The PJM Members Committee is set to vote on several proposals drafted by the RTO and stakeholders to determine how to allocate costs associated with generators required to remain online through the U.S. Department of Energy’s emergency orders under Federal Power Act Section 202(c). 

Package sponsors, RTO staff, the Independent Market Monitor and other stakeholders will meet with PJM’s Board of Managers just before the committee’s meeting June 18 as the final phase of an expedited Critical Issue Fast Path (CIFP) process initiated to determine how to raise the funds to compensate Constellation Energy for continuing to operate its 760-MW Eddystone Generating Station, which DOE ordered to remain online past its May 31 deactivation date through Aug. 28. 

Constellation and PJM agreed to use the deactivation avoidable cost credit (DACC) model used to compensate resources retained past their deactivation date on reliability-must-run agreements. The allocation methodology associated with the DACC, however, is designed for assigning costs to load in the region of the transmission violations leading to an RMR arrangement; PJM has said it is not suited to instances where the federal government mandates a generator remain online for resource adequacy. (See PJM Board Initiates CIFP Process for Eddystone Compensation.) 

PJM proposed to allocate the costs to all RTO load by dividing each market buyer’s share of the RTO-wide unforced capacity (UCAP) obligation and multiplying that figure by the credit to Constellation. A new line item would be added to billing statements to show the cost of 202(c) credits, with information also posted to PJM’s website. During the CIFP meeting June 12, PJM Senior Director of Market Settlements Lisa Morelli said the RTO had estimated the 90-day cost to load to be $34.72/MW of UCAP. 

Package D from the East Kentucky Power Cooperative would assign costs to all RTO native load and exports using actual megawatt-hour consumption per month unless the resource subject to the 202(c) order is within a zone that fell short of its capacity procurement obligation — in which case the costs would be allocated to that zone — or if the RTO cleared short of its obligation, in which case costs would be assigned to each locational deliverability area (LDA) according to their contribution to the shortfall. The charges would be calculated by adding a market buyer’s energy consumption and exports and dividing that sum by total monthly energy production, then multiplying that by the credit to Constellation. Resources exporting to external balancing authorities they have capacity obligations to would be excluded. 

The cooperative’s Package E would assign costs to each buyer according to the same formula regardless of how each zone cleared in the capacity market. 

Stakeholders were divided on whether the proposal should focus solely on compensating Constellation for operating Eddystone under the current emergency order or establishing rules for other resources subject to a 202(c) order. Morelli said establishing more lasting rules would carry the benefit of avoiding additional rushed CIFP processes if more resources are ordered to remain online. 

Two PJM packages would apply more broadly, though with differing criteria; Package A would apply to all DOE orders under Section 202(c) in which the resource owner opts to be compensated through models similar to the DACC, while Package C would limit that to orders issued within 180 days of PJM filing the cost allocation proposal. Morelli said establishing a time limit for the proposal would give time for stakeholders to continue discussions for a more holistic solution without the result of the CIFP becoming permanent. 

Package B from Gabel Associates and EKPC’s Package E would limit the changes to the Eddystone order expiring on Aug. 28. Package D from EKPC would apply to all units subject to a 202(c) order not subject to an RMR agreement and being compensated through models akin to the DACC. 

Proposals with a wider applicability also differed on how they would allocate costs if future DOE orders specified a region within PJM where localized resource adequacy concerns prompted the need to retain a generator beyond its desired deactivation date. PJM’s packages would assign the charges only to load in the LDAs or zones identified, while Gabel would continue to allocate them to all RTO load. 

Stakeholders opposed to a locational element to allocating costs argued that Eddystone is not being retained to serve a particular zone and future orders could retain generation for resource adequacy issues that have not yet manifested.