Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

3. Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines will be 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.
4. Manual 14A: Generation and Transmission Interconnection Process will be revised with the addition of a new section 1.14 regarding interim deliverability studies.
5. Manual 14D: Generator Operational Requirements will be updated as part of an annual review and include changes reflecting North American Electric Reliability Corp. standard MOD-025-2.
6. Manual 18: PJM Capacity Market will be amended to include details of the processes regarding maintenance outages for Annual Demand Response.

3. FTR/ARR Senior Task Force (FTRSTF) Problem Statement, Issue Charge and Charter (9:30-9:40)

Members may be asked to vote on changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to evaluate the causes for FTR underfunding and determine whether the current FTR and auction revenue rights processes to improve FTR funding levels. The proposed changes include an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.

4. Credit subcommittee Items (9:40-10:00)

Members will be asked to approve the following changes recommended by the Credit Subcommittee. The changes were approved by the Market Implementation Committee Sept. 3:

• Risk Documentation Requirements – Remove the requirement that officer certifications be notarized and allow electronic submissions. Eliminate 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 – Reduce 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 – PJM will establish 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. The 30% limit was based on analysis showing that the largest two-day-ahead zonal forecast shortfall from January 2013 through March 2014 was 28%.

PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January. Due to an input error, the company entered a demand bid about 100 times the retailer’s load. Because demand bids are currently unlimited, bids exceeding actual load act as a decrement bid but lack the protections of the virtual transaction credit screen and minimum participation requirement.

5. Cap Review Senior Task Force (CRSTF) (10:00-10:30)

Members will vote on proposed changes to the $1,000 energy market offer cap.

Cost-based incremental energy offers would be limited to production costs as defined by Cost Development Guidelines plus 10% with no cap. Market-based offers would be limited to the greater of the cost-based offer or the offer cap for 30-minute notice demand response. Adders for frequently mitigated units (FMUs) and associated units (AUs) would not apply above $1,000/MWh. Market-based offers must be less than or equal to cost-based offers when cost-based offers are greater than the 30-minute DR offer cap.

The proposal won 63% support at the Cost Review Senior Task Force. If it does not win a two-thirds vote at the MRC, members may vote on an alternative proposal by Old Dominion Electric Cooperative and the Delaware Public Service Commission. It would allow offers above $1,000/MWh during Maximum Emergency Generation Alerts but would not allow the offers to set LMPs.

Members also will consider sunsetting the task force.

6. Capacity Senior Task Force (CSTF) (10:30-10:45)

Members will consider a proposed transition mechanism related to changes requiring more operational flexibility from DR providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the 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 will consider sunsetting the Capacity Senior Task Force.

7. RPM: Capacity Import Limits – CTRs and ICTRs (10:45-11:00)

Members will vote on a problem statement and issue charge proposed by H-P Energy Resources to consider allowing qualifying transmission upgrades (QTUs) for capacity import limits. PJM instituted the limits on capacity imports in the May 2014 Base Residual Auction. (See Major Rule Changes Reduced Imports, DR.)

QTUs are currently allowed to increase the Capacity Emergency Transfer Limit (CETL) into locational deliverability areas (LDAs).

8. Transparency of TO Calculations (11:00-11:10)

Members will consider closing 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

2. CONSENT AGENDA (1:20-1:25)

1. Members will consider proposed revisions to the Operating Agreement clarifying the definition of supplemental transmission projects. Under the proposed revision, a supplemental project is 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.

1. Members will be asked to endorse proposed 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.
2. Members will be asked to endorse proposed 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.)

3. CREDIT SUBCOMMITTEE ITEMS (1:25-1:45)

See MRC agenda item #4, above.