FERC’s Proposed Restructuring of PJM’s Capacity Market Could Cut Capacity Revenues for Both Subsidized and Unsubsidized Generators

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Eric Selmon Hugh Wynne

Office: +1-646-843-7200 Office: +1-917-999-8556

Email: eselmon@ssrllc.com Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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July 16, 2018

FERC’s Proposed Restructuring of PJM’s Capacity Market

Could Cut Capacity Revenues for Both Subsidized and Unsubsidized Generators

FERC’s decision of June 29th found PJM’s existing tariff to be unjust and unreasonable, and consequently proposed a material restructuring of PJM’s capacity market. Without significant care in designing these changes, however, FERC’s proposed modifications to PJM’s tariff could lower capacity prices, both for state-subsidized resources exiting the capacity market and the resources that remain. In addition, the short time frame to develop the new tariff – FERC’s goal is to issue its final order no later than January 4, 2019, in time for PJM to conduct its 2022/2023 capacity auction as scheduled in May of next year – is likely unrealistic and could result in a delay to next year’s auction. Finally, the breadth of issues to be addressed in the proceeding materially augments the uncertainty facing generators and load serving entities, raises the risk of unforeseen consequences and will likely put PJM’s tariff at risk of continued legal challenges.

  • FERC’s decision of June 29th found PJM’s existing tariff to be unjust and unreasonable and instituted an accelerated proceeding in the form of a paper hearing to consider a radical restructuring of PJM’s capacity market. FERC’s goal is to issue its final order in the hearing by January 4, 2019, in time for PJM to conduct its 2022/2023 capacity auction as scheduled next May.
  • Rather than make a final determination as to a replacement for PJM’s tariff, FERC suggests modifying two aspects of the PJM tariff:
    • First, FERC proposes that PJM’s Minimum Offer Price Rule (MOPR) be modified to include all resources, both new and existing and regardless of type, that received out-of-market support.
    • Second, FERC recognizes that under the new MOPR uneconomic resources receiving out-of-market revenues may be forced to offer capacity prices so high that they do not clear the auction. To allow these resources to stay on the system, and avoid double payment for capacity resources by retail ratepayers, FERC proposes a resource-specific Fixed Resource Requirement (FRR) Alternative, where such resources could withdraw from the capacity auction for a period of time, taking with them a commensurate amount of load.
  • We expect FERC’s proposed changes to PJM’s tariff to lower capacity prices, both for state-subsidized resources exiting PJM’s capacity market and for the resources that remain.
  • Compared to the status quo, where state-subsidized resources may offer their capacity into the PJM auction below full cost, thereby clearing the auction and securing the clearing price, the FRR alternative would likely result in a materially lower price for state-subsidized capacity.
    • States will likely be required to pass new legislation or regulations establishing new sources of revenue for state-subsidized resources to replace the PJM capacity payments currently received by these resources. If the current combination of state subsidies and PJM capacity revenues generates a return in excess of the minimum return required by the generation resource owner to keep the resource online, then a regulated capacity contract designed to ensure the minimum return is achieved under the FRR alternative is likely to result in lower total revenues for the resource than the status quo.
  • Moreover, the exit of state-subsidized resources from the capacity market under the FRR alternative could also materially reduce the auction clearing price for the capacity that remains. The price impact depends critically upon how much load the exiting capacity takes with it.
    • Under the terms of PJM’s current FRR alternative we estimate that the exit of 5,000 MW of state-subsidized nuclear generation via the FRR would have reduced the clearing price of last May’s 2021/2022 capacity auction by ~$7/MW-day or 5.0%.
  • However, one group of resources that could materially benefit from the resource specific FRR proposal is wind, solar and storage, which, if pooled together as a portfolio under the FRR, would likely qualify for a higher capacity value than any of these resources would individually in the PJM capacity market.
  • Predicting the impact of the proposed reform is complicated by the myriad unresolved structural issues that remain to be addressed. The most important of these issues is the scope of out-of-market support to be mitigated by the new market design.
    • As can be seen in Exhibit 1, the larger the scale of the resources to be mitigated, and thus permitted to exit the PJM capacity auction under the FRR alternative, the larger the potential impact on the clearing price for capacity.
  • Finally, the many issues to be addressed in designing the new capacity market construct, and the many parties whose interests are affected, may prevent FERC from issuing its final order by its January 4th deadline and, thus, may force the delay of next May’s 2022/2023 capacity auction. Even if this is not the case, dissatisfaction with FERC’s decision among the affected parties will likely give rise to numerous legal challenges, creating material uncertainty as to the validity of the auction results.
  • Most exposed to this uncertainty, and the potential for lower capacity prices, are NRG, VST and, to a lesser extent, EXC and PEG.

