VALLEY FORGE, Pa. — PJM last week wrapped up the second phase of its Critical Issue Fast Path (CIFP) process to address resource adequacy concerns with two meetings about proposed changes to the RTO’s capacity market.
At May 30’s meeting, Constellation Energy proposed shifting to a prompt capacity auction held closer to the corresponding delivery year; the Consumer Advocates of the PJM States (CAPS) discussed states’ priorities and concerns around overhauling the Reliability Pricing Model (RPM); and American Municipal Power (AMP) presented changes to its conceptual design.
PJM also provided additional information about its contemplated switch to an expected unserved energy (EUE) model for measuring risk. (See PJM Presents Lessons Learned from Elliott, More CIFP Presentations.)
Thursday’s meeting saw presentations from the Natural Resources Defense Council on creating a seasonal capacity market; a former market design architect from ISO-NE providing information on a conceptual market design; Cornerstone Research’s Roy Shanker on his concerns about the current market structure; and Vistra on creating a credit market to value resource upgrades providing added reliability.
Stakeholders will begin developing formal packages during the third CIFP stage beginning June 14, when PJM will present its proposal.
Constellation Proposes Tighter Auction Schedule
Constellation’s Bill Berg said many of the inputs to the capacity auction could be more accurate and price signals could be improved if PJM holds capacity auctions six months to a year in advance of a delivery year. The status quo of holding auctions three years in advance makes it difficult to accurately forecast load and for generators to be sure whether they can procure firm fuel supply — a parameter PJM is considering having generators report prior to the auction.
Several stakeholders said the rationale for holding auctions three years in advance has been to allow the reference resource, currently a combined cycle generator, to be built between the auction clearing and the start of the delivery year to shore up capacity procurement shortfalls. Berg said investors monitor resource needs regardless of auction timing and are likely to make investments if they believe a region will be short on generation, regardless of auction timing.
Ryann Reagan, of the New Jersey Board of Public Utilities (BPU), questioned how a shortened time frame would interact with state retail auctions, noting that New Jersey has a three-year forward capacity product.
Berg responded that there’s a balance between price certainty and accuracy, which he believes is best weighed in favor of accuracy. Resources participating in state auctions with a longer lead time than a prompt auction would have to estimate PJM capacity prices when participating in state markets.
Constellation also suggested that compensating capacity resources at the end of the delivery year could improve performance incentives and lead to higher collections of any performance penalties the generator may accrue over the year.
While Berg said his company supports PJM’s proposal to set a minimum number of performance assessment intervals (PAIs) each year, market sellers must be able to reflect all risks and avoidable costs in their capacity offers.
CAPS Executive Director Greg Poulos said expanding the costs included in capacity market offers could run afoul of FERC’s 2021 order on PJM’s market seller offer cap (MSOC). (See Judges Skeptical of Capacity Sellers in PJM Offer Cap Dispute.)
“This seems like a dead-end to us because FERC already ruled on this,” Poulos said.
Berg also urged stakeholders to consider changes to the energy market, where he said PJM has put the onus of addressing reliability risks posed by forecast uncertainty and resource constraints, but it has had to resort to out-of-market actions to maintain operational reliability.
CAPS Outlines Advocate Concerns
As stakeholders discuss an overhaul of the capacity market, Poulos said state advocates are concerned about the Base Residual Auction (BRA) schedule, as well as how to ensure that market power is kept in check, performance incentivized and proper price signals are sent.
Advocates also lack firsthand insight into how the markets functioned during the December 2022 winter storm, also known as Elliott, making it difficult for them to evaluate proposals being discussed in the CIFP process, he said.
When considering changes to Capacity Performance (CP) penalties, Poulos said, it’s important to balance having penalties so high that generators risk bankruptcy after one event and having them so low that they don’t lead to better performance during future emergencies. Though performance was an issue during both the 2014 polar vortex and Elliott, he said CP likely did lead to increased readiness.
“The goal is not to bankrupt people — that is not helpful — but if you can’t perform, I don’t know what your value in this mix is,” Poulos said.
AMP Presents Revised Proposal
AMP revised the proposal it has been building throughout the CIFP process, which would replace the CP construct with a process for testing generators and penalizing them if they are not able to meet the amount of capacity they cleared. The changes aired May 30 would marry that concept with the proposed reworking of the performance penalty structure endorsed by the Members Committee last month but rejected by the PJM Board of Managers.
