Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee and Members Committee meetings 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 (previously PJM 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 (9:10-9:25)

A. Manual 12: Balancing Operations

Reason for change: PJM is changing the regulation requirement to align it with operational needs and address volatility in light load periods.

Impacts:

• Changes On-peak (05:00-23:59) requirement to 700 effective MW, a decrease in the requirement for 52% of days, an increase for 48% of days. Net daily decrease of about 60 MW (section 4.4.3).
• Changes Off-peak (00:00-04:59) requirement to 525 effective MW, an increase for 66% of days and a decrease for 34% of days. Net daily increase of about 20 MW (section 4.4.3).
• Changes regulation scoring methods:
  • Performance scoring for small regulation allocation: Historical performance scores will be used if the control signal has an average absolute value less than 1% of the regulation assignment (section 4.5.6);
  • Performance scores when data is not available: Historical performance scores will be used if data is not available and for intervals less than 15 contiguous minutes (adds section 4.5.9);
  • Regulation Assignments: Scoring will be suspended for 10 minutes after assignment to allow time to ramp into position (adds section 4.5.10).

PJM contact: Rus Ogborn

B. Manual 19: Load Forecasting and Analysis.

Reason for changes: Integration of East Kentucky Power Cooperative (EKPC), addition of annual demand resources and need to ensure accuracy of load shed programs.

Impacts:

• Adds EKPC to load forecast model;
• Revises assumption for winter load management;
• Makes minor typo fixes and clarifications for NERC audits;
• Changes demand resources available in winter months due to addition of annual DR product;
• Codifies guidelines for switch operability studies for load management programs. The guidelines are designed to ensure the accuracy of load shed estimates for participants in direct load control programs. The study must be designed for a minimum 90% confidence level and based on a randomly selected sample from the entire population of participating customers. No customers can be excluded.

PJM contact: John Reynolds

C. Manual 20: PJM Resource Adequacy Analysis

Codifying procedure approved by FERC. The changes were endorsed by the Planning Committee in October 2012.

Impact: Revises section 5 to add Test 2 for the six-hour duration requirement for the Limited DR Product.  The Test 2 procedure is effective with the 2016/17 Delivery Year.

PJM contact: Tom Falin

D. Manual 1: Control Center and Data Exchange Requirements

Reason for change: New rules for access to PJM Energy Management System (EMS).

Impacts:

• Added new section 2.5.7 detailing rules for transmission owner read-only access to PJM’s EMS. No screen scraping is allowed;
• Modified section 3.2.3 to clarify procedures for data communication outages;
• Modified section 4.2.4 to clarify repeating of All Call messages;
• Adds details to Information Access Matrix in Attachment A.

3. WIND LOC ELIGIBILITY (9:25-9:45)

Wind farms that fail to follow PJM’s electronic dispatch signals will no longer receive lost opportunity cost payments under a tariff amendment the MRC will be asked to approve.

Reason for change: Some wind generators are not following their economic basepoint, requiring PJM to issue manual dispatch instructions. This delays generators’ responses, causing less efficient market operations and a potential risk to system reliability, PJM says.

PJM proposed the new language as a Tariff change in response to a May 29 Federal Energy Regulatory Commission order that rejected its earlier proposal to incorporate the new rules in the Operating Agreement. The commission said the OA language “failed to provide any detail or tariff language describing the specific circumstances under which compensation would be reduced or how the compensation would be reduced.”

Impact: Would add language to section 3.2.3 of Tariff Schedule 1 to deny lost opportunity credits to pool-scheduled or self-scheduled wind generators that fail to follow PJM dispatchers’ electronic instructions to reduce output. (See PJM to Tighten Penalties on Wayward Wind.)

4. MUST-OFFER EXCEPTION DEADLINE (9:45-10:00)

To overcome generators’ objections, PJM and the Market Monitor have modified this proposal, which would set earlier deadlines for power plants seeking exemptions from participation in PJM’s capacity market auctions.

Reason for change: PJM says the current rules, which require 120 days’ notice before the opening of the auction, don’t give it enough time to analyze the impact of plant retirements on system operations.

Impact: The proposal would require generators seeking exemption from the “must-offer” requirement to file notice by Sept. 1 for the annual base residual auction (BRA) and 120 days before incremental auctions. The exemptions apply to generators that will be unable to provide capacity because they plan to retire.

At July’s MRC meeting, generators said the policy change could cause staffing problems and financial burdens at generators that will be forced to announce retirements earlier. (See Generators Balk as PJM Seeks Earlier Notice on Plant Retirements.)

In response, PJM and the monitor changed the proposal to provide generators more flexibility and to mask the identities of individual power plants. Under changes announced yesterday at the Members Committee Information Webinar:

• Retirement requests must be made by September 1 but can be based on a conditional deactivation analysis. The submission would specify the conditions that are creating uncertainty, such as pending negotiations on fuel or labor contracts. The finalized deactivation plan would be required by December 1 unless the request is withdrawn.
• PJM will post information on pending plant retirements in the first week of September but will do so using zonal aggregation rather than identifying individual generators. For each transmission zone, PJM will specify the amount of capacity scheduled to retire within one of the following ranges:

• Less than 100 MW
• 100 MW to 500 MW
• 500 MW to 1000 MW
• Total capacity to be retired will be specified if a zonal total exceeds 1,000 MW.

