VALLEY FORGE, Pa. — PJM’s plan to switch which side of a transformer is considered for cumulative ramping impact is “a win-win” because it models the system better without implicating expensive upgrades, the RTO’s Jonathan Kern explained to stakeholders at last week’s Planning Committee meeting.
The RTO was proposing to include in its calculations only transformers whose lowest terminal voltage level is at least 500 kV rather than any whose high side is at least 500 kV. PJM justified the change because distribution factors for transformers are generally closer to the lower-side system they connect to than the higher side. The plan was part of a larger package of revisions to Manual 14B developed through an annual review. Stakeholders endorsed moving the proposal to the Markets and Reliability Committee but not before examining PJM’s determinations.
Kern said an analysis found that two transformers — the 500/138-kV Wescosville and 500/230-kV Ladysmith — could potentially be overloaded by the change at a cost of $18 million and $25 million, respectively. He said the change would only take effect starting with the 2023 Regional Transmission Expansion Plan, an initial analysis of which doesn’t show any impacts.
“There’s very strong evidence for the technical change we’re proposing to make here,” Kern said. “To us, it appears like a win-win change. In other words, it’s meeting the obvious technical intuition we have for generation delivery but also not creating any new overloads.”
However, American Municipal Power’s Ryan Dolan reminded everyone that no cost increases come without impact.
“I would argue that over $30 million of required upgrades wouldn’t be minimal,” he said.
External Capacity
PJM’s Aaron Berner successfully urged stakeholders to endorse rule revisions that would allow pseudo-tied external resources wanting to offer into the RTO’s capacity auctions to deliver into the energy market any additional generation beyond what’s authorized for capacity.
The RTO’s rules for external resources impose requirements that can limit how generation those units can offer into the Reliability Pricing Model.
“That doesn’t mean though that the transmission service is not deliverable for energy use,” Berner explained. “So with the addition of this language, the studies that PJM performed previously or would perform for new generation would still allow that generation to be delivered as transmission service for participation in the energy market.”
The revised language was added to changes developed for Manual 12 to address pseudo-tied capacity resources. Berner fielded several clarifying questions before stakeholders requested that PJM add detail to their proposed revisions.
“The current language does not explain in detail what you explained,” said James Manning with the North Carolina Electric Membership Corp.
Berner agreed to work with stakeholders on that issue, but he asked that they endorse the intent of the revisions so it can move on to the MRC.
Limiting Meetings Causing Stakeholder Strain
In explaining why proposed revisions to Manual 21 were only presented at the Planning Committee, staff said they were only trying to comply with stakeholder requests to limit meetings.
PJM’s Jerry Bell explained the revisions, which would change how generators are tested to receive and retain capacity interconnection rights (CIRs). Stakeholders argued that the changes are wide-ranging, requiring input from experts who don’t typically attend committee meetings, and asked why the considerations hadn’t been put to a task force or other high-level committees.
“This is really a generation operations issue, but we’re looking at it in the Planning Committee. We’ve got mostly transmission planners in the room here. We really need to expose this to all of the people this is really going to affect,” FirstEnergy’s Jim Benchek said. “These changes are pretty major.”
“I don’t necessarily think there’s any ill intent here, but it’s just that sometimes what looks to be just something for the Planning Committee has broader impacts,” said Adrien Ford with the Old Dominion Electric Cooperative. She suggested that PJM’s problem statement/issue charge process could have arrived at a result faster because the necessary stakeholder groups could have been identified up front.
“We’re trying to balance the needs of the stakeholders where we’ve gotten feedback about having too many other meetings and having the agendas jammed and the days of the week jammed with other meetings,” said Ken Seiler, who chairs the Planning Committee. He said he would confer with the chairs of the Operating and Market Implementation committees about how to handle the requests.
Stakeholders noted several concerns with the proposal, which would eliminate June from the summer testing period (leaving July through August) and require simultaneous testing of all resources at a plant except wind and solar units. They would have to be able to start within five minutes.
“If you were to call on all the units at a plant and apply the test simultaneously, the start-up costs could get quite expensive,” Benchek said, adding that his company didn’t favor the reduced testing period either.
Solar and wind would be exempt because they use their average capacity factor during the peak hours included in the testing, but all capacity factors will be determined by calculating the median rather than average performance going forward. Bell confirmed those calculations won’t become fully effective until 2021/2022.
Mike Borgatti with Gabel Associates was concerned that the proposed language changes didn’t adequately enunciate that units’ capacity factors wouldn’t be affected for three years.
Bell also walked stakeholders through analysis that shows that the 650 MW of non-dispatchable hydro generation might be overstated by 520 MW because the expected capacity factor of 20% shows that 130 MW is predicted to be available.
AEP Project Removed from RTEP Modeling
American Electric Power’s portion of Duff-Rockport-Coleman project has been placed on hold and will not be modeled in the 2018 RTEP, PJM told the Transmission Expansion Advisory Committee on Thursday.
Robert Bradish, AEP’s vice president of transmission grid development, informed PJM of the change in a letter Feb. 20. Bradish said the supplemental project was proposed to address voltage stability limitations and eliminate the special protection scheme at the Rockport plant by interconnecting the Rockport 765-kV station with the MISO Duff-Coleman 345-kV market efficiency project.
“The current generation situation at Rockport plant is quite different from the situation when this supplemental project was included in the 2015 RTEP,” Bradish wrote. “There is currently significant uncertainty regarding generation-related conditions which may affect future operation of the Rockport units. Certain of these generation conditions can only be addressed through coordination with third parties, regulatory proceedings and other circumstances outside of AEP’s control.”
Retirement Studies Update
PJM has completed reliability analyses on retirements at six generating stations and is conducting reviews for three others.
The retirements of Buggs Island 1 and 2 (138 MW), Bremo 3 and 4 (227 MW), and Bellemeade CC 1 (265.7 MW) are all effective April 16; Possum Point 3 and 4 (317.7 MW) and Chesterfield 3 and 4 (262.1 MW) are both scheduled for Dec. 1. PJM said it has asked Dominion Energy, the transmission owner for all the plants, to perform additional analysis to identify any required upgrades.
PJM said it identified no impacts from the scheduled May 3 closing of Evergreen Power United Corstack (25 MW) in Met Ed.
It is conducting analyses on the Morris Landfill Generator (1.9 MW) in ComEd and the Reichs Ford Road Landfill Generator (1.7 MW) in APS, both set for May 31, as well as FirstEnergy’s Pleasants Power Station 1 and 2 (1,278 MW), scheduled for Jan. 1, 2019. (See FirstEnergy Shutting down Unsold Coal Plant.)
Market Efficiency Update
PJM planners have selected a $25.4 million proposal by Baltimore Gas and Electric to address constraints on the Conastone-Graceton-Bagley 230-kV corridor after finding it cleared their reliability and cost/constructability analyses. The project (proposal 5E), which involves reconductoring and upgrades to equipment at the Conastone and Windy Edge substation, is expected in service in 2021. It will be recommended for approval at the Board of Managers meeting in April.
Planners said they won’t be recommending any market efficiency projects in the PPL zone after seeing the projected congestion benefits from the proposed Susquehanna–Harwood drop by about half under the base case because of a lower load forecast and changes in generation expansion since the start of the 2016/17 project window.
PJM is now developing assumptions for its 2018/19 RTEP long-term window, which it expects to open between November and February 2019.
Officials also said they expect to open a 60-day reliability project window in May or June.
— Rory D. Sweeney & Rich Heidorn Jr.
