NextEra Energy Resources and operate battery energy storage systems co-located with solar generation. Each storage system and solar facility function as separate resources but share the same point of interconnection (POI). As per CAISO’s large generator interconnection agreement, the resources cannot exceed the POI limit.  

In December 2021, CAISO modified its tariff to prohibit co-located battery facilities from deviating from dispatch instructions. According to the order, NextEra was unaware of the tariff change and thus didn’t update its software to comply.  

“During the relevant period, when the combined output of a plant’s battery and solar facilities approached the POI limit, the programmable logic controllers at the plant that controlled the output of the solar and battery facilities automatically curtailed the battery facility, allowing the solar facility to continue to deliver its output to the CAISO grid, as was permitted prior to CAISO’s December 2021 tariff change,” the order states. “NextEra’s software did so even during intervals in which the plants’ batteries received ancillary services awards.”  

There were 3,835 five-minute intervals during which the plants’ batteries deviated from dispatch instructions while holding ancillary service awards, resulting in the companies’ receiving approximately $381,724 in revenues.  

NextEra has since updated its software and will pay a civil penalty of $105,000 and $381,724 in disgorgement to CAISO.  

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Early Heat, Wildfires Signal Increase in California PSPS Events

Intense heat coupled with this summer’s early and active fire season will likely increase the need for public safety power shutoffs (PSPS) this year, according to utilities presenting at a California Public Utilities Commission workshop Aug. 7-8.  

Southern California Edison COO Jill Anderson spoke about the “relentless heat waves” and “months of wildfires” that have hit the state this summer. 

“We’ve been setting records, certainly in SCE’s service area and other places, and all of that for us is a reminder of how critical it is that we are ready with all the tools at our disposal to make sure that we can be managing and responding to extreme weather,” Anderson said. “We know that one of those tools — what we consider a last resort tool — is PSPS.”  

PSPS allow utilities to temporarily shut off power in certain areas to reduce the risk of fires caused by electric infrastructure. Several utilities, including SCE, Pacific Gas and Electric, PacifiCorp, and San Diego Gas and Electric, discussed the summer forecast in their service territories, PSPS predictions, and methods of implementing and preventing power shutoff events.  

The transition to the La Niña weather pattern, associated with decreased rainfall in California, could extend high fire danger conditions later into fall and winter and increase the number of PSPS events, the utilities noted.  

“We’re concerned about the La Niña weather pattern because it historically correlates with more offshore wind days and also less precipitation, and these are not good markers for PSPS,” said Tom Brady, principal manager of business resiliency at SCE.  

But that correlation isn’t always the case, Brady noted. In some instances, meteorologists have seen rains come early during La Niña weather patterns. Additionally, climate change could weaken the relationship between La Niña and precipitation in Southern California, Brady said.  

The utilities highlighted that above-normal precipitation this past winter and in the past few years contributed to the vegetation growth that is fueling wildfires across the state. 

“August fuel levels are now at critical levels, and any moisture benefit from 2024 has mainly elapsed,” Brady said. “We’re in PSPS season, and in fact, we’re activated today for a small event with localized impacts on the border of Kern and Los Angeles counties. We can begin to expect larger events to begin occurring when weather patterns shift and we have more widespread high winds across our service territory.” 

PG&E painted a similar picture, highlighting extreme weather conditions that have increased the likelihood of PSPS events.  

Scott Strenfel, PG&E senior director of meteorology operations and fire science, said historically high temperatures have rapidly dried the fuels and “set the stage for what’s already been a very challenging fire season.” 

“It is more probable than not that this will be a more active PSPS season compared to the last two years, just because of the danger of fuel,” Strenfel said. “But all of that is going to depend on how many wind events we get and the timing of rainfall that could occur before or after those dry wind events that we get from the northeast.”  

Conditions are similar in SDG&E’s service territory, with hot temperatures, increased vegetation and high fire risk.  

“It’s certainly not the forecast that a lot of us want to see going into the fall, but it is one that our situational awareness is very focused on, and we’re very prepared,” said Brian D’Agostino, vice president of wildfire and climate science at SDG&E.  

‘Positive Trend’

The utilities all highlighted ways they’ve worked to prevent PSPS events through system hardening, undergrounding, sectionalizing devices and transmission switches, and using cameras and weather stations.  

In 2023, SDG&E completed 72 miles of undergrounding, trimmed and removed 13,000 trees, conducted 15,000 drone inspections, implemented 60 miles of covered conductors and more. In 2024, the utility aims to implement 40 more miles of covered conductors, 125 miles of undergrounding, trimming and removing 11,000 more trees, and conducting 17,000 detailed asset inspections.  

