On Sept. 29, 2017, the U.S. Department of Energy (DOE) submitted a Proposed Rule on Grid Reliability and Resilience Pricing (Proposed Rule) to the Federal Energy Regulatory Commission (FERC), proposing that FERC use its authority under Sections 205 and 206 of the Federal Power Act to issue new regulations assuring certain coal and nuclear power plants’ recovery of their full cost of providing service, including a fair return on equity. Eligibility for the proposed revenue guarantee was to be limited to “fuel secure” plants that have a 90-day supply of fuel on-site and are located in the footprint of a Regional Transmission Operator (RTO) or Independent System Operation (ISO) that administers a forward capacity market. While that initiative has stalled, at least for now, with FERC having declined to go forward with the Proposed Rule, the commission is undertaking a broader, holistic examination of the resiliency issue to determine the appropriate course of action. Those expecting FERC to throw a life preserver to struggling coal and nuclear power plants en masse had best not hold their breath.

Few would dispute the importance of the nation having a resilient bulk power system. However, opinions differ widely on what “resilience” means, how much different levels of resilience are worth, what measures would best help achieve a desirable level of resilience, and whether any new regulatory measures are even necessary. There are no simple answers to these questions, and each region is different. Increasing reliance on intermittent variable energy resources, principally wind and solar, and a number of other factors, have posed numerous challenges to ensuring the reliability of the bulk power system, and the FERC and the nation’s RTOs and ISOs are nowhere near resolving all of them. Addressing very important resiliency concerns, without doing more harm than good, will require great care and a balancing of many conflicting interests.

Concerns about the impact of power plant retirements on the reliability, as opposed to resiliency of the bulk power system, are nothing new. RTO and ISO forward capacity markets were established to ensure the adequacy of capacity to reliably meet load, and FERC has long approved of capacity market rule changes designed to advance that objective while ensuring just and reasonable rates. In recent years, ISO New England and PJM have received FERC approval for reforms to their capacity markets to improve the performance of capacity resources and address fuel supply issues that arise during periods of system stress.

Additionally, RTOs and ISOs have long been authorized by FERC to enter into reliability-must-run (RMR) agreements and similar contracts requiring plants to keep operating for a specified period of time beyond the date on which they otherwise would have retired in return for guaranteed recovery of the plant’s “going forward costs,” i.e., its costs of continued operation with no return on equity. For example, the Midcontinent Independent System Operator (MISO) has the power to impose System Support Resource agreements on generators that plan to retire, but that MISO determines are needed to maintain system reliability. PJM’s RMR tariff procedures allow generation resources to either elect a “going forward” compensation system or file a rate case. Most recently, ISO New England announced plans to seek FERC authorization to block Exelon Generation from retiring its 1,998 MW Mystic power plant in Charlestown, MA, on grounds that it is needed for reliability.

Are the capacity markets, as currently administered, and the ability of RTOs and ISOs to forestall closures on a case-by-case basis, sufficient to maintain a desirable level of resilience going forward? A flood of low-cost shale gas from the combination of hydraulic fracturing and horizontal drilling has led to a surge in combined-cycle gas turbine plant development, which, coupled with state policies subsidizing nontraditional resources, and most recently, certain nuclear plants, has placed coal and other nuclear baseload generation units on life support. At this time, ISO New England reports that 4,600 MW, or about 16 percent of the region’s non-gas-generating capacity, will have retired by 2021, and another 5,000 MW of coal-and oil-fired generation is at risk for retirement in coming years. PJM reports that it has received owner requests for the deactivation of 13,300 MW of capacity by 2021.

DOE’s Proposed Rule sought to stem the wave of retirements by offering guaranteed profitability to plants with 90 days of fuel supply on grounds that such plants are needed to ensure resiliency. DOE pointed to resiliency problems exposed by the 2014 polar vortex and a growing recognition that the organized markets fail to compensate resources for all the attributes they contribute to the grid, including resilience.

FERC responded to the DOE Notice of Proposed Rulemaking by promptly establishing a rulemaking proceeding to consider the Proposed Rule and soliciting comments and information from interested parties. After reviewing the numerous comments received, FERC issued a decision on Jan. 8, 2018, terminating the rulemaking proceeding and initiating an administrative proceeding instead in which FERC will examine the issue of resilience in RTO and ISO markets holistically. The FERC-stated goals for this proceeding are to 1) develop a common understanding among the FERC industry and others of what resilience means and requires; 2) understand how each RTO and ISO assesses resilience; and 3) use this information to evaluate whether actions are needed. To that end, FERC posed a series of questions to the RTOs and ISOs and required them to submit responses by March 9, 2018.

