By Christen Smith

Utilities Question Primary Frequency Response Calculation

VALLEY FORGE, Pa. — PJM’s Operating Committee last week endorsed revisions to Manual 12: Balancing Operations over the opposition of FirstEnergy, which challenged the manual’s formula for judging primary frequency response performance.

Under the formula included in a newly added Section 3.6 of the manual, PJM will evaluate generators’ performance during events in which the system frequency goes outside a +/-40-MHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz.

PJM’s Danielle Croop, senior engineer of operation analysis and compliance, said the formula was vetted by the Primary Frequency Response Task Force based on NERC criteria.

“We opened up our criteria to be more lenient … and we are catching as much performance as we can,” she said. “We are open to changing the formula.”

Jim Benchek, FERC and RTO market technical support at FirstEnergy, said the formula is too sensitive and could result in false failures. “We prefer not to have the formula memorialized in the manual at this time.”

He added that his company remains committed to providing PFR.

The manual changes were endorsed despite 24 objections by FirstEnergy and Duke Energy and 20 abstentions.

At the January OC meeting, American Electric Power noted that FERC’s order did not require scoring of PFR and said PJM had little stakeholder support for it. (See “The Right Metric on Frequency Response?” PJM Operating Committee Briefs: Jan. 8, 2019.)

PJM Continues Review of Non-retail BTM Generation Business Rules

PJM provided stakeholders additional background on a proposed problem statement and issue charge that could result in revised rules for non-retail behind-the-meter generation (NRBTMG).

Terri Esterly, PJM’s senior lead engineer for capacity market operations, said business rules in the RTO’s governing documents need modifications to address the growth of distributed generation. NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load; they do not participate in PJM markets but can be netted against load to reduce certain charges.

Esterly said it’s been nearly 15 years since a settlement agreement established rules for NRBTMG — long before the RTO implemented the Reliability Pricing Model and Capacity Performance and took on several utility companies as members, including American Transmission Systems Inc., East Kentucky Power Cooperative and Duke Energy’s Ohio and Kentucky divisions.

Under existing rules, NRBTMG must operate at full output during the first 10 instances of maximum emergency generation conditions between Nov. 1 and Oct. 31. However, it’s not clear in Manual 13: Emergency Operations what procedures trigger this requirement.

Likewise, the RTO doesn’t know how close the grid is to exceeding the 3,000-MW NRBTMG cap set in 2005. PJM estimates put this value closer to 4,600 MW, but incomplete public records make it difficult to determine an exact figure.

PJM first proposed reviewing NRBTMG rules during a Jan. 8 Operating Committee meeting and faced suspicion from several municipal utilities and cooperatives. (See Munis Wary of PJM Rules on Non-Retail BTM Generation.) Stakeholders at last week’s meeting requested more firm data surrounding megawatt estimates before moving forward in the process.

Committee Endorses Updates to TO/TOP Matrix

Stakeholders unanimously endorsed changes to the Transmission Owners/Transmission Operator Matrix to document their responsibilities under new NERC reliability standards.

The matrix is an index between the PJM manuals and NERC reliability standards that spells out which responsibilities are PJM’s as the TOP and which are assigned to member TOs.

Version 13 of the matrix adds references for reliability standards:

• TOP-001-4 R20 and R21, which took effect in July 2018;
• VAR-001-5, which took effect Jan. 1;
• EOP-004-4, EOP-005-3 and EOP-008-2, which take effect April 1; and
• PER-003-2, which takes effect July 1.

The endorsed changes head to the Transmission Owners Agreement Administrative Committee for approval.

Incremental RFP Window for New Black Start Resources Closes May 1

PJM opened a window for new black start resources in the Baltimore Gas and Electric and Potomac Electric Power Co. (PEPCO) zones on Feb. 1.

PJM initiated the new request for proposals — separate from the five-year process completed in November 2018 — after receiving notice late last year of generator deactivations in BG&E’s territory not included in the original scope of projects. The RFP seeks service beginning by April 1, 2021.

“We have included the PEPCO zone and also some surrounding adjacent TO zones in this RFP in the event there are cross-zonal black start options that may be considered,” said David Schweizer, PJM’s manager of power system coordination. “We did not specify megawatts in the RFP because we want to be able to consider any size black start unit that’s proposed.”

Expressions of interest are due by Feb. 25, with detailed proposals due May 1.

Lisle RAS Scheduled for Retirement

A reinforcement project will trigger the retirement of two remedial action schemes designed to prevent thermal overloads at the Commonwealth Edison’s Lisle substation.

The project will add breakers to the four existing 345-kV lines and reconfigure the 345-kV bus into a ring-bus. ComEd said the schemes will be removed as they become unnecessary. The work is scheduled to begin in March and be complete by June 1, 2020.