Details

  • FERC’s decision of June 29th found PJM’s existing tariff to be unjust and unreasonable and instituted an accelerated proceeding in the form of a paper hearing to consider a radical restructuring of PJM’s capacity market. FERC’s goal is to issue an order in the hearing by January 4, 2019, in time for PJM to conduct its 2022/2023 capacity auction as scheduled next May.
    • FERC found that PJM’s existing tariff “fails to protect the integrity of competition in the wholesale capacity market against unreasonable price distortions caused by…out-of-market support to keep existing uneconomic resources in operation.”
    • FERC notes that Zero Emissions Credits (ZECs) and Renewable Energy Credits (RECs) provide nuclear and renewable resources, respectively, with out-of-market revenues of $250 to $265/MW-day, well in excess of the $140/MW-day clearing price set last May in PJM’s 2021/2022 capacity auction. These resources can therefore offer their capacity in the PJM auction at prices well below their total cost, clear the auction and cause an equal amount of unsubsidized, higher cost capacity not to clear. The result is to suppress capacity prices.
    • FERC and PJM agree that the scale of state-subsidized resources is now so large that the issue can no longer be ignored. Approximately 5 GW of nuclear capacity in Illinois and New Jersey now benefits from ZECs, equivalent to 3% of the capacity cleared in PJM’s 2021/2022 auction.
  • Rather than make a final determination as to a replacement for PJM’s tariff, FERC suggests that modifying two aspects of the PJM tariff may produce a just and reasonable rate:
    • First, FERC proposes that PJM’s Minimum Offer Price Rule (MOPR) be modified to include both all resources, both new and existing and regardless of type, that receive out-of-market support. The purpose of this change is to ensure that all generation resources are offered into the capacity auction at their true cost, excluding the benefit of out-of-market revenues. The capacity supply curve would thus properly reflect the full, going forward cost of maintaining existing power plants in service.
    • Second, FERC recognizes that under the new MOPR, uneconomic resources receiving out-of-market revenues may be forced to offer at capacity prices so high that they do not clear the auction. To allow these resources to stay on the system, without requiring retail ratepayers to pay twice for capacity, FERC proposes a resource-specific Fixed Resource Requirement (FRR) Alternative, where state-subsidized resources could withdraw from the capacity auction for a period of time, taking with them a commensurate amount of load.
  • The current PJM tariff includes an FRR alternative that allows investor owned utilities, electric cooperatives and public power entities to satisfy their capacity requirements through direct ownership of, or bilateral contracts with, generation resources, provided these resources are sufficient to meet the capacity obligation of the load serving entity (LSE) for its entire service area.
    • Having satisfied these conditions, the LSE is under no obligation to participate in PJM’s annual capacity auction. However, the capacity resources committed under an FRR must meet all the requirements of the PJM Tariff, including those relating to capacity performance.
  • FERC apparently wishes to explore a modification of PJM’s tariff that would allow LSEs to procure capacity for a portionof their load under contract with a resource receiving out-of-market payments, allowing the resource and that portion of the LSE’s load to be withdrawn from the capacity market.
    • To ensure that such bilateral agreements produce sufficient revenue to allow the generation resource to remain in service, states may choose to subject such contracts to rate regulation on a cost of service basis. As a result, states may allow such contracts to recover only the difference between (i) the full, going forward cost of maintaining an existing power plant in service and (ii) the out-of-market revenues received by this resource in the form of ZECs or RECs.
