Energy Price Formation Task Force looks at Reserve Market

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Following the March 22 approval by the Markets and Reliability Committee of its charter, the Energy Price Formation Senior Task Force spent the day March 29 focusing on the reserve market and shortage pricing.

Under the revised issue charge approved by the MRC at its March 22 meeting, the Operating Committee is tasked with examining reliability-related aspects of a new, real-time secondary reserve product.

The meeting featured presentations by Lisa Morelli, manager, Real-Time Market Operations; Catherine Tyler of Monitoring Analytics; and ERCOT.

Morelli highlighted gaps in the estimation, event response, valuation and compensation of Tier 1 resources – units that are online and following economic dispatch, but which are only partially loaded. They can then increase their output within 10 minutes at the PJM dispatcher’s request.

The use of Tier 1 resources can lead to inaccurate accounting of reserve capability, she said. These resources also aren’t obligated to respond, and in 2017, did so at a rate of 50.5 percent.

In addition, Tier 1 MW are assumed to be free, when they “could be considered the most valuable synchronized reserves,” she said.

Morelli also outlined the benefits of having a potential new, 30-minute real-time reserve market. Such a product could serve as a tool to help avoid operating emergencies instead of simply serving as an indication that the system is in one, she said.

Tyler said the cost of Tier 1 resources to provide more energy is zero because they’re already online, she said. Therefore, any clearing price based on non-synchronized reserve clearing prices is a “windfall.”

She recommended eliminating the payment of Tier 1 resources at non-synchronized reserve clearing prices, defining rules for Tier 1 biasing or getting rid of the category of Tier 1 resources altogether.

Distributed Energy Resources Subcommittee

The DERS reviewed results from a stakeholder poll and discussed next steps for Wholesale DER market participation rules at its March 26 meeting.

PJM and stakeholders discussed FERC Order 807 regarding multiple entities behind a single point of interconnection and implications for DER. The Planning Committee will continue to review issues related to FERC Order 807 and will update the DERS as appropriate.

PJM and stakeholders also began developing the solutions matrix for non-wholesale DER observability, looking at interest development, design components and solution options. Stakeholders should be prepared to discuss additional solution options at the next meeting on April 25.

Stakeholders heard about the PJM workshop on the IEEE 1547–2018 standard that requires voltage and frequency ride-through from inverter-based resources. PJM plans to coordinate and host another workshop with TOs and EDCs in the PJM region this fall to further discuss implementation on the new standard.

Joint System Operations Subcommittee

Operations in March were marked by three unusual winter storms, Donnie Bielak, manager, Reliability Engineering, told the Joint System Operations Subcommittee at its March 29 meeting.

The first, on March 2, brought not just snow but high winds, he said, leading to a total of 1.2 million customer outages. The second storm, which followed the next week, delivered a comparable amount of snow, but winds were milder, resulting in 200,000 customer outages, he said. The third storm, which blew in on March 21, saw 80,000 customer outages.

Joe Ciabattoni, manager, Markets Coordination, presented a plan that would replace phone notification when calling generators online to an automated, electronic method. PJM is looking to start a pilot program around the end of this year.

Bielak also presented two NERC Lessons Learned and members heard a status update on eDart, a reliability compliance update and definition changes to the Eastern and Cleveland reactive transfer interfaces to reflect a new Breinigsville-Alburtis 500 kV line, transmission upgrades and generation retirements.