Market Efficiency Process Packages Move to MRC
Incumbent transmission owners in PJM won a victory last week as the Planning Committee endorsed creation of a new regional targeted market efficiency project (RTMEP) process that would be excluded from competition. The new process will involve backward-looking analysis to address persistent congestion not identified in the forward-looking planning model.
The PC endorsed a combined proposal by American Electric Power and FirstEnergy on the RTMEP process with 56% support. The AEP-FE package, which would exempt RTMEPs from competition, edged out PJM’s proposal (55% support), which called for 30-day competitive windows to select the developer.
The two packages were otherwise identical. They would calculate benefits based on the average of the past two years of day-ahead and balancing congestion, adjusted for outage impacts. To be approved, a project would have to recover the project’s capital cost within four years.
AEP-FE’s proposal for the benefit calculation metric also was preferred, winning 54% to PJM’s 52%. AEP and FE would employ a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and Regional Transmission Expansion Plan (RTEP) years. PJM proposed averaging Monte Carlo results and running them on RTEP, RTEP+3 and RTEP+6 years. Projects must have a capital cost under $20 million and be in service within three years.
The Independent Market Monitor’s proposals on those two components each received less than 20% support.
PJM’s proposed window for capacity drivers won 52%, besting the IMM’s proposal with 25%. (AEP and FE did not offer an alternative window.) PJM proposed a 24-month cycle for energy drivers and a 12-month cycle for capacity.
AEP and FE said the interregional PJM-MISO TMEP planning process has produced six projects costing $120,000 to $6.7 million, none of which involved greenfield projects and each of which was assigned to incumbent TOs. Three involved line reconductoring; two required replacing or upgrading terminal equipment; and one was for reconfiguration of a ring bus. The companies said they expected that regional TMEPs would produce similar projects.
The PC’s May 12 endorsement culminated 18 months of work the Market Efficiency Process Enhancement Task Force and sets up final votes at the Markets and Reliability Committee. Each issue in the package needed at least a 50% vote to move on to the MRC for a final sector-weighted vote.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked when manual language will be drafted for the AEP package to be voted on. PJM’s Jack Thomas said manual language or government document language will be drafted for the first read at the June MRC meeting but could be pushed back to the July meeting depending on how long it takes to put together.
Changes Approved to CISO Issue Charge
The PC approved Exelon’s revisions to the Critical Infrastructure Stakeholder Oversight issue charge over the objection of the original sponsor, the D.C. Office of the People’s Counsel.
Exelon’s redline of the issue charge that was originally endorsed by stakeholders in December was approved by a 61% vote. The D.C. OPC had proposed the issue charge in response to transmission owners’ decision to file a new Tariff Attachment M-4 for the planning of critical infrastructure protection (CIP-014) mitigation projects (CMPs). (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)
The original issue charge said it would consider whether “procedures that provide stakeholder oversight of CMPs and CIP-014 facilities are appropriate.”
Exelon’s revision eliminates the term “stakeholder oversight,” saying instead that it will “evaluate whether procedures are appropriate for stakeholder review of measures to avoid a transmission facility from becoming a future CIP-014 facility and of the process that would handle mitigation of future CIP-014 facilities.”
Exelon’s change also included a paragraph noting FERC’s approval in March of the TOs’ Attachment M-4 filing. (See PJM Remains Neutral in CIP-014 Debate.)
Exelon brought the changes of the issue charge to the April PC meeting and agreed to delay a vote until the May meeting so discussion could be conducted with stakeholders. “We made an effort to make it clear that we’ll be focused on the avoidance of future assets,” Exelon’s Robert Taylor said.
Erik Heinle of the D.C. OPC presented an alternative to the redline version of the issue charge that included developing nondisclosure agreements regarding assets under CIP-014. His proposal was rejected, with 61% voting against it.
Heinle said stakeholders agree on wanting to address critical infrastructure avoidance. He said the biggest issue is determining the appropriate levels of confidentiality for projects.
“We should work on getting the policy right with mitigation, with avoidance, with confidentiality and send it to FERC and say, ‘This is the best policy that we’ve drawn up to address these facilities,’” Heinle said.
