VALLEY FORGE, Pa. — PJM is moving to implement three changes to its financial transmission rights market, developed through its FTR Modeling, Performance & Surplus special sessions. All three received endorsement at last week’s Market Implementation Committee meeting.
The first involves changes in long-term FTR modeling to account for future transmission system upgrades, which can impact congestion revenue. PJM is concerned that long-term FTR clearing prices don’t reflect “true future system capability.” FTRs entitle holders to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. They can be purchased or converted from auction revenue rights, which are allocated to network and firm point-to-point customers.
PJM’s annual ARR/FTR network model includes transmission upgrades that will be in place by the following June 30, and staff proposed expanding that methodology to the long-term FTR network model so that it also looks forward one year. The model would be filtered to only include upgrades that fit a “low-frequency, high-impact” threshold.
That threshold would be defined as the upgrade being a constraint itself or impacting by +/-10% constraints that have contributed at least $5 million to congestion over the past year or any future constraint. For new facilities, the analysis would be based on the line outage distribution factor (LODF), a measure determining how the change in a line’s status affects flows elsewhere in the system. The FTR group would work with PJM’s planning staff to determine which upgrades should be included in the model. PJM included in its presentation an example of how that process would have worked for 2016 and found that three out of 21 upgrades would have been modeled.
PJM would also develop a new long-term residual ARR market to ensure holders maintain priority rights to any incremental capability created by upgrades still to be modeled.
The second set of changes would improve PJM’s ability to finalize and publish FTR auction results on time. Impetus for the solution came after PJM delivered its March auction results late and blamed it on having to simultaneously finish the results for several overlapping FTR auction periods. (See “FTR Lateness Blamed on High-Volume Period,” PJM Market Implementation Committee Briefs.)
PJM proposes to resolve the issue by eliminating some auction periods. PJM’s Brian Chmielewski said the proposal, if endorsed on its current timeline, would be filed with FERC in February to be effective for the June overlapping period.
The third set of changes would allocate any surplus from FTR auctions and day-ahead congestion to ARR holders after FTRs are fully paid to their target allocations. The issue developed after FERC required PJM to revise its methods for allocating ARRs and balancing congestion. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)
MIC members had to vote on two proposals: one developed by a coalition of ARR holders that allocated all surplus to holders, and a second developed by financial traders that allocated FTR surpluses to ARR holders up to their target credits and all day-ahead congestion surpluses to FTR holders.
The MIC endorsed the ARR holder proposal with 90% in favor and rejected the financial traders’ proposal with 34% in favor.
EnerNOC DR Aggregation Solution Questioned, Approved
Stakeholders endorsed by acclamation a problem statement and issue charge to examine the aggregation rules for seasonal demand response, but not before thoroughly questioning the proposal’s sponsor, EnerNOC. (See “Seasonal DR Aggregation Registration Rules,” PJM Market Implementation Committee Briefs: Nov. 8, 2017.)
“We don’t think this is a problem,” Independent Market Monitor Joe Bowring said, adding that “it seems to be presupposing the solution.”
Other stakeholders reiterated previous complaints that PJM’s stakeholder meeting schedule is already overbooked and that examining the issue doesn’t provide enough relative benefits to justify adding to the load.
“If we take issues up where there’s not really a problem, we create extra work for ourselves. I don’t think you can blame PJM for that. We have to blame ourselves,” Calpine’s David “Scarp” Scarpignato said.
EnerNOC argues that the current registration process is inefficient and provides a Capacity Performance value that fails to reflect the full reduction that the aggregated resources could achieve. PJM did not update its customer-registration rules when DR rules were revised to comply with CP requirements, nor did it seek stakeholder endorsement prior to unilaterally filing for approval last year of its seasonal aggregation plan. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)
EnerNOC’s Katie Guerry said the issue is worth examining because it could lead to more efficiency for both DR aggregators and PJM dispatch operations.
“If status quo comes out [as the result], we’re ok with that as well,” she said.
Other DR stakeholders supported her.
“I hope this doesn’t take 20 meetings, but I think it’s worth working on,” NRG Energy’s Brian Kauffman said.
Monitor, Financial Marketers Propose Different Paths
Unable to work out their differences on how to regulate the market path of energy sales coming into PJM, the Monitor and financial marketers are asking the MIC to resolve the issue. They are presenting three different proposals on the issue.
The Monitor’s proposal would develop a list of “prohibited paths” that could be subject to resettlement. The Monitor would develop a monthly report of activity on those paths and share it with PJM so that either entity could refer use of those paths to FERC for enforcement.
Pierce Atwood partners Ruta Skucas and Jared des Rosiers presented a proposal developed by American Electric Power and the Financial Marketers Coalition. It would entail a change in PJM’s Tariff for the initial list of banned paths and require FERC, PJM and Monitor approval for any additions. It would also develop a “query” where users could seek a preliminary evaluation from PJM on whether a potential path would risk resettlement.
Stephen Kelly of Brookfield Renewable presented another proposal that would allow market participants the opportunity to establish with PJM and the Monitor that a potentially problematic transaction is “legitimate” before it is automatically resettled.
The proposals also differed on what level the activity should be evaluated. The Monitor proposed considering it from the level of the parent corporation, but the others called for analysis on the level of individual companies.
— Rory D. Sweeney