VALLEY FORGE, Pa. — The Market Implementation Committee voted March 6 to endorse a PJM proposal to revise its approach to measuring and verifying the capacity provided by energy efficiency resources. (See PJM Seeking Expedited Approval of Energy Efficiency Changes.)
PJM’s Pete Langbein said the proposal aims to clarify which baseline EE providers should use to measure the savings a resource can offer into a Base Residual Auction (BRA); require that they demonstrate to PJM that installations of the more efficient equipment was completed; and show they have exclusive rights with the owner of the equipment to enter its savings into the capacity market.
The PJM proposal received 52% support, winning out over packages sponsored by CPower and Affirmed Energy, which respectively received 26% and 4% support. The question of whether stakeholders preferred the PJM proposal over the status quo originally tied, but multiple stakeholders cited challenges casting their ballots. The committee opted to reconsider the item, and support for the package grew to 61%.
The changes are being brought under an expedited process with the aim of receiving stakeholder approval in time to implement for the 2025/26 BRA, scheduled for July. Redlines were first presented at the Feb. 22 Markets and Reliability Committee, where several stakeholders argued that the proposal is moving too quickly to ensure that it’s understood by market participants and fully vetted to prevent unintended consequences.
The proposal would draw a sharper distinction between the standard baseline — which considers the last efficient equipment that could be installed versus the product being installed as an EE resource — and the current load baseline — which requires there be a cause-and-effect link between the revenues EE resources receive through the capacity market and their participation in the BRA. If a resource is eligible to use the current load baseline, the proposal would set a three-year limit on technical reference manuals (TRMs) to measure the load of the new equipment against; if no TRMs were available, EE providers would be required to use meter data.
Independent Market Monitor Joe Bowring said PJM’s proposal does not go as far as he would like in tightening EE standards but that it would nonetheless improve market functionality. As he often does, Bowring noted that EE is not a resource in PJM’s capacity market and argued that it should not be paid through the capacity market.
Affirmed’s Luke Fishback and CPower’s Ken Schisler raised issues they said would prevent EE providers from complying with the proposal. They argued that the three-year limit on TRMs would disqualify the majority of those produced by PJM states. Their companies had offered longer windows in their own packages.
Langbein told RTO Insider that older TRMs may include equipment that is no longer representative of what is being installed in that region, possibly leading to an inflated baseline.
Bowring said a five-year TRM may include data from at least three years prior to the TRM date and that the eight-year-old results are then used to estimate savings for four years into the future. The baselines even for a three-year-old TRM are not relevant to any actual savings, he argued.
Schisler said PJM’s language requiring a causal link between capacity market participation and the revenues it offers comes from an understandable desire to ensure that capacity revenues are producing a reduction in load. But he argued the proposal is too strict and would exclude projects from participating in the market if they have multiple benefits, including capacity revenues. At the February MRC meeting, he gave the example of a project to improve home insulation that would reduce climate control load while also alleviating health issues from building materials exposed to humid air.
Bowring said the fact that EE providers assert that there does not need to be a link between the wholesale PJM capacity market and the assumed savings for which customers pay $100 million per year demonstrates why EE should not be paid through the capacity market. He argued that the market is not intended as a vehicle to subsidize broader social goals.
Fishback said Affirmed’s proposal was aimed at taking a more data-driven approach to the question of how often TRMs are updated and would have included updates to PJM’s attestation requirements, the way they verify installations and how they verify unique ownership of capacity rights. He said PJM’s language would likely prove especially onerous incentivizing adoption of efficient products through retailers.
“This language as written in the redline runs the risk of taking the vast majority of utility programs and removing them from the table, because the majority of them are run through retailers and retailers will not be able to get an address for each lightbulb they sold,” he said.
Fishback also argued that the changes are being made too quickly without any apparent need ahead of the next auction. He motioned to defer the vote to the April MIC meeting, arguing that the three proposals were similar in many ways and more time could allow for a compromise to be found. The motion failed with 57% in opposition.
