VALLEY FORGE, Pa. — Stakeholders last week continued to refine proposals to overhaul PJM’s capacity market through the second phase of the RTO’s Critical Issue Fast Path (CIFP) process.
The first stage two meeting on April 19 featured presentations from American Municipal Power (AMP), the Independent Market Monitor and a joint proposal from the East Kentucky Power Cooperative and Daymark Energy Advisors.
A second meeting on April 26 included presentations from MN8 Energy and the Capacity Coalition, a group of five generation companies collaborating to create a combined package. Vistra and Autumn Lane Energy were also scheduled to present on the that day but had to postpone until May 17 because of time constraints.
The proposals aim to address several issues highlighted by the PJM Board of Managers when it initiated the CIFP process in February, including evaluating whether the Capacity Performance (CP) construct is adequately incentivizing resources to meet their obligations and creating stronger winter or seasonal requirements for accreditation and fuel security standards.
The second phase of the process involves forming proposals, which will be finalized in the third stage and voted on by the Members Committee in August. PJM’s Dave Anders reiterated that there is not a hard line between the second and third phase, and proposals can continue to be created and modified at any point.
EKPC and Daymark Propose Two Types of Capacity
The proposal from EKPC and Daymark would create base and emergency capacity variants, with the latter being designed to address extreme weather conditions. Emergency capacity would also be required to have firm fuel or the technical equivalent to it, be available to commit within two hours’ notice and demonstrate the ability to financially withstand any non-performance penalties should it not operate.
“Should they fail to perform and thus not be paid as a consequence of that nonperformance and it could have a substantial impact, the next step should not be that they leave the market because that would be problematic,” Daymark’s Marc Montalvo said.
The base capacity would be focused on addressing systemic conditions and wouldn’t include winterization requirements above those already mandated by NERC. However, the PJM proposal would require all capacity resources to winterize to a higher standard or not receive any revenues for those months.
Adrien Ford of Old Dominion Electric Cooperative said multiple connections to gas pipelines may not be useful as a firm fuel qualification, given that in some locations a single pipeline connection can be more reliable than multiple pipelines in another location.
AMP Seeks Subannual Accreditation
AMP presented a proposal that would create sub-annual accreditation and replace capacity performance, which penalizes and rewards generators depending on whether they meet their obligations during emergencies. Under the concept, all capacity resources would be required to participate in sub-annual auctions, which would clear after the annual Base Residual Auctions (BRAs). Auctions would also be held closer to the delivery year, a shorter time frame than the current three-year advance schedule, reflecting market participants’ experience with auction delays leading to compressed timelines.
“The idea would be that we don’t do away with annual [accreditation] outright. … We firmly believe that the majority of the capacity that clears should be annual, but recognize that monthly or seasonal has value,” AMP’s Steve Lieberman said. The specifics of how granular sub-annual could go would depend on stakeholder feedback in the coming months, he said.
The proposal would replace CP with a regular testing requirement consisting of a penalty and reward structure based on testing performance. The incentives would be based on capacity market revenues and operate on a “pay as you go” basis.
Independent Market Monitor Adds Detail to Proposal
Monitor Joe Bowring provided additional detail on the proposal he unveiled during the first-phase CIFP meetings. The proposal would seek to identify the energy needs for each hour of a delivery year and provide capacity revenues that cover the avoidable costs for generators meeting that need. Capacity would be paid based on annual auction clearing, hourly supply and demand and an annual avoidable-cost rate (ACR).
The Monitor’s plan would base accreditation on a unit’s installed capacity (ICAP) multiplied by its modified availability factor (MAF), an attribute which aims to provide a methodology to capture the availability of all resource types by incorporating forced outage rates, maintenance outages and intermittent resource availability. Bowring said availability would be a stronger measure than PJM’s current effective load-carrying capability (ELCC) measure.
All resources holding capacity interconnection rights (CIRs) would be subject to a must-offer requirement for that capacity and weekly generator testing. Capacity resources would also be required to possess firm fuel or the technical equivalent. For intermittent resources, that would mean being obliged to perform at their full possible output when called upon. Winter Storm Elliott last December showed, however, that firm fuel is not a guarantee of the ability to perform when called upon.
