VALLEY FORGE, Pa. — PJM is planning to add another volume to its Manual 14 series by splitting out the requirements for generation interconnection from Manual 14A into a separate Manual 14G, staff told attendees at last week’s Planning Committee meeting.

PJM’s Lisa Krizenoskas walked through the separation, noting that the new manual will be organized by generators under 20 MW, over 20 MW and other types of generation.

Staff said that rules for handling multiple generators behind the same point of interconnection will be addressed after the manual split is endorsed, but Ryan Dolan from American Municipal Power questioned why they wouldn’t try to sort out both issues simultaneously. Krizenoskas said the new rules might delay the separation, which is meant to provide clarity for generators.

Load Model Selection

PJM’s Patricio Rocha-Garrido presented PJM’s proposed load model for the 2018 reserve requirement study focused on the 2022/23 delivery year. Staff recommend the same model used last year, along with again switching the peak week for regions external to PJM, known as the “world” in the analysis, to a week that doesn’t coincide with PJM’s peak.

Staff used 18 years of load history, 23 years of weather history and at least seven years of hourly loads to develop 78 model candidates. The candidates were compared to PJM’s “coincidental peak 1” distribution analysis, which represents the highest load forecasted for the summer of the forecast year, using two separate approaches. The comparisons found that the 10-year model from 2003 to 2012 used in 2016 and 2017 remains the best choice because it was a close second to a nine-year model in the comparisons but includes an extra year of load data.

The “world” peak week was again switched to not coincide with PJM’s because the peaks haven’t coincided in 11 of the past 19 years.

Dolan questioned why PJM doesn’t use more-recent data to reflect changes in demand-side activity.

“The world is changing, and I think … [the] ability to control our load is much different from what it was in the earlier years of your data set,” he said.

Facility Ratings Fine

PJM’s Mark Kuras discussed staff’s process for confirming transmission owners’ facility ratings, concluding that “TOs have demonstrated that strict processes and controls are already in place to ensure facility ratings used in PJM operation are determined based on technically sound principles” and that “there are no requirements for PJM to approve or verify a TO’s ratings or do any kind of consistency check.”

The discussion came after AMP and the PJM Industrial Customer Coalition criticized how TOs calculate the ratings. (See “Facility Rating Concerns,” PJM PC/TEAC Briefs: April 5, 2018.)

TOs are required by NERC Standard FAC-008-3 to develop and adhere to a methodology for developing facility ratings, but they aren’t required to publish it. Kuras noted that PJM publishes the final facility ratings on a public page.

“I think this presentation shows that, in and of itself, there are no issues with FAC-08” and how it’s implemented, PJM’s Aaron Berner said. “If that continues to be a concern, we can have those further discussions” about specific projects with proposing entities, he said.

Dolan said part of the concern is that in the process for determining whether they can develop a successful project bid, prospective developers must seek information that could make the incumbent TO aware of the potential proposal in a competitive window, which creates competition issues.

TO Planning Criteria Updates

Both Public Service Electric and Gas and American Electric Power provided updates to their planning criteria filed earlier this year with FERC.

AEP announced it will no longer use Rate A for category P1 contingencies for lines above 345 kV and instead evaluate those facilities using Rate B for P1 through P7 contingencies.

PSE&G’s Glenn Catenacci presented his company’s updates, which modify pre-fault voltages, certain contingencies and other definitions. Dolan noted that several of the changes create requirements for building additional system infrastructure.

Among the changes was including non-firm transfers in models when considering common-mode outages. The presentation to stakeholders of the change comes after FERC rejected a complaint from the New Jersey Board of Public Utilities seeking to revise how infrastructure costs are allocated, and that would have included several merchant lines into New York City that have changed their transmission rights to non-firm transfers. (See PSE&G on the Hook for Bergen-Linden Costs.)

Dolan questioned including non-firm transfers in the calculations because they wouldn’t be included in allocating any costs for any system upgrades that subsequently become necessary.

“We think the people driving the need for transmission should be paying for it; however, there is a reliability issue,” PSE&G’s Esam Khadr said. “We need to address that reliability issue.”

Khadr said he can’t terminate non-firm transmission service, which hadn’t been planned for previously because “it was not as prevalent as it is today.”

“We have an obligation to all of our neighbors … to maintain reliability to the bulk power system,” said PJM’s Ken Seiler, who chairs the PC.

Staff haven’t engaged with NYISO on non-firm transfers in planning criteria, but he said, “We’ll evaluate it and certainly make any recommendations back to the Planning Committee.”

Dolan and Khadr also sparred on whether to use breakers as an option for maintaining system reliability. The discussion came as part of PSE&G’s clarification of how it will handle N-1-1 situations and its decision to not permit opening breakers.

“We’re not going to plan a system by further degrading the system by opening breakers,” Khadr said. “You’re taking away that redundancy by taking away that breaker.”

“Or utilizing its flexibility,” Dolan pressed.

“We disagree,” Khadr responded.

Nuke Closures Spark Transmission Upgrades

PJM’s Phil Yum presented attendees at the Transmission Expansion Advisory Committee meeting 23 baseline projects sparked by FirstEnergy Solutions’ announcement in April that it plans to shutter its three nuclear facilities within three years. (See FES Seeks Bankruptcy, DOE Emergency Order.)

The projects would cost upward of $190 million combined, and because they are all within the three-year window for “immediate need” projects, they would all be assigned to the incumbent TO. PJM’s Jason Connell confirmed that was the reason they can’t be opened to a competitive bidding window. The projects are in the transmission zones of AEP, Duquesne, and FirstEnergy subsidiaries Allegheny Power Systems and Penelec.

Several of the projects are associated with the closure of the Davis-Besse nuclear plant, which is scheduled to deactivate on June 1, 2020. The projects can’t be implemented until a year later, but PJM’s planning group has discussed the issue with RTO operations and found operating measures that can mitigate the reliability impacts in the interim.

AMP’s Ed Tatum questioned why PJM didn’t include more details in the project descriptions. Connell said, “Certainly the scope of the timing is a little different” because of the deactivations. “We were on a very, very accelerated timeline” to determine “as best was we could do in the time frame that we had,” he said.

Dolan questioned what might happen to the projects if FES ultimately decided not to deactivate the plants. Seiler dismissed the implication, saying, “Folks don’t play games with this type of thing” because it includes jobs, communities and other large-scale factors. However, he acknowledged, “I’m not saying it couldn’t happen in the future” based on a federal mandate or policy changes.

“We’ve never had any situation like this before. I agree it’s not gamesmanship or anything like that, but things could change very quickly,” Tatum said.

Seiler said money is already being spent on the engineering portions of the projects but said that if the decisions are reversed, “I think that would happen sooner rather than later.”

— Rory D. Sweeney