The following issues were approved by stakeholders with little or no opposition Thursday.

Markets and Reliability Committee

Manual Changes

Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines were revised to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.

Manual 14A: Generation and Transmission Interconnection Process was revised with the addition of a new section 1.14 regarding interim deliverability studies.

Manual 14D: Generator Operational Requirements was updated as part of an annual review. It includes changes reflecting North American Electric Reliability Corp. standard MOD-025-2.

FTR/ARR Senior Task Force

Members approved changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to identify ways to improve FTR funding levels. The new scope includes an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.

One sentence was struck from the revised problem statement as a result of objections by the Market Monitor. The sentence stated that: “With FTR underfunding that has occurred over the last several years, FTRs no longer perform the function of an effective hedge against congestion in the Day-Ahead market.” While PJM officials said it was factually accurate, the Monitor said it wasn’t appropriate for inclusion in the problem statement.

Credit Requirements

The MRC and Member Committee approved the following changes recommended by the Credit Subcommittee:

• Risk Documentation Requirements – Removes the requirement that officer certifications be notarized, and allows electronic submissions. Eliminates the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
• Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
• Virtual and Export Transactions Credit Requirement Timeframe – Reduces the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
• Demand Bid Volume Limits – Establishes a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January.

Transition to 30-Minute Demand Response

The MRC and Members Committee approved a transition mechanism related to changes requiring more operational flexibility from demand response providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the new 30-minute-lead-time requirement. CSPs would be relieved of their obligations and have their capacity payments reduced. The transition mechanism was developed to comply with the Federal Energy Regulatory Commission’s May 9 ruling on the DR changes (ER14-822). Members also agreed to sunset the Capacity Senior Task Force.

Transparency of TO Calculations

Members voted to close an issue relating to the transparency of the calculations transmission owners use for allocating energy, capacity and transmission costs. PJM has created a webpage listing the methodologies transmission owners use for calculating total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL). The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged. (See TOs Will Disclose Calculation Methodologies.)

Members Committee

Supplemental Transmission Project Definition

Members approved revisions to the Operating Agreement clarifying the definition of supplemental transmission projects as one that is not a state public policy project and is not required for system reliability, operational performance or economic criteria. The change removes a reference to supplemental projects as “Regional RTEP” (Regional Transmission Expansion Plan) projects. It also clarifies that any reliability upgrades required as a result of the supplemental project are considered part of that project and are the responsibility of the entity sponsoring it.

Data Submittal Deadlines

Members endorsed Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes would allow load reconciliation data to be included in the calculation of balancing operation reserve deviation charges.

Members also endorsed Reliability Assurance Agreement revisions to allow EDCs to submit corrections to peak load contribution and network service peak load assignments until noon on the next business day. The changes, which will also be reflected in Manuals 18 and 27, are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)