President Obama’s proposal to slash carbon dioxide emissions from the existing power plant fleet could scramble regulatory compliance strategies and alter electricity markets, consultants from ICF International said in a webinar July 30.
Unfortunately, the issue of what EPA can actually do that can withstand legal challenge won’t be known until the process plays itself out, ICF Vice President Steve Fine said.
Other ICF officials who discussed the issue were Principal Chris MacCracken and Vice President Shanthi Muthiah.
The president released his climate action plan June 25. The goal is to achieve 17% reduction in GHG below 2005 levels by 2020.
Most relevant to the power sector, President Obama explicitly said he would seek EPA regulations, through the Clean Air Act, for CO2 limits on existing power plants, Fine said.
“It really is nothing new” in a way given the EPA GHG mandate laid out in a series of court decisions. “This is all in process,” Fine said.
U.S. emissions have declined, but are not likely to hit goal by 2020 without further action, Fine said.
The president’s timeline suggests that EPA re-issue its proposed rule for new power plants by Sept. 20 of this year. The proposal has already been sent to the Office of Management and Budget “for scoring,” the ICF officials said.
A big question is whether EPA will include carbon capture and storage (CCS) as part of a standard for new plants.
The EPA proposed guidelines for existing plants is due June 1, 2014, and the final guidelines due June 1, 2015. State implementation plants would have to be submitted to EPA by June 30, 2016.
Under Section 111(d) of the Clean Air Act, states could submit to EPA “standards of performance” for any existing source. If rejected, or the state fails to submit a plan, EPA imposes a Federal Implementation Plan, according to ICF
The Clean Air Act has never been used before to control GHG emissions, Fine said. A unit-specific rate might stand the greatest change of surviving legal challenges, Fine said. Such a standard could be set based on emission rates across combined technology and fuel categories – such as subcritical coal units burning Powder River Basin coal.
The addition of more flexibility standards, like trading, could increase the potential for a successful legal challenge.
EPA could also produce a “model rule” that could include flexibility measures. That approach could be akin to the so-called NOx SIP Call, Fine said.
The factors EPA might consider – efficiency improvements, fuel switching, co-firing, carbon capture – all remain unknown.
MacCracken noted that the Natural Resources Defense Council (NRDC) came out with its own proposal at the end of 2012 that would employ section 111(d).
Under NRDC’s plan, EPA would develop CO2 emissions standards for existing standards based on state-specific historical fossil generation mix and NRDC-specified fuel-specific benchmark.
NRDC would eventually arrive a state standard that would give rise to a emission credit trading system. Non-emitting sources, like energy efficiency and renewable power, could generate such credits, MacCracken said.
For example, combined-cycle gas units and wind units, could create emission trading credits.
Of course, EPA has not proposed any GHG emission trading program, nor is there any guarantee that it will, MacCranken said.
A unit standard could impost capital costs on a select group of units with limited dispatch, Muthiah said.
CO2 performance standards for existing units could drive changes in all aspects of the power market: Power prices, compliance strategies; need for new capacity and transmission; gas and coal demand; Muthiah said.
The issue of what EPA can do to actually withstand legal challenge won’t be known until the process plays itself out, Fine said.