Proposed DOE coal and nuclear plant subsidy could be expensive for consumers, study says
Energize Weekly, November 1, 2017
A Trump administration proposal to provide subsidies to coal-fired and nuclear power plants for their fuel reserves could add $311 million to $10.6 billion to customer bills, with the grants going to a handful of utility companies.
More than 80 percent of the subsidies for coal would go to just five companies, and nearly 90 percent of nuclear subsidies would go to no more than five companies, according to an analysis done by Energy Innovation: Policy and Technology LLC, in conjunction with the Climate Policy Initiative (CPI).
Energy Innovation is an energy consultant, and CPI is a non-profit group trying to improve energy and land-use practices of governments, business and financial institutions.
The U.S. Department of Energy (DOE) is asking the Federal Energy Regulatory Commission (FERC) to implement out-of-market subsidies for plants with a 90-day supply of fuel, contending these add resiliency to wholesale power markets.
The proposal would apply to areas served by wholesale energy and capacity markets. A capacity market ensures that there is adequate generation.
The move is seen as a way to throw a lifeline to economically ailing coal-fired and nuclear plants. The DOE said 531 coal-fired generating units were retired between 2002 and 2016, while eight nuclear reactors have announced retirement plans in the past year.
The DOE proposal “could significantly alter the structure of the nation’s wholesale market by requiring customers to pay for revenue shortfalls at coal and nuclear plants, many of which are not profitable given cheaper options available in the market today, the [proposal] will significantly increase costs for customers,” the analysis said.
The regional markets that would be affected are the PJM, which covers the Mid-Atlantic and part of the Midwest, the New York Independent System Operator (NYISO), the ISO New England (ISO-NE), and the Midcontinent ISO (MISO), whose area stretches through the middle of the country from the Gulf of Mexico into Canada.
The proposal’s “ambiguous language” makes it unclear exactly how much of an economic impact it would have, Energy Innovation said. The analysis calculates four different ways the proposal could be implemented.
Under the most conservative interpretation, units that have negative net cash flows would receive payments to increase their cash flow. This would cost consumers $311 million, according to the study.
If not only cash flow, but also capital recovery plus a rate of return on remaining undepreciated capital and future ongoing capital expenditures are added to the subsidy, the cost of the grants goes up to $700 million.
The cost of the subsidy grows to $10.4 billion if the market revenues are not netted out, so that customers pay all units—not just the ones with negative cash flow—all of their fixed operating and maintenance costs, and full recovery of undepreciated past capital expenditures and ongoing capital expenditures, at a guaranteed rate of return, on top of energy and capacity market revenues.
The most generous interpretation, which adds the assumption that coal plants would be paid their full operating costs, boosts the total to $10.6 billion.
The PJM, which is the country’s largest wholesale power market, would see the biggest impact—$7.3 billion under the most-generous scenario. The cost would be $1.6 billion for MISO, $1.1 billion for NYISO and $700,000 million for ISO-NE.
The $7.3 billion figure for PJM would represent a 17 percent increase in total cost for the system, according to the analysis.
“Just a handful of companies stand to benefit significantly,” the analysis said. About 80 percent of the coal subsidies would go to five companies—American Municipal Power, NRG, Dynegy, AGC Division of APG Inc. and PPL.
The companies benefiting from the nuclear subsidy would be Exelon, Entergy, PSE&G, FirstEnergy and NextEra.
The analysis said the proposal “would very likely change overall market clearing prices” for energy and capacity—decreasing both by encouraging uneconomical units to remain online, driving up the costs of the rule.
PJM, in comments filed with the FERC, said the DOE incorrectly identified a “perceived problem” and is seeking a remedy that isn’t supported by reliability and resilience concerns. It said that the DOE is proposing a regulatory instead of a market solution.
In comments filed with the FERC, the Rhodium Group, an energy and commodities research and consulting firm, said that between 2012 and 2016, utilities reported about 3.4 billion customer-hours of major electrical disruptions. The main reason for the outages had to do with the distribution system, not a loss of electric supply, Rhodium said.