VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting endorsed PJM’s recommended load model for the 2018 reserve requirement study, which uses data from 2003 through 2012.

The study was adjusted to reflect the fact that load within the RTO’s footprint peaks during a different week than the area outside the footprint included in the model.

PJM selects a model for the study because the coincident peak distributions from the load forecast can’t be used directly in the PRISM modeling software, the RTO’s Patricio Rocha-Garrido said.

American Municipal Power’s Ryan Dolan asked why staff chose not to use the best-performing model from 2004 to 2012.

“We prefer more data to less data,” Rocha-Garrido replied, adding that the extra year “is a close second.”

“What’s the point of doing the test if we’re not going to accept the result?” Dolan asked.

“The test informs the decision,” Rocha-Garrido said.

CETL Changes

The complex interdependency of PJM’s procedures was on display when a presentation on proposed revisions to Attachment C of Manual 14B — billed as improving transparency and clarity — evolved into a discussion on potential impacts to capacity emergency transfer limits (CETLs) and concerns about how that might affect zonal capacity requirements.

The RTO’s Jonathan Kern presented the proposal, which would also “correct any conflicts between how the procedures are described and how PJM actually implements them” and include “a few minor procedural changes.” Many of the revisions focus on procedures for the load deliverability test or calculating CETLs.

Several stakeholders asked PJM to delineate how each revision might potentially affect CETL calculations. Kern said staff could provide all the distribution factors but that it was “premature” to perform full CETL analyses because the RTO hasn’t yet decided to include any of the external facilities. Staff believe considering them is “prudent” to ensure they’re not “turning a blind eye” to the potential impact of external systems if PJM analyses don’t account for them.

Market Efficiency

It appears the toil at a July 5 meeting of the Market Efficiency Process Enhancement Task Force has paid off. PJM’s Brian Chmielewski reviewed results of a last-minute poll that was requested to be completed in the few days between the task force’s meeting and the PC. (See PJM Market Efficiency Project Rules Could Slip Deadline.)

At issue was a set of six proposals to address how PJM evaluates and selects discretionary transmission projects. The poll showed majority support for Package G, which would exclude from the base case those units with facility study agreements (FSAs) and suspended interconnection service agreements and their associated network upgrades at the time of case build, unless they are needed for reliability.

Energy benefits of projects that are proposed to be in service later than the Regional Transmission Expansion Planning year would be adjusted to account for any savings forgone because of the later in-service date. Annual mandatory sensitivity studies would include FSA units only if they were excluded from the base case analysis. Sensitivities would be used for evaluation of a proposals’ robustness and sizing, but not for benefit-to-cost ratio tests. Parameters would be decided prior to the beginning of the project proposal window. In all simulated years, generation and transmission topology would be set at the RTEP-year level.

LS Power’s Sharon Segner asked that the proposed Tariff language be ready to review at the task force’s next meeting on July 20 so it can be discussed prior to the July meeting of the Markets and Reliability Committee.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked for more clarity on FSA issues because they are “certainly of concern” to some advocates.

Segner and Public Service Electric and Gas’ Alex Stern, who had requested the fast turnaround on the poll, praised Chmielewski and other staff on the task force for compiling it so quickly.

Cascading Trees

PJM’s Aaron Berner reviewed staff’s efforts to incorporate resilience objectives into transmission planning. As part of that initiative, staff have developed a visualization tool called “Cascading Trees” that considers the potential impact to the grid of “more extreme” events and analyzes probabilities of what issues such events could cause.

“That will play an important piece in how we develop plans,” Berner said. He clarified that the current analyses assume the trigger event has occurred and said it’s unclear whether staff will consider calculating the probability of the triggering event happening in the first place.

Stakeholders seized on the analysis with questions about PJM’s plans for addressing resilience. Berner turned many of those questions away, emphasizing that the analysis remains in its infancy.

“That’s more in depth than I planned on going into today,” Berner said.

In response to a question from Dolan, Berner confirmed that staff are working with TOs, many of which already have resilience factors included in their internal planning assumptions.

“We do not intend to move forward in isolation. We are having conversations with the transmission owners on how this might work,” Berner said.

PJM’s Steve Herling reminded stakeholders that staff are simply acting on their marching orders.

“The direction we’re taking to pursue resilience is coming from the board,” he said.

RTEP Processes

Berner and PPL’s Frank “Chip” Richardson presented plans for reorganizing the processes for reviewing transmission projects. Berner covered plans for the sub-regional RTEP and Transmission Expansion Advisory Committee. Richardson explained TOs’ plan for supplemental projects.

The process designs are similar and stick to the requirements outlined in FERC’s ruling that TOs weren’t properly complying with their obligations under Order 890 to involve stakeholders early enough to solicit their needs and provide required information before making decisions to proceed with “supplemental” projects — transmission expansions or enhancements not required for compliance with PJM reliability, operational performance or economic criteria. TOs describe them as projects planned by each company individually to address items not addressed by PJM, such as customer service, replacement of failing, poor performing or antiquated equipment and enhancements to the security of their transmission system. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)

Stakeholders pressed TOs for more detail on how they plan to engage in the meetings, but Richardson emphasized the TOs’ focus on implementing the changes.

“Certainly, as we implement this, people will be able to voice opinions about what they think … but we’re not focused on changes right now. We’re focused on getting it implemented,” he said. “When we’re ready to have you take a look at it, we’ll let you know. … We’ll think about [feedback] after we get through a few cycles.”

— Rory D. Sweeney