The Department of Energy’s proposal to provide “full recovery” of coal and nuclear plant costs in RTOs with capacity and energy markets was short on details, notably providing no estimate of the cost of such policies.
But PJM’s Independent Market Monitor and several other stakeholders have published estimates ranging from $300 million to more than $32 billion. (See related story, Critics Slam PJM’s NOPR Alternative as ‘Windfall.’)
In its response to the DOE proposal, PJM’s Monitor estimated the NOPR would cost ratepayers in the RTO $3 billion annually — equal to 36% of capacity payments in 2016 — if nuclear and coal units were all paid 25% of current replacement value. (The current replacement value of a coal plant is $1,434/MW-day and that of a nuclear plant is $2,639/MW-day. In contrast, the gross cost of new entry for a combustion turbine is $312/MW-day and a new combined cycle is $406/MW-day.)
The cost would rise to $13 billion — a one-third increase in the total cost of wholesale energy — if nuclear and coal units were paid 50% of replacement value.
If the units received full replacement value, the price tag would rise to $32 billion — an 84% increase in total wholesale energy costs.
Robert Chilton, executive vice president of Gabel Associates and a former New Jersey regulator and consumer advocate, told FERC he calculated the NOPR would result in increased costs of about $7.1 billion annually for the first five years. Gabel mostly represents generators in PJM.
Chilton cited cumulative costs of between $35.4 billion ($28.9 billion net present value) and $100.8 billion ($64.1 billion net present value) over a five and 15-year term, respectively. His analysis assumes all fixed and variable costs are recovered by the eligible generators and all incremental net revenues are returned to customers.
A separate analysis, by the Climate Policy Initiative and Energy Innovation Policy & Technology, put the nationwide cost of the NOPR at between $300 million and $10.1 billion annually, based on which of four scenarios are used. (Energy Innovation is devoted to supporting policies “that most effectively reduce greenhouse gas emissions.” The Climate Policy Initiative seeks to improve energy and land-use policies to “help nations grow while addressing increasingly scarce resources and climate risk.”)
The $300 million lower-band estimate assumes units with negative net cash flows (energy and capacity market revenue, minus the sum of fuel, variable and fixed operations and maintenance, and annual capital expenditures) receive uplift payments to bring their net revenue up to zero.
The $10.1 billion upper-band estimate assumes covered units would receive all their fixed operation and maintenance, 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. It also assumes payments to all coal and nuclear units in the RTOs — not just those with negative cash flows — and that coal plants will increase generation to their maximum output. (Nuclear units generally already run at maximum output.)
Small Number of Winners
About $7.3 billion of the $10.6 billion would be paid by PJM ratepayers, raising the RTO’s total costs by 17%. “Spreading the incremental costs evenly over the 65 million people served by PJM results in an increase of $112 per person per year (though this probably is not how costs would be passed through),” the report said.
In both the high and low scenarios, nuclear plants account for two-thirds of the out-of-market payments.
Under all four scenarios, more than 80% of the coal subsidies would go to five companies, with NRG Energy’s revenue boosted by $40 million to $1.2 billion annually, and FirstEnergy and Dynegy seeing an increase of up to $500 million each.
Exelon would receive half of the nuclear subsidies, as much as $3.6 billion. Other winners would include Entergy and Public Service Enterprise Group.
Depending on the final rule, the NOPR could also bring 2 to 4 GW of recently retired plants back into service, resulting in additional costs of $113 million to $228 million annually. “While costs represented here are annual, they could continue in perpetuity, since generators would now have no reason to retire,” the report said.
— Rich Heidorn Jr.