Posted on January 7, 2022 by Eugene M. Trisko*
The Biden Administration’s April 2021 pledge for new U.S. commitments to the Paris Agreement calls for an 80% reduction of electric power greenhouse gas emissions by 2030. The Administration also is committed to achieving decarbonization of the power sector by 2035. Current climate change proposals in Congress mirror these targets. At the same time, mandates for 100% electric vehicle sales by 2035 are being considered, potentially leading to a significant increase in electricity demand.
U.S. DOE’s 2021 Annual Energy Review indicates that the phase-out of fossil-based generation would eliminate 6,020 natural gas generating units and 668 coal-based generating units across the nation, with a combined nameplate generating capacity of 790 Gigawatts. Together, these generating resources represent 67% of total U.S. electric generating capacity.
The policy discussion about near-term elimination of fossil-based generating capacity emissions needs to consider the effects of reduced depreciation and other capital cost recovery timetables on the ability to finance new generating capacity. DOE’s current reference forecast of new plant capacity calls for 395 Gigawatts of new natural gas combined cycle capacity to be constructed between 2020 and 2050. Combined cycle units are the most efficient form of fossil generation, typically achieving conversion efficiencies of 60% or more.
With a 2035 target for phase-out of carbon emissions from the electric generation sector, electric utilities may face severe difficulties in financing new natural gas combined cycle units, and in securing necessary state regulatory approvals for their construction. In most states, capital costs of new plants are recovered through rate-based mechanisms, with costs typically spread over 30-year plant lifetimes across residential, commercial and industrial customers.
The effects of reduced capital cost recovery timetables for a new 800-Megawatt gas combined cycle plant with a 70% capacity factor are significant. Assuming an initial capital cost of $1 billion and an 8% weighted average cost of capital for debt and equity financing, annual capital costs would be recovered at a rate of $18.11 per Megawatt-hour (MWh) of generation over a typical 30-year depreciation period.
As the recovery period is reduced to meet a 2035 phase-out, annual capital recovery increases from $121 million (2023 startup) to $560 million (2033 startup). The increase is from $24.73 per MWh – 36% greater than the 30-year depreciation case – to $114.31 per MWh in the 2033 startup case. State utility regulators may frown at the rate consequences of such large cost recovery increases.
These increased capital costs are likely to preclude much new natural gas combined cycle development in the event that 2035 or a similar date is chosen for the elimination of carbon emissions from the electric generating sector. Because natural gas generation is needed as a backstop for expanded renewables development, as well as for meeting new demand from the transport sector, the prospective consequences of accelerated fossil energy phaseouts for national and regional electric reliability and costs need to be carefully examined by state and federal regulators.
* The author (B.A., NYU, 1972; J.D., Georgetown Law Center, 1977) is an advisor to several international energy unions. He also served for 10 years as an expert witness on utility cost of capital before state public utility commissions. He may be contacted at emtrisko@earthlink.net.