On January 8, 2018, the Federal Energy Regulatory Commission (the “FERC” or “Commission”) issued its decision in the controversial and highly publicized Docket No. RM18-1-000, titled Grid Reliability and Resilience Pricing (“GRRP” or “Proposed Rule”), that was submitted to the FERC by the Secretary of Energy, Rick Perry. The Proposed Rule, which was published in the Federal Register on October 10, 2017, received broad coverage primarily because it was viewed by critics as a mechanism to prop up coal and nuclear generation to the exclusion of other resources by providing cost-of-service rates that exceeded market values. While the FERC ultimately terminated the proceeding, thereby disposing of the Proposed Rule, it also took the affirmative step of opening a new proceeding, Docket No. AD18-7-000, titled Grid Resilience in Regional Transmission Organizations and Independent System Operators. This new Docket focuses on some of the same issues as the GRRP—namely resilience of the bulk power system in regions operated by regional transmission organizations (“RTOs”) and independent system operators (“ISOs”).1 Accordingly, the resilience and reliability debate relating to the America’s bulk power system will continue.
Background and the Rationale Behind the Proposed Rule
By way of background, there are nine RTOs/ISOs that operate approximately two-thirds of the bulk electric power systems across North America. The concept of ISOs/RTOs arose in the 1990s as a result of the Commission’s policy to encourage competitive generation through open access to transmission.2
The Proposed Rule submitted to the FERC directed it to consider “requiring certain RTOs and ISOs “to establish a tariff mechanism providing for: (1) the purchase of energy from an eligible reliability and resilience resource; and (2) the recovery of costs and a return on equity for such resources (i.e., a “resilience rate”).” To qualify as a “reliable and resilient resource,” three factors were required: (1) it had to be located in an RTO/ISO with an energy and capacity market; (2) it to be able to provide essential reliability services; and (3) it had to have a 90-day fuel supply on-site.
To support its Proposed Rule, the Department of Energy pointed to “market changes” that were “resulting in a significant loss of fuel-secure generation.”3 The Proposed Rule cited various reports relating to the retirement of certain types of power plants. Citing the January 2017 Quadrennial Energy Review (QER), the Proposed Rule noted that between 2010 and 2015, 37 GW (52 percent) of retired power plant capacity was in the form of coal power plants, and that there was an expectation that a significant number of additional coal power plants would be closed between 2016 and 2020.4 It also pointed to the Department of Energy “Staff Report to the Secretary on Electricity Markets and Reliability,” which noted:
- Between 2002 and 2016, 531 coal generating units representing approximately 59,000 MW of generation capacity retired from the U.S. generation fleet.
- EIA reported that coal-fired power plants made up more than 80 percent of the 18,000 MW of electric generating capacity that retired in 2015.
- It is anticipated that approximately 12,700 MW of coal generation will retire through 2020.
- Between 2002 and 2016, 4,666 MW of nuclear generating capacity was announced for retirement, or approximately 4.7 percent of the U.S. total.
- Eight reactors representing 7,167 MW of nuclear capacity (7.2 percent of U.S. nuclear capacity and 0.6 percent of total U.S. generating capacity) have announced retirement plans since 2016. This does not include seven reactors that averted early retirement through state action.
The Proposed Rule highlighted these retirements, together with the significant weather event referred to as the 2014 Polar Vortex, when there was a significant loss of generation capacity as a result of various equipment failures—a large portion of which was tied to natural gas generation. Due to equipment failures and other issues with the pipeline system during the 2014 Polar Vortex, the real-time deliveries often relied upon by natural gas generation facilities through the country’s sophisticated pipeline system were unavailable. As a result, generation in some areas had to come from other generation sources such as coal powered plants—some of which were actually scheduled for future retirement at the time. Citing this significant weather incident, the Proposed Rule suggested that “Coal-fired and nuclear generation have the added benefits of high availability rate, low forced outages, and secured on-site fuel. Many months of on-site fuel allow these units to operated [sic] in a manner independent of supply chain disruptions.”
Given that framework, the Proposed Rule asserted that the “organized markets do not necessarily pay generators for all the attributes that they provide to the grid, including resiliency.” Hence, the Proposed Rule sought a tariff mechanism that would make up for the market’s apparent unrecognition of resiliency value by providing “fuel-secure” sources with what the FERC described as a “resilience rate.”
