Roundup: Energy Price Formation, Market Efficiency Projects, Demand Response

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Energy Price Formation Senior Task Force

Stakeholders discussed synchronized-reserve-market issues at the April 18 meeting of the Energy Price Formation Senior Task Force.

They also heard a proposed timeline for short- and mid-term goals from Adam Keech, executive director of Market Operations.

“This is just an attempt to start bracketing some of the topics we’ve talked about,” he told the group. “This is a first sketch; it’s not etched in stone.”

First on the list of short-term solutions, tentatively pegged for delivery in the third quarter of this year, is working on the consolidation and accuracy of the synchronized reserve market.

A solution would address the poor response of Tier 1 resources; relying on synchronized resources that are not obligated to provide, nor penalized for not performing; and pricing that is inconsistent with system conditions and/or reliability value.

A straw proposal presented by Lisa Morelli, manager, Real-Time Market Operations, would consolidate Tier 1 and Tier 2 reserves into a single product. That product would be obligated to provide reserves, compensated and subject to consequences for nonperformance.

Keech also introduced as a short-term goal an effort to simplify the operating reserve demand curve, which currently has two step changes.

Morelli also outlined a suggested reserve zone modeling change. It would retain the existing RTO reserve zone with a closed-loop sub-zone structure but allow the location of the sub-zone to be flexible. Only one sub-zone would be used at a time.

The group’s next meeting is May 4 at 9 a.m.

Market Efficiency Process Enhancement Task Force

The Market Efficiency Process Enhancement Task Force continued education and responded to stakeholder questions at its April 20 meeting before moving into ongoing work on possible solutions.

The task force’s mission is to discuss challenges and opportunities for improvements that have arisen since PJM implemented Order 1000 processes. It reports to the Planning Committee. The scope of work includes making necessary changes to process, as well as respective governing document and manual revisions.

As part of its Phase 1 education, the task force covered the regional targeted market efficiency process (TMEP), congestion drivers and the benefit calculation for market efficiency projects.

There is a July 1 deadline for completion of Phase 1, so PJM can implement necessary changes prior to the opening of the 2018/19 Market Efficiency window on Nov. 1. PJM wants to work Phase 2 (market efficiency window and post-window mid-cycle assumption updates) through the stakeholder process by March 1, 2019.

PJM highlighted the benefits of the proposed TMEP. These small, low-cost projects have a short lead time and fix historical congestion. There are very specific criteria – the project must be an upgrade with persistent historical congestion issues not due to planned outages and not addressed by any planned upgrades. Capital cost is less than $20 million, and the project must be in service by the third summer season. Total capital costs must be covered by four years of benefits.

For the Interregional Market Efficiency Project Selection Process, PJM identifies congestion drivers, including market-to-market flowgates. As part of the new selection process, there are proposed language changes to PJM Manual 14F: Competitive Planning Process.

PJM also addressed gaps in the current benefit calculation methodology for Market Efficiency projects. PJM wants to correct inconsistency between transmission topology and generation retirement assumptions and alleviate uncertainty in benefits calculation due to unknown future market conditions.

The task force’s next meeting is May 18, at 1 p.m.

Demand Response Subcommittee

Members of the Demand Response Subcommittee discussed a consensus proposed change to section 4.3.7 of Manual 18: PJM Capacity Market regarding the calculation of Winter Peak Load at their April 18 meeting.

Currently, this calculation is based on the average of a curtailment service provider’s five peak demand values on the five PJM-defined coincident peak winter days. The proposed change would allow a CSP to exclude up to two of those five days if the customer’s usage is very low (less than 35 percent of the five-day average).

The group also received a reminder about the missing load data process in the calculation of Winter Peak Load, as well as an update on the demand response energy offer cap validation process.

According to new rules approved by the FERC and implemented on April 12, $1,000 is the default energy offer cap for both economic and emergency energy-only registrations. Members must validate incremental costs above $1,000.

The subcommittee’s next meeting is May 21 at 9:30 a.m.

Summer-Only Demand Response Senior Task Force

The education portion of the April 13 meeting of the Summer-Only Demand Response Senior Task Force focused on the Pennsylvania Act 129 program.

Signed into law in 2008, the act aims to reduce energy consumption and peak demand. The program is in its third phase, targeting performance years 2017 through 2020.

Bruce Campbell of CPower presented an overview and summary. Three Act 129 events occurred in the summer of 2017 and corresponded with PJM coincident peak days.

Eric Matheson of the Pennsylvania PUC provided analysis of summer 2017 performance under the act.

Task force members also worked on the options matrix. The next meeting is set for May 9.