Poulos said the Critical Infrastructure Stakeholder Oversight group is very close to finishing its work. But he said the Exelon changes removed the consumer interest from the Tariff in regards to CMPs. Poulos said the changes proposed by Exelon are not typically done in an issue charge, and he indicated that he may bring the issue up directly to the MRC.
Taylor said Exelon incorporated stakeholders’ feedback in its revisions. “I think it’s fairly inappropriate to come out of the gate saying that if we don’t get our way out of the Planning Committee vote, we’re going to take it straight to the MRC,” Taylor said. “We’ve really tried to bend over backwards to take into account the concerns that have been raised.”
Emily Smithman of the New Jersey Board of Public Utilities said the BPU supported the original issue charge and disagreed with Exelon’s changes. Smithman said the BPU views the changes as increasing noncompetitive transmission investment in PJM.
Taylor said Exelon doesn’t see the mitigation of critical infrastructure as a competitive process, saying FERC has ruled that competition is not suitable for the assets.
“I don’t think anybody has envisioned or proposed that there would be a competitive window for these projects,” Taylor said.
PMU Placement First Read
PJM is considering using a “quick fix” Tariff revision to address the RTO’s plans to expand the use of synchrophasors and formalize their placements into the RTEP.
Shaun Murphy of PJM reviewed the problem statement, issue charge and proposed solution during a first read to require synchrophasors — also known as phasor measurement units (PMUs) — in all new substations and major construction projects to monitor bus voltage and line flows. The committee will be asked to approve the issue charge and endorse the proposed manual language at the June PC meeting under the quick-fix process detailed in section 8.6.1 of Manual 34.
In the PJM presentation, Murphy said additional language is being proposed for section 1.4.1.3 of Manual 14B that would include a PMU Placement Strategy (PPS) to identify the synchrophasor device coverage needed to support the RTO’s real-time synchrophasor applications. The PPS would include placement targets and required operational dates to guide installation plans and make mandatory a program that is currently voluntary.
Murphy said instituting the PPS would close the gap between research and real-time control room use, and improve data reliability and oscillation detection.
PJM completed a PMU data exchange with the Tennessee Valley Authority in February and expects to exchange data with Southern Co. and SPP later this year. The exchanges are intended to support reliability coordinator situational awareness and the Department of Energy’s oscillation detection pilot, an effort prompted by the Jan. 11, 2019, oscillation event. (See Oscillation Event Points to Need for Better Diagnostics.)
Murphy said the communication equipment needed at each substation costs as much as $120,000, and each substation would have two or three PMUs that cost about $10,000 each. As many as 889 projects could be created over a 12-year span if a voltage threshold of 115 kV for each unit is accepted, according to data presented by PJM.
Calpine’s David “Scarp” Scarpignato asked if the Tariff revisions would change the requirements for new generation having to install PMUs and if there would be any change for existing generators.
Murphy said PJM did not expect any changes for existing generators, but he said there could be an impact for generators on future generation projects depending on the manual language adopted.
Scarp requested that the impact on future generation projects be included in PJM’s next presentation.
Dave Mabry of the PJM Industrial Customer Coalition questioned the RTO about the cost of the initiative. According to numbers provided in the presentation, Mabry said, the cost could be as much as $135 million.
“I think my clients aren’t really sold that this technology is a need-to-have,” Mabry said. “We’re seeing it more as a nice-to-have and perhaps still not ready for prime time.”
Load Forecast Update
Andrew Gledhill of PJM provided an update on estimated COVID-19 pandemic impacts on PJM loads.
Gledhill said the high-level findings of the pandemic’s estimated impact on load has shown weekday peaks coming in 10% less than normal, or about 9,000 MW. Gledhill said the weekday peak impacts have ranged from 6.5 to 15.2%, with the largest estimated impacts happening on May 4 and 5 at 15% and 15.2%, respectively.
Energy has tended to be less affected by the pandemic, Gledhill said, with the average reduction since March 24 coming in around 7.9%. He said the hourly load shapes have been flatter than what is typically seen in the spring, and weekends seem to have been less impacted.