1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions
Dominion Energy and American Electric Power presented a joint proposal to accurately assign the capacity obligations from large load additions (LLAs) to entities within a transmission zone, including entities operating under fixed resource requirement (FRR) and Reliability Pricing Model (RPM) rules. (See “Capacity Obligations for Forecasted Large Load Adjustments,” PJM MIC Briefs: Oct. 4, 2023.)
When bringing the issue charge, AEP’s Josh Burkholder argued that the data center growth can lead to the obligation to procure capacity to serve that load being split between market participants in a transmission zone even when the load falls entirely within one’s footprint.
In February, FERC granted AEP a waiver of the capacity obligation for four of its vertically integrated utilities to not include about 1,860 MW of data center load expected in AEP Ohio (ER24-545). The waiver is applicable for only the 2025/26 auction; in its filing, AEP noted that a stakeholder process had been initiated to consider changes to how capacity obligations for large load additions are calculated. (See FERC Grants AEP Utilities Waiver of Capacity Obligation.)
Dominion has submitted a similar waiver request, though Old Dominion Electric Cooperative (ODEC) and Northern Virginia Electric Cooperative (NOVEC) have protested, arguing that the circumstances around the Data Center Alley in Northern Virginia differ from those AEP faced in Ohio (ER24-1037).
The proposal would exclude LLAs from the calculation of base zonal scaling factors and apply that load to the obligation peak load (OPL) of the zone it is projected to be added to. LLAs are determined by PJM using information from load-serving entities about expected load growth and detailed in the RTO’s annual load forecast reports under Table B-9.
Much of the discussion centered around how PJM uses the hourly load forecasts provided by LSEs to determine the LLAs it enters into Table B-9.
ODEC’s Mike Cocco said that because the transmission provider will be assigning LLA directly to transmission-dependent utilities, this shifting of incentives and associated costs will necessitate the ability for the TDUs to provide their own LLA forecast to the Load Analysis Subcommittee. In addition, he could understand the arguments as to why the proposal should not be voted on without language detailing how PJM approves the LLAs, suggesting there should be some documented process PJM follows that should be established in the manuals.
Dominion’s Jim Davis and MIC Facilitator Foluso Afelumo said changes to the development of Table B-9 are out of the scope of the issue charge approved in October.
Rory Sweeney of NOVEC argued that because that process is not laid out in the manuals, it would not constitute a change to existing practices and therefore is within the issue charge’s scope.
Bowring said the proposal needs to have explicit rules governing the treatment of changes in the load forecast for large loads. The final amount of capacity paid for is a result of a final forecast just prior to the delivery year that can vary significantly from the forecast in the proposal. The final forecast also defines the level of capacity transfer rights, the capacity market equivalent of financial transmission rights.
Other Committee Business
The MIC endorsed a PJM quick-fix proposal seeking to outline its existing practices around interface pricing points, which groups buses together when calculating LMPs for energy transfers between external areas. The revisions to Manual 11 include a definition of interface pricing points and establish an annual review of power flow impacts on each interface and a recommendation from the Monitor to adjust the weighting of component interfaces to maintain congruity between prices and system conditions.
PJM also presented a joint proposal with the Monitor to add more details to the parameters that synchronized condensers include in their market offers. PJM’s David Hauske said the proposal is focused on adding Operating Agreement and manual definitions of condense startup costs, condense-to-generate costs and condense energy use; there would be no change to PJM practices, he said.
There will be some overlap between the 2025/26 BRA and the initiation of pre-auction activities for the following auction, Langbein told the committee. Pre-auction activity deadlines that will fall before the conclusion of the 2025/26 auction include: the deadline for planned resources to notify PJM of their notice of intent, minimum offer price rule certification, requests for an exception from the must-offer requirement, the Monitor’s posting of unit-specific energy and ancillary services (EAS) offset, and seller requests for winter capacity interconnection rights. Langbein said PJM is not currently considering any delay to the 2026/27 BRA, which is scheduled to open in December.