PG&E completed 664 miles of undergrounding between 2019 and 2023, hardened 1,664 miles of power lines, and installed 602 cameras and 1,424 weather stations. The utility plans to underground 250 more miles, harden 280 more miles, enable the use of AI for the cameras and continue to optimize the weather stations.  

PacifiCorp has made similar progress, replacing over 95 miles of bare conductor with insulated covered conductor in 2023, undergrounding 5 miles of line, upgrading over 35 reclosers, relays and circuit breakers, and installing over 4,000 non-expulsion fuses. The utility also implemented the FireSight model to identify areas of heightened fire risk, which led it to identify a new high fire-risk area. In total, high fire-threat districts encompass approximately 1,700 overhead line miles and 54% of PacifiCorp’s territory in California.  

SCE implemented approximately 5,900 miles of covered conductor and 26 miles of undergrounding, trimmed or removed over 2 million trees, installed or replaced over 14,200 fast-acting fuses and 160 remote-controlled sectionalizing devices, and conducted over 1 million equipment inspections.  

The utilities also highlighted the importance of artificial intelligence and machine learning in their modeling, forecasting and preparedness for PSPS events. For example, SDG&E is using machine learning at each of its 222 weather stations to train AI models to predict exactly which areas could experience a shutoff, allowing the utility to more accurately target notifications.  

SDG&E also relies on three primary AI-based tools to enhance its PSPS response: gridded AI-based fuel models that provide a holistic look at fuel moisture content, machine learning wind gust models and AI smoke detection. The utilities also rely on enhanced powerline safety settings (EPSS), which allows powerlines to automatically turn off power within one-tenth of a second.  

PG&E relies on outage and ignition probability weather models, as well as a fire potential index, to calculate the need for PSPS.  

CPUC President Alice Reynolds expressed optimism despite predictions for increased PSPS events.  

“I’m really pleased to see the progress that has been made on PSPS events over the last several years,” Reynolds said, noting that PSPS customer notifications across all utilities declined from 5.8 million in 2019 to about 500,000 in 2023.  

“There’s a positive trend for the number of customers that have been de-energized … so clearly significant improvements,” Reynolds said.

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Stakeholders Endorse PJM EE Measurement and Verification Proposal

VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a PJM proposal to revise how the capacity offered by energy efficiency resources is measured and verified, rejecting competing proposals from EE providers and the Independent Market Monitor. The package passed with 65.5% support during the Aug. 7 MIC meeting. (See PJM Hears Proposals to Redesign EE Participation in Capacity Market.) 

The proposal requires that EE providers demonstrate that capacity market revenues were the only factor in allowing a project to come to fruition and that it would not have occurred otherwise. The package also would reduce the period for which an EE project can participate in the capacity market from three years to one year after completion, which would address a possible delay in load-serving entity cost savings on lower peak load contributions (PLC). 

Any EE megawatt that did clear the Base Residual Auction (BRA) under PJM’s proposal would continue to be tacked onto the load forecast in a process known as the addback, which is meant to ensure that EE cannot act on both the supply and demand side. A withdrawn proposal from CPower included language that would have opened a separate problem statement and issue charge to consider the continued role of the addback, which also is the subject of a FERC complaint filed by three state consumer advocates (EL24-118). (See PJM Consumer Advocates File Complaint on EE Market Design.) 

The ability for EE to participate in fixed resource requirement (FRR) plans also would be eliminated on the grounds that the option has not been used and would be redundant, as cleared EE would be added back to the FRR obligation. 

“It’s a complicated package, but if members choose and they want to keep energy efficiency as a market product, we think this package can help put those checks and balances in there,” PJM’s Tim Horger said while presenting the proposal Aug. 7. 

The resource has been the focus of stakeholder attention over the past year, as PJM contends that under the current framework, EE providers have not demonstrated the capacity market revenues they receive have a causal link with reduced load and should not receive capacity market revenues until that link can be demonstrated. Several complaints have been filed at FERC during that time, alleging PJM’s market structure discriminates against EE, its treatment of market participants is unfair and EE resources have not demonstrated they meet the Reliability Pricing Model (RPM) participation requirements. 

Presenting PJM’s first read of the proposal during the July 24 Markets and Reliability Committee meeting, PJM’s Pete Langbein said he believes there’s a large amount of “naturally occurring” EE from consumers wanting to reduce their carbon footprint or energy bills by buying more efficient devices. He argued those installations should not be eligible for BRA revenues. 

PJM CEO Manu Asthana gave the example of a recent washing machine purchase he made, where the deciding factor was appliance features rather than the efficiency of the device. He said it’s possible it had a lower load than competing models and therefore would qualify for mid- or upstream EE programs that seek to use capacity market revenues to discount the purchase price, even though the purchase would have occurred regardless. While in aggregate EE programs may be successful in shifting consumer behavior in favor of reducing capacity needs, he said the capacity market isn’t entirely designed for that kind of cost allocation. 