  • We expect FERC’s proposed changes to PJM’s tariff to lower capacity prices, both for state-subsidized resources exiting PJM’s capacity market and for the resources that remain.
  • Compared to the status quo, where state-subsidized resources may offer their capacity into the auction well below full cost, and thus clear the auction and secure the clearing price, the FRR alternative would likely result in a materially lower price for capacity.
    • First, no LSE would freely contract with a state-subsidized resource outside of the capacity market unless the LSE were offered a price below that available in the capacity market. Moreover, where there is active competition among state-subsidized resources for FRR capacity contracts with LSEs, this competition should cause the capacity price to reflect the full, going forward cost of such resources less any out-of-market revenues received.
    • Second, were state regulators to mandate LSEs to contract with state-subsidized resources, these contracts will likely be subject to rate regulation on a cost of service basis. If the current combination of state subsidies and PJM capacity revenues generates a return in excess of the minimum required by the generation resource owner to keep the resource online, then a regulated capacity contract designed to ensure the minimum return is achieved under the FRR alternative is likely to result in lower total revenues for the resource than the status quo.
  • Ironically, the ability of state-subsidized resources to exit the capacity market under the FRR alternative could materially reduce the auction clearing price for the capacity that remains. The price impact depends critically upon how much load the exiting capacity takes with it.
    • Based upon the planning parameters and historical results of the 2021/2022 PJM capacity auction, we have modeled the impact on the clearing price of that auction of the exit via the FRR alternative of different amounts of state-subsidized capacity. Initially, we have assumed that the amount of load that could exit with such capacity would be equivalent to the installed capacity (ICAP) of the exiting resources, reduced by PJM’s target reserve margin of 15.8%.
    • Were all 5.0 GW of state-subsidized nuclear capacity to exit PJM’s capacity auction via the FRR alternative, we calculate that 4.7 GW of unforced capacity (UCAP, or installed capacity less the RTO forced outage rate of 5.9%) would be withdrawn from the capacity supply curve, equivalent to 2.9% of all the capacity that cleared the 2021/2022 auction.
    • By contrast, assuming PJM’s target reserve margin of 15.8%, only 4.3 GW of load could exit PJM’s capacity market with the departing resource, equivalent to 3.1% of the peak load for which capacity was procured in the 2021/2022 auction.
    • Reflecting the larger percentage reduction in load, or the demand for capacity (3.1%), relative to the percentage reduction in the supply of capacity (2.9%), the effect is to reduce the clearing price for capacity. Whereas the 2021/2022 auction cleared at $140/MW-day, our simulation of the withdrawal of 5.0 GW of state-subsidized capacity and only 4.3 of load results in an estimated clearing price of $133/MW-day, a reduction of 5.0%.
    • PJM could engineer a different result were it to assign a higher target reserve margin to the load exiting its capacity market. For example, by applying a target reserve margin of 24.6% (equivalent to the reserve margin at which PJM’s demand curve for capacity produces a price of zero), the load that would be removed from the PJM capacity with the exit of 5.0 GW of state-subsidized nuclear generation could be reduced from 4.3 to 4.0 GW, or from 3.1% to 2.9% of estimated peak demand in 2021/2022. In this scenario, the percentage reduction in the supply of capacity (2.88%) is slightly larger than the percentage reduction in load (2.86%), causing our estimate of the PJM clearing price to rise to $144/MW-day, as compared with the price of $140/MW-day at which the 2021/2022 capacity auction actually cleared. (See Exhibit 1.)

