The Summer-only Demand Response Senior Task Force continued its comprehensive review of proposals as it works toward a task-force vote and presentation at the September Markets & Reliability Committee meeting.
Stakeholders have conducted robust conversations around resources’ ability to participate in markets both as a Capacity Performance demand resource and as a load forecast adjustment (LFA), and on resources’ eligibility to participate in both the base residual auction and incremental auctions.
At the Aug. 29 meeting, the consumer advocates presented their concerns with the mechanisms established in the different proposals. This continued the discussion from Aug. 15, when the Pennsylvania Public Utility Commission presented some of the state’s concerns on peak shaving in incremental auctions. The PAPUC stated that PJM’s base residual auction timeline does not align well with state planning timelines.
Becky Carroll, director – Member Relations and chair of the task force, pointed out that the mission of the task force is to develop solutions for demand response resources that are unable to participate in the market, due to Capacity Performance rules that limit market participation to annual resources.
At both the Aug. 29 and Aug. 15 meetings, Tom Falin, director – Resource Adequacy Planning, said PJM’s focus is improving the accuracy of the long-term zonal and RTO load forecast. While the proposal’s design components endeavor to respond to participant needs, they still must satisfy PJM’s planning needs and be both predictable and measurable.
Participation is restricted to load reduction programs (both direct control and behavioral) governed by a tariff approved by the relevant electric retail regulatory authority.
Programs will be evaluated on a case-by-case basis, said Falin. Programs must submit a list of requirements, which PJM would evaluate to guarantee there is sufficient program information up front.
Energy Price Formation Senior Task Force
The Energy Price Formation Senior Task Force expects to vote on a proposal package following its Nov. 1 meeting, in time to present it for a first read to the Markets and Reliability Committee on Dec. 6. If that time schedule holds, the Members Committee could see the item on its agenda for a vote on Jan. 24.
That would mark a year since the group was convened. It was tasked with identifying ways to enhance energy market pricing so that prices accurately reflect the true cost of serving electricity demand and minimize the need for out-of-market uplift payments.
Previously, the task force had hoped to be able to vote on a package after its Aug. 22 or Sept. 10 meetings. At the group’s Aug. 22 meeting, it was announced that the Sept. 10 session has been canceled, and the next meeting will be Sept. 26. There is one more meeting scheduled before Nov. 1, on Oct. 12.
At the Aug. 22 meeting, members continued discussion of the Operating Reserves Demand Curve, with a data analysis of adjustments to the ORDC for operator actions. PJM also provided answers to questions posed at the Aug. 6 meeting and shared its simulations methodology.
Joe Bowring and Catherine Tyler of Monitoring Analytics, the independent market monitor, delivered a presentation on the synchronized reserve must-offer requirement.
Distributed Energy Resources Subcommittee
A vote of stakeholders in the Distributed Energy Resources Subcommittee indicated 88.39 percent approval of a proposal to enhance the observability of non-wholesale DER, also known as behind-the-meter generation.
The vote reflected 17 unique responders representing 112 companies. The poll results were shared at the Aug. 27 meeting of the DER Subcommittee, where members also discussed the results of a nonbinding poll question in which 58.93 percent (66 votes) said they would rather retain the status quo than make a change.
Having garnered more than 50 percent of the vote, the proposal went before the Markets & Reliability Committee for a first read on Aug. 23.
Also at the subcommittee meeting, a group calling themselves DER Supporters gave a presentation outlining hurdles to DER innovation in the current interconnection process. Member companies in the group are Advanced Energy Economy, A.F. Mensah, EnerNOC, Icetec and Mosaic Power, along with the Microgrid Resources Coalition, the Tibiri Energy Group and the University of Delaware.
Members reviewed an issue statement drafted by the Primary Frequency Response Senior Task Force. The issue statement addressed operational capability requirements for interconnection projects that are non-FERC jurisdictional and only execute a wholesale market participation agreement with PJM and the transmission owner.
Laura Walter, PJM senior lead economist, gave an update on a straw proposal for compliance with FERC Order 841 on electric storage participation in the markets.
Members also discussed a separate straw proposal regarding ancillary services for “net excess” DER behind a customer meter.
Market Efficiency Process Enhancement Task Force
The Market Efficiency Process Enhancement Task Force moved into its second phase at its Aug. 17 meeting, introducing possibilities for market efficiency capacity benefits calculation, regional targeted market efficiency process and project reevaluation. The task force will continue to brainstorm the proposals at its next meeting Sept. 7.
Alex Worcester, System Planning Modeling and Support, reviewed the current Interregional Targeted Market Efficiency Project type for market-to-market flow gates between PJM and MISO, and presented sticking points for creating a comparable regional process.
The Targeted Market Efficiency Project process looks at projects that have significant historical border (market-to-market) congestion. The guiding principles include that the projects must be small and low-cost, with a short-lead time and targeted at specific, historical congestion issues. The task force is charged with considering options for the creation of a comparable regional process for internal PJM flow gates.
Nicolae Dumitriu, senior lead engineer – Market Simulation, reviewed Phase 1 discussions on both the market efficiency reevaluation process and market efficiency capacity and energy benefits calculation.
Dumitriu guided stakeholders through capacity benefits calculations, detailed capacity benefits and outlined PJM’s concerns with the current process. For example, planning parameters applicable for capacity market drivers cannot now be calculated beyond the Regional Transmission Expansion Plan year.
Dumitriu also outlined PJM’s proposal regarding the reevaluation of previously approved market efficiency transmission upgrades. The PJM proposal limits reevaluations, based on a capital cost threshold; it ceases reevaluating projects once the project completes 20 percent of its construction within the engineering and procurement status.
June stakeholder poll results showed that the majority prefer to limit the number of market efficiency projects for which reevaluation is done. Dumitriu noted that PJM would like to add an additional checkpoint that will exempt from reevaluation those market efficiency projects that are less than 18 months from being energized.
Niloufar Mirhosseini, senior engineer – Market Simulation, gave an overview of the outstanding energy benefit calculation design components from Phase 1.
She said that PJM is fine with moving forward with status quo for the remaining energy benefit calculation design components, since most of the concerns with the current energy benefit calculation methodology will be addressed by the changes endorsed by Planning Committee in Phase 1.