Gledhill said PJM has updated the RTO forecast using economic assumptions from April in place of the September 2019 forecast. He said planners intend to use the April economics for the parameters for the 2021/22 delivery year in the second Incremental Auction scheduled for July.
Whether there will be additional forecast updates has to do with the timing of the eventual 2022/23 and 2023/24 Base Residual Auctions, Gledhill said, as forecasters are still waiting for guidance on when the BRAs will run.
“This is an event that we’ve never seen,” Gledhill said. “So, getting as much information as possible is key to understanding how it’s affecting load and how it might affect load in the next several months or year.”
Transmission Expansion Advisory Committee
Beaver Valley Reinstatement Cuts $93M in Tx Spending
The reinstatement of the Beaver Valley nuclear plant will eliminate $93 million in planned transmission upgrades, PJM told the Transmission Expansion Advisory Committee.
FirstEnergy Solutions (FES) had filed a deactivation notice for the two-unit, 1,872-MW nuclear plant in Shippingport, Pa., in March 2018, targeting a 2021 retirement. But Energy Harbor, the new name for FES after emerging from Chapter 11 bankruptcy in February, told PJM in March it would keep Beaver Valley in operation, citing Pennsylvania’s plan to join the Regional Greenhouse Gas Initiative. (See Beaver Valley Nuclear Plant to Say Open.)
PJM initially identified $414 million in needed transmission upgrades after FirstEnergy announced the retirements of the Davis-Besse, Perry and Beaver Valley nuclear plants and six coal plants in 2018. The RTO reduced the projects to about $216 million after Davis-Besse, Perry and three coal units were reinstated last July.
With the reinstatement of Beaver Valley in March, the price tag has been cut to $123 million, PJM’s Phil Yum said.
He said eight baseline projects totaling $94 million are either already built or too far along in construction to cancel. Three other baseline projects totaling $8 million are still required for identified violations from the remaining deactivations, Yum said.
PJM’s re-evaluation also identified a needed $21.4 million upgrade to the 138-kV Smithton-Shepler Hill Junction line (B3214), Yum said.
All pending baseline projects are currently on hold, Yum said, and a final decision on canceling the projects will occur after the completion of required RTEP analysis and interconnection service agreements (ISAs) for affected generation queue projects.
The Beaver Valley reinstatement was included in the 2025 RTEP model build, Yum said.
TO Supplemental Projects
TOs presented more than $300 million in supplemental project solutions to the TEAC.
American Electric Power
AEP will spend $120 million to reconductor or rebuild 18 miles of 138-kV lines and install a 138-kV +/-75-MVAR Statcom system for dynamic voltage support as part of a project in response to a customer request for new service west of Cameron, W.Va. The forecasted peak demand is 30 MW initially, with long-term prospects of 90 MW (AEP-2018-OH032). The $120 million project will address strains on the local 138-kV system.
Commonwealth Edison
Commonwealth Edison will spend $65 million to rebuild the 345-kV Itasca bus as an indoor GIS double ring bus expandable to breaker-and-a-half connecting four lines and two transformers (ComEd-2020-002).
ComEd also plans to spend $55 million to rebuild the 345-kV Elmhurst bus as an indoor GIS double ring bus expandable to breaker-and-a-half connecting two lines and three transformers (ComEd-2020-003).
Both projects are needed to replace straight bus designs that do not meet current standards.
Dominion Energy
Dominion Energy Virginia will interconnect a new substation by cutting and extending Line 2137 (Poland-Shellhorn) about a half mile to the proposed Aviator Substation with a four-breaker ring arrangement to create an Aviator-Poland line and an Aviator-Shellhorn line at a cost of $22 million. The new Aviator substation is needed to accommodate a new data center campus in Loudoun County, Va., with a total load in excess of 100 MW (DOM-2020-0003).
It also will spend $40 million to construct a 230-kV underground line from the Tysons Substation to a new Springhill Substation to replace the portion of existing overhead Line 2010. It will install a 230-kV, 50-100-MVAR variable shunt reactor at Tysons. The project, which will span about three-quarters of a mile, was requested by a customer and Fairfax County to allow construction of a planned mixed-use development (DOM-2020-0010).