The RTO and ISO responses reveal the complexity of these issues and provide little indication that any are prepared to move forward with major reforms in the near term. Alone among the organized markets, ISO New England acknowledged significant resilience concerns, reporting that energy shortfalls due to inadequate fuel supply would occur with almost every fuel-mix scenario, beginning in the winter of 2024-25. However, ISO New England also indicated that this gap could be filled by increased levels of imports, liquefied natural gas and renewables. PJM called on FERC to direct all RTOs, ISOs and jurisdictional transmission providers in non-RTO regions to propose market reforms and related compensation mechanisms to address resilience concerns within nine to 12 months of the issuance of a final FERC order. Reply comments of other interested parties in response to the RTO and ISO filings are due on May 9, 2018.

As both FERC and each of the RTOs and ISOs have recognized, the first and most fundamental issue that must be addressed with respect to resiliency is how “resilience” is to be defined. FERC has proposed to define resilience as “[t]he ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to, and/or rapidly recover from such an event.” While the RTOs and ISOs have suggested important refinements to this definition, it is important to note that the generality of the definition could pose challenges to any effort to secure new regulations or market rules that effectively pick winners and losers. Virtually, all resources and transmission facilities help support the resilience of the grid under FERC’s broad proposed definition. Therefore, any attempt to throw dollars at certain generation plants in the name of resilience, but not at other resources and facilities that provide the same or other resilience benefits, may be vulnerable to legal challenge.

The answer seems to lie in identifying specific attributes that are needed for the resiliency of the grid and adopting mechanisms to ensure that all resources and facilities contributing such attributes are compensated for them in a manner that is proportional to the value they provide. The markets already do this to some extent, with FERC imprimatur. By rewarding good performance and penalizing poor, the current designs of the ISO New England and PJM capacity market seek to compensate resources based on the value of their respective capacity.

The ancillary service markets already reward generators, based on certain other attributes their plants provide to the grid, including their capabilities to provide regulation service, black start, frequency response, reactive power and spinning and nonspinning reserves. For example, under FERC Order 784, generators are compensated not just for the amount of regulation services they provide, but also for providing a more rapid response time or greater accuracy following a regulation signal. In addition, the MISO and California Independent System Operator (CAISO) have adopted ramp capability products that reward generators for the ramping capability they provide to the market. CAISO has also adopted a Flexible Resource Adequacy product to help it retain sufficient levels of flexible capacity resources to meet the state’s renewable resource objectives without harming reliability.

On the other hand, there are a number of resource attributes that are beneficial to reliability and resilience but that are not specifically reflected in compensation in some or all RTOs and ISOs. For example, the grid needs dispatchable resources to match generation with load continuously, but the level of compensation paid to resources does not generally reflect their relative dispatchability. Similarly, the amount of compensation paid to resources typically does not reflect the relative security of a resource’s fuel supply. Other examples of generally uncompensated resource attributes include start times, ramp rates, inertia, minimum load level and proximity to load.

Determining which of these and other attributes merit special compensation for purposes of assuring resiliency will require modeling of countless scenarios involving a wide array of high-impact, low-frequency events to identify the attributes critical to achieving or maintaining a desirable level of resilience at an acceptable cost. An RTO or ISO proposing a market product to compensate such attributes will need to be able to show why that attribute’s contribution to resilience should be reflected in resource compensation while other attributes’ contributions continue to go uncompensated.

Assuming such a showing can be successfully made, additional challenges will remain. How will the amount of compensation for a necessary attribute be determined?

Will resources with the important attribute be assured recovery of their entire cost of service, including a reasonable rate of return, as DOE’s Proposed Rule contemplated? If not, will resources be compensated for the costs associated with their resource-specific capability, or only for actual utilization of this capability? Will all resources with the attribute be entitled to such compensation or only resources in a certain part of the ISO/ RTO footprint? How will the costs of this compensation be allocated by the RTO or ISO? How often will resilience and the attribute be re-evaluated to determine whether the attribute merits continued compensatory treatment in light of resources’ additions and other relevant changes, or perhaps greater compensation in the event the compensation scheme proves inadequate to stem retirements? These are just some of the many questions with which the RTOs and ISOs will need to grapple, and any proposals will have to be accepted by FERC and survive all-but-certain legal challenges.

In short, by declining to adopt DOE’s Proposed Rule and opting instead to approach resilience holistically, FERC has required that the RTOs and ISOs weave a tangled web to formulate and push through any major market reforms to promote resiliency. For power plants teetering on the precipice of retirement, restorative action may not come soon enough, if at all.

The views expressed in this article are those of the authors and not necessarily those of BakerHostetler or its clients.