Several stakeholders said the causal link sets an impossible standard for EE providers to meet and would result in all programs being eliminated from the market. 

Market participants proposed competing visions of how the accuracy of market participating EE could be improved. Affirmed Energy proposed a standardized approach for the measurement and verification (M&V) methodologies providers submit, an EE registration process akin to the rules around demand response, and third-party review for PJM’s verification. Mid- and upstream EE programs that use capacity market revenues to discount efficient devices in an effort to incentivize their purchase would not be required to obtain contracts with each consumer to offer the capacity associated with the energy savings into PJM’s market. 

The Affirmed proposal initially sought to eliminate the addback by increasing the amount of EE data PJM incorporates into its load forecast. That component was dropped as the number of complaints pending at FERC regarding EE market design multiplied. The proposal received 2.2% support. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said there’s a concern the addback leads to capacity market payments going to EE providers without any corresponding increase in reliability. 

A proposal from Exelon aimed to preserve the ability for utilities administering EE programs on behalf of their states to enter savings into the capacity market by positing that programs run “under the direction, authorization and/or supervision of state public utility regulatory authorities are de facto qualified as EE capacity market products.” 

The proposal also would differentiate the state directed, authorized and supervised programs from those offered by third-party EE providers with respect to the approval of M&V plans. Those plans outline how the EE provider intends to demonstrate the amount of capacity it will offer and validate that figure, as well as PJM’s evaluation of post-installation measurement and verification (PIMV) reports, where providers describe how they put those methodologies into practice.  

Exelon’s Alex Stern said the utility believes that if PJM approves a M&V plan, it should not reject PIMV reports that accurately follow through on the described approach that has been reviewed and accepted by the states. The proposal received 37.2% support. 

Stern said for as long as the states want their programs to have the ability to participate in the PJM capacity market, a distinction should exist between the rigor and regulatory scrutiny states already exercise over utility-run EE programs and EE that is bid into the capacity market by other EE market participants. 

“We certainly don’t oppose other energy efficiency market participants … so long as the rules are fair. And by fair, I mean allowing opportunities for all, but [respecting] that the state programs are different in regard to measurement and verification,” he said. 

The Independent Market Monitor proposal would go the furthest by removing EE from the capacity construct entirely, arguing that the energy savings have been incorporated in PJM’s load forecast since the 2016/17 delivery year and there is no basis in the tariff for keeping them in the market. Though the package received 54% support over the status quo, it failed to receive endorsement with a tie. 

“The IMM’s proposal is the only one to recognize the current reality. EE is factually not a capacity resource under the tariff, EE is not in the capacity market, and PJM has not treated EE as a capacity resource since 2016. It is not PJM’s role to choose to subsidize EE outside the market. The lack of credible measurement and verification and the absence of causality make the subsidies even more unsupportable,” Monitor Joe Bowring told RTO Insider in an email. 

He noted that the votes were not on a sector-weighted basis and the results of PJM’s proposal and the IMM’s proposal in a sector-weighted vote could be quite different, whereas rejection of the other packages likely would not have changed with sector weighting. 

CPower withdrew its proposal during the Aug. 7 meeting, which focused on standardizing M&V and creating a separate process to reconsider the addback. It threw its weight behind the Exelon package while urging stakeholders to vote against the proposals from PJM and the Monitor. 

“The Market Monitor’s proposal would by definition eliminate (EE) from the market … and as others have noted as well … the PJM proposal would de facto eliminate it because it continues to include this unmeetable 100% causality test,” CPower’s Aaron Breidenbaugh said. 

CPower Complaint Alleges PJM Guidance Ahead of 2025/26 Auction Violates Tariff

In a July 17 complaint to FERC, CPower argued PJM has improperly taken a step toward implementing some of those changes, in contravention of the reigning tariff and manual language. It did so by issuing a guidance document on June 13 that informed EE market participants that limited the project installation years eligible to participate in the 2025/26 Base Residual Auction (BRA) to the 2023/24 and 2024/25 delivery years. 

The document also revised how PJM determines the standard baseline used for measuring EE savings for lightbulbs, requested documentation showing that providers hold exclusive capacity rights, and added a process where the Monitor can review PIMV plans to provide comments and recommendations to PJM (EL24-128). 

The complaint asks FERC to allow CPower to participate in the Incremental Auctions (IAs) for the 2025/26 delivery year under the status quo rules and establish a settlement process or an administrative law judge to mediate disputes around PJM’s market rules for EE in the 2025/26 BRA. The amount of EE that cleared in the 2025/26 auction fell to 1,459.8 MW from 7,668.7 MW for the prior year. 

CPower argued that the PJM tariff and the 2010 FERC order establishing EE participation in the RPM hold that resources can offer into four auctions and that limiting that period would constrain participants’ ability to use past projects as replacement capacity to cover any shortfalls caused by new installations not being completed by the start of the delivery year. 

