Wide-ranging discussions of the competitive planning process marked the Planning Committee on July 12, stretching the group’s usual half-day meeting into the late afternoon.
The conversation kicked off with the first read of a proposal from the Market Efficiency Process Enhancement Task Force. The group was convened in February to identify manual enhancements based on two market efficiency project proposal windows held since the implementation of FERC Order 1000, which opened transmission projects to non-incumbents. The group has focused its work on the modeling of facility study agreement (FSA) generators and the interregional market efficiency project selection process.
Brian Chmielewski, manager – Market Simulation, told the Planning Committee that several of the topics slated to be considered in Phase 1 have been pushed to Phase 2 due to lack of ready consensus and timing issues. Those topics are: benefits-to-cost calculations, regional targeted market efficiency projects, and the market efficiency re-evaluation process. (See Market Efficiency Process Enhancement Looks at New Packages.)
A June poll to gauge support of six different packages indicated that 88.9 percent of respondents favored making a change; however, none of the packages received majority support.
Following the June poll, the task force winnowed the proposals to three – two from PJM and one put forward by AEP. The packages include a subset of Phase 1 design components, including:
- FSA modeling (three options)
- Benefits-adjustment for in-service date (two options)
- Sensitivity documentation/transparency (two options)
- Fixed generator and transmission topology to RTEP levels for all simulated years
The task force then conducted another poll with the majority (67 percent) favoring a change. One of the PJM packages (G) received 64 percent.
Among the main points of contention:
- Whether to exclude FSAs from the base case (PJM Package G)
- If FSAs should have their megawatt capability scaled to 40 percent (AEP package)
- How to handle the benefit adjustment for the in-service date
This led into the first-read discussion about proposed updates of Manual 14F: Competitive Planning Process.
Chmielewski presented the changes related to market efficiency project evaluation. Jason Shoemaker, senior lead engineer – Infrastructure Coordination, introduced proposed changes to reflect the new project proposal template, capture recent FERC filings and include some changes stemming from recent cost containment discussions. (The new template and a training video may be found on PJM’s Competitive Planning Process page.)
Other Committee Business
Mark Sims, manager – Infrastructure Coordination, presented the status of the cost containment initiative and next steps, including monthly committee updates.
PJM is coordinating with the independent market monitor to develop a comparative framework for projects, with the initial framework expected to be ready by Sept. 1. The next long-term project proposal window will open in November. “We won’t have proposals in our hands until February, so we have some time,” Sims said.
Aaron Berner, manager – Transmission Planning, reviewed the process of Subregional RTEP and Transmission Expansion Advisory Committee meetings.
“We’re open to suggestions to better manage the flow of information,” said Steve Herling, vice president – Planning. “We’re trying to put together a more structured process here.”
Berner also introduced the start of efforts to formulate principles associated with resilience in PJM’s transmission planning studies.
Chip Richardson of PPL, on behalf of PJM transmission owners, presented the revised supplemental project planning process (as directed by FERC in February).
- Improvements to the Manual 14 series, which guides the regional transmission planning process
- Load model to be used for the 2018 Reserve Requirement Study. The Planning Committee endorsed the study’s assumptions in June.
- This model is the same one used in the 2106 and 2017 Reserve Requirement Study.
- Patricio Rocha-Garrido, senior engineer – Resource Adequacy Planning, presented a recommendation to use the 10-year (2003–2012) load model for the 2018 Reserve Requirement Study base case. In addition, he advised switching the peak of the “world” – the adjacent region of MISO, NYISO, TVA and VACAR – to a different July week. This way, the peak for PJM and the world occur in the same month, but not on the same week.
- Updates to Manual 14B: PJM Region Transmission Planning Process, including minor procedural changes
- Revisions to PJM Protective Relaying Philosophy and Design Guidelines, which supplements Manual 07: PJM Protection Standards
- Proposed updates to Manual 14C: Generation and Transmission Interconnection Facility Construction
- Security initiative overview: Two-step verification will be rolled out to PJM stakeholders Oct. 10 (training begins Aug. 15).
- Compliance update: Order 845 – generator interconnection reforms. Final rule effective July 23; compliance filing due Nov. 5
- Dominion Energy removal of Carolina 54 remedial action scheme
- Reliability compliance update: NERC Standards and Compliance Workshop July 24–25, Columbus, Ohio; Monitoring and Situational Awareness Technical Conference Oct. 2–3, Carmel, Ind.
- System planning modeling update
Transmission Expansion Advisory Committee
The TEAC meeting followed the July 12 Planning Committee meeting.
Members were informed that the first 2018 proposal window opened July 2 and will close on Aug. 31. Three out of 160 flowgates identified will be included in the window.
Additionally, reliability upgrades not associated with the 2018 proposal window were reviewed with the committee.
Members also heard the market efficiency update related to the long-term proposal window scheduled to open in November.