June 15, 2015
In an order issued late in the evening of June 9, 2015, the Federal Energy Regulatory Commission (“FERC”) largely approved PJM Interconnection, L.L.C.’s (“PJM”) December 12, 2014 Capacity Performance Proposal (“CPP”) to restructure its capacity market, the Reliability Pricing Model (“RPM”), over the dissent of FERC Chairman Norman Bay. PJM’s CPP was proposed in response to widespread generator outages in the January 2014 “Polar Vortex” and concerns that retirements of oil- and coal-fired generation and increasing reliance on natural-gas-fired generation might further reduce reliability in the future. FERC approved the CPP effective April 1, 2015, as requested by PJM, and in time for PJM to apply the new rules in its next Base Residual Auction (“BRA”) for the 2018/2019 Deliver Year. PJM will phase in these reforms over a three-year period, with full implementation in the 2020/2021 Delivery Year.
The central elements of the CPP are a new capacity product–the Capacity Performance Resource–and the adoption of an essentially “no excuses” performance requirement for generators and other Capacity Performance Resources to provide energy (or reduce load) during extreme weather events and other emergencies. Rather than adopting a “prescriptive” set of objective eligibility requirements (e.g., requiring generators to obtain firm gas supplies or weatherization requirements), PJM would largely enforce the heightened standards with the “stick” of large financial penalties for non-performance and the “carrot” of higher auction clearing prices designed to incentivize improved performance by existing resources and the construction of new, reliable generation to meet both load growth and replace retiring resources, supplemented by additional bonus payments to all resources that exceed their performance obligations during emergency periods.
Apart from improving reliability, PJM’s Capacity Performance reforms will likely have a number of significant market impacts. The CPP will likely increase capacity prices and revenues (by PJM’s estimates up to $4 billion per year). In addition, the likely increases in clearing prices for the BRA will improve the economics of nuclear generators, while the Non-Performance Charge may encourage the retirement of resources that cannot meet the new standards. The CPP may also incentivize intermittent renewable resources wishing to participate in the capacity market to pair their offers with storage and/or fossil-fueled generators in order to ensure that such renewable generators are able to fulfill their capacity obligations in emergency situations even when their fuel resource (e.g., wind or solar) is unavailable. In addition, the CPP’s encouragement of investments in existing resources and the development of new dispatchable and reliable generating resources will likely also spur investment in natural gas pipelines and related infrastructure.
FERC Chairman Norman Bay issued a dissent to FERC’s order based on his belief that the CPP “has a serious design flaw that undercuts the very aim that it seeks to achieve” and his concern that this flaw “may result in billions of additional costs for consumers without achieving its intended aim of [improving reliability].” According to Chairman Bay, PJM’s existing capacity market rules are working “tolerably well” and concerns regarding generator performance can be addressed by inexpensive fixes such as better preparation, winterization, or gas-electric coordination.
Chairman Bay claims that the CPP’s “incentive structure creates an opportunity for resources to profit from non-performance” due, in his view, to PJM’s overly generous estimate that there will be 30 Performance Assessment Hours in each year, rather than the most recent three-year historical average of 14 hours per year (or six hours per year if the 2014 Polar Vortex is excluded). Using this historical average, Mr. Bay calculated that a supplier that never performed during these Performance Assessment Hours could still theoretically receive positive capacity payments if the clearing price were to be higher than the Non-Performance Penalties.
We agree with Chairman Bay that the risk of the Non-Performance Penalty should begin to change bidding behavior, thus raising PJM’s capacity clearing prices in the future. And, while Chairman Bay’s proposed set of circumstances could potentially occur under the CPP structure, his assumptions assume that market participants will drastically change their bidding behavior such that BRA auction clearing prices will be substantially higher than what has historically occurred.
The results of the 2018/2019 BRA later this August will be telling as to whether Chairman Bay’s concerns have merit, and the June 9 Order does protect against such outcomes by requiring “PJM submit informational filings with FERC after the conclusion of each of the first five delivery years under PJM’s proposal . . . to evaluate the impact of this 30 hour assumption on resource performance during Performance Assessment Hours. . . .”
Chairman Bay also questioned whether the CPP’s costs were roughly commensurate with its benefits, characterizing it as a fix to “a several hundred million dollar uplift problem in the energy market with a multi-billion dollar redesign of the capacity market,” citing previous PJM estimates that CPP would run from $1.4 to $4.0 billion per year. Mr. Bay concluded that, “given the potential multi-billion dollar cost of the CPP and the burden consumers will be asked to bear, any analysis, no matter how rudimentary, would have been helpful before concluding this proposal is just and reasonable.”
Most tellingly, however, is Chairman Bay’s last two sentences, where he explains his disagreement with the CPP. Chairman Bay rightly observes that “[t]he reality is that once a market construct is accepted and implemented, it is very difficult to unwind” and that one of the biggest disappointments he sees with the CPP is “the opportunity cost of the time and resources that could have been used to develop a more sustainable, efficient, and cost-effective design.” What Chairman Bay seems to be implying is that the piecemeal fixes of the CPP are not enough, and a more holistic and comprehensive reform of these markets is needed.
