VALLEY FORGE, Pa. — PJM’s Planning Committee deferred voting on a problem statement and issue charge on critical infrastructure mitigation projects in light of a webinar planned by transmission owners to further discuss stakeholders’ transparency concerns.
Stakeholders agreed Thursday to delay voting on the proposal for one month after Exelon’s Pulin Shah suggested some of the issues raised in the proposal would be discussed in the meeting. The D.C. Office of the People’s Counsel, which proposed the initiative, said a delay was unnecessary but acquiesced nonetheless.
The issue came to a head at the Markets and Reliability Committee meeting in August when incumbent TOs asked for feedback on a proposed Tariff attachment that would establish a process for vetting transmission system enhancements designed solely to reduce the number of critical assets identified under NERC’s critical infrastructure protection standard CIP-014, of which fewer than 20 exist within the PJM footprint. NERC deems these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”
The Consumer Advocates of the PJM States and other stakeholders expressed concern about the opaqueness surrounding the TOs’ proposal. (See PJM TO Tariff Filing Stirs up Transparency Concerns.) The D.C. OPC then came to the September PC meeting with a problem statement and issue charge to create language for PJM’s manuals, Tariff and Operating Agreement that addresses future management of critical transmission assets on NERC’s CIP-014 list. (See “Consumer Advocates: CIP-014 Projects Need More Transparency,” PC/TEAC Briefs: Sept. 12, 2019.)
“One of the big concerns that we really heard from all quarters was that whatever process is looked at here, that we should cover not just the facilities covered by the Aug. 12 notice, but those that might become security-impacted facilities in the future,” said Erik Heinle of the D.C. OPC. “So, we want to make sure we have a process that works for a broad set of facilities in that respect.”
Shah said TOs hope to schedule the webinar early next month, ahead of the Nov. 14 PC meeting.
2019 Installed Reserve Margin Study Results
PJM’s Patricio Rocha Garrido said the final values of the 2019 Installed Reserve Margin study differ from those presented to the PC last month.
The annual study determines PJM’s installed reserve margin (IRM) and forecast pool requirement (FPR), which will reset key parameters for the RTO’s upcoming capacity auctions.
The recommended IRM is now 14.8% and the recommended FPR is 1.0860 with an average equivalent forced outage rate on demand (EFORd) of 5.4%. Rocha Garrido said the new values account for deactivation withdrawals submitted in July.
He said the 2019 load model and capacity benefit of ties put “downward pressure” on both the IRM and the FPR. The retirement of 8,600 MW of generation and the addition of 15,000 MW of more efficient resources — mostly combined cycle plants — explained the 0.5% reduction in EFORd.
The PC endorsed the results by acclimation. The MRC will hear a first read of the results at its Oct. 31 meeting.
ELCC Methodology Revisited
PJM said it’s time to revisit its proposed methodology for calculating wind and solar capacity values after discussions last spring went nowhere.
The RTO wants to use an effective load-carrying capability (ELCC) calculation, which measures the additional load that a group of generators can supply without a reduction in reliability.
“The ELCC method is meant to be a consistent way of valuing all the resources in the system,” Rocha Garrido said.
The five-step ELCC process for delivery year 2022/23 would begin with an average of the ELCCs for each year since 2012/13. The RTO has determined that the composite ELCC is 4,181 MW, 21% of the 19,910 MW of nameplate wind and solar capacity projected for 2022/23.
After calculating the ELCCs for the two generation types separately, PJM would then prorate the shares between wind and solar, resulting in capacity factors of 12.3% and 45.1%, respectively. (See “PJM Pushes Change in Wind, Solar Capacity Measurements,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
PJM’s ELCC formula represents a shift in thinking for the RTO, which had been pushing an alternative method using average values. The new methodology is more representative of the incremental value of adding a new unit to the existing fleet, PJM’s Tom Falin said in February.
