VALLEY FORGE, Pa. — PJM’s Planning Committee endorsed capacity generation rule changes for Manual 21, save for the controversial effective load-carrying capability (ELCC) calculations deferred for a vote until next month.
The endorsed revisions include a new section devoted to obtaining, maintaining or losing capacity interconnection rights (CIRs), as well as sections for installed capacity calculations and testing requirements.
New rules on testing within temperature bounds would take effect June 1, with provisions on simultaneous testing and the ELCC effective for delivery year 2022/23. Wind and solar units losing CIRs would be notified before Jan. 1, 2025.
The committee will consider PJM’s ELCC calculations, as well as modifiers proposed by the American Wind Energy Association last month, at the May 16 meeting. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)
PJM wants endorsement from the Markets and Reliability Committee at its April 25 meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. The proposal would not affect UCAP values from prior auctions.
Market Efficiency Process Enhancement Task Force Gets Phase 3
Stakeholders agreed to a third phase for the Market Efficiency Process Enhancement Task Force after approving manual revisions that change how often PJM re-evaluates projects and shifts planning timelines.
The phase 2 proposal moves the long-term planning window back two months to January-April from November-February to align it with MISO’s processes. If approved at the April MRC, both RTOs would post economic drivers in January.
The mid-cycle model refresh would be made in late April to allow project proposers extra time to analyze their projects under the revised case prior to a final submission.
PJM’s Brian Chmielewski said the task force agreed the RTO will not re-evaluate any projects once a certificate of public convenience and necessity (CPCN) has been issued or — in the case of states without such a process — once construction has begun. Under current rules, PJM reviews the costs and benefits of economic-based transmission projects annually to ensure they remain economical. (See “PJM Readies Package on Market Efficiency Rule Changes,” PC/TEAC Briefs: March 7, 2019.)
Stakeholders modified proposed language in Section 1.5.7 of the Operating Agreement by adding “or relevant regulatory authority” to ensure projects that don’t require a CPCN or fall under the jurisdiction of any state agency will be covered under the new rules.
Phase 3 will tackle how regional targeted market efficiency projects address historical congestion using the same criteria as used in interregional TMEPs and possibly changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits.
Staff will seek MRC approval of the changes in April and Members Committee endorsement of Operating Agreement revisions in May. PJM wants the new rules effective Aug. 1 for the 2020/21 long-term window.
Revisit Benefit-cost Analysis, Monitor Says
The Independent Market Monitor wants stakeholders to reconsider how it performs benefit-cost analyses, noting the current process turns a blind eye to any drawbacks that come with a transmission project.
“The current analysis ignores anywhere where benefits are negative,” said Howard Haas, of Monitoring Analytics, as he presented the Monitor’s first read of a problem statement and issue charge addressing the matter. “If you are ignoring the effect on locations where the effect is negative and only accounting for effects where they are positive, you’re going to approve things you shouldn’t approve.”
Specifically, the Monitor says PJM’s current method ignores increased congestion in all zones resulting from a transmission project when calculating energy market benefits. Haas said the benefit-cost analysis does not account for the fact that transmission project costs are not subject to cost caps and may exceed estimated costs by a wide margin. When actual costs exceed estimated costs, the benefit-cost analysis is effectively meaningless and low estimated costs may result in inappropriately favoring transmission projects over market generation projects or the option of no project at all, he said.
“We think there is something we could be doing differently, and we’d like to have a discussion about what those could be,” Haas said.
While stakeholders appeared supportive of discussing some of the Monitor’s concerns, many — including PJM itself — pushed back against questioning the RTO’s 15-year planning horizon for measuring benefits.
“That was literally just approved by FERC two months ago,” PJM’s Tim Horger said. “Let’s get some experience with using this.”
In a Feb. 19 ruling, PJM won its bid to revise the benefit-cost ratio to ensure projects with delayed in-service dates only receive analysis within the existing 15-year planning horizon. Under previous rules, PJM said it spent considerable time developing ad hoc projections for years beyond the current cycle, resulting in “risky” and “unreliable” modeling.