The change to the standard baseline resulted in LED lightbulbs being set as the standard practice for consumer behavior. The standard baseline determines the device that more efficient devices included in EE plans are measured against. CPower argued that the shift was made with little evidence that it reflects typical consumer behavior, stating that a memo sent from Apex Analytics to Rutgers University staff was the basis for the change. 

“PJM does not offer any robust sets of studies or analyses about standard practice. It conducted no stakeholder process to seek input on standard practice. Allowing PJM to issue edicts about what standard practice is throughout the region with alleged support as flimsy as the Apex Memo would set damaging precedent and allow PJM to wield an inordinate amount of power outside of the commission’s just and reasonableness FPA [Federal Power Act] review process, both as to EE and beyond,” the company wrote in its complaint. 

The company took issue with including the Monitor in the approval of PIMV reports on the grounds that complaints have been filed against EE providers by the Monitor, calling into question whether it can be impartial and independent when reviewing reports submitted by those parties. CPower said it received two letters from the Monitor on June 26 stating it would recommend PJM not approve its M&V plan for the 2025/26 delivery year unless the company provided several items to the Monitor, including its justification for opposing PJM’s June 13 guidance. 

“PJM is thus effectively denying CPower’s ability to withhold from the IMM what amounts to discovery outside of a commission-mandated process. Given the consequences of not providing the information, which included precluding its participation in the upcoming BRA, CPower had no real choice but to provide it to the IMM, despite its legal objections,” CPower said. 

PJM responded on Aug. 5, stating that the tariff language provides that EE may participate in the auction for four delivery years but does not mandate it. It also argued that the M&V review is within the Monitor’s scope and responding to its inquiries is a condition of PJM membership. 

“CPower unreasonably claims it is entitled to a four-year installation period for EE projects that clear a BRA even under a compressed auction schedule when two of the delivery years have already been completed and the load forecast reflects those efficiency projects as having already been installed. CPower’s position is irrational from an economic or operational perspective and is grounded in a gross misinterpretation of the tariff, RAA and PJM Manual 18B,” PJM said. 

PJM Argues Addback Necessary to Implement EE in Response to Consumer Advocate Complaint

PJM has responded to a complaint filed by the New Jersey Division of Rate Counsel, Maryland Office of People’s Counsel and Illinois Citizens Utility Board arguing that the RTO’s use of the addback deprives consumers of the reliability benefits EE can offer while still requiring them to pay market participants. Given the significance of the addback, they also state that it should be enshrined in the governing documents, rather than business manuals, and be subject to FERC review. 

In a July 10 response, PJM said the addback is necessary to avoid contravening tariff language prohibiting the double counting of EE resources as a capacity resource while also reducing peak load forecasts. PJM argued that the addback is envisioned by the tariff and can be accomplished through the manuals under the “rule of reason” as a mechanism to implement tariff language. Without the addback, it said the reliability requirement for the 2024/25 BRA would have been 142,973 MW, short of the 151,631-MW peak summer load requirement.  

“The addback was designed to address changes in the methodology for determining the PJM load forecast to preserve the ability of EE resources to qualify for capacity payments as they had under the previous load forecast methodology. Thus, far from being a ‘fundamental change’ that undermined the participation of EE resources in RPM auctions, as complainants argue, the introduction of the addback preserved the status quo for EE resources seeking to receive capacity commitments,” PJM wrote. 

Both Advanced Energy United (AEU) and the PJM Power Providers (P3) submitted comments supporting the consumers’ call for FERC to convene a technical conference to consider the addback and EE market design more thoroughly. 

In its July 10 complaint against PJM, the Monitor also argued that PJM’s implementation of the addback violates the tariff, stating that EE is permitted to offer capacity only for savings that are “not reflected in the peak load forecast prepared for the delivery year for which the energy efficiency resource is proposed.” The complaint says PJM should have eliminated EE from the capacity construct once it revised its load forecast approach to include EE data produced by the Energy Information Administration’s Annual Energy Outlook (EL24-126). 

“When EE was added to the forecast and EE was removed from the capacity market, PJM should have simply followed the tariff, recognized that EE was not capacity, recognized EE resources do not meet the definition of EE resources in the filed tariff and eliminated payment to EE resources. Instead, PJM recognized that EE resources are not capacity, stopped including EE resources in the capacity auction, and began to pay EE resources an uplift payment equal to the capacity market clearing price without making any provision for such payments in the filed tariff,” the Monitor wrote. 

PJM responded that the addback is permitted under the rule of reason and that it cannot change the results of the 2024/25 BRA due to the filed rate doctrine, citing a March 2024 Third Circuit Court decision rejecting a post-auction change to a regional reliability requirement. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.) 