Many stakeholders, however, felt the proposed method did not account for the improved performance of wind and solar seen in the last decade. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)
Rocha Garrido said Wednesday that staff will come back to the November PC with a plan to move forward. He agreed with stakeholders who saw the outdated methodology as a “prospective problem” rather than a current one and clarified that if the ELCC was adopted, it wouldn’t take effect for four years.
“We support the improved accuracy in calculating the actual capacity provided by all forms of capacity,” Independent Market Monitor Joe Bowring said. “Improved accuracy should be implemented as soon as possible. Waiting four years is not appropriate.”
TEAC: Artificial Island Cost Allocation Update
It’s been eight months since FERC told PJM to use the stability deviation method to allocate costs for the Artificial Island project, but the RTO has yet to get board approval or file the plan with the commission, staff said Thursday.
The stability deviation method determines that a measurement of the change in the voltage angle is higher for substations that are more impacted by a disturbance or stability event, also referred to as the angular deviation. This change would identify the loads that would be most impacted by a stability disturbance and would benefit from transmission projects that address stability-related issues.
PJM has long agreed it needed a different way of divvying costs for stability-related issues, noting those who cause these problems aren’t always the same ones who will benefit from it being repaired — such as in the cases of thermal violations, voltage/reactive issues, storm hardening, end-of-life/aging infrastructure or real-time operation concerns.
Under the existing solution-based distribution factor (DFAX) method, the Artificial Island project, for example, would have assigned 93% of the project cost to Delmarva Power & Light. Under the stability deviation method, the costs would fall 19% to Public Service Electric and Gas, 15% to PECO Energy, 12.5% to PPL, 12.4% to Jersey Central Power & Light, 10.4% to Delmarva Power, 7.2% to Atlantic City Electric and about 5% to Metropolitan Edison.
FERC agreed in February the latter method best suits the Artificial Island project. (See FERC: Stability Deviation Method Best for Artificial Island.) TOs requested rehearing, however, based on two Tariff changes the commission ordered in approving the new methodology: requiring PJM to perform stability simulations without the stability upgrade when technically meaningful angle deviations can’t be observed, and giving the RTO discretion to modify the 25% threshold for excluding deviations.
PJM said TOs plan to submit Tariff amendments to the commission that would remove the second revision entirely and require the RTO to “perform simulations with the stability upgrade and extend the fault duration to the critical clearing time in order to achieve technically meaningful angle deviations.”
Staff said they will bring the revised cost allocation to the board in December. After receiving approval, PJM will file the revisions with FERC and give designated customers 30 days to review. In January, PJM will assign cost responsibility for the project using the revised methodology.
ComEd, Dominion, AEP Supplementals
Commonwealth Edison’s Quad Cities-Cordova 345-kV line has obsolete relays and is becoming difficult to service, Exelon said Thursday. The line is an intertie between PJM and MISO and needs upgrades to address equipment condition, performance and risk.
In a second project, ComEd said it wants to rebuild 16 miles of the 345-kV Kendall-Lockport double-circuit towers beginning in 2022 to increase the line rating and eliminate 10.5 miles of wood poles that are 60 years old.
American Electric Power has identified a $3.16 million solution for a failed breaker at its Sullivan 765/345-kV substation in western Indiana: replace the failed unit.
The company also proposes upgrading the Dumont 765-kV substation in northern Indiana with a new 2,250-MVA transformer and two new 345-kV breakers. The substation suffered a catastrophic failure in 2018. The upgrade will cost $27.8 million.
Dominion also said it will cost $250,000 to install a 1,200-ampere, 50-kAIC circuit switcher to feed a new transformer at the Enterprise Substation in Loudoun County, Va. A similar project at the nearby Poland Road substation will cost $2 million. Finally, the company proposes spending $2 million to cut an existing 230-kV line between its Cannon Brand and Winters Branch substations to support the proposed Brickyard substation in Prince William County, Va. At Brickyard, Dominion will install four 230-kV breakers and terminate the two lines. Two 230-kV circuit switchers and any necessary high-side switches and bus work for the two initial transformers is also included in the solution.
– Christen Smith