VALLEY FORGE, Pa. — PJM on Wednesday proposed an alternative stakeholder process to implement the market rule changes recommended in a special report on the RTO’s role in the GreenHat default.
Last month, three independent consultants completed a six-month probe into how a small trading shop amassed the largest portfolio of financial transmission rights in PJM history without the collateral to back it up, ultimately blaming naïve staff and underlying market flaws for the 890 million-MWh default that could cost members up to $430 million. (See Report: ‘Naïve’ PJM Underestimated GreenHat Risks and PJM: FERC Order Could Boost GreenHat Default by $300M.)
CEO Andy Ott told the Market Implementation Committee on Wednesday he will oversee organizational and procedural changes within PJM itself but will rely on stakeholders to guide the process for market rule changes.
“We are going to suggest a stakeholder process to you all,” he said. “We think the current process may not be the best approach. Let me be clear, it’s a suggestion.”
PJM’s suggestion is to create a Financial Risk Management Senior Task Force that will assemble beginning May 2 to begin the overhaul of credit and risk management requirements, market design, membership qualifications and processes and the stakeholder process itself.
PJM’s Dave Anders wants the Markets and Reliability Committee (MRC) to approve staff’s proposed charter for the task force at its April 25 meeting so an educational session can commence in May. Staff will present their own observations at a May 13 meeting and propose foundational questions for thoughtful discussion over the following two weeks. The task force will then create a work plan and develop packages that produce the report’s recommendations for the Board of Managers to consider at its Dec. 4 meeting.
“Our stakeholder process is a strong one, but it’s not always the most efficient,” Anders said. “We believe we need to adapt the process to provide more efficiency.”
ORDCs Shrink in Updated Energy Price Formation Simulation
A late-stage change to how PJM treats expected generation outages resulted in a smaller Operating Reserve Demand Curve (ORDC) in the RTO’s energy price formation simulation.
PJM’s Adam Keech said changing unit commitment based on real-time instead of day-ahead markets increased locational marginal prices, boosted energy revenues and cut uplift by more than 80% compared with the status quo.
“It’s not exactly what real-time is but it’s the closest we can get to what real-time would be,” he said. “We stayed toward real-time because we think that’s the best tool we have and gives us the best approximation we can get.”
Likewise, implementing a 30-minute reserve market and PJM’s proposed ORDC increased LMPs by an average of $0.46 MWh, assigned an additional 1,350 MWh of synchronized reserve and 3,337 MWh of secondary reserve and generated $550 million more in total energy and reserve market revenues, Keech said.
FTR Forfeiture Calculation Change Endorsed
Stakeholders endorsed calculation changes for financial transmission rights forfeitures on Wednesday.
Brian Chmielewski, manager of market simulation, said PJM and the Independent Market Monitor agreed the current forfeiture rules should be adjusted because they do not distinguish between on-peak and off-peak FTRs. (See “First Read on Change to FTR Forfeiture Calculation” in PJM MIC Briefs: March 6, 2019.)
FTR forfeitures are intended to discourage traders from cross-market manipulation. Holders subject to forfeiture are credited for the hourly cost of the FTR. Under current rules, a $1,500 off-peak FTR for June 2018 would be credited an hourly cost of $2.08, equivalent to $1,500 divided by 720 hours (30 days x 24 hours). Under the endorsed change, the FTR cost would be divided by only 384 off-peak hours, increasing the credit to $3.91.
The proposal will now advance to a first read at the April 25 MRC. PJM hopes to implement the changes in the third quarter of 2019.
MIC Will Work IARR Funding Flaw
Chmielewksi told the MIC last month underfunding of interregional incremental auction revenue rights (IARRs) may occur because MISO’s process cannot guarantee future firm flow entitlements on upgrades consistent with PJM’s rules. (See “Incremental Auction Revenue Rights Funding” in PJM MIC Briefs: March 6, 2019.)
IARRs are granted to the customer only if the transmission improvement provides additional capacity that makes the request feasible. PJM guarantees that awarded IARRs are at least 80% of studied IARR megawatts. Any portion of the FFEs for an affected coordinated flowgate that is less than 80% of the IARR megawatt total will result in inadequate FTR revenues, the RTO has found.
PJM wants stakeholder work completed by Aug. 1 to allow implementation of the new rules for the 2020/21 planning period.
Gas Contingencies on Reserves Spur Manual Changes
PJM will update Manuals 11 and 28 to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.
“In the existing manual language, based on the triggers that are defined for how PJM identifies a gas contingency, there’s language in there that says very broadly that PJM would increase reserve requirements either in day-ahead or real-time to address the need for reliability for gas contingency,” said PJM’s Natalie Tacka. “So this just clarifies how we would do that.”
The MIC will be asked to endorse the revisions in May.
RT SCED Process Lacks Transparency, Monitor Says
PJM’s Independent Market Monitor wants stakeholders to review processes for real-time security constrained economic dispatch (RT SCED) and pricing that PJM uses in the energy market to send dispatch signals to generators and calculate LMPs.
The monitor presented a problem statement to the MIC and asked for feedback from stakeholders about the status quo. The IMM raised questions surrounding RT SCED case execution and approval processes, who approves the SCED cases, what criteria PJM uses to approve RT SCED cases and what criteria PJM uses for selecting cases to be used in the locational pricing calculator (LPC). Manual language should be updated to reflect the answers to these questions, the monitor said.
“This is all good stuff ,and we as a company, as a stakeholder, have been pushing for greater transparency,” said Gary Greiner, of PSEG. “More of an open kimono where we understand the dispatch decisions that are getting made.”
Lisa Morelli, PJM’s real-time markets operations manager, said staff would be open to exploring the issue further.
“We are certainly supportive of providing education in these areas and take the conversation from there,” she said.
NYISO and PJM Agree to New Flowgate Type
NYISO and PJM will revise their Joint Operating Agreement to create a new flowgate type for the East Towanda-Hillside 230-kV tie line.
The RTOs will classify the line as an “other coordinated flowgate,” defined as a flowgate where constraints are jointly monitored and coordinated for reliability purposes but are not settled on due to a lack of impactful dispatchable generation on the non-monitoring system.
The ISO and PJM last September filed with FERC a joint request for waiver of the JOA to permit them to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. The requested waivers enable PJM to temporarily conduct redispatch operations to control flows to the more restrictive rating on the NYISO side of the line without violating its Tariff while the grid operators work to develop a permanent solution. The commission granted the waiver in November. (See “NYISO, PJM Revising JOA for Tie Line Issues” in NYISO Business Issues Committee Briefs: March 13, 2019.)
– Christen Smith