The New Jersey Board of Public Utilities asked FERC to reject the Monitor’s request to cease EE payments, consolidate the remainder of the complaint with the consumer advocates’ filing and convene a technical conference centered on EE’s role in the capacity market. 

“The NJ BPU supports a holistic review of [energy efficiency resource] eligibility and discussions around whether including EE in the market clearing mechanism is preferable to the EE addback. However, this decision must be the result of a process that allows for participation and input from all relevant stakeholders,” the board wrote. 

PJM Responds to Monitor Complaint Against EE Providers

In a July 3 response to a complaint filed by the Monitor alleging that several EE market participants have not demonstrated they were eligible to participate in the 2024/25 and subsequent capacity auctions, PJM defended its approach to reviewing PIMV reports and said the Monitor proposed an unworkable approach to determining what qualifies as EE (EL24-113). (See Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.) 

The complaint argued that EE mid- and upstream programs must be able to demonstrate that the more efficient products purchased with EE rebates actually were installed and are being operated within the PJM footprint. It asks the commission to either bar the EE providers from receiving capacity revenues in the 2024/25 delivery year or open an investigation to determine eligibility. 

“For instance, short of conducting on-site audits for every location where EE is claimed right before the start of each Delivery Year, it is unclear whether any other methodology or estimate would satisfy the Market Monitor’s allegation that the Post-Installation M&V Reports fail to establish that the Indicated Energy Efficiency Sellers have actually installed the resources in homes or businesses,” PJM wrote. “However, such an approach would clearly [be neither] feasible nor cost-effective given that 7,716 MW of EE resources cleared the capacity auction for the 2024/2025 delivery year alone, which could include tens of thousands, or even hundreds of thousands, of individual end-use customer sites that would need to be audited.” 

While PJM agreed that improvements should be made to measurement and verifications, it said that should be done through the stakeholder process instead and indicated it plans to file M&V changes within the coming months. It also stated it intends to solicit an independent third party with expertise in EE to review the PIMV reports submitted for the 2024/25 delivery year. 

“These audits will confirm or amend the final nominated EE value and capacity performance value for the EE resources that comprise the indicated energy efficiency sellers’ portfolios for the 2024/25 delivery year,” PJM said. 

The American Council for an Energy Efficient Economy commented that a technical conference would be the proper forum to resolve the dispute and that the approaches favored by PJM and the Monitor would constrain EE’s ability to participate in the capacity market. 

“ACEEE believes that PJM and IMM are not appropriately assessing the benefits of energy efficiency, not assigning it its deserved value and trying to kill its role in capacity markets to the detriment of electricity consumers. Energy efficiency with appropriate evaluation belongs in the capacity system, both to benefit consumers and to ease growing demand for new electric generation,” the trade group wrote. 

The Environmental Law and Policy Center argued that the Monitor’s complaint is a collateral attack on past FERC orders mandating the ability for EE to offer capacity. 

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Nevada Climate Plan Prioritizes Natural Gas, Mineral Production

Echoing policies he laid out early in his administration, Nevada Gov. Joe Lombardo released a climate plan that calls for keeping natural gas in the state’s energy mix. 

Lombardo on Aug. 8 announced the release of the Nevada Climate Innovation Plan, which “seeks to mitigate the changing patterns of the environment, while also considering economic realities and national security,” according to a release. 

The plan said Nevada needs to find ways to maintain energy reliability while also “potentially decreasing emissions … over a sensible time frame.” That means an approach that includes natural gas, solar, geothermal, hydroelectric, wind, hydrogen, energy efficiency and energy storage projects. 

“Nevada can’t persist with the mentality that everything must transition to sustainable energy overnight,” the plan said. 

Statements in the new plan are consistent with what the Republican governor said in a March 2023 executive order that called for “diverse energy options” in the state, including natural gas and renewables. (See New Governor Seeks Shift in Nevada Energy Policy.) 

Lombardo’s goal of having an energy portfolio that includes natural gas prompted the governor to pull Nevada from the U.S. Climate Alliance last year. (See Nevada Exits US Climate Alliance.) 

Nevada’s new climate plan stands in contrast to the state’s 2020 Climate Strategy, developed under previous Gov. Steve Sisolak (D), which called for transitioning away from natural gas to meet the state’s 2050 net-zero emissions goal. 

Minerals, Rangeland

The new Climate Innovation Plan sets broad goals in areas such as regulatory reform and economic and educational opportunities. 

One objective is to modernize the state’s energy infrastructure — a goal that comes with a caveat. 

“With the undeniable effects of inflation occurring across the nation, we must be mindful of cost,” the plan said.  

Another section of the plan, focused on rangeland management, lists wildfire prevention strategies such as controlled burns, strategic grazing and invasive species removal. 