PJM’s Capacity Performance reforms are anticipated to have profound effects on the economics and supply of capacity in PJM going forward.
The new Capacity Performance standards are expected to immediately result in higher BRA clearing prices in the upcoming 2018/2019 Delivery Year BRA, thus increasing capacity payments for generators that meet the Capacity Performance standards. The magnitude of the revenue increase will not be known until the next BRA is run in August. Likewise, it may take some time for the amount of offsetting benefits in the form of increased reliability and lower energy market prices to be fully known.
One significant variable in the equation is the standard for qualifying as a Capacity Performance Resource. As it often does, PJM has left the standard flexible, and it has resisted attempts to provide objective qualification standards. Because the standard is flexible, the costs for generators to meet the new standard are not entirely clear and will largely depend on how PJM interprets and applies its standard. Like other flexible tariff standards, the specific requirements will likely evolve as PJM and capacity suppliers gain experience with the new construct. However, that same flexibility could allow PJM to determine how much and what types of resources qualify as a Capacity Performance Resource, which could affect capacity market prices. A stricter interpretation of the Capacity Performance Resource standard may reduce supply and increase prices, while a more loose interpretation could increase supply and decrease prices.
One significant winner from the CPP is expected to be nuclear power, which has on-site fuel and runs around-the-clock (except, of course, during refueling, maintenance, and relatively rare, unplanned outages). Nuclear power plants thus will likely all qualify as Capacity Performance Resources and receive higher capacity revenues and Bonus Performance Payments without needing to make any incremental investments. Similarly, baseload coal generators that can economically winterize their fuel delivery systems should also benefit from the CPP reforms (assuming they continue to operate in the future, given the potential compliance obligations under EPA’s proposed Clean Power Plan).
The need to firm up natural gas fuel supplies to meet the CPP standards, and avoid steep Non-Performance Charges, should also spur investments in natural gas pipeline and storage infrastructure to provide firm gas supplies to natural-gas-fired generation. It may also spur further production of shale gas in and around the PJM footprint as a way to increase the likelihood of delivery to generating facilities in the region.
The new CPP requirements also provide significant new opportunities for intermittent renewable resources like wind and solar to capitalize on capacity payments and, especially, Bonus Performance Payments, by allowing renewable generation owners to pool their resources together, which will provide a hedge against failure to perform. And if intermittent resources perform above their expected output, such as occurred during the 2014 Polar Vortex when many wind facilities over-performed, these resources now stand to capture significant bonus payments. Moreover, the new aggregation option allows renewable resource owners to aggregate with other renewable resource types (e.g., wind and solar) in different locations, as well as with energy storage resources or fossil-fuel generators, as a way to further hedge risk. These changes should increase system reliability and the economics of renewable resources.
Generators that are not able to economically upgrade to meet the Capacity Performance Resource standards will ultimately be forced out of the PJM capacity market by the 2020/2021 Delivery Year. Such resources will no longer be able to earn capacity revenues from PJM. The resulting economic impact may force some generation into early retirement (at least to the extent that they depend on capacity revenues), or they may look to sell into nearby markets that do not have such stringent performance requirements.
Another likely result of the CPP changes is additional disputes, complaints, and litigation. PJM’s decision not to adopt “prescriptive” or objective eligibility requirements (e.g., requiring generators to obtain firm fuel supplies), gives PJM a great deal of discretion in applying its standards. In addition, the dramatic increase in non-performance penalties may result in disputes over what constitutes non-performance and force majeure. And if the CPP results, as expected, in higher capacity clearing prices, there may be a wave of complaints from load-serving entities and their stakeholders demanding reforms, including demands that penalty payments be distributed to load, rather than to over-performing generators.
Finally, Chairman Bay’s dissent sends several messages. First, it seems that FERC’s June 9 Order will not be the last we have heard on PJM’s capacity markets. Moreover, FERC will be keeping a close eye on the implementation and results of the CPP. Second, Chairman Bay’s focus on the lack of a cost-benefit analysis to support PJM’s proposal may signal a renewed interest at FERC to use cost-benefit analyses as a tool for evaluating regulatory matters. While the cost-benefit tool has some appeal on its face, it also opens up the potential to dive into fact-intensive disputes to address regulatory policy matters, which will provide fertile ground for an increase in FERC hearings and litigation.
 See PJM Interconnection, L.L.C., 151 FERC ¶ 61,208 (2015) (“June 9 Order“). As used herein, the term CPP means the PJM proposal, as ultimately accepted and modified by FERC in the June 9 Order. Unless otherwise specified, capitalized terms used herein shall have the meaning assigned to them in the CPP or in the PJM Open Access Transmission Tariff.
 PJM and FERC emphasized that generator forced outage rates during the 2014 Polar Vortex increased from an annual average of approximately 7% to 22% (and up to 40% for natural-gas-fired units). Further, PJM stated that approximately 26,000 MW of coal- and oil-fired units had retired or would retire by 2019, while over 80% of new generation in the interconnection queue is natural gas generation.
 Chairman Bay Dissent at 1.
 Id. at 4.
 June 9 Order at P 13.
 Bay Dissent at 6.
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