Roundup: Primary Frequency Response, Joint System Operations, DER Metering

1220

PJM and stakeholders reviewed metering and accounting methodologies for energy storage at the Distributed Energy Resources Subcommittee’s April 25 meeting.

Scott Baker, senior business solution analyst and subcommittee chair, reviewed Section H of Order 841 to provide context on the subcommittee’s compliance obligation.

Order 841, Section H details proposed accounting methodologies to calculate wholesale stored electric energy when energy storage is located behind a retail customer’s meter, or has the ability to serve retail load during an outage/emergency.

The subcommittee’s work on Order 841 is only a small part of the order – the part affecting DER. Most of PJM’s work on Order 841 is being done through a special session of the Market Implementation Committee on electric storage.

There were two methodology proposals. The PJM proposed methodology looked at front-of-meter resources that have the ability to serve load during an outage/emergency. Icetec presented a member proposed methodology for behind-the-customer-meter electric storage resources.

Energy used to charge electric resources must be settled at nodal locational marginal prices. For PJM, that is already the case. The Order states that the sale of electric energy from RTO/ISO markets to an electric storage resource that the resource then resells back to that market must be at the wholesale LMP. If the energy is injected back to the grid, it must be wholesale.

Baker said that because this is a fairly new concept, PJM and stakeholders are still looking at what other entities are doing – there may not yet be a best practice to compare against.

He directed stakeholders to a Southern California Edison filing with the California Public Utility Commission, which shows a completely different approach than either PJM or Icetec’s, in that the utility battery needs to offer into the day-ahead market.

Pete Langbein, manager – Demand Response Operations, and stakeholders continued discussion of the process and data requirements to gain greater observability of non-wholesale DER. The group discussed existing and new solution options.

Stakeholders are still at what Langbein termed baby steps, looking at mapping elements rather than modeling into the Energy Management System. Langbein and Baker encouraged stakeholders to begin building package proposals.

A distributed energy resource is a generation or electric energy storage resource connected at distribution voltages and/or connected behind a load meter.

Joint System Operations Subcommittee

The PJM system experienced one spinning event this month, on April 12, Chris Pilong, director – Dispatch, told the Joint System Operations Subcommittee at its meeting April 26.

The event lasted about 11 minutes. Out of 1,050 megawatts of Tier 1 resources requested, 637 MW responded, he said, encouraging members to make sure their operators are ready and on call for synchronized reserve needs.

Natalie Tacka, ARC engineer – Corporate Client Services, introduced a PJM effort to enhance unit restriction reporting and tracking. Currently, the communication methods are static snapshots and are not tied in real time to actual run hours, she said.

At issue are restrictions that limit run time and that can be monitored in advance of current operating day or day ahead, including on-site fuel inventory, emissions limitations, demineralized water and cooling water.

PJM wants to consolidate current methods of restriction communication and dynamically track how close a unit is to its restrictions.

Tacka asked for generation owners to provide feedback, particularly to review design and scenarios for entering restriction information. Interested parties should reach out by May 11.

Members also learned that PJM will begin gathering generator data through the eDART Black Start Calculator for restoration planning purposes on May 7, with a submission deadline of June 10.

In addition, the committee endorsed changes to Manual 36: System Restoration and Manual 3: Transmission Operations.

Primary Frequency Response Senior Task Force

Stakeholders reviewed poll results and discussed plans going forward at the April 26 Primary Frequency Response Senior Task Force meeting. The task force is awaiting actions by the Federal Energy Regulatory Commission.

The task force agreed to keep meeting and discussing alternative proposals. It will not have a binding vote, however, until FERC provides clarification on Order 842. Glen Boyle, manager – System Operator Training and chair of the task force, will present a task force update at the May 24 Markets & Reliability Committee meeting.

In general, the proposals were not aligned with Order 842; some stakeholders interpret Order 842 as specifically exempting existing resources from PFR requirements. PJM asked FERC for clarification or rehearing, which will determine whether or not PJM may put PFR requirements on existing resources.

A proposal from AEP was the only one that received a majority in the nonbinding poll. The AEP package applies PFR capability requirements on new units as well as existing unit that increase their unit capability via a modified interconnection agreement.

Primary frequency response is vital to system restoration. It is the first line of defense and is needed for accurate modeling and event analysis.