5. CSTF CHARTER UPDATES (10:00-10:15)

MRC will be asked to approve changes to the charter of the Capacity Senior Task Force.

Reason for change: Recently approved problem statements require a change in work scope.

Impact: The charter will be changed to reflect two recent problem statements:

• Demand Response as an Operational Capacity Resource – A problem statement approved by MRC June 27 charges the CSTF to investigate and develop recommended solutions on the following issues: Changes to DR obligations to move from administrative procedures to economic dispatch; diversifying notification time requirements based on physical response capability, similar to current requirements for generators; allowing DR to operate with a dispatchable range; caps on the amount of Limited DR that can be cleared above the quantity specified in the reliability analysis and changes in the way DR is modeled in PJM planning studies. The task force is expected to complete its work in time for a December 1, 2013 filing for implementation in the 2014/15 Delivery Year. (See PJM Demand Response Providers Decry Scrutiny, “Freight Train” of Changes.)
• Unit-specific review process under Minimum Offer Price Rule (MOPR) – MRC instructed CSTF to research this issue on May 23 in response to a FERC Order (docket ER13-535) which suggested PJM conduct a stakeholder process to consider revisions to standardize the unit specific review process. The task force will consider changes to financial modeling assumptions and ways to increase the transparency of the process. The task force is expected to complete its work in time for a December 1, 2013 filing for implementation in the 2014/15 Delivery Year. (See PJM, Monitor Push New MOPR Changes.)

6. NON-FIRM CAPACITY RESOURCE INCENTIVES (10:15-10:30)

Jason Barker, of Exelon, will seek MRC approval of a problem statement to consider modifying the design of the Reliability Pricing Model to ensure physical delivery of resources that clear the capacity auction.

Reason for Change: Barker told the MRC in July that the current design lacks sufficient penalties for those who offer capacity resources but fail to produce them in the delivery year.

He said the problem statement was needed to address reliability concerns caused by the increase in non-firm, planned resources clearing in the past three base residual auctions — including uncontracted demand response, planned internal generation, and existing and planned external generation that lacks firm transmission service.

(See PJM Demand Response Providers Decry Scrutiny, “Freight Train” of Changes.)

Members Committee

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

B. Proposed errata revisions to the OA and Tariff

Reason for change: The committee will be asked to approve corrections to errors inserted in Schedule 1 of the PJM Operating Agreement and Attachment K of the Tariff in 2008 and 2009. One correction will clarify how deviations occurring within one zone are associated with PJM’s Eastern or Western region for purposes of Operating Reserve charges. The other will insert a cross reference to tie language concerning forgiveness of positive demand deviations to the shortage pricing “trigger.”

C. FTR modeling changes developed by the FTR Task Force

The committee will be asked to approve two proposals for lowering the risk of Financial Transmission Rights revenue shortfalls. The two proposals were developed by the FTR Task Force and approved May 8 by the Market Implementation Committee.

Reason for changes: The two proposals reduce or remove infeasibilities in the FTR model and may allow increased counterflow FTRs to clear.

Impact: Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.” The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”

The proposals were among more than 20 options the task force considered in eight meetings since October. (See MIC OKs Options to Reduce FTR Shortfalls.)

D. Suspension of the day-ahead market after loss of Internet

PJM will suspend its Day Ahead market if it loses Internet service under a contingency plan the committee will be asked to approve.

Reason for change: PJM’s Tariff and Operating Agreement do not specify procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application.

Impact: Under the tariff changes approved in July by the Markets and Reliability Committee, all market settlements would be done in real time in such circumstances. (See MRC OKs Contingency Plan for Loss of Internet.)

E. New benefit test for market efficiency projects

The committee will consider changes to the way PJM determines beneficiaries of market efficiency transmission projects and how PJM planners add generation in market efficiency simulations.

Reason for change: The changes, which were approved by MRC in July, were developed by the Regional Planning Process Task Force to align modeling and beneficiary determinations with the revised cost allocation formula approved by the Federal Energy Regulatory Commission in PJM’s Order 1000 compliance filing.

Impact: Benefits of regional projects will be calculated on a 50/50 ratio based on their impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity pay­ments (capacity benefits). Benefits of local, low-voltage projects will be determined entirely on the change in net load or capacity payments for zones that experience decreases. (See chart.)

Under the previous method for both regional and local projects, 70% of benefits were calculated based on production or capacity cost savings, with the remainder based on change in net load or capacity payments.

Also included in the changes are a revised definition of production costs to include cross border purchases and sales. (See MRC Approves New Benefit Test for Market Efficiency Projects.)

3. WIND LOC ELIGIBILITY (1:25-2:00)

See MRC item # 3 above

4. MUST-OFFER EXCEPTION DEADLINE (2:00-2:25)

See MRC item #4 above