FERC directed to favor coal and nuclear
Most United States competitive markets would be forced to dispatch nuclear and coal power plants ahead of other power plants and have them receive cost-based rates under a proposal the US Department of Energy sent the Federal Energy Regulatory Commission at the end of September.
It would amount to a bailout of operating nuclear plants and coal plants that are not price competitive in the regional power markets and ensure them market share at the expense of gas and renewable energy plants.
US Energy Secretary Rick Perry used an obscure provision in the Department of Energy Organization Act to propose rules that FERC is supposed to decide within 60 days to force competitive regional transmission organizations or RTOs—like PJM, MISO, New York ISO and ISO-New England—that FERC regulates to modify their rate structures to pay nuclear and coal plants the full operating and capital costs whether or not the electricity offered from these plants is cost competitive.
This proposed rule only applies to these competitive markets. In parts of the United States with such markets currently, the RTO takes bids each hour from electricity generators to supply the power the market requires that hour and then dispatches power plants in economic merit order from least cost to most expensive until the full needs that hour have been met.
Since the regional power markets set prices based on competitive bids, not on the bidder’s operating costs, the proposed rule would undermine the fundamental approach to economic dispatch of generation resources in these markets.
The authority that DOE is using to direct FERC to act has not been used since the early 1980s. The Department of Energy was created in 1977. FERC has exclusive jurisdiction over wholesale electric rates charged in the United States. DOE has authority to propose a rule to FERC and direct FERC to act within a reasonable period.
DOE says emergency action is needed because reliability of the power supply in these regions may be being threatened if baseload nuclear and coal plants are not able to operate. Many nuclear and coal plants are no longer cost competitive with other plants, like baseload gas-fired plants and intermittent renewable resources like wind and solar projects.
DOE cited selectively from its own recent study of grid reliability, as well as certain selective statements from the NERC—the North American Electric Reliability Corporation—and FERC about the need to understand the implications of the changing resource mix in power sources to assure reliability.
However, it did not cite any statement from any reliability council or regional transmission organization or FERC that any particular region’s reliability is inadequate now or in the immediate future. In fact, the DOE study itself concluded only that “[a] continued comprehensive regional and national review is needed to determine how a portfolio of domestic energy resources can be developed to ensure grid reliance and resilience.”
The proposed rule that DOE wants FERC to adopt does not expressly limit the cost-based subsidization to nuclear and coal projects. However, support would be provided only to any project that has “a 90-day supply on site enabling it to operate during an emergency, extreme weather conditions, or natural or man-made disaster.” Coal plants and nuclear plants, unlike gas plants and renewable power projects, require substantial on-site fuel storage.
Many coal plants would have to buy more coal to qualify. US power plants that burn coal had average stockpiles in August of 71 to 91 days.
RTOs generally operate with generators bidding every day on an hourly basis to supply their energy. Subject to certain transmission constraints, the generators are economically dispatched, with the lowest bids dispatched until the entire load on the system is met. Those projects that offer non-competitive priced bids above that level of system demand will not be dispatched and will not receive any revenue for their energy. In the last couple years, some coal and nuclear plants have not been able to compete with newer, more fuel-efficient natural gas power projects that are benefiting from very low gas prices and therefore have low operating costs.
Several states have been moving separately to subsidize nuclear power plants. New York and Illinois have recently put in place subsidized pricing for operating nuclear plants in their states that are having a hard time competing in the energy markets in MISO (for Illinois nuclear) and NYISO (for New York nuclear). These programs, which created a value for a new environmental attribute known as a zero-emission credit or ZEC for nuclear-only energy, are currently subject to litigation by competitive generators who claim that even this limited price support is disrupting competitive markets. (For more detail about the litigation, see “Zero Emissions Credits Upheld” in the August 2017 NewsWire.) Other states with nuclear power plants are considering similar state legislation.
DOE initially delivered its proposal to FERC on September 28, 2017. FERC then issued a notice of proposed rulemaking on October 2 seeking initial comments on the DOE proposal by October 23. On October 4, FERC issued another notice requesting that commenters address a list of questions in a variety of categories including whether there is need for reform, what types of entities should be eligible for compensation, how the 90 days of on-site fuel supply should be determined, how environmental regulations and weather conditions could affect the reliability of the fuel supply, and how eligible projects should be dispatched given the systemwide economic dispatch of the current RTO systems.
On October 6, DOE reissued its notice of proposed rulemaking for publication in the Federal Register on October 10. The 60-day window for action by FERC would expire 60 days from publication, or December 11, unless the DOE changes its deadline.
DOE made clear that the proposed rule does not apply to any utility that operates outside of an RTO. The proposed rule only applies to projects that are “not [already] subject to cost of service regulation by any state or local regulatory authority.” Therefore, utilities that have coal and nuclear plants in their rate bases and are subject to state rate regulation will not benefit from the proposed subsidies. However, since state utility rate regulation is outside of FERC jurisdiction, DOE may have recognized the limits on its ability to influence these utility rates.
The irony of this exclusion is that most of the utilities in regions that do not have RTOs, which include most of the southeastern United States and the west and northwestern United States (except for California, which has only one nuclear unit and no coal plants), have been shedding their coal assets as rapidly as possible and replacing their capacity with new gas-fired and solar and wind capacity to increase their investment rate base and return on investment. Most of the existing coal plants are 40 to 60 years old and are largely depreciated, causing cost-based regulated utilities to earn little on their coal plants.
It appears from the list of questions that FERC suggests commenters should address that the DOE proposal took the FERC commissioners completely by surprise.
It also appears that the entire natural gas industry, which the President had sworn to encourage and which have the most to lose from this nuclear and coal subsidy proposal, was also blindsided. It has roundly condemned the proposal.
There are certain legal requirements that will prevent FERC from issuing any rule consistent with the DOE proposal, even if it were inclined to do so.
Under the Federal Power Act, the authority to modify a utility’s or an RTO’s rate structure requires a prior determination by FERC that the existing rates are unjust and unreasonable. FERC cannot find that an existing rate is unjust and unreasonable without a hearing. If it determines after hearing that the existing rates are unjust and unreasonable, it would then not only have to explain why the existing rate is unjust and unreasonable, but also explain why the changed rate would then become the just and reasonable rate.
Typically, a cost-of-service rate determination would require the submission of expert testimony covering many disciplines, which would be subject to a hearing, cross-examination and subsequent briefing by the parties to the proceeding. The typical ratemaking issues would include what should be allowed as the investment in rate base, what taxes, depreciation and operating costs should be included, what is an appropriate rate of return, what costs should be classified as generation, transmission or distribution costs, and what percentage of the costs should be allocated to specified customers.
In the case of the DOE proposal, the hearing would likely have to be expanded to consider the relevant components of the proposals, including the reasonableness and scope of the 90-day on-site fuel storage requirement, which specific resources should be eligible for these cost benefits, what energy services each eligible resources should be required to provide, what the impacts will be on electric consumers, and how a new cost-based rate program should be incorporated into a market system based on economic dispatch using competitive bids.
It remains to be seen if the DOE proposal will be seriously promoted by the Trump administration or is merely a political document. If the former, a process far longer than 60 days will be required.