VALLEY FORGE, Pa. — PJM has scheduled a two-day workshop on enabling distributed energy resources to “ride through” frequency fluctuations but postponed action on a task force on the issue in the face of stakeholder concerns.

PJM’s Emanuel Bernabeu told the Planning Committee last week that the workshop is the first step in developing a guidance document for how DERs should implement a ride-through standard and presented a problem statement and issue charge to create a DER Ride Through Task Force. The proposal met with immediate concern from representatives of transmission owners, who felt it focused on jurisdictional issues rather than safety and reliability.

“That gives us pause,” FirstEnergy’s Jon Schneider said. “The spirit of this initiative is really to find the right balance … so it can support the bulk transmission system and the distribution system. … What’s resonating is jurisdiction rather than safety.”

“Absolutely what we want to do is what you described,” Bernabeu said.

Duquesne Light’s Tonja Wicks also voiced concerns, including that a focus on interverter-based technologies that was in previous versions of the proposal had been removed. That focus was challenged as not being technology-neutral during the proposal’s first read at last month’s PC meeting, but Wicks said the scope could be overly broad without it.

The reticence threw a wrench in PJM’s plan to receive approval for the task force in advance of the two-day workshop, which has already been scheduled for Oct. 1-2. Bernabeu received no concerns with his explanation of the issue at the monthly Operating Committee meeting earlier last week. There, he highlighted three disturbances within the past 12 years that were triggered by large amounts of renewable generation disconnecting from the grid in response to frequency fluctuations. A 2006 outage in Europe — which Bernabeu called “one of my favorite blackouts” — identified the threat from many small generators collectively tripping in what’s been termed the “50.2-Hz Problem.”

“Basically, they did not have this concept of ride-through,” Bernabeu said, adding that similar issues occurred in two subsequent incidents in Southern California and Australia in 2016. “You would think we would have solved this.”

A challenge in PJM’s territory, he said, is that the vast majority of DERs aren’t under PJM’s authority and instead follow state and local regulations. Staff hope the task force will settle on a standard that can then be provided to state and local regulators as guidance. The issue charge calls for developing a PJM-wide “profile consisting of an abnormal voltage and frequency performance category and specified trip settings, if adjusted from the defaults.” As an alternative, the rule could specify minimum ride-through and trip times and defer to distribution utilities on implementation details, the issue charge said.

The topic isn’t “overly complex,” Bernabeu said, but will require a broad group for input.

“We can’t ignore the fact that it’s the vast majority of DER sources. … What we want to establish is consensus across the footprint on specific standards,” he said. “If we succeed, everyone will embrace it.”

Staff agreed to postpone requesting a vote on the proposal to address TOs’ concerns, but they also asked if there was any issue with holding the workshop as scheduled on an “ad hoc” basis. No one opposed.

Vote Delayed on Capability Testing

Staff had also agreed prior to the meeting to postpone a vote planned on revisions to Manual 21 that would change some of the procedures for generators’ annual capability testing. The proposal has created concern because it could reduce units’ capacity injection rights. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)

PJM’s Patricio Rocha-Garrido also presented an analysis of the effective load carrying capability (ELCC) for wind units. The study calculated ELCC values for each year from 2009 through 2017 using the 12,540 MW of wind units projected to be operating in 2021. It found that the mean ELCC is 11.5% of the nameplate capacity and the median is 10.2%. The numbers backed up PJM’s argument for using median capacity factors for wind rather than mean. The median of capacity factor values PJM calculated for wind output from 2015 to 2017 was 7.9%, while the mean was more than twice as high at 16.7%.

Some stakeholders were critical of the analysis, saying it didn’t account for geographic differences and that using historical numbers for expectations of future performance ignores technology improvements.

“I don’t think we should be using any assumptions on the future, because what do we assume?” Rocha-Garrido said in response. He added that while GEMARS, PJM’s hourly loss-of-load-expectation tool, is capable of more detailed analyses, the study was in relation to the installed reserve margin, which is calculated at the RTO level, so “it’s immaterial to me where [the units] are located.” He acknowledged that units could receive a higher value if they were able to increase their output during the hours tested but said he doesn’t “see a significant difference” between PJM’s methodology and alternatives suggested by stakeholders.

Dave Mabry, representing the PJM Industrial Customer Coalition, said he was still trying to understand the differences between the RTO’s study and a similar study by General Electric that came to different conclusions. He suggested that perhaps ELCC is the metric that should be used for measuring wind capacity.

Rob Gramlich, representing the American Wind Energy Association, criticized what he felt was a low amount of data provided and said he appreciated PJM tabling the vote for further discussion.

“We still have a lot of concerns,” he said.

IRM, FPR Reduced

PJM is recommending a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both of which are slight reductions from last year. The IRM recommendation fell 0.1% and the FPR — which reflects the reserve margin to account for peak loads and generator outages — dropped 0.0011, both based on the 2018 capacity model.

Update on Integrating Cost-containment Guarantees

PJM’s Mark Sims outlined staff’s work on integrating cost-containment guarantees in its analysis of developers’ proposed transmission projects. The five-step process will standardize the cost-containment measures offered in each proposal, present them in a visual way, compare them and allow staff to choose the “most economically efficient” proposal. Sims said it will all be implemented into a comparative matrix and that stakeholders should expect to see more details about each of the five “boxes” in the coming months.

“You would expect to see this as part of the overall decision-making process,” he said. “This is our high-level concept. We are into the weeds with the [Independent Market Monitor] on several of these boxes.”

He said “the most challenging pieces right now are” figuring out how to standardize the proposals and then crunching the numbers to evaluate them. Staff sought input from a “large corporate lender” and are not anticipating lender risk being “a huge factor” in evaluation, he said.

LS Power’s Sharon Segner, who led the effort to incorporate cost guarantees into PJM’s evaluations, voiced her approval of the progress. (See “Delay Approved for Cost Containment Comparisons,” PJM MRC/MC Briefs: Aug. 23, 2018.)

“This is all sounds very good,” she said. “It is a hard assignment, and we very much appreciate what you’re doing. But this is an important discipline to establish.”

First M-3 Experience

Dominion Energy’s Ronnie Bailey briefed stakeholders on 13 violations of its system planning criteria his company plans to correct— implementing for the first time the TOs’ new process for supplemental projects, which is detailed in Tariff Attachment M-3. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning.)

In accordance with the M-3 processes, Dominion will follow up at a subsequent meeting with how it plans to address the issues.

FERC Orders on Tx in Calif.

PJM and American Municipal Power have agreed to revise their proposals for developing transmission-replacement processes to reflect FERC’s Aug. 31 rulings that Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity.

The orders (EL17-45 and ER18-370, AD18-12), which rejected complaints by California regulators and others, were discussed at a special session of PJM’s Markets and Reliability Committee that met briefly after the Transmission Expansion Advisory Committee meeting. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)

PJM’s Chris O’Hara said the focus during the RTO’s stakeholder process hasn’t included maintenance.

The RTO and AMP will revise their proposals so they can be presented at an Oct. 16 meeting on the issue and prepared for consideration at the Oct. 25 MRC meeting.

“I think the goal from PJM’s perspective is we have an ongoing process and in that process, we want to provide the appropriate level of process and transparency while avoiding any unproductive litigation that may come from it,” O’Hara said.

AMP’s Lisa McAlister said including maintenance has “never been AMP’s goal.”

— Rory D. Sweeney