The Monitor protested PJM’s reasoning, proposing instead a longer horizon exceeding 20 years. FERC rejected the Monitor’s arguments. (See PJM Extends Planning Window After FERC Approvals.)
“To the extent that we just had the paint dry on one filing … if we had filed our proposal, we do believe it would have been approved,” Haas said on Thursday.
Pauline Foley, PJM’s legal counsel, questioned the Monitor’s insistence on bringing the issue up now instead of during the earlier phases of the Market Efficiency Process Enhancement Task Force.
“There’s a little bit of frustration. … I think the task force is the appropriate place to bring this, and I think we need a new problem statement, frankly,” she said. “My suggestion is that this be a whole new initiative because it looks like you’re trying to revamp the market efficiency process as a whole.”
LS Power Will Seek 2nd Deferral on Transmission Replacement Language
LS Power’s Sharon Segner told the PC on Thursday she will seek another 60-day vote deferral on her company’s proposed revisions to the Regional Transmission Expansion Plan process.
Segner’s amendment to Manual 14B was slated for stakeholder endorsement at the April 25 MRC meeting. The proposal specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria.
Aaron Berner, PJM manager of transmission planning, said stakeholders agreed to another deferral after conducting two educational sessions last month to discuss how projects are removed from the RTEP. (See “RTEP Removal Discussions Scheduled,” PJM PC/TEAC Briefs: March 7, 2019.)
“There is still some work to be done and some technical discussions to be had,” he said. “It’s a good step to keep moving forward. We are finding some resolution and some common ground on some of the language.”
PJM will schedule as many as five additional meetings on the subject over the coming months, Berner said.
TMI Deactivation Costs Rise $1.5 Million
Three Mile Island’s scheduled deactivation just got $1.5 million more expensive, PJM’s Phil Yum said Thursday.
The plant requested new station service to a control building with a new 230-kV bus ahead of its planned closing in September. Yum said the work is necessary in order to fulfill the deactivation request.
JCP&L Needs Transmission Line Upgrades
Jersey Central Power & Light requested a dozen transmission line upgrades, citing outdated and faulty equipment with few experts left to fix it.
FirstEnergy identified protection schemes using a certain vintage of relays and communication equipment with a history of misoperation, the utility said in a problem statement submitted to the Transmission Expansion Advisory Committee on Thursday.
Affected 230-kV lines include: Atlantic-Red Bank, Atlantic-Eaton Crest-Red Bank, Pohatcong-West Wharton, Gillette-Traynor, Greystone-West Wharton, Raritan River-Werner, Greystone-Portland, Atlantic-Smithburg, Chester-Glen Gardner, Gilbert-Glen Gardner and Chester-West Wharton.
Dominion Supplementals
Dominion Energy said customers requested two new transformers in Northampton County, N.C., and Charles City County, Va. The new units will support commercial load growth and contingency loading for the loss of an existing transformer.
Dominion also proposed a $2.5 million project to satisfy requests for a new substation in Chesterfield County, Va. The plan involves cutting into line No. 2066, installing three switches and a 230-kV circuit switcher on the high side of a new transformer.
In addition to building a third transformer at the Winterpock substation, Dominion suggests installing a four-breaker ring and a circuit switcher on the high side of the new transformer for $8.5 million. The utility also wants to spend $750,000 to install a new 230-kV circuit switcher at the Rockville substation and $4.5 million to replace an old transformer along the Chesterfield line. Transformer replacements near the Peninsula substation are estimated to cost $16.1 million.
AEP Takes over Dayton Line
Dayton Power and Light will retire its Killen substation in June and transfer use of the 345-kV Don Marquis-Stuart line to American Electric Power. AEP said it will need to bypass Killen taps in order to complete the line circuit.
– Christen Smith