Stakeholders Endorse Quick Fix Solution on Day Ahead Scheduling Reserve Calculation

The Operating Committee endorsed a quick fix proposal to revise Manual 13: Emergency Operations to add transparency to the Day Ahead Scheduling Reserve (DASR), a figure that is calculated annually to determine when the 30-minute reserve requirement may be insufficient and emergency procedures necessary. 

The quick fix process allows for an issue charge to be voted on concurrent with a proposed solution. (See “Quick Fix Proposal on Day Ahead Schedule Reserve Calculation,” PJM OC Briefs: Oct. 10, 2024.) 

The 30-minute reserve requirement is set at the greater of the primary reserve requirement, active gas contingency or a flat 3,000 MW, which PJM has argued is not flexible and does not account for operational risks. An earlier proposal to shift to a requirement based on load forecast error and forced outage rates was rejected by stakeholders in July. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.) 

The DASR is the sum of the three-year average underforecast load forecast error (LFE) and generator forced outage rates (FOR), which currently results in a 74,257-MW peak load threshold after which 30-minute reserves are considered inadequate.  

The manual revisions are intended to clarify how operators use DASR. No change is proposed to the functioning of 30-minute reserves. They are set to go for a first read at the Markets and Reliability Committee (MRC) on Nov. 21, followed by a vote Dec. 18. 

PJM Presents Revisions to Manual 1 Addressing Hybrid Resource Rules, Loss of EMS Real Time Assessment

PJM presented a quick fix proposal to revise Manual 1: Control Center and Data Exchange Requirements to clarify its communication processes and data collection protections. The language is scheduled to be voted on at the Dec. 5 OC meeting and, if endorsed, at the Jan. 23 MRC meeting. 

The changes would add more detail to its backup communication methods to be used in the event of widespread SCADA software outages, as well as alternatives ways of conveying data to PJM during a SCADA outage, such as a cyberattack. The package also includes clarifications around PJM’s view-only mode to protect Inter-Control Center Communications Protocol (ICCP) data from potential errors during planned maintenance. 

The RTO also first read a set of revisions to Manual 1 identified through its periodic review, which would update several definitions to be more precise and consistent with other manuals. The language also includes requiring that the state of charge be conveyed by SCADA for open-loop hybrid resources, a requirement that already stands for close-loop hybrids.  

PJM Seeks Advance Notice of Expected Maintenance Outage as RTEP Upgrades are Scheduled

PJM is requesting that generation and transmission owners increase coordination around planned outages while a significant number of transmission assets are taken offline to build upgrades under the RTO’s 2023 Regional Transmission Expansion Plan Window 3. The work ramps up in 2026 and continues through 2030, with the number of outages exceeding 30 in some months. 

Transmission owners are asked to review planned outages for conflicts with the scheduled upgrades, provide PJM with a preferred timeline for their outages and fill out the RTO’s Prioritization Scoring Matrix. Quarterly meetings are being held with transmission owners and developers within the six zones affected by the RTEP projects to bolster the coordination efforts. 

On the generation side, any units in the BGE, PEPCO, Dominion and surrounding regions with outages expected over the next two to three years are asked to provide advanced notice as early as those outages can be foreseen. PJM’s Joe Rushing noted that generation outages require only a 30-day notice. The extent of the transmission work that will be conducted will limit the number of generators that can be taken offline at a given time.  

Congestion and increased use of emergency procedures, such as post contingency local load relief warnings (PCLLRWs), are likely throughout the duration of the RTEP work. 

October Operating Metrics

Presenting the October operating metrics, PJM’s Marcus Smith said October saw both hourly and peak load forecast error fall below the 25-month averages, with an hourly rate of 1.32% and peak forecasts off by 1.46% across the month. Underforecasts exceeding PJM’s 3% error rate benchmark were seen Oct. 3 and 6, while overforecasting was seen Oct. 22 and 31. 

The month saw one spin event Oct. 22 that lasted 6 minutes and 11 seconds and a generation response rate of 95% and demand response (DR) deployment at 151% of dispatch. One shared reserve event, two high system voltage actions and 16 PCLLRWs were implemented in October as well.  

Security Briefing

PJM Director of Enterprise Information Security Jim Gluck said the FBI is warning that renewable generation increasingly is being targeted by attacks to steal technology, render systems inoperable for ransom and disrupt generation operations. 

The Infrastructure Information Sharing and Analysis Center (ISAC) has published a research paper detailing several threats to infrastructure in the leadup to the November 2024 elections, including “hacktivist” attacks and state-sponsored actors. As a precaution, PJM implemented a conservative operations procedure the night of Nov. 5 through midnight the following day. 

“While PJM has received no indication of credible threats to the power grid at this time, our government partners have encouraged the industry to remain alert to an elevated risk environment. Out of an abundance of caution, … PJM … will establish a more conservative posture,” the alert stated. 

The RTO also is monitoring the possible impact of a breach at Schneider Electric, where about 40 GB of records were compromised and could be released to the public if a ransom is not paid. 

Gluck recommended that members ensure employees use multifactor authentication and default passwords are not used. 

PJM Presents 2024 Winter Study

PJM’s Mark Dettrey presented the 2024/25 Winter Study prepared by the Operations Assessment Task Force (OATF) to evaluate the risk landscape for the season. While some switching, phase angle regulator (PAR) adjustments and re-dispatch may be required to address transmission violations, no reliability issues were identified under the 50/50 or 90/10 load forecast studies. (See PJM OC Briefs: Oct. 10, 2024.) 

The report expects 177.6 GW of cleared capacity and fixed resource requirement (FRR) resources will be available, as well as 2.2 GW of resources that historically have been available under the study conditions. It assumes 5.5 GW will be exported under the scenario analyses, 18 GW of generator outages and 7.1 GW of load management being deployed. 

The RTO is projected to maintain an 8.7-GW reserve margin under the low wind and no solar scenario, which reduces available generation by 3.1 GW. That margin shrinks to 7.1 GW under the largest gas/electric contingency, which would take 4.7 GW of generation offline. 

The report also included a scenario developed on experiences during December 2022 Winter Storm Elliott, increasing forced outages to 46 GW, which would lead to a reserve margin deficiency of 13.8 GW. The scenario is not included in the reliability analysis but was developed as a numbers game to be informative. 

Other Committee Business:

PJM’s Pete Langbein presented the 2023/24 Load Management Event Summary, which showed that emergency and pre-emergency DR performance was “very good, well north of 100%” across the delivery year. While there were no events requiring load management deployment, testing showed a 122% response rate reflecting 1,614 MW in overcompliance. 

Stakeholders endorsed revisions to Manuals 3 and 10 drafted through the documents’ periodic review. The changes to Manual 3: Transmission Operations include language to reflect existing practices on facility ratings, shifting which section details Automatic Remediation Action Scheme (RAS) operating criteria, and updating several notes and links. 

The Manual 10 language clarifies how the quantity of energy offline during an outage should be reported for inverter-based resources in eDART and more explicitly states that forced outages must be completed before work can begin on a planned outage.