The plan points to critical mineral production in Nevada, as well as the state’s “Lithium Loop” — a U.S. Economic Development Administration-designated technology hub. The hub plans to grow technology across the full lifecycle of lithium batteries, from lithium extraction and processing to battery manufacturing and recycling. 

The EDA last month recommended the tech hub for $21 million in grant funding. 

The climate plan criticizes the federal government for taking actions including national monument designations that have blocked access to critical mineral assets in the state. More than 80% of Nevada land is federally controlled, the plan noted. 

In March 2023, Lombardo blasted the Biden administration for its designation of the Avi Kwa Ame national monument, which the governor said would disrupt rare earth mineral mining in Southern Nevada. 

“The federal confiscation of 506,814 acres of Nevada land is a historic mistake that will cost Nevadans for generations to come,” Lombardo said in a statement at the time. 

Climate Actions Underway

More than 20 pages of the 33-page Climate Innovation Plan are devoted to climate initiatives already underway within various state departments. 

Among the programs listed is an incentive for residents to replace older wood-burning stoves with cleaner-burning models. In the Governor’s Office of Energy, the Renewable Energy Tax Abatement (RETA) program gives sales- and property-tax breaks to eligible renewable energy projects. 

The Nevada Division of Environmental Protection received a $3 million planning grant from the U.S. EPA to develop a short-term Priority Climate Action Plan (PCAP) and a more in-depth Comprehensive Climate Action Plan (CCAP). (See Nevada Draft Climate Plan Outlines GHG-reduction Priorities.) 

The PCAP was completed this year. The CCAP is due in July 2025. 

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SPP Board of Directors/RSC Briefs: Aug. 5-6, 2024

Board Approves 36% PRM for Winter over Stakeholder Objections

ST. LOUIS — SPP directors and state regulators have approved the grid operator’s first winter planning reserve margin, endorsing a base PRM that is 3 percentage points higher than many of its utilities wanted.

The Board of Directors during its Aug. 6 meeting approved a 36% PRM for the winter season and a 16% margin for the summer season, effective 2026/27 and 2026, respectively. In doing so, the board sided with the Regional State Committee’s recommendation over that of the Market and Operations Policy Committee, which endorsed a 33% winter PRM.

The approval of the tariff change (RR622) capped months of discussions and deliberations by several stakeholder groups, including the Resource Energy and Adequacy Leadership (REAL) Team that is responsible for resource adequacy issues. (See SPP Markets and Operations Policy Committee Briefs: July 16-17, 2024.)

“I’m very disappointed that we did not agree to common ground with implementing the PRM,” SPP CEO Barbara Sugg said after the vote. “There are things I want to focus on what we all agree with. We agree that we have to get more steel in the ground, and we can’t do that fast enough. We agree nobody wants to explain why we have to shed load or why we’ve been turning away load. Nobody wants to tell customers why the rates are going up. It goes without saying nobody wants to find themselves paying for [RA] deficiencies.

“Again, I’m disappointed when we can’t reach consensus. It’s not who we are. But I know we all want the same thing. We want a reliable, affordable system. We have more work to do to achieve that,” Sugg added.

SPP said the action marks the first time a winter PRM requirement has been defined separately from the summer requirement and was necessary to ensure member utilities acquire enough generating capacity for both seasons. The RTO’s load-responsible entities must have access to enough generating capacity to meet their peak consumption by at least a 36% margin during the winter and at least 16% margin during the summer.

The grid operator says severe extreme weather has become “increasingly common” in recent years. The February 2021 winter storm forced SPP to shed load for the first time in its then-80 years of operation. During the December 2022 winter storm, the RTO’s staff was forced to curtail almost 6.5% of demand to prevent uncontrolled outages after a higher-than-expected level of coal-fired generator outages and derates.

“Winter is becoming our trouble season,” RSC President John Tuma said.

Minnesota PUC Commissioner John Tuma | © RTO Insider LLC

SPP’s 2023 loss-of-load study, the first to directly analyze seasonal risk beyond summer, found that a 15% PRM would not meet a 1-in-10 loss-of-load expectation in either season.

The grid operator’s Market Monitoring Unit said it saw 36% as a minimum threshold. It preferred a 37% PRM to allow for extra maintenance outages during the winter season.

Tuma likened SPP’s quest for the appropriate resource adequacy requirements to a fellowship’s travails straight out of fantasy novels.

“It’s a long journey that we’re on here at SPP … We’re at one of those points where you have a difficult lift,” he said. “You see that the trail turns ahead of you, and you don’t know exactly where it goes. This is difficult stuff. We understand that, but it’s unclear what’s coming around the corner, and we still need to go forward.”

“I wish someone would put together a trajectory that was giving us a pathway to growth and future … so that we know how much water to pack,” American Electric Power’s Richard Ross said. “I don’t want to get down that target and find out we’re going another 20 miles and not having enough water. Let’s not go on that trail and not be prepared.”

