VALLEY FORGE, Pa. — PJM’s Planning Committee will consider whether the RTO must develop governing document language to deal with the mitigation of existing and future critical infrastructure on NERC’s CIP-014 list.

Some 54% of stakeholders endorsed the issue charge from the D.C. Office of the People’s Counsel after two deferrals and a late-stage challenge from Exelon that many on the committee considered out of order. (See “Critical Infrastructure Vote Delayed Again,” PJM PC/TEAC Briefs: Nov. 14, 2019.)

At the heart of the debate was Exelon’s preference to exclude mitigation of existing projects from the scope of the issue charge, as described in their alternative motion. Transmission owners, including Exelon, are currently working on a Tariff attachment that would handle those specific facilities. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)

The issue came to a head at the Markets and Reliability Committee meeting in August when incumbent TOs asked for feedback on their proposal 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.”

Other sectors expressed concerns about the opaqueness surrounding the proposal, encouraging the D.C. OPC to bring its problem statement forward the following month. After successfully lobbying for a deferral on the vote for two months in a row, the TOs in November held a webinar to address concerns about their proposal to no avail.

At the PC meeting Thursday, Exelon presented for a vote its slightly modified issue charge that excluded existing CIP-014 projects. Some stakeholders pressed PJM on the appropriateness of voting on an alternative issue charge that’s not been moved properly through the stakeholder process or even attached to its own problem statement. After more than an hour of debate — and a failed motion to overturn the decision of the committee chair — stakeholders chose the D.C. OPC’s issue charge over Exelon’s alternative.

The PC will take on the scope of the issue charge and formulate recommendations within six months.

DER Ride Through Task Force Sunset

Stakeholders agreed to sunset the Distributed Energy Resources Ride Through Task Force now that its work considering a default standard is done.

PJM said distributed energy resources currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride through” the event, providing much-needed reliability benefits, while others trip off to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.

The task force had been considering ways to fix this problem — even going so far as to bring in federal experts to help develop new standards — but decided against an RTO-wide rule because of the uniqueness of local distribution systems. (See DER Ride Through Task Force Considers New Direction.) Instead, the task force suggested that PJM create a recommendation when a local distribution system lacks an official policy. The committee also endorsed revisions to Manual 14G: Generator Operational Requirements that include this guidance from the task force.

PJM Defends Transource Tx Project Analysis

PJM said Thursday a recent analysis of multiple projects designed to relieve congestion in central Pennsylvania and northern Maryland — including Transource Energy’s reconfigured Independence Energy Connection project — still exceed the RTO’s 1.25 cost-benefit ratio threshold. (See Transource Files Reconfigured Tx Project.)

LS Power disputed the RTO’s analysis of the newly proposed path for the eastern segment of the project, telling the Transmission Expansion Advisory Committee in November that it only carries a benefit-cost ratio of 1. (See PJM Analysis of Transource Alternative Challenged.) The TO said PJM’s base case used to calculate its 1.6 ratio doesn’t consider the impact of a nearby project that would alleviate congestion on the Hunterstown-Lincoln 115-kV line.

PJM’s additional calculations performed after the November TEAC meeting concluded that the aggregate benefit-cost ratio for the alternative Transource project, the Hunterstown-Lincoln 115-kV line and a third project that upgrades the Gracetone-Bagley 230-kV line falls between 2.25 and 2.33. If state regulators in Maryland and Pennsylvania opt for the original configuration for the Transource project, that ratio jumps to 2.87.

LS Power objected to the aggregate ratio presented to the committee Thursday, arguing that market efficiency projects should be re-evaluated on a standalone basis.

RTEP Upgrades

PJM will recommend that the Board of Managers approve system enhancements totaling $134 million for inclusion in the Regional Transmission Expansion Plan in 2020. Two projects, from American Electric Power and Old Dominion Electric Cooperative, are Form 715 criteria-driven enhancements; two others, in MetEd and NIPSCO, are PJM-selected market efficiency projects; and the last project, from Penelec, is being considered for its baseline load growth deliverability and reliability-driven enhancements.

The projects include:

• In AEP’s zone, rebuild 3.11 miles of the 69-kV LaPorte Junction-New Buffalo line with 795 aluminum conductor steel reinforced wire: $12.3 million.
• In ODEC’s zone, create a line terminal at Belle Haven Delivery Point (three-breaker ring bus) and install a new single-circuit 69-kV line rated at 55N/55E from Kellam substation to new Bayview substation (21 miles): $22 million.
• In Penelec’s zone, rebuild 20 miles of the 115-kV East Towanda-North Meshoppen line and adjust relay settings at the 115-kV East Towanda and North Meshoppen substations: $58.6 million.
• In NIPSCO’s zone, rebuild the 138-kV Michigan City-Trail Creek-Bosserman line: $24.69 million ($22 million is PJM’s portion).
• In MetEd’s zone, rebuild the 115-kV Hunterstown-Lincoln line and upgrade substation equipment: $7.21 million.

Projects costing less than $5 million — which often include transformer replacements, line reconductoring, breaker replacements and upgrades to terminal equipment, including relay and wave trap replacements — are not broken out individually in PJM’s white paper.

Dominion, FirstEnergy Supplementals

FirstEnergy would like to replace the 230-kV static VAR compensator at its Atlantic substation in central New Jersey with a 300-MVAR, 230-kV STATCOM for $55.7 million. The enhancement will address the increasing trend of outages and failures on the line.

Dominion Energy revised an earlier solution it identified for a customer-requested data center in Loudoun County, Va. The TO said with projected load likely to exceed 100 MW, two transmission sources will be required to comply with its facility interconnection requirements and avoid a violation of mandatory NERC reliability criteria.

Its latest solution would cut and extend the Brambleton-Yardley Ridge line into and out of a new Evergreen Mills switching station, which will be constructed with four 230-kV breakers in a ring bus arrangement. The customer has also requested two additional 230-kV breakers to be installed for additional redundancy and will be responsible for excess facilities charges, Dominion said. The entire project will cost an estimated $21.2 million.

– Christen Smith