VALLEY FORGE, Pa. — PJM is considering providing generation operators an indicator to signal that the RTO has entered emergency conditions, which triggers a performance assessment hour under Capacity Performance rules.
The RTO will determine if there should be any delay in the notification process and, if so, for how long, PJM’s Rebecca Stadelmeyer said. Stakeholders requested that PJM also ensure the signals don’t create any type of market advantage.
Stadelmeyer also clarified that non-ramp-limited basepoints have no impact on calculating either performance bonuses or nonperformance charges during a PAH.
The question arose because generators had been asking for the basepoints to be sent via PJM’s network, thinking they could help estimate units’ expected performance, Stadelmeyer said.
Non-ramp-limited basepoints are theoretical expectations based entirely on the economics of the current LMP and regardless of the unit’s actual capabilities. Ramp-limited basepoints, however, are developed from information about each unit submitted by operators into PJM’s systems.
Nonperformance charges are imposed when a unit’s output fails to meet its expected performance, and bonuses occur when actual output exceeds expected performance without exceeding PJM’s dispatch instructions. Expected performance is calculated by multiplying a balancing factor by the amount of a unit’s unforced capacity (UCAP) that clears as CP in a Base Residual Auction.
Balancing factors are hard to estimate, Stadelmeyer said, so she urged using the maximum 1.0 to identify the highest possible expectations.
PJM also clarified that the difference between UCAP and installed capacity (ICAP) is also available for bonuses as long as the RTO has dispatched the unit to that level.
In May, FERC rejected Tariff changes that would have exempted a capacity resource from nonperformance charges if it was following the RTO’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed as an interim solution to guard against generators self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)
Post-Polar Vortex Tools Enable PJM to Better Face Severe Weather
Thanks in part to new forecasting, scheduling and reserve-checking tools implemented after the polar vortex of 2014, PJM was better able to weather a seven-day July heatwave, PJM’s Chris Pilong told the Operating Committee last week.
The RTO recorded its 13th-highest peak load at 151,822 MW on July 25, a day that saw an average LMP of $35.51. During the hot spell, which ran July 21-27, the daily average LMP ranged from $25.88 on July 26, which recorded a peak load of 143,654 MW, to $42.72 on July 27, which saw a peak load of 146,166 MW.
Pilong said the experience was good news for PJM, which wanted to gauge the self-scheduling behavior of generators now that Capacity Performance is in effect. The RTO doesn’t want generators to disregard its dispatch orders and self-schedule more capacity to avoid penalties when they believe they are approaching a performance assessment hour. (See “Ramp Rate Approach Would Excuse Nonperformance Penalties,” PJM Markets & Reliability and Members Committees Briefs.)
“The day-ahead self-scheduled megawatts didn’t change much from the past few summers,” he said. “We’re not seeing a big shift.”
Day-ahead self-schedules for July 25 stood at 69,476 MW, compared with 68,649 MW a year ago, when load hit 143,633 MW. In real time, generators self-scheduled 73,177 MW, compared with 76,430 MW a year ago.
Self-scheduled units are price takers and cannot set marginal prices; they also are ineligible for operating reserve credits.
July 25 was the first time under the new market construct that PJM issued a maintenance outage recall. It canceled 11 planned outages, totaling 124 MW over 72 hours. Eight of them, a sum of 48 MW, were online by noon July 25; the remaining three, totaling 76 MW, did not return and were converted to forced outages.
An RTO-wide hot-weather alert was issued July 22-25. A heat advisory was issued July 21 in the ComEd zone and July 26-28 in Mid Atlantic and Dominion.
The grid experienced no transfer or interconnection reliability operating limits (IROL) issues during the hot weather, Pilong said.
However, two 765/345-kV transformers tripped in different parts of the system, causing local congestion. (See “Grid Remains Strong During Recent Heat Wave,” PJM Markets and Reliability and Members Committees Briefs.)
PJM’s new tools address two scheduling concerns leading into the polar vortex. Operators’ ability to view the capacity position for the next several days was limited, as was their capacity to capture generator reserves in real time in order to validate their calculations.
In June 2014, PJM rolled out its “long lead” tool, which consolidates load forecasts, safety margins and generator data, and adopted a new procedure for scheduling generation that includes a seven-day look-ahead.
Last September the RTO developed an instantaneous reserve check, allowing it to validate unit reserves in real time.
Pilong said the new tools helped reduce balancing operating reserve (BOR) payments. BOR payments totaled $18.1 million from June through August 2015. That amount stood at $10.1 million through July 26, 2016.
Uplift payments for July 25 came to nearly $1.1 million, compared with $447,118 for the hottest day in 2015, which occurred on July 28.
Metering Task Force Presents Proposal to Improve Clarity
PJM presented the first read of an 11-point proposal for manual and Tariff changes to close the gap between PJM’s metering requirements and members’ understanding of the rules.
The proposal was outlined by Nancy Huang of the Metering Task Force, which was formed by a problem statement approved Sept. 8. (See “Metering Requirements to Receive Overhaul,” PJM Operating Committee Briefs.)
The group also recommended two topics for further study: minimum metering requirements for location and density to ensure system observability, and metering requirements for distributed generation.
The revisions aim to reduce the risk of non-compliance, provide clarity around the specifications and design of new equipment, improve the energy management system’s state estimation solution and maintain operation reliability and market fairness.
The proposal is set to go before the Members Committee on Sept. 29, with a FERC filing expected in October.
Systems Information Committee Heads into the Sunset
Members approved sunsetting the Systems Information Committee.
Topics related to the energy management system will be assigned to the Data Management Subcommittee (DMS), which will meet next on Aug. 25. Remaining topics will be transitioned to the new Tech Change Forum, which will hold its first meetings Sept. 27-28.
To accommodate the changes, the Operating Committee also approved modifying the DMS charter.
The DMS will now function as a joint subcommittee, with generator and transmission owners addressing pertinent issues and TOs considering topics applying only to them.
— Suzanne Herel
