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 (9:10-9:20)
A. Members will be asked to endorse manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
B. Members will be asked to endorse changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.
3. COORDINATED TRANSACTION SCHEDULING (9:20-9:50)
Members will be asked to approve a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
4. SYNCHRONIZED RESERVE (SR) PERFORMANCE (9:50-10:20)
MRC will be asked to approve increased penalties for under-performing Tier 2 synchronized reserve providers.
At a special Operating Committee meeting yesterday, members rejected a proposal from PJM and the Market Monitor (Package A) in favor of one introduced by Dave Pratzon, of GT Power Group, who represents generation owners (Package B).
Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
The current penalty is to take away revenue for the hour when the resource did not perform and also require the resource to provide Tier 2 reserves without compensation when needed for three days. If a resource fails to perform in one hour it doesn’t affect its credit for performing in another hour during the same day.
Because Tier 2 SR calls have declined to about once every 10 days from one in every three days, the three-day penalty has lost its bite.
The proposal to be considered by the MRC Thursday removes the “contiguous” hours statement from the same-day penalty and creates a retroactive obligation to refund the shortfall for all of the hours the resource was assigned over the immediate past interval (i.e., 10 days currently). It also increases the penalty by eliminating the conversion of shortfall MW to MWh.
Package B was supported by almost three-quarters of those voting yesterday, with heavy backing from generator representatives. Package A won only 18% support. Package C, which would have added a 25% additional penalty to Pratzon’s proposal, won less than 27% support.
See OC Hears New Proposal on Synchronized Reserve Penalty; Delays Vote
5. CAPACITY CREDIT CALCULATION FOR WIND RESOURCES (10:20-10:45)
Members will be asked to choose one of two alternatives to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.
The Planning Committee last month recommended a proposal (Alternative 2) under which state estimator data would be used to interpolate output for each five-minute period with curtailments. MRC also may consider a second option (Alternative 3), which was approved more narrowly by the PC. It would substitute forecast data from PJM operations — which is currently used for lost opportunity cost calculations — for curtailment periods.
See Planning Committee OKs Relief for Wind Generators; MRC Considers Changes to Wind Capacity Calculations
6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS (10:45-11:00)
Members will vote on two proposals approved this month by the Market Implementation Committee to streamline the demand response registration process.
Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.
The MIC approved the following changes:
- Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
- Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.
The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.
See Simplified Demand Response Registration OKd
7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) Charter (11:00-11:10)
Members will be asked to approve the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.
PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.
See PJM Proposes Operating Reserve Changes to Cut Uplift
8. ENERGY STORAGE RESOURCES (11:10-11:25)
Members will be asked to approve a proposed problem statement allowing batteries, flywheels and other advanced energy storage technologies to participate in its capacity market.
See Energy Storage: Ready for its Close-up? p. 1; Energy Storage Vies for Capacity Role
Members Committee
3. CETL STABILITY– EASILY RESOLVED CONSTRAINTS (1:25-1:45)
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal the MC will be asked to endorse. The proposal was approved by the MRC in August.
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.
Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
See Quick-Fix Transmission Upgrades OKd
4. PARAMETER LIMITED SCHEDULES (PLS) REVISIONS (1:45-10:00)
PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes the MC will be asked to endorse.
The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues. The changes were approved by the MRC in August.
See: MRC Actions
5. NODAL SETTLEMENTS (2:00-2:20)
Retail marketer Direct Energy will attempt to win Members Committee approval for Tariff revisions that would allow network load customers more frequent opportunities to switch to nodal pricing.
The Market Implementation Committee in August rejected the company’s proposals after utility representatives said the changes would create administrative problems for their electric distribution companies (EDCs).
The company said the changes would allow retail marketers to offer more innovative products but would not have significant impact on EDCs or other market participants because it would cap switches at 5% of the EDC network service peak load.
