Roundup: Distributed Energy Resources, Primary Frequency Response, Summer-Only Demand Response

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This is the periodic roundup of the work of PJM’s subcommittees and task forces.

Distributed Energy Resources Subcommittee   

At the Distributed Energy Resources Subcommittee meeting on July 30, Scott Baker, senior business solution analyst, reviewed final draft manual language associated with the proposal to gain greater observability of non-wholesale distributed energy resources/behind-the-meter-generation resources.

He led the discussion on stakeholder feedback received at other committees, as well as language changes.

FirstEnergy presented proposed modifications to the manual language, which included clarification that transmission owners may contact transmission-interconnected behind-the-meter generation resources or may contact the relevant electric distribution company to coordinate with distribution-interconnected behind-the-meter generation.

There were no objections to the proposed changes in the meeting, though a request for more time to review prior to voting was made.

An electronic vote will be opened on Thursday, Aug. 2 and closed on Thursday, Aug. 9.  If the proposal receives greater than 50 percent in support, it will go for a first read at the Aug. 23 Markets & Reliability Committee meeting.

Scott Benner, senior lead engineer – Advanced Analytics, explained the status quo for synchronized reserve event performance for generation resources, which is always measured at a generator’s point of interconnection.

Andrew Levitt, senior business solutions architect – Applied Innovation, presented solutions options for a proposal on how to measure and verify distributed energy resources’ ancillary service performance. They include options for measuring at the point of interconnection or via a sub-meter that directly measures the performance of a wholesale DER. Stakeholders reviewed the matrix with draft design components and solution options.

Susan McGill, manager – Interconnection Analysis, provided an educational presentation on the interconnection process for wholesale DER in PJM. This included how jurisdiction over the interconnection is determined, how the pre-application process works, and how the connection of behind-the-meter generation differs in the interconnection process from the ways other generation is connected. The presentation also covered high-level concepts that could improve the interconnection process for wholesale DER at PJM.

McGill also provided follow-up clarification that state net-energy-metered resources are not eligible for the PJM non-queue process (more about the non-queue process can be found in Manual 14A: New Services Request Process, Section 5.4.5).

Primary Frequency Response Senior Task Force – July 25

Scott Baker, senior business solution analyst, discussed moving operational requirements for resources on Wholesale Market Power Agreements to the Distributed Energy Resources Subcommittee.

The Federal Energy Regulatory Commission’s Order 842  on primary frequency response clearly specified that the primary frequency response requirements should apply to all new generation or modified generation that executes a new Interconnection Service Agreement. The question is whether these same requirements should apply to resources participating in PJM’s wholesale markets through a wholesale market power agreement (WMPA).

Currently, other than metering requirements, there are no operational requirements for resources on a WMPA. Other possibilities of operational requirements in addition to primary frequency response for resources on WMPA could include reactive services, voltage and frequency ride-through, power factor control and possible services. PJM believes the Distributed Energy Resources Subcommittee is the most logical forum for stakeholder discussion of these issues.

Baker said the DERS will discuss jurisdictional responsibilities and methods of implementation of WMPA reliability requirements under existing PJM governing documents.  Some of that discussion will be policy focused, in addition to addressing technical considerations.

The DERS will also work with distribution utilities and state commissions on whether reliability services from WMPA projects would conflict with state interconnection agreement and/or distribution system reliability metrics.

PJM briefly discussed the North American Electric Reliability Corporation’s request to update its contact list for generation owners in the PJM footprint.

Glen Boyle, manager – Operations Analysis and Compliance and task force facilitator, reviewed the matrix and discussed the minor updates since the June meeting.

The next task force meeting is scheduled for September 26.  While the primary frequency response requirements for new units have been filed, PJM and others are awaiting a FERC clarification on whether or not the requirements could also be applied to existing units.

Summer-Only Demand Response Senior Task Force – July 25

Four proposal packages have been offered to date in the task force. All the packages propose a load forecast adjustment as the mechanism to recognize summer-only demand response. The adjusted load forecast would then be used in calculating the Reliability Pricing Model reliability requirement.

All of the packages also propose a modification to the forecast adjustment based on most recent performance if a program does not perform.

The packages differ on program eligibility, when and how the programs will be expected to curtail, how program performance is measured, and how programs are valued.

Rebecca Carroll, director – Member Relations and task force facilitator, reviewed the results of the non-binding poll on the level of support for the current packages and key design components.

The poll was broken down into support for the individual packages, as well as preference of the individual components within the packages.

Andrew Gledhill, senior analyst – Resource Adequacy Planning, reviewed a spreadsheet that showed how RTO load (as a share of seasonal expected peak) corresponds to zonal temperature humidity index (THI).

Gledhill said the seasonal expected peak is assumed to be the weather normal peak. It is not the same value as the forecasted peak, however. The RTO load being compared to the seasonal peak is actual load and not the day-ahead forecasted load.  The THI values are actual maximum THI values and not forecasted values.

Tom Falin, director – Resource Adequacy Planning, led a discussion on a stakeholder request to review the feasibility of certain design components in the current proposals, including performance measurement and curtailment triggers, some of the issues on which the packages differ significantly.

Falin also shared that PJM does not view the participation requirements of new and existing peak shaving programs differently.

Falin also reviewed the working matrix, highlighting changes to the PJM package since the last task force meeting.  These included elements for supervisory and operational control.