Weekly testing may be considered an “extreme position” for many stakeholders, Bowring said, but he argued that regular testing throughout the year, not just during the summer, recognizes that resources need to be able to perform any time of year.
“If there had been adequate testing, we would not have had either the polar vortex or Winter Storm Elliott” challenges, he said.
Casey Roberts, with the Sierra Club, questioned whether the Monitor’s proposal would consider gas generators to be available if they did not nominate for fuel ahead of potential emergency conditions. Bowring responded the proposal doesn’t currently address that, but it is something all proposals will have to weigh.
Capacity Coalition Presents Short- and Long-term Proposals
Emma Nix of Leeward Renewable Energy and John Horstmann of AES presented a Capacity Coalition proposal that aims to introduce short-term changes to the capacity market through the CIFP process, while putting long-term changes on the table.
The short-term changes include retaining the status quo of exempting renewable resources from the capacity market must-offer requirement, developing transparent and coherent triggers for a Performance Assessment Intervals (PAI), increasing market seller’s flexibility in reflecting their risk in their market seller offer caps (MSOCs), and changing how thermal resources are accredited to reflect expectations of how they would operate through weather and historical performance.
The proposal says that, in the short term, the status quo must-offer exemptions for intermittent and limited-duration resources should remain in place given that capacity is an annual product that commits those resources around-the-clock at times they may not reasonably be expected to be provide capacity. Renewable and storage resources need the exemption so they can adjust their capacity offers based on their individual risk tolerance for Capacity Performance penalties should a PAI be called when the resource is not online, Nix said. Implementation of the seasonal proposal in the long-term would negate the need to maintain the must-offer exception in the short term.
The proposal would also only allow generators to be penalized when there has been advance notice of a PAI, when PJM is not exporting to non-firm load commitments in other regions and when the RTO does not have adequate system reserves. It would limit the bonuses derived from the penalties to only be payable to resources that participate in the capacity market. They are currently paid to any generator that performs above expectations.
PJM’s Becky Carroll said the RTO’s proposal to eliminate the pre-emergency demand response as a PAI trigger could effectively allow DR deployments to serve as advance notice for the potential for generators to be subject to penalties, though she added that there could be PAIs that don’t follow a pre-emergency DR call.
Horstmann said there’s an open question as to what obligations a capacity resource committed in PJM might have to serve load in other regions during an emergency. The coalition proposal seeks to define that as being an obligation to serve PJM’s load.
The proposal also calls for the creation of Capacity Performance quantified risk (CPQR) values for resource classes, to reduce the administrative burden in the unit-specific MSOC process while still allowing companies to reflect their risk across their portfolio.
The long-term side of the proposal calls for a transition from a single annual price to a seasonal capacity model consisting of 12 monthly intervals and four daily intervals by 2030.
The seasonal proposal would align accreditation and offers with how resources are capable of performing during specific times of day. Most important, the RPM auction would set the price for each interval allowing market forces to appropriately establish prices based on PJM system supply and demand needs to incentivize new capacity entry, particularly during times of system need. The coalition includes Leeward, AES, Pine Gate Renewables, Ørsted and Cypress Creek Renewables.
MN8 Energy Suggests ‘Pay as You Go’ Model
A proposal from MN8 Energy aims to build on PJM’s proposed accreditation and risk modeling — namely, capturing a larger breadth of factors affecting generator operation, such as temperature impacts and lead time — while proposing a “pay as you go” model for performance assessment, a seasonal capacity market and additional inputs to CPQR.
MN8’s presentation said PJM’s two-tiered PAI system risks including hours that are not relevant to maintaining reliability and could incentivize some resources in a discriminatory fashion. The PJM proposal would have a minimum of 30 assessment hours for each delivery year, with generators’ performance being assessed in the tightest hours if there are not 30 emergency hours in a delivery year.
The proposal would instead use a pay-as-you-go design for performance assessment where a performance factor would be determined for each generator at the end of a delivery year to calculate compensation. Those resources that underperform would collect a portion of revenues cleared in the BRA, while overperformers would receive all their cleared revenues plus a portion of uncollected revenues as a bonus.
Should the capacity market continue to carry a significant risk of penalties, the MN8 proposal suggests that CPQR should consider opportunity costs, expectations of penalties and bonuses, and the costs to manage risk.
