The U.S. Department of Energy (DOE) today announced a Notice of Proposed Rulemaking (NOPR) – Grid Resiliency Pricing Rule requiring FERC to act within 60 days to provide additional financial support to baseload power plants. This NOPR could have a major impact on the industry and markets and could be a huge game changer for baseload plants. Timing is unclear along with most of the details. The only certainty is the uncertainty that this will create in the marketplace as the rule is developed and the details debated. Read on to learn more about what the rule could mean for you.
Unprecedented Steps By DOE
DOE has rarely, if ever, exercised its authority vis-a-vis Federal Energy Regulatory Commission (FERC) in this manner. It is even rarer to act with such very tight deadlines – i.e. 60 days, and with such broad regional coverage – it applies to any ISO or RTO with an energy market (Day Ahead and Real-Time) and any plant not subject to state rate of return regulation. In the past, most NOPRs originated from FERC directly. Thus, past experience is not necessarily a good guide in predicting the likelihood of implementation. Also, the political environment is without obvious precedent.
Only Limited Specifics
There are no specific proposals for how this NOPR would be implemented. DOE requires FERC to issue a new rule, and public comment is invited. The rule must provide baseload units recovery of costs, and recovery on and of capital at just and reasonable rates. The rule must work broadly, in RTO markets with and without capacity markets. There is no discussion of whether there needs to be, or can be, mitigation of impacts on existing market structures and non-baseload plants.
It also appears to envision requirements going beyond the August DOE report. While the proposal must adhere to the Federal Power Act’s main operative language on rates (they must be “just and reasonable and not unduly discriminatory”), is fuel neutral (provision of ancillary services and 90 days on-site fuel supply is mandated), and is market-based, there were no clear statements about recovery of and on capital in the report. The goal clearly appears to include finding sufficient revenue to keep the units from retiring, not just for fuel cost recovery.
Implied Security & Disaster Recovery Emphasis
The timing may be propitious because of recent hurricanes (e.g. Harvey, Maria, Irma) and national security developments (e.g. North Korea, etc.). While there is no specific mention of these developments, the requirement is based on both national security and natural disaster concerns. As one handicaps the viability of the rule, national security and responsibility for disaster relief may create a strong basis for rule-making.
This is because it requires a court to substitute its judgment for that of the executive in order to overturn (assuming something can be devised and be approved by FERC). While we are not lawyers, a national security-based rationale—or emphasis on low frequency but extreme events like recent hurricanes—increases the likelihood of the new rule ultimately being upheld. Having said that, there could be delays because it will take time to get to the court of the last remedy, and initial venues may delay action.
Courts might find the evidentiary basis lacking on the 90-day fuel requirement for all baseload plants. Ninety days is a level easy for nuclear units and coal units to achieve, but could be more difficult for some gas units. Some gas plants would require new permits, construction of fuel tanks, purchase and delivery of fuel, plans to maintain the fuel stockpile in emergencies, equipment modifications, and of course, not relevant to renewables. For example, would 10 days of on-site fuel be enough?
The timing of the DOE's NOPR is such that it will be difficult for the FERC to evaluate alternative proposals which are likely to involve significant complexities:
- Is mitigation of market impacts required? If so, how?
- What is a fair rate of return?
- Does this apply to reactivated units? New Units?
- Is an Environmental Impact Statement (EIS) required?
Adding to the challenge, FERC recently reached a quorum, but its proposed Chair is still not seated or approved by the full Senate (the remaining two Commissioners were approved by committee recently). The timing is extremely aggressive. A critical set of market deadlines is the May 2018 PJM auction, and another looming deadlines is the January 2018 ISO NE capacity auction.
There is an alternative approach which would be more rigorous (and perhaps easier to defend in court), but also more time-consuming to implement (arguing that this is a case in which security must be judged by the executive on a timely basis). As such, the rule may stand temporarily until more permanent arrangements can be established. Even if the Executive determined the severity of the event, e.g. loss of one or two pipelines, one could imagine that the gas industry could determine the consequence of loss of one or two pipelines in terms of fuel supply for power plants accounting for alternative pipelines, backup fuel, demand and supply conditions including reliance on interruptible contracts, and then input these assumptions into the power industry’s electric transmission security analysis modeling (e.g. AC load flow contingency analysis).
The power industry analysis would seek to determine whether the power supply could be maintained. This is time-consuming because neither the power industry nor FERC, NERC or DOE for that matter, is set up to do this. Also, the gas industry lacks an RTO equivalent – an independent entity that conducts hydraulic and other detailed gas delivery modeling and other analyses to assess the likely consequences. This is the result of historical and political factors and creates a huge asymmetry between these two FERC regulated industries; however, depending on how this proposed rulemaking is implemented there will be major implications on the competitive power markets.
Impacts on Coal and Nuclear Power Plants
To the extent this rule is implemented, most coal and nuclear plants would likely see an uptick in valuation to depreciated book value. The exact extent would be a function of the details, and determination of rates of return. In many cases, there would be a major increase in value because while many of these plants are old, ongoing capital improvements have been major. Further, the NOPR should greatly decrease—though not eliminate—retirements and may also obviate the need for state action to support baseload units in places like in Illinois, New York, etc.
What About Gas Power Plants?
To the extent this rule is implemented, there could be significant impacts on gas plants. In one scenario, the lack of coal and nuclear retirements lower capacity prices and energy prices. Alternatively, FERC and the RTOs could mitigate the impacts on the markets, and under some mitigation approaches, prices could increase. Mitigation of mandates is a big feature of the August DOE report which argues for the potential for mitigation. For example, the market could be rerun with baseload plant bids set at costs. Because in the PJM capacity auction, baseload plants appeared to bid below costs, the impacts on gas power plants might be higher capacity prices and higher value for gas plants. Cost increases could be opposed by the states; no shortage of legal challenges is anticipated.
What About Renewable Power Plants?
Similar considerations apply to renewables as gas power plants, though they are not affected as much by capacity market developments and lack of retirements. In short, even assuming the proposal is implemented, until more details on implementation and mitigation, firm conclusions and estimate of impacts will have to be delayed.
We plan to be watching closely. Let us know what you think or reach out to one of our experts to learn more about how this could affect you.