The revisions would shift the penalty rate and annual stop loss from being based on the net cost of new entry (CONE) to the BRA clearing price. AMP championed the language in the MC as a way of aligning market sellers’ capacity revenues with any penalties they’re assessed, while retaining an incentive to perform throughout the year.
Opponents of the language when it was before the MC argued that it would pose a reliability risk by cutting the penalty rate and stop loss by 90% without adding to requirements like winterization requirements.
PJM Presents Risk Modeling Analysis
PJM presented preliminary results of its analysis on the impact of switching to a reliability requirement based on an EUE model, which measures the amount of load that would go unmet during outages. The RTO currently uses a loss-of-load expectation (LOLE) model, which is a count of the number of outages expected. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)
In past CIFP discussions, PJM has proposed shifting the metric as part of its effort to improve risk modeling.
PJM’s analysis found that the EUE equivalent to the current one-day-in-10 reliability threshold would be around 1,800 MWh of lost load, with 96% of the outage risk concentrated in winter. Under the LOLE model, PJM estimates that 78% of the risk is in the winter, with the remainder being in summer.
PJM’s Patricio Rocha Garrido said winter outages tend to last longer and lead to more lost load, which he said is captured as increased winter risk through the EUE model.
The largest summer supply loss represented in the data was about 15 GW in July 2012, Rocha Garrido said, while 46 GW of generation was lost during Elliott.
James Wilson, a consultant to state consumer advocates, argued that the change would exaggerate risk and said that if being conservative in resource adequacy is a goal, that should be done through policy rather than modeling. He noted the analysis shown May 30 doesn’t account for climate change, which he said is likely to reduce the amount of risk in winter relative to summer by leading to warmer temperatures in both winter and summer.
Patrick Bruno, PJM | © RTO Insider LLC
PJM’s Pat Bruno said the RTO plans to continue improving the modeling, including by incorporating climate change into the data. He added that PJM had run sensitivities that found that climate change was unlikely to move the needle much for the type of modeling under discussion. Future analysis is also likely to include the impact on the installed reserve margin (IRM) and resource accreditation.
Bruno said the planning and market structures are currently based on an assumption that risk is concentrated in the summer, but the analysis suggests that a rethinking of those rules may be needed to maintain future reliability.
Vistra Presents Credit Market for Reliability Upgrades
During Thursday’s CIFP meeting, Vistra presented a proposal to create tradable credits to be awarded to generators that make investments to increase their performance, which would also raise their capacity accreditation.
Erik Heinle, Vistra’s director of PJM market policy, said that such investments may not lead to more capacity clearing in the BRA; however, it will increase a generator’s performance obligation, making it more likely to be subject to penalties and less likely to receive bonus payments.
The credits would be tradable in a PJM market and could be used by a buyer to excuse a performance shortfall equal to the increased capacity accreditation. PJM would create weekly risk assessments based on factors such as load and intermittent forecast variation, outages and fuel supply surveys, which buyers and sellers could use to determine their estimates of being subject to penalties.
Credits would only be awarded for facility upgrades on a list PJM would create during each quadrennial review.
Heinle said the proposal would add a financial product to allow generators to mitigate their non-performance risk, while still retaining an incentive to invest in upgrades.
Vitol’s Jason Barker said similar transactions exist today through bilateral transactions or within larger companies that maintain generation portfolios containing resources that can offset each other’s risks. Heinle said a PJM marketplace would increase transparency and improve price discovery.
Vistra’s Muhsin Abdur-Rahman said the proposal could also reduce the Capacity Performance quantified risk (CPQR) component of generators’ capacity offers to correspond with the reduced risk.
PJM Capacity Market Fuel Assurance Accreditation Concept
PJM’s Brian Fitzpatrick discussed a possible addition to the proposal being crafted by PJM that would create tiers of fuel security paired with the effective load-carrying capability (ELCC) model for each level. The proposal is currently focused on natural gas but would likely be expanded to other resource types as well.
Generators participating in the BRA would be required to indicate whether they will have dual fuel, single fuel with firm supply or single fuel without firm supply.
