PJM members last week approved two changes to the RTO’s market efficiency project planning process while rejecting a third to create a new regional targeted market efficiency project (RTMEP) process that had been challenged by stakeholders.
The RTMEP package proposed by American Electric Power and FirstEnergy received a sector-weighted vote of 1.56 (31%), failing to meet the 3.33 (66.7%) threshold for passage at Thursday’s Market and Reliability Committee meeting. The package, which transmission owners said would target small projects addressing persistent congestion not identified in the forward-looking planning model and would have awarded RTMEPs to the incumbent TO, was opposed by other stakeholders who had criticized it for excluding competition. (See PJM Stakeholders Debate Market Efficiency Proposals.)
PJM’s proposal, which called for 30-day competitive windows to select the developer in the RTMEP process, also failed to garner support, receiving a sector-weighted vote of 2.63 (53%). The AEP-FE proposal originally won 56% support in Planning Committee vote in May, edging out the PJM proposal, which received 55% support.
Brian Chmielewski of PJM said the RTMEP issues have been worked on by stakeholders for more than two years, and the packages were the product of extensive member input. Chmielewski said the idea to examine the RTMEP process originated from the interregional PJM-MISO TMEP planning process that had successfully produced a half-dozen projects.
Steve Lieberman, director of regulatory affairs for American Municipal Power (AMP), said he appreciated the effort that went into the packages, but he said AMP didn’t feel like the solutions in the packages were supportable.
“That’s not an indication for the need for more discussion,” Lieberman said. “We just don’t think there’s a problem here to be solved.”
Stakeholders did approve two changes regarding the RTO’s existing market efficiency, or “economic,” projects.
In a vote on the benefit calculation metric MEPs, stakeholders rejected a FirstEnergy solution package, which would have averaged multiple Monte Carlo results and run them on Regional Transmission Expansion Plan (RTEP), RTEP+3 and RTEP+6 years. That package failed with a sector-weighted vote of 2.02 (40%).
But PJM’s proposal and Operating Agreement revisions, which would use a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and RTEP years, won support from stakeholders, coming away with a sector-weighted vote of 3.75 (75%).
Stakeholders also approved PJM’s package to clarify when capacity benefits of MEPs are calculated, removing obsolete language from the Tariff that conflicted with the OA.
The approved packages now move on to the Members Committee for a final vote on Sept. 17 and a FERC filing in October.
Zonal NSPL Values
Stakeholders by acclamation endorsed deadline changes for adjustments associated with finalizing the zonal network service peak load (NSPL) values in Manual 14D and Manual 27.
Ray Fernandez, PJM manager for market settlements development, reviewed updates to the generator operational requirements in Manual 14D and the Tariff Accounting section of Manual 27. The Manual 27 revisions were endorsed at the Aug. 5 Market Implementation Committee meeting, while the related Manual 14D revisions were endorsed at the Aug. 6 Operating Committee meeting.
The revisions are related to the border yearly charge (BYC), the charge for long- and short-term point-to-point transmission service for points of delivery at PJM’s border, which goes into effect on Jan. 1 of each year. Fernandez said deadlines in both manuals conflicted with the deadlines of the BYC, including ones for the NSPL verification and zonal adjustments.
In Manual 14D, the behind-the-meter generation business rules had a Dec. 1 deadline for a load-serving entity to request a downward adjustment to its NSPL or obligation peak load. PJM proposed revising the deadline from Dec. 1 to Oct. 31.
Changes in Manual 27 included adding clauses to section 5.2 stipulating adjustments that need to be provided to PJM Market Settlements by Nov. 10. Any adjustments provided after the deadline will not be included in the NSPLs for the next calendar year and won’t be used in the BYC calculation.
Risk Management Committee Charter
The newly minted Risk Management Committee is set to meet for the first time in fall after stakeholders approved revisions to the Credit Subcommittee charter, expanding its scope to incorporate risk and changing its reporting structure.
Under the revised charter, the renamed subcommittee is also being elevated to a standing committee, reporting to the MRC rather than the MIC.
In her presentation, Jen Tribulski, PJM’s senior director of member services, said the Credit Subcommittee last met in March 2019 with much of the work around the RTO’s credit and risk rules accomplished through the Financial Risk Management Senior Task Force in the wake of the GreenHat Energy default.
Tribulski said the task force was established for the specific purpose of overhauling PJM’s rules for managing the credit risks of market participants and was not tasked with reviewing credit and risk management issues outside of its limited purposes. (See PJM Members OK Tighter Credit Rules.) She said PJM felt it was important to have a committee available to review and work on issues beyond those contemplated by the task force.
Critical Infrastructure Task Force Tabled
Stakeholders withdrew a problem statement and issue charge set to be voted on to revoke a related issue charge being worked on at special Planning Committee sessions regarding critical infrastructure stakeholder oversight after seeing progress.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, and Erik Heinle of the D.C. Office of the People’s Counsel had proposed creating a Critical Infrastructure Stakeholder Oversight Senior Task Force under the MRC.
Poulos and Heinle said the task force would have considered whether rule changes are needed to address facility avoidance and mitigation through planning processes and criteria on NERC’s critical infrastructure protection (CIP-014-2) list. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)
PC special sessions on the topic are currently scheduled through September, with avoidance and mitigation processes and criteria under consideration. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.) In proposing the task force, Poulos and Heinle expressed concern progress wasn’t being made in the PC special sessions and that TOs can bypass the stakeholder process with filings under Federal Power Act Section 205.
But on Thursday, Poulos said the PC is “in a much better position this month” with “great discussions” among members on mitigation and avoidance of CIP-014 projects. Poulos said PJM and AMP have been putting together “thoughtful packages” to achieve compromises.
Alex Stern, director of RTO strategy for PSEG Services, said he was “a little anxious” of the idea of members being able to make a motion at the MRC if they don’t like the direction the stakeholder process is going on an issue.
Poulos said he recognizes stakeholders can vote any way they want to on an issue, but the ability to bring an issue to a vote at the MRC is the right of stakeholders.
Cost Development Subcommittee
Glen Boyle of PJM reviewed proposed revisions to the Cost Development Subcommittee charter during a first read. Boyle said the CDS has been dormant since 2013 and was tasked with developing, reviewing and recommending standard procedures for calculating the costs of products or services.
PJM and the Independent Market Monitor have discussed the need to restart the CDS to address several issues, Boyle said, including Manual 15 clarifications, variable operations and maintenance (VOM), and fuel-cost policy clarifications and educational topics.
The CDS charter has been revised by PJM to report to the MIC instead of the MRC, as most of the issues are handled at the MIC.
The charter changes are scheduled to be voted on at the September MRC meeting.
Consent Agenda
Two issues were endorsed in the consent agenda, with one stakeholder voting no on the agenda items.
First, revisions to Manuals 14A, 14B and 14G in response to PJM PC/TEAC Briefs: July 7, 2020.)
Second, stakeholders endorsed OA revisions to grant TOs access to the Dispatch Interactive Map Application. (See “DIMA Quick Fix Endorsed,” PJM OC Briefs: July 9, 2020.)