VALLEY FORGE, Pa. — PJM Planning Committee Chairman Ken Seiler said the new executive director of systems operations, Dave Souder, will replace him as committee chair in July.

Souder currently heads the Operating Committee. Seiler is becoming PJM’s vice president of planning. (See related story, “New Chair Come July,” PJM Operating Committee Briefs: June 11, 2019.)

Seiler’s promotion came during a leadership shake-up with the announcement of CEO Andy Ott’s retirement, effective June 30. (See PJM CEO Andy Ott to Retire.)

RTEP Poll

Aaron Berner, manager of transmission planning, said after more than six meetings with stakeholders, staff believe they are “close” on tweaks to Manual 14B that address how and when supplemental projects are removed from the Regional Transmission Expansion Plan.

Staff will email two questions to PC members regarding whether they believe the posted manual changes “are on the right track” and what further revisions still need to be made. Results will be presented at the Markets and Reliability Committee meeting June 27. (See “RTEP Removal Language on Track for June MRC Vote,” PJM PC/TEAC Briefs: May 16, 2019.)

The decision was made after stakeholders expressed confusion over how the results of the nonbinding poll would be interpreted. Some felt uncomfortable signaling approval without complete consensus on the language. A few transmission owners remain diametrically opposed to the entire effort and consider existing manual language sufficient as is, possibly skewing PJM’s perception of how willing stakeholders are to adopt changes. (See PJM Rebuffs Stakeholders on Supplemental Projects.)

PJM Developing Hybrid Fee Structure

Stakeholders will soon see PJM’s proposal for a hybrid-fee structure for transmission project cost–containment analyses, Manager of Infrastructure Coordination Mark Sims said.

Currently, the RTO charges nothing for cost-containment reviews of projects $20 million or less. Projects up to $100 million cost $5,000 to review, and larger projects incur a $30,000 fee. Sims said the new formula may include a flat fee, plus itemized study costs. Projects considered the most competitive will accumulate more itemized costs, Sims said, while those considered less viable could pay nothing additional beyond the flat fee.

“The way we are headed, we think, is to keep some flat fee structure plus detailed studied costs,” he said. “It will be somewhere between that zero and $30,000.”

Sims told the PC last month that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: May 16, 2019.)

Generation Interconnection Rules Endorsed

The PC endorsed revisions to Manual 14G to update PJM’s generation interconnection process and clarify the site control requirements. The changes expand rules for demand response in section 1.7 and refers on-site generators used to reduce load that participate as DR to Manuals 11 and 18 for further guidelines. The portion of such generators that inject power past the point of interconnection follow the interconnection process outlined in Manual 14G.

PJM also proposes a minimum site control term of three years — two years for projects of 20 MW or less — commencing on the first day of the new services queue in which the customer submits its request. Extensions must have been exercised by the developer when site control evidence is given to PJM if the initial term is less than the required minimum.

Despite some misgivings about site control extensions expressed during the May PC, stakeholders endorsed the revisions with only one abstention and zero objections. (See “Generation Interconnection Requests Update,” PJM PC/TEAC Briefs: May 16, 2019.)

Market Efficiency Process Enhancement Task Force Charter

The PC endorsed the updated charter for phase 3 of the Market Efficiency Process Enhancement Task Force.

Both the PC and the Markets and Reliability Committee approved phase 3 of the task force last month. Under its new charge, the group will explore possible alternatives to regional targeted market efficiency projects and consider changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits, as well as other concerns raised with benefit-cost calculations. (See “Market Efficiency Process Enhancement Task Force Gets Phase 3,” PJM PC/TEAC Briefs: April 11, 2019.) The group will make recommendations to the PC by Dec. 12.

Reserve Requirement Study Assumptions

PJM’s assumptions for its reserve requirement study earned unanimous support at the PC.

The capacity benefit margin — the amount of transmission import capability reserved to capture the reliability benefit of emergency sales — modeled in the study will be 3,500 MW. PJM will also use a load forecast error factor of 1% and base load models on assessment work performed by staff and reviewed by the Resource Adequacy Analysis Subcommittee.

Staff will use the PRISM model to develop a cumulative capacity outage probability table for each week of the year except the winter peak. During the winter peak, staff will create a table based on RTO-aggregate outage data collected between 2007/08 and 2018/19 to better account for the risk caused by the large volume of concurrent outages observed during the winter peak week.

The results of this study will be used to determine the forecast pool requirement for the 2020/21, 2021/22, 2022/23 and 2023/24 delivery years. A final report will be presented to the PC in September.

Dayton, Dominion, AEP Solutions

Dayton Power & Light, Dominion Energy and American Electric Power presented proposed supplemental projects during the Transmission Expansion Advisory Committee.

Dayton said AEP will re-energize a dead section of the Stuart-Marquis 345-kV line to bypass the now-defunct Killen substation near Wrightsville, Ohio. The $200,000 project will consist of Dayton installing guy stub poles for tension on the open section of the 345-kV loop.

A cheaper solution, Dayton said, would be to de-energize the Killen substation, update relay settings on the Stuart end of the line, install new tie-line meters and work with AEP to complete end-to-end relay testing for a cost of $100,000.

AEP estimates its share of the work — re-energizing the line, upgrading relay at the Don Marquis station and retiring intercompany metering — will cost approximately $1 million.

Dominion proposes installing a 3,000-amp, 50-kAIC circuit breaker to feed a requested new transformer at Chickahominy substation in Charles City County, Va., for an estimated cost of $750,000.

– Christen Smith