The FERC’s Decision
The FERC was deliberate in its analysis of the Proposed Rule, beginning its decision with a lengthy description of the evolution of the Electric Power Industry. It explained this background was important to “more fully understand the context in which the Proposed Rule was issued and the actions [it] was taking . . . .” The Commission began by discussing the original “vertically integrated utilities” that “built and owned the generation, transmission and distribution facilities need to serve load” within their own territories. The evolution toward the competitive market we have today began in the 1970s and evolved through the late-1990s. As a result of the trend towards competition, the FERC:
largely adopted a pro-market regulatory model . . . rel[ying] on competition in approving market rules and procedures that . . . determine the prices for the energy, ancillary services and capacity products. Under this pro-competition, market-driven system, owners of generating facilities that are unable to remain economic in the market may take steps to retire or mothball their facilities.
The FERC further noted that “innovation in the energy sector and . . . change[s] in energy resource mix” have acted as “a continually evolving phenomenon” affecting the “development and evolution of electric markets.”
The Commission also clearly wanted to communicate that this was not the first time it had considered issues relating to “bulk power system resilience.” It pointed to the multi-year evaluation it conducted of the coordination of wholesale natural gas and electricity market scheduling, as well as its study of the grid response to the 2014 Polar Vortex and how each RTO/ISO addresses fuel assurance. It also noted its prior approval of market reforms in ISO New England, Inc. and PJM Interconnection, LLC, that were designed to bolster performance from capacity resources and address fuel supply issues during periods of system stress. Despite these prior efforts, the FERC reiterated its recognition of grid resilience as an important issue moving forward and then turned to its attention to actual analysis of the Proposed Rule.
The Commission based its termination of the Proposed Rule on its application of Section 206 of the Federal Power Act, which requires a showing that existing RTO/ISO tariffs be found unjust, unreasonable, unduly discriminatory or preferential before any changes may be implemented. The FERC found that there had been no demonstration that the current RTO/ISO tariffs were unjust or unreasonable. Further, none of the “extensive” comments submitted by the RTOs/ISOs pointed to any “planned generator retirements” that would threaten grid resilience.
Under the second prong of the Section 206 analysis, the FERC further found that eligible resources under the Proposed Rule would be entitled to receive “a cost-of-service rate regardless of need or cost to the system,” which the Commission did not believe was “just or reasonable.” It also noted that the remedy from the Proposed Rule was likely to be unduly discriminatory or preferential, as the 90-day fuel supply requirement appeared limited to certain resources while excluding others that could also have resilience attributes—this was the point echoed by many opponents of the rule in addition to suggesting that the implementation of the Proposed Rule would significantly increase electricity customers’ costs.5 Based on these two findings, the FERC terminated the Proposed Rule.
In recognition, however, of how significant it views grid resiliency to be, as well as the other risks and changes being seen in the electric markets, the FERC initiated a new proceeding, Docket AD1818-7-000, to: (1) develop a common understanding of “what resilience of the bulk power system means and requires;” (2) “to understand how each RTO and ISO assess resilience in its footprint;” and (3) “to evaluate whether additional [FERC] action on these issues is warranted.” This new proceeding seeks comments on more than twenty areas of inquiry within 60 days from RTOs and ISOs on a host of resilience-related topics, and invites additional interested entities to submit reply comments within 30 days of the RTO and ISO submissions.
While the FERC ultimately terminated the Proposed Rule, it went out of its way to recognize the concept of resiliency as a critical topic in the conversation regarding our nation’s power system(s). Absent an extension, RTOs/ISOs will submit their comments in March 2018, with other interested parties commenting thereafter in April. Assuming critics of the GRRP were correct, both residential and commercial consumers of electricity are likely beneficiaries of the FERC’s decision, since the requested tariff actions had the potential to increase consumer costs while providing eligible resources with increased revenue to compensate them for their “added value” of resiliency. As cyberterrorism threats continue to flood the daily headlines, however, everyone can expect the resiliency conversation to continue in both the short and long term future, unless there is a drastic makeover on the horizon relating to the bulk power system. Even then, the idea of securing American’s power sources will always an apt topic for discussion.
1. RTOs and ISOs were the creations of FERC’s Orders 2000 and 888 for the purpose of, among others, providing competition among wholesale suppliers, non-discriminatory access to transmission through the use of scheduling and monitoring, ensuring reliability, managing interconnection of resources. See generally, https://www.ferc.gov/industries/electric/indus-act/rto.asp. See also, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,639-31,645 (1996); Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom. Pub. Util. Dist. No. 1 v. FERC, 272 F.3d 607 (D.C. Cir. 2001).
2. See http://www.isorto.org/about/Role.