VALLEY FORGE, Pa. — Stakeholders approved PJM’s 2017 installed reserve margin (IRM) calculations at last week’s Planning Committee meeting.

The updated calculations reduced the IRM from 16.6% to 15.8% for delivery year 2021/22, thanks to an anticipated fleet-wide equivalent forced outage rate (EFORd) reduction from 6.59% to 5.89%. PJM calculated EFORd — which measures the probability a generator will fail completely or in part when needed — for the existing generation fleet and the fleet expected in future study years. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

PJM also reduced the winter weekly reserve target for each month this winter. December dropped from 24% last year to 23% this year. January’s target fell from 30% to 27% and February from 28% to 25%.

Interconnection Study Process to be Rearranged

PJM is planning to revise its evaluation process for new and upgrade transmission service requests to provide early analysis of recommended upgrades and cost estimates. The initial study, which does not address the upgrades or cost estimates, would be replaced with a feasibility study, PJM’s Ed Franks said. The subsequent system impact and facilities studies would remain the same. (See “Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues,” PJM Planning and Tx Expansion Advisory Committees Briefs.)

“The analysis as it’s currently done is just constantly refined as projects drop out of the queue. That’s just the nature of the process,” Franks said. “We feel that at least giving them something up front high-level is more appropriate than having them wait until the impact study to get something.”

Franks said PJM could evaluate and consider combining the feasibility and impact studies if customers preferred that approach. The changes don’t apply to requests that enter the queue through available transfer capability calculations.

PJM is planning to request FERC approve an April 1, 2018, implementation, which will require the Markets and Reliability Committee endorse the Tariff changes in December and the changes to Manual 14A in February. Necessary changes for Manual 2 will be developed through the manual’s usual endorsement process.

Stakeholders Question Transmission Design Standards

PJM is hoping to continue developing its transmission design standards with new underground line construction guidelines, but transmission customers question their usefulness. (See “Competitive Planning Components Endorsed; Pieces Remain,” PJM Planning & Tx Expansion Advisory Committees Briefs.)

Transmission developers acknowledge the standards when they sign PJM’s designated entity agreement (DEA) to receive approval to construct a project, but the RTO does not enforce them. DEAs are required for companies assigned projects through PJM’s competitive-bidding process. Customers were concerned that the standards don’t bind the developers to any specific actions.

“It raises the question for me … is whether all underground construction should be held to the same … standard,” said Ed Tatum of American Municipal Power.

“PJM is not going to go through a checklist with the proposing entities ensuring that they considered all of … the minimum standards. It’s more for an awareness,” the RTO’s Michael Herman explained. Some of the highly detailed standards are “really beyond the scope of tracking,” he said.

“These are minimum standards,” PJM’s Sue Glatz added. “These are not the only standards that apply to transmission projects.” Transmission owners have their own, she said.

Resilience in Planning

As PJM works on factoring resilience into planning, stakeholders are hoping the new criteria will address specific issues. PJM’s Mark Sims provided an update on the RTO’s progress, which elicited questions from state advocates.

Ruth Ann Price with the Delaware Division of the Public Advocate asked about a comment PJM CEO Andy Ott made at the Grid 20/20 conference in September. Ott had said that one of PJM’s resilience goals would be to make “critical facilities less critical.” (See PJM Defends Resilience Focus as Pre-emptive, not Excessive.)

Price asked how that concept would be applied in PJM’s planning, but the RTO’s Steve Herling cautioned against jumping to conclusions.

“That’s just an example that Andy was using as to how we might visualize the problem and how we might go about solving them,” he said.

Greg Poulos, executive director the Consumer Advocates of the PJM States, was disappointed PJM isn’t specifically focused on that goal.

“I was really surprised to hear that’s not a main emphasis. I didn’t realize it was just an example and not a major project,” he said.

PJM staff asked for patience in developing a plan.

“Traditional power flows are well understood. They haven’t changed much over time, those metrics. But for resilience, we’re creating brand new metrics,” Sims explained. “I think the approach is to set a longer timeline … but we’re still very much working on the technical side of things.”

Interconnection Webpage Gets a Facelift

PJM has redesigned its webpage for the interconnection queue to incorporate more information. PJM’s Tawnya Luna unveiled the new look, explaining that it includes new county-level and megawatt filters. Users will be able to save a list of projects and receive weekly or monthly updates on them via email.

The site will change over in late October. PJM is seeking feedback for future revisions, Luna said.

How Immediate is Immediate?

Transmission customers and merchant transmission developers joined together at last week’s meeting of the Transmission Expansion Advisory Committee to raise concerns about PJM’s categorization of “immediate need” projects.

The debate began when Sims described modifications that will raise the costs of a project in Dominion Energy’s territory. The b2361 project northeast of Fairfax City, Va., originally ran about 4.5 miles from the Idylwood substation to a new Scott’s Run substation and was expected to cost about $32 million. But that plan ran into siting issues at Scott’s Run. The project’s scope has been expanded to instead rebuild the Tysons substation and run the line there for a total cost of at least $111.7 million. The project’s in-service date has also been moved back five years to 2022.

Mark Ringhausen with Old Dominion Electric Cooperative said the changes should warrant including the project in PJM’s competitive bidding processes for transmission projects that were developed through FERC Order 1000, but Dominion’s Ronnie Bailey disagreed.

“I don’t think an Order 1000 process would get us to a better answer,” he said.

Sims said the project has already been approved for construction by PJM’s Board of Managers.

“We’re changing to scope for it,” he said.

“This seems a little different than a routine scope change because it’s a five-year scope change,” said LS Power’s Sharon Segner. “Delaying the in-service date by five years would clearly put this project not in ‘immediate need.’ … We would encourage this immediate-need designation process to not be a rubber stamp process.”

PJM’s Tariff requires that “immediate need” projects must be in service within three years. But Sims clarified that the designation refers to when the project is needed, not when it will be in service.

John Farber with the Delaware Public Service Commission brought up the issue again later in the meeting during a discussion of projects in Public Service Electric and Gas’ territory.

“Really, it’s a ‘wanted by’ date, and the ‘required date’ is when it actually goes into service?” he asked.

Sims said the “required in-service date” is when the project is needed, but that date can’t always be met. He added that it’s “a little circular” to suggest competitive bidding for such projects would be faster at defining an in-service date because that wouldn’t be known until the end of the bidding process.

— Rory D. Sweeney