PJM TO/TOP Task Matrix Endorsed

The Operating and Planning committees last week endorsed an updated Transmission Owner/Transmission Operator matrix of shared and assigned tasks. The matrix, an index between NERC reliability standards and PJM manuals, is used as an audit tool.

Reason for changes: Update to reflect reliability standards enacted since the last revision in April.

Impact: Adds standards becoming effective in January 2014 and revisions to existing standards. Key changes:

• EOP-001-0.1b — TOs shall develop and maintain a set of plans to mitigate operating emergencies for insufficient generating capacity.
• EOP-005-2 R2 — Restoration Plans should be submitted by eDART instead of PERCS website.
• EOP-008-1 R5.1 — Fixed errors regarding submittal of backup functionality plans through PERCS website.
• PRC-001-1 R2.2, R3.2, R4 — Align with PRC-001 Compliance Bulletin. Requires TOs to report all protection system failures and protection system outages on EHV facilities (345 kV and above) through eDart. Also requires TOs to report to PJM Operations any protection system failures and outages on any other Reportable Facilities requiring PJM to modify PJM EMS Network Application Contingencies.
• EOP-004-2 (effective Jan. 1, 2014) — Requires TOs experiencing a disturbance to supply sufficient information to allow PJM to meet its 24-hour reporting requirement.
• VAR-001-3 (effective Jan. 1, 2014) — Adds more specific PJM Manual references in R1.

Compliance is expected upon TOA-AC approval. TOs must provide evidence of compliance back to their last PJM TO/TOP audit.

PJM contact: Mark Kuras

Winter Reserve Target Cut to 27%

The committee endorsed a minimum winter reserve target of 27%, down from 28% a year ago.  The target is revised annually to maintain the one in 10-year loss of load expectation (LOLE).  The target is based on unit summer ratings and is expressed as a percentage of the forecasted weekly peak load.

PJM contact: Tom Falin

MANUAL CHANGES

Manual 13: Emergency Operations

Reason for changes: Annual review of load forecast error and forced outage rate components of day-ahead scheduling reserve: (effective Jan. 1, 2014); updates to comply with revised NERC standards.

Impact: Numerous changes, including:

• Load forecast error (LFE) changed from 2.13% to 2.12%. Forced outage rate changed from 4.66% to 4.28%. The day-ahead scheduling reserve for RFC and EKPC regions of PJM is changed from 6.91% to 6.41% times peak load forecast.
• References to ILR (interruptible load for reliability) — no longer a valid term — are removed.
• Revised order of emergency procedures so that curtailment of non-essential plant and building load is curtailed prior to issuing a manual load dump warning and voltage reduction.
• Updates to the min gen and max gen alerts process to include posting to the RCIS.
• Hot and cold weather alert unavailability numbers updated to include East Kentucky Power Cooperative.
• Clarifies section 5.4 post contingency local load relief warning (PCLLRW)
• References to transmission emergency alerts (TEA) and security emergency alerts (SEA) deleted due to retirement of the terms.
• Section 4: Replaced “CIP” reference for Event Reporting with reference to “EOP-004-2.”
• Section 6: Updated to reference revised Attachment J, (PJM operating plan for compliance with EOP-004-2). Attachment J almost entirely rewritten to support EOP-004-2 compliance.

Manual 41: Managing Interchange

Reason for changes: Manual 41 and Section 2 of the Regional Practices cover the same material regarding managing interchange.

Impact: PJM merged M41 into Regional Practices document and will retire M41. Other changes include:

• Chapter 2, Section 1.2.6 – Added clarifying language around PJM’s default ± 1000 MW ramp limit
• Chapter 2, Section 1.2.6 – Added clarifying language around NYISO interface ramp limit
• Chapter 2, Section 4 – Removed reference to pre-schedule checkout

PJM contact: Mary Mason

GRID OPERATIONS

New 500 kV Lauschtown Substation

PPL is building a new Lauschtown 500 kV substation as part of a baseline upgrade (b2006.1).

Reason: Correct NERC category C3 N-1-1 thermal violations.

Impact: Existing TMI‐Hosensack 500 kV line will terminate at the Lauschtown substation and keep the 5026 line designation. Proposed designation for the Lauschtown‐Hosensack 500 kV line is 5066.

Target completion date: Spring 2017.

Belmont SPS Revised

FirstEnergy Corp.’s Belmont special protection scheme (SPS) will be revised Dec. 1 as a result of the retirement of the Willow Island generator.

The Belmont substation is surrounded by a pocket of generation and has only two extra high voltage paths out of the area. The loss of either line creates potential stability and thermal overload issues that puts the second line at risk.

Existing procedure: The SPS is armed upon loss of the Belmont-Harrison 500 kV line (528 ) followed by loss of the Belmont No.5 765/500 kV Autotransformer or the Kammer-Belmont-Mountaineer 765 kV line. The SPS trips both Oak Grove combustion turbines and a selected Pleasants unit upon the loss of the other second facility.

Revised procedure: The retirement of the Willow Island generator eliminates the need to trip either Oak Grove unit. The revised procedure limits the output of one of the Pleasants units to a maximum of 520 MW and arms-to-trip the other Pleasants unit.  Oak Grove units will not be affected.

Target implementation date: Dec. 1, following a 90-day lead time to review changes with RFC.

Brandon Shores SPS Removed

The Brandon Shores SPS in the BGE zone will be removed in February because of the cancellation of the underlying transmission upgrade.

Background: Constellation Energy Commodities Group, Inc. submitted a merchant interconnection request (W3-122) for physical upgrades to the Brandon Shores –Riverside circuits 2344 and 2345 (ratings increase). A temporary SPS (W3-123) was designed to operate during the upgrade work to address a contingency analysis that indicated that a loss of one Brandon Shores – Riverside 230kV circuit may overload the other parallel circuit. Agreement W3-122 was cancelled in September

Existing procedure: The SPS was armed when a contingency analysis showed the Brandon Shores –Riverside (2344/2345) 230kV circuit is loaded up to 100% of its LTE rating. The SPS initiated a trip of either Brandon Shores Unit 1 or Brandon Shores Unit 2 when the Brandon Shores–Riverside 2344/2345 is lost and current on opposite circuit exceeds the setting for 30 seconds.

Impact: Minimal: The SPS was armed only once in the past year. The SPS will be removed from service Feb. 28, 2014.