On September 29, 2017, the Department of Energy (DOE) issued a notice that may impact wholesale rates in all federally regulated wholesale markets (not including ERCOT). The following types of entities may be affected by this proceeding: (i) merchant plant owners, (ii) wholesale market customers, (iii) renewable and gas fired generation, (iv) coal and nuclear power plant owners, and (v) power traders.
The DOE directed the Federal Energy Regulator Commission (FERC) to issue a Notice of Proposed Rulemaking (NOPR) requiring regional transmission organizations (RTOs) and independent system operators (ISOs) “to ensure that certain reliability and resilience attributes of electric generation resources are fully valued.” The DOE seeks market reform that would provide additional compensation for what it identifies as “eligible grid reliability and resiliency resources” (EGRRRs) – practically, coal and nuclear power plants that have been vulnerable to retirement because they are not always competitive in current federally regulated wholesale markets.
The DOE issued the notice pursuant to Section 403 of the Department of Energy Organization Act, which allows the Secretary of Energy to propose rules and gives FERC exclusive jurisdiction over the Secretary’s proposals. In regard to jurisdiction, the FERC has opposed state-level attempts to include such out-of-market compensation mechanisms in wholesale rates. The Supreme Court and federal District Courts have indicated that FERC has jurisdiction over generator compensation mechanisms that are tethered to wholesale markets, and states may create compensation mechanisms – only when they do not require generators to participate in wholesale markets. See, e.g., Hughes v. Talen Energy Marketing, 136 S. Ct. 1288, 1299 (2016); Coalition for Competitive Electricity v. Zibelman, Case No. 16-CV-8164, Slip Op. (S.D.N.Y. July 25, 2017); Village of Old Mill Creek v. Star, Case No. 17 CV 1163, Slip Op. (N.D. Ill. July 14, 2017).
The DOE notice directs FERC to either (a) consider and complete “final action” within 60 days of publication of the NOPR in the Federal Register, or (b) issue “the proposed rule” as an interim final rule, effective immediately, providing that it may be modified after consideration of public comments. If FERC issues a final rule, the NOPR directs it to take effect within 30 days of publication in the Federal Register, and proposes that RTOs and ISOs submit a compliance filing 15 days after the effective date of the final rule.
Observations
FERC will undoubtedly take the DOE’s NOPR very seriously and it will issue an expedited NOPR in short time. Once the NOPR is issued, however, it may take longer than DOE estimated for a final rule to take effect. The NOPR proceeding must adhere to the Administrative Procedure Act’s due process requirements. Additionally, it must contend with the RTO and ISO stakeholder processes that must be memorialized in a compliance filing to FERC; most RTOs/ISOs must follow their stakeholder processes before they can file proposed tariff changes for approval by FERC. Such stakeholder processes take time to carry out. If an issue is controversial, stakeholders in some regions could reach a deadlock and not authorize the RTO/ISO to make a filing at all.
The proposed rule is not specific about how RTOs/ISOs should establish compensation mechanisms, such as through a new market clearing process or an out of market rate adder of some kind. In any event, the proposed rule’s criteria for generators to qualify for compensation may significantly limit the number of generators that can qualify as an EGRRR. To qualify as an EGRRR, proposed Section 35.28(g)(12) requires:
- A resource must be physically located in an ISO/RTO region. That requirement would eliminate all resources that are physically located outside of an RTO/ISO region, and potentially those that are electrically connected, but not physically located in an ISO/RTO region. Moreover, it is not clear if this would allow a resource in one RTO region to sell in another, e.g., a coal plant in MISO selling to PJM.
- A resource must have a 90-day fuel supply on site. Most nuclear plants would meet this requirement, but coal plants generally have only a 30-day fuel supply.
- A resource cannot be subject to state cost of service regulation. This would disqualify any nuclear or coal plant that is part of a vertically integrated utility’s rate base. This means that EGRRRs would be limited to merchant plants.
- A resource must be compliant with all applicable federal, state and local environmental laws. The rule does not explain how FERC (or RTOs/ISOs) will determine whether a resource has met all such environmental laws. Such a determination could be a source of significant delays for EGRRR qualification.
In addition, the proposed rule states that reliability and resiliency rates provided to EGRRRs should be established for (1) the purchase of energy, and (2) the recovery of costs, including a return on equity, for resources dispatched during grid operations. Such rates shall include pricing to ensure that EGRRRs are compensated for the benefits they provide to the grid, such as reliability, resiliency and on-site fuel assurance. Presumably, the reliability and resiliency rate is proposed to be a rate that is over and above the market clearing rate, but only for EGRRR units that are dispatched.
It is not clear if the proposed rule will have the intended effect of keeping baseload coal and nuclear plants from retiring. Nuclear units will likely benefit because they can meet the EGRRR criteria and they are most always running. Coal plants, however, may not benefit because they may not meet the EGRRR definition requirements (e.g., 90-day on site fuel supply), or, even if they meet the EGRRR criteria, they may not be dispatched during grid operations frequently enough to receive enough EGRRR market revenue.
Unanswered Questions
The DOE’s proposal does not answer several big questions, including:
- How will the reliability and resiliency benefits be quantified? Will the rates be tied to a particular EGRRR’s cost of service?
- Who will pay the extra costs attributed to the EGRRR units? If the costs are to be allocated to all load in a region, FERC will have to show that all load in the region benefits from the EGRRRs and meets FERC’s cost causation principle, or if the rule is challenged, face remand from an appellate court.
- If load outside of the ISO/RTO regions also benefits from the EGRRR units, can ratepayers in ISO/RTO regions challenge the rule’s application on the basis of cost shifting?
- What effect will additional out-of-market compensation to EGRRR units have on the economics of other resources? Such out-of-market compensation mechanisms have been found to unreasonably affect wholesale market outcomes.
- How will each Commission-approved RTO and ISO demonstrate compliance?
This proceeding can be monitored in FERC Docket No. RM18-1. Interested persons are invited to submit comments regarding the proposal. Comments are due on or before October 23, 2017. Reply comments are due on or before November 7, 2017.
Contact Us
If you have questions about the NOPR and how it might affect your business, please contact Chris Reeder, Linda L. Walsh or another member of Husch Blackwell’s Energy & Natural Resources group.