Ross was one of 12 Members Committee representatives to oppose the 36% PRM in the committee’s advisory vote for the board, with eight in favor and three abstentions. He said MOPC’s 33% recommendation “strikes the proper balance between what is needed to maintain reliability in the system and what is actually achievable, given the situations that we have.”

Richard Ross, AEP | © RTO Insider LLC

“What we really need to do though is figure out what we’re going to do for the long term, so we don’t yet again repeat this exact same conversation where SPP is cranking up the reserve margin,” Ross said. “I think you’ve heard from everyone that it takes five to six years to bring a resource online.”

“At 36%, the region as a whole has enough capacity to meet that requirement, but in all likelihood, the reality is a number of LREs [load-responsible entities] would be short in the near term,” said MOPC Chair Alan Myers, with ITC Holdings.

All 64 of SPP’s LREs met the 15% requirement for this summer.

However, Xcel Energy has issued a request for proposals as it faces the need for more than 3 GW of accredited capacity in its Southwestern Public Service (SPS) footprint. Arkansas Electric Cooperative Corp. CEO Buddy Hasten has said the organization will have to spend $2 billion on new dispatchable generating capacity to meet the requirements.

Tuma agreed that staff, the REAL Team and several stakeholder groups recognize the need for “critical, long-vision steps” beyond the current path.

“We’re soberly going into this knowing that there’s a lot more work in front of us. SPP is on an industrial transition, and it’s not going to be cheap,” he said. “We need to take this back to our commissions, take it back to our state leaders. It will cost money, but we need to do it smartly and wisely. If we don’t do it as part of SPP or MISO, it will be more costly. This is where reliability happens.”

Texas Public Utility Commissioner Lori Cobos cast one of two dissenting RSC votes against the 36% requirement, expressing concern over rising rates and supply chain issues that have increased construction costs.

“The challenge that I have on my end is trying to get to a place where I believe my LREs can feasibly work on these reserve margins that are coming in next several years in a feasible but also affordable manner,” she said.

The board and RSC also approved a fuel assurance policy (RR621) that SPP says will further strengthen RA policies by placing additional emphasis on conventional resources’ performance during the season’s most critical hours and reduce the PRM’s socialization of capacity allocation.

The MC unanimously endorsed the change, with the Natural Resources Defense Council abstaining.

Rate Cap Increased 10.8%

The directors and members both approved the Finance Committee’s recommendation for a 10.8% increase in SPP’s rate cap, from the 46.5 cents/MWh set in 2021 to 51.5 cents/MWh, effective next year.

FC Chair Stuart Solomon said the bump in the rate cap is in line with previous increases that have averaged 11.2% every three years and will serve as a bridge between the current cap and projected expenses through 2028. He said the compound annual growth of inflation has outpaced the billing units and net revenue requirement (NRR) from 2018-2024.

SPP Director Stuart Solomon | © RTO Insider LLC

SPP calculates its rate cap by dividing the budgeted NRR, including a true-up from prior periods, by the estimated amount of transmission service to be provided under the tariff in the coming calendar year.

“The rate cap is a longer-term planning measure that provides predictability for planning purposes,” Solomon said. “SPP has shown the cost-control over time, from 2018 to the present day, as the services increased very significantly over that period.”

More services mean additional staff, but Solomon noted the RTO’s staff ran a “whole lot” of model runs, all of which indicated a need to increase the cap.

The MC endorsed the increase with a 19-4 vote. AEP, Google, Oklahoma Gas & Electric and SPS all voted against the measure. Several members said they will support the rate increases but will focus more closely on the budget, which will be brought before stakeholders and the board in October.

“I am sympathetic [that] FERC’s continuing orders are getting more and more responsibility into the hands of the RTO. More and more compliance,” said Denise Buffington, Evergy’s director of federal regulatory affairs. “I just encourage the organization to continue their focus on their core mission. It’s nice to have staff, but really, how do we get steel in the ground, how do we get generation connected, how do we get transmission planned in an appropriate way? I will be looking at the budget very closely.”

GI Waivers to be Filed

The board approved staff’s proposal to file two waiver requests with FERC following a unanimous vote by the MC that will help SPP clear the backlog in its generator interconnection queue.

The first waiver would allow SPP to delay the 2024 definitive interconnection system impact study (DISIS) cluster’s first phase. The phase would begin after the 2023 DISIS second phase’s restudy is completed and posted in August 2025; without the waiver, the phase would start before the second phase of the 2022 and 2023 clusters and likely lead to unplanned restudies, staff said.

The second waiver would pause the opening of the 2025 DISIS cluster. Together, staff say they will ease conflicts with their effort to clear the GI queue’s backlog and transition to a new planning process. (See “DISIS Waivers Endorsed,” SPP Markets and Operations Policy Committee Briefs: July 16-17, 2024.)

