VALLEY FORGE, Pa. — PJM last week presented Operating Committee members with a proposed pro forma agreement for dynamic schedules, saying it would eliminate potential confusion and improve reliability.

Dynamic schedules are power flows into the RTO from a generator that is controlled by and located in a different grid operator’s territory. Unlike pseudo-tied units, the flows are not modeled in PJM’s systems as internal supply.

Because PJM lacks a standard agreement for dynamic schedules, individual agreements may contain variations in language that can result in incorrect operating procedures, the RTO said.

Under PJM’s proposal, the native balancing authority would only need to acknowledge awareness of the agreement because it remains operationally responsible for the resource. Unlike pseudo-ties, dynamic schedules require tagging and are subject to curtailment under NERC’s transmission loading relief procedures, PJM’s Phil D’Antonio said.

D’Antonio said PJM hadn’t yet decided whether they would seek to make the agreement retroactively enforceable for existing schedules. The agreement will be brought to a vote at next month’s OC meeting.

PJM’s Jacqui Hugee gave the OC an update on additional Joint Operating Agreement revisions MISO has requested relating to the pro forma pseudo-tie agreement. “For the most part, the changes are to clarify the language that is there,” she said. (See Late Agreement with MISO Forces Another Delay on Pseudo-Ties.)

Stakeholders voiced concerns about the language, but Hugee explained that PJM does not need, nor will it seek, stakeholder endorsement for the changes.

SCED Changes Implemented

PJM on Monday transitioned from a 15-minute to a 10-minute “look ahead” on its security-constrained economic dispatch (SCED) engine. The changes went into effect at 9 a.m.

PJM’s Joe Ciabattoni said the RTO will review the system’s performance after a week to ensure there are no reliability issues and evaluate whether to retain the changes. Ciabattoni said PJM does not need stakeholder approval to make the changes.

“We’re trying to better align real-time reserve levels with reserves calculated and dispatched by SCED,” he said. “Historically, we started with a 22-minute look ahead and have moved it over time to 15 minutes.”

Resilience Planning Moves Forward

PJM’s Jonathon Monken reviewed the RTO’s ongoing development of system resilience, noting that communication has expanded with related industries such as natural gas distributors. (See “Bryson Leads on Next Steps for Fuel Resiliency,” PJM OC Briefs.)

“I would expect that this will drive a lot of exercises and drills, recognizing that when we identify a vulnerability, we would much prefer to test it in an exercise environment than experience it in real life,” said Monken, senior director of systems resilience and strategic coordination.

He said that PJM is developing both internal and external roadmaps for enhancing resilience to severe weather, physical or cyber attacks or disruptions in fuel supplies. He also reviewed PJM’s Resilience Steering Committee, which includes himself and 14 other PJM staffers with responsibilities for various aspects of the plan.

John Farber of the Delaware Public Service Commission questioned using resilience as a driver for approving projects in the Regional Transmission Expansion Plan. While it was not listed on the current version of the external roadmap he presented, Monken confirmed that it is still a focus.

Farber warned that evaluation of resilience in RTEP projects wouldn’t be “as straightforward as described” and said completing quantifiable metrics by the end of 2018 is an aggressive timeline. “I would just note that the last time that PJM addressed drivers in the RTEP process … that took two and a half years. And those were, in my view anyway, difficult years,” he said.

“We certainly recognize the fact that we’re certainly not going to go faster than what the stakeholders would like it to go,” Monken said.

Ramp Rate Changes

PJM’s Cheryl Mae Velasco highlighted enhancements to its Markets Gateway online tool that will allow generators to adjust their regulation offers throughout the day instead of just once daily.

“The [web-coding] vendor had a chance to put them in,” Velasco said. “They’ve been on the backlog for quite a while.”

The announcement was met with appreciation, but also a request.

“These are items that could provide optionality in how we operate units, so to hear about it in the Operating Committee a week before [implementation] is, for me at least, problematic,” American Electric Power’s Brock Ondayko said. He asked that similar changes be brought to stakeholders’ attention “preferably” two or three months in advance.

“Once we found out [that the vendor had made the updates], we sent the communications out as soon as possible,” Velasco responded.

PJM’s Ken Seiler acknowledged Ondayko’s concern and said he would work with the RTO’s Tech Change Forum to provide earlier notice in the future.

Ciabattoni said that generators making changes to their ramp rates will not require corresponding price points in their cost-based offers.

Solar Eclipse Impacts

PJM estimates a loss of up to 2,500 MW in solar output during the solar eclipse that will occur on Aug. 21. The event is expected to last about an hour.

While grid-connected and behind-the-meter systems will be impacted the same, the difference in deployed amounts means that grid-connected output is expected to drop about 500 MW, while BTM resources could drop about 2,000 MW. PJM expects it will need to increase non-solar generation by about 1,000 MW if it’s an overcast day and up to 2,500 MW if it’s sunny. Coordination will be important during the ramp up and ramp down periods.

PJM’s Joe Mulhern said the eclipse is expected in the middle of the afternoon when the sun is high and solar generation is near its peak output. If it’s a hot day, load will no doubt be near its peak as well, he said. However, a NERC analysis showed no reliability impacts are expected for the Bulk Power System.

Primary FR Task Force Begins July 25

PJM’s Glen Boyle announced that the Primary Frequency Response Senior Task Force will have its first meeting at 9 a.m. July 25, with monthly meetings to follow for at least six months. (See “PJM Defends Interest in Paying for Frequency Response,” PJM Markets and Reliability Committee Briefs.)

– Rory D. Sweeney