VALLEY FORGE, Pa. — PJM staff told the Operating Committee last week that questions still remain about why their load forecast veered so far off course during a two-day spell of hot weather across the region last month.

Speaking at the committee’s Nov. 12 meeting, Rebecca Carroll, PJM’s director of dispatch, said staff’s backcasting analysis found that an early-arriving cold front in the ComEd and FirstEnergy zones on Oct. 2 impacted temperatures during the two-hour demand response event, accounting for a portion of the 4,500 MW of anticipated load that never materialized on the system. (See PJM, Stakeholders Baffled by DR Event.)

That same analysis, however, revealed that temperatures in the Mid-Atlantic and AEP zones were higher than initially forecast — meaning the missing load and unusual price signals have a different, unknown cause.

“According to all of our data, the load in AEP should have come in higher and quicker and more significant than what it did, even though we called the pre-load management in this area,” she said. “There’s several hundred megawatts we can’t account for.”

The trouble began Oct. 1, when PJM’s peak load exceeded its forecast by 5,500 MW, knocking the RTO into a spinning reserves event and triggering shortage pricing for three five-minute intervals. Carroll said PJM also called upon 800 MW of shared reserves from the Northeast Power Coordinating Council to compensate.

The following morning, operators lost a 765-kV line in the AEP zone, and 2,000 MW of generation called upon the day before failed to start. Those losses, in combination with a peak load forecast of 131,000 MW and anticipated congestion over the Hyatt transformer and the Peach Bottom-Conastone 500-kV line, prompted staff to call up 725 MW of long-lead DR resources for a pre-emergency load management event. The decision triggered a performance assessment interval (PAI) that lasted from 2 p.m. until approximately 4 p.m. in the AEP, Dominion, Pepco and BGE zones.

What should have happened next, according to several stakeholders, was a rise in LMPs for those zones, set by DR operating during the PAI. Instead, prices in the AEP zone tanked, and 4,500 MW of load never came onto the system.

PJM had hoped backcasting could solve the mystery of the missing megawatts, but Carroll said last week that more answers will likely come when the official DR data become available next month.

“I don’t buy this missing load argument,” said Dave Mabry, of McNees Wallace & Nurick. “I’m not sure we’ve got a missing load issue as much as we have a forecast issue. It seems like there is something else going on with the backcasting.”

Mabry suggested that a large industrial-use customer participating in DR could account for the “missing nodal load” — a possibility that Joseph Mulhern, a senior engineer at PJM, said staff were still considering.

“That’s one of the things that we are trying to look into now … mapping the nodes where we see this behavior to demand response customers,” he said. “It’s the first time we’ve looked into anything like this, so we aren’t sure what we will get or what the outcome will look like.”

He said staff attribute “a significant amount of missing load to DR,” but not all of it. He also said a lack of visibility at the distribution level and the rarity of 90-degree weather in October may also have played a role.

“When there is an unusual day that’s not got a lot of history, that can lead to errors,” he said.

Black Start Packages Anticipated in ‘Early 2020’

PJM’s Janell Fabiano said that stakeholders will present new rules for black start resource fuel requirements in “early 2020.”

Stakeholders began meeting in July 2018 to reconsider whether the existing fuel requirement of 16 hours proved sufficient given PJM’s focus on resilience in recent years. The group is also considering ways to mitigate high-impact, low-frequency events across all black start resources and fuel types.

The D.C. Office of the People’s Counsel, Calpine, PJM and Monitoring Analytics continue to work on four similar plans to define fuel assurance and tweak the hourly reserve requirement. Fabiano said stakeholders will bring the finalized packages to both the OC and the Market Implementation Committee for votes early next year. Changes will not move forward without support from both committees, she said.

Winter Weekly Reserve Target Endorsed

The OC endorsed weekly winter reserve targets for 2019 that remain unchanged from last year. The targets for December, January and February are 22%, 28% and 24%, respectively.

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling during the winter and cover against uncertainties associated with load and forced outages.

PJM also sets a 0% goal for its loss-of-load expectation (LOLE) in the winter, preferring instead to expect higher LOLEs throughout the summer.

Preliminary Day-ahead Scheduling Reserve Requirement Approved

The committee also endorsed PJM’s new day-ahead scheduling reserve requirement (DASR) of 5.07%.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations.

PJM will seek endorsement for the change at the Markets and Reliability Committee and implement the new requirement in Manual 13 revisions.

Stakeholders Sunset NERC Ratings Initiative Task Force

Stakeholders approved PJM’s request to sunset the 2011 NERC Ratings Initiative Task Force.

The group held more than 30 webinars over three years to address a NERC alert that asked RTOs to “verify that field conditions are consistent with established ratings.”

The task force created an automated process to notify members of pending NERC outages. Since adopting the new procedures, PJM has received 1,386 outage and derate tickets, completing about 65% of submitted requests. About 9% impacted the system, according to PJM’s data.

OC Meetings Moving to Thursday in 2020

PJM’s standing committee week will look a little different in 2020.

The OC will convene on Thursdays, while PJM’s Planning Committee and Transmission Expansion Advisory Committee will move to Tuesdays. The MIC will remain on Wednesdays.

PJM Manuals Endorsed

Manual 03A: Energy Management system (EMS) Model Updates and Quality Assurance (QA) — Cover-to-cover periodic review. Adds a new section on PJM’s modeling philosophy.

Manual 3: Transmission Operations — Cover-to-cover periodic review. Updates dozens of terms and values in sections 1, 3, 4 and 5 and Attachments A and B.

Manual 14D: Generator Operational Requirements — Minor changes identified through the Distributed Energy Resources Ride Through Task Force that apply to distribution-connected generators connected to radial distribution lines of voltage less than 50 kV. The revisions also direct DERs to appropriate transmission owner engineering and construction standards, a standalone document on PJM’s website. The term “generating facilities” was also added in section 7.1.1: Generator Real-Power Control.

– Christen Smith