“This really just reflects the reality of the situation that we’re in, in terms of the sheer magnitude and our customers’ generation figures that we’re seeing in the restudies that are resulting from that,” said Natasha Henderson, senior director of grid asset use for SPP.

“I know efforts to clear the queue are challenging … but it’s not fast enough,” Buffington, said. “I still have a lot of concerns about the timing. We’re just asking you to be creative about how we can get the process moving more quickly. There’s a lot of concern about alleged queue jumping, but at some point, we’ve got to cut out speculative developers and get a concrete study and concrete development.”

SPP plans to transition to the consolidated planning process (CPP) in late 2026 after a transition period. Opening the 2025 DISIS would mean the cluster’s generation would “significantly” overlap with the CPP’s transition study and first annual assessment.

FERC’s approval of the waivers would enable the timely completion of backlog studies and allow time to further develop CPP. The grid operator has 416 requests in the GI queue totaling about 84 GW in proposed capacity, down from the original backlog of 1,139 requests for 221 GW of capacity.

SPP Responds to Deficiency Letter

CEO Sugg said staff are working to address FERC’s questions about the Markets+ tariff filing and “some of its nuances, particularly transmission usage.”

The commission on July 31 filed a deficiency letter asking the RTO to address 16 issues with its proposed day-ahead market offering in the Western Interconnection. FERC gave SPP 60 days to respond. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)

“We’ve been working on formulating a response,” Sugg said. “We anticipate filing the response to those questions in the deficiency letter within the next 60 days.”

The Markets+ Participant Executive Committee has set aside an hour during its Aug. 13 meeting in Westminster, Colo., to discuss the deficiency letter with SPP legal staff.

OCC’s Hiett Leaves RSC

Oklahoma Corporation Commissioner Todd Hiett was a no-show for the RSC meeting Aug. 5, two days before he would give up his seat on the committee to seek treatment for alcoholism.

OCC staffer Jason Chaplin represented the state in Hiett’s absence.

Hiett, the RSC’s vice president, also stepped down as the OCC’s chair Aug. 7 but remains on the commission. Some lawmakers have asked for a special session to impeach Hiett. His fellow commissioners have called for his resignation and an independent investigation following two instances of public drunkenness and allegations of sexual misconduct. Hiett has refused to resign but offered to step down as chair.

The OCC elected Vice Chair Kim David as its new chair, and she will replace Hiett on the RSC.

The allegations against Hiett were first publicized last month by The Oklahoman, which reported that one incident occurred June 9 in the lobby of the hotel where the Mid-America Regulatory Conference was being held in Minneapolis. Hiett acknowledged to the newspaper that he had had too much to drink but could not remember any of his alleged actions.

In an additional piece of business, the RSC selected an “F Troop” as its Nominating Committee: Kansas’ Andrew French, Louisiana’s Mike Francis and South Dakota’s Kristie Fiegen. They will be responsible for selecting the committee’s 2025 term leadership.

2025 Operating Plan Endorsed

The board’s approval of its consent agenda included SPP’s 2025 operating plan, as recommended by the Finance and Strategic Planning Committees.

The plan is meant to provide a reference point for the highest priorities that will drive “significant” long-term gains for SPP and its members.

The consent agenda also contained recommended in-service date changes for a pair of competitive project certificates of convenience and necessity (CCNs) recently awarded to NextEra Energy Transmission Southwest (NEET SW). Staff urged approval of the transmission developer’s new in-service dates for its 345-kV Wolf Creek-Blackberry project in Missouri and Kansas and the 345-kV Minco-Draper line in Oklahoma, from Jan. 1, 2025, to July 15, 2025, and from July 1, 2024, to Jan. 31, 2025, respectively.

Staff also recommended new language for Evergy Kansas’ 345-kV Wolf-Creek-Waverly line to include re-termination at Wolf Creek, allowing NEET SW’s Wolf Creek-Blackberry project to progress without crossing the two lines.

NEET SW has been awarded SPP’s last three competitive projects. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021 and SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)

The consent agenda additionally included: Emeka Anyanwu’s (the CEO of Lincoln Electric System) nomination to fill a vacant transmission-using member’s seat on the Human Resources Committee; cost increases for a 138-kV Western Farmers project and Omaha Public Power District upgrades; a sponsored upgrade study for terminal equipment at several Western Area Power Administration substations; and the withdrawal of NTCs for Western Farmers substation work and SPS 115-kV terminal upgrades.

Finally, the agenda had two tariff changes that:

    • RR602: add process structure, tracking and improved criteria for evaluating potential transmission reconfigurations.
    • RR619: add application programming interfaces as an acceptable submittal process.