Fitzpatrick said the proposal is meant to help identify a lack of capacity on a gas pipeline or encourage greater fuel subscription to incentivize pipelines to expand, rather than creating another penalty structure for gas generators.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said fuel supply needs to be looked at holistically, incorporating issues being addressed by the Electric Gas Coordination Senior Task Force and examining other fuel types as well.
NRDC Proposes Seasonal Market
The NRDC presented a series of priorities it believes CIFP proposals must address around managing resources’ performance risk, including accurately accrediting resources and avoiding double-penalizing resource characteristics through CP and accreditation.
Tom Rutigliano, senior analyst for the NRDC, said accounting for resources’ characteristics through accreditation is the most effective option, rather than creating eligibility criteria for capacity resources, penalties or combining approaches. He supported PJM’s proposal to expand the use of the ELCC model to all resource types on the basis that it can weigh generators’ performance against the disparate risks the grid faces for each hour throughout the year.
Creating a system like ELCC to evaluate multiple gas generators fueled by a single pipeline to determine the marginal capacity value could also improve accreditation by revealing whether a pipeline is likely to be oversubscribed during an emergency, he said.
Though he said it would likely be topic to explore after the CIFP process, Rutigliano suggested moving to a seasonal capacity market to resolve some of the issues that expanding ELCC would not address, including variable transmission constraints, price signals incentivizing winterization investments, and treatment of planned and maintenance outages.
Rutigliano said that subjecting resources, particularly intermittent ones, to penalties for underperformance owing to characteristics already priced into their accreditation amounts to penalizing them twice. During Elliott, he said, wind and solar both performed as expected, but solar resources were generally assigned penalties, while wind resources receive bonuses based on attributes included in their ELCC analyses.
Shanker Highlights Concerns with Market Structures
Consultant Shanker presented a series of suggestions for stakeholders to consider throughout the CIFP process impacting all proposals, including:
- how the must-offer requirement relates to auction planning parameters and performance obligation during PAIs;
- how power exported from PJM during emergencies affects the balancing ratio;
- who is the beneficiary of export premiums if the capacity benefit of ties is removed;
- how many of these issues result in hidden future transmission charges; and
- how stochastic generation and common mode outages could cause locational impacts adverse to reliability.
The forecast pool requirement (FPR) and associated IRM are determined with the assumption that all resources holding capacity interconnection rights (CIRs) will offer into the capacity market; however, excepting intermittent resources from the must-offer requirement skews both parameters, Shanker said.
Shanker cited Independent Market Monitor studies showing that about half of such resources hold CIRs but have not been offering in auctions. Because the variable resource requirement (VRR) curve is derived from the FPR and IRM, this leads to overstatement of the reliability of the capacity procured through the BRA. He said the calculation of the capacity emergency transfer objective (CETO), capacity emergency transfer limit and locational deliverability areas’ reliability requirements cause the same issue. The issue also raises market power issues regarding holding CIRs but not using them, he contended.
Shanker also said that many market components, including the FPR, IRM and CETO, incorporate an infinite transmission assumption, which can also lead to overstated reliability by not taking location and intermittency into account, causing additional hidden transmission costs.
Shanker also called for eliminating the capacity benefit margin (CBM) and capacity benefit of ties (CBOT) when determining PJM’s reliability requirement in order to ensure the RTO can meet its own needs at a capacity price that matches the cost of resources required to reliably meet grid requirements. He noted that this should logically change the price of emergency assistance and that associated export revenues would flow to native load rather than into any potential penalty and bonus structures added to the current CP design.
Conceptual Capacity Market Exchange Presented
Dick Brooks of Reliable Energy Analytics presented how PJM could use an always-on capacity exchange (AOCE) with further development of the concept.
A former software architect of ISO-NE’s forward capacity market clearing engine, Brooks said the project was developed as a strawman design for the clean energy transition and was being brought before the CIFP to demonstrate that other paradigms are being created.
The market would use a shorter auction advance timeline with capacity prices determined using an exchange and clearing price similar to day-ahead energy markets. Capacity resources would be approved by the RTO and enter offers into the market to be bid on by customers.
The RTO would continue to determine the total amount of capacity needed for a location and time, which the RTO would issue its own reliability bids to meet needs in the short or long term. Bids exceeding the total amount of capacity needed wouldn’t be cleared to receive capacity payments.