Exhibit 1: Estimated Clearing Price of the 2021/2022 PJM Capacity Auction Had State-Subsidized Capacity Been Allowed to Exit Under an FRR Alternative ($/MW-day)

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Source: PJM Interconnection, SSR estimates and analysis

  • FERC’s proposed FRR alternative for state-subsidized resources thus raises doubts as to whether its effect will be to raise or lower the clearing price for capacity in the PJM market, with the default option of using the same parameters as the current FRR resulting in lower clearing prices.
  • One group of resources that could potentially benefit from a resource specific FRR is wind, solar and storage.Each of these resources individually has difficulty meeting PJM’s capacity performance standards. When they bid into the capacity market, therefore, these resources do so at a small fraction of their nameplate capacity. However, by pooling a combination of these resources into a portfolio of state-subsidized resources, they could qualify for a higher capacity value than any of these resources would individually, due to the complementarity of their generation profiles. Wind, solar and storage resources could thus combine to offer capacity to LSEs under the FRR alternative, securing contracted capacity revenues and improving their economics.
  • Predicting the impact of the proposed reform is complicated by the myriad other structural issues that remain to be addressed. The most important of these issues is the scope of out-of-market support to be mitigated by the new market design. As can be seen in Exhibit 1, the larger the scale of the resources to be mitigated, and thus permitted to exit the PJM capacity auction by the FRR alternative, the larger the potential impact on the clearing price for capacity.
    • Commissioner Glick’s dissenting opinion is of interest in this respect, in that it offers a checklist of challenges to the concept that only nuclear and renewable resources receiving ZECs and RECs should be subject to the expanded MOPR. Glick argues that regulated utilities and fossil fuel power plants also benefit from out-of-market subsidies and consequently should be subject to the MOPR and permitted to exit the PJM capacity market under the FRR alternative. To the extent Glick’s arguments[1] are advanced successfully by generators seeking to penalize their competitors, the scale of the resources exiting under the FRR alternative could increase, aggravating the impact on prices (see Exhibit 1).
  • A further risk relates to the quality of the capacity resources offered under the FRR alternative. The larger the scale of the resources subject to FERC’s proposed new MOPR, and thus eligible for exit from PJM’s capacity market via the FRR alternative, the greater the probability that, in regulating the sale of this capacity to LSEs, states will seek to impose standards of performance that differ from PJM’s and may be less demanding with respect to the quality and deliverability of capacity committed.
    • In its June 29th order, FERC specifically seeks comment on “the best approach to ensure that locational resource adequacy needs are met after removing load and resources from the capacity market under the FRR Alternative”; “whether the existing Capacity Performance construct for FRR resources can be applied to a resource-specific FRR Alternative”; and how the proposed “reforms will interact with PJM’s ongoing fuel security initiative.”
  • Finally, the many issues to be addressed in designing the new capacity market construct, and the many parties whose interests are affected, may prevent FERC from its issuing its final order by its January 4th deadline and thus may force the delay of next May’s 2022/2023 capacity auction. Even if this is not the case, dissatisfaction with FERC’s decision by the affected parties will likely give rise to numerous legal challenges, creating material uncertainty as to the validity of the auction results. Among the issues to be resolved are the following:
    • Given the plethora of federal and state subsidies for fossil, nuclear and renewable resources, will PJM face a wave legal challenges to the design of its expanded MOPR?
    • How is load to be matched with state-subsidized resources in the FRR alternative, and by whom?
    • Could a resource specific FRR give rise to market power concerns within a Location Deliverability Area (e.g., in the case of Exelon’s Quad Cities and Dresden nuclear plants in Illinois, with a combined capacity of 3.6 GW).
    • With PJM’s next capacity auction only ten months away, will states have the time to regulate the supply of capacity from state-subsidized resources to LSEs outside PJM’s capacity market?
    • If these issues cannot be addressed in a timely manner, will FERC, having found PJM’s tariff to be unjust and unreasonable, be forced to allow PJM to postpone its May capacity auction?
  • Most exposed to this uncertainty, and the potential for lower capacity prices, are NRG Energy (NRG), Vistra Energy (VST) and, to a lesser extent, Exelon (EXC) and Public Service Enterprise Group (PEG).

Exhibit 2: Heat Map: Preferences Among Utilities, IPP and Clean Technology

Source: SSR analysis

©2018, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

  1. In his dissenting opinion, Commissioner Glick argues that it is not only nuclear and renewable resources that benefit from out-of-market support, but regulated utilities and fossil fuel power plants as well. He points out that coal and gas fired plants benefit from federal tax incentives for the exploration and production of fossil fuels, as well as state tax credits for coal mining in West Virginia. In Pennsylvania, utilities producing electricity at coal or gas fired plants enjoy exemptions from sales, gross receipts and real estate taxes. Glick also points out that ~20% of PJM’s installed capacity is owned by vertically integrated utilities that are guaranteed recovery of the cost their resources, allowing these utilities to offer their capacity at prices well below the full economic cost of these assets. Finally, Glick argues that if the expanded MOPR targets out-of-market ZEC and REC revenues awarded nuclear and renewable generators for their environmental benefits, it would be logical for the MOPR also to adjust for the environmental costs imposed, but not paid for, by coal fired power plants. Some of these arguments may be taken up by capacity market participants seeking to force competitors to offer their capacity at higher cost and possibly prevent them from clearing the capacity auction. 
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