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EPA’s Power Plant CO2 Rule 2.0: Much Ado About Nothing . . and Some Things

At first glance, there is nothing surprising about EPA’s September 20 revised proposal to set CO2 emissions standards for new power plants. Version 2.0 proposes roughly the same numerical standards as the April, 2012 Version 1.0, and with the same practical effect: no new coal-fired power plants without carbon capture and storage (“CCS”). And, just as it did before, EPA points out that the economics of natural gas mean that “few, if any, solid fossil fuel-fired EGUs will be built in the foreseeable future” because “electricity generators are expected to choose new generation technologies (primarily natural gas combined cycle) that would meet the proposed standards.” Thus, again, “EPA projects that this proposed rule will result in negligible CO2 emission changes, quantified benefits, and costs by 2022.” (More on that below)

The real importance of this rule is that the Clean Air Act requires that it be in place before EPA can regulate existing power plants, which the President has said will be in place by June 2015. And (unlike this rule), the existing plant rule will have immediate impacts. When it proposed Version 1.0, EPA denied that it had any plans to ever regulate existing plants.

Thus the bottom-line question is whether this rule will survive the certain challenge in the D.C. Circuit. We understand that was precisely the reason for the only significant change from Version 1.0. EPA now describes CCS as the “Best System for Emissions Reductions” for CO2, the relevant CAA standard; in Version 1.0, EPA repeatedly said that it was not so labeling CCS, and instead relied on a bit of regulatory juggling to impose the CCS requirement. (Ironically, many of the lawyers who will be litigating this rule think EPA would be better off defending Version 1.0)

The DC Circuit will have to decide whether EPA is justified in deeming CCS the Best System for Emissions Reductions for coal-plant CO2 emissions, and that means EPA has to show that CCS is (in layman’s terms) technically doable and economically reasonable. And because no one really denies that partial CCS from new coal-fired power plants can be done, the real question is “at what cost?”

Economically Reasonable?

EPA’s economic rationale is that coal plants with CCS cost about the same as new nuclear power plants, and because five new U.S. nuclear units are under construction, this means that “the cost of new coal-fired generation that includes CCS is reasonable today.”

EPA uses the National Energy Technology Laboratory (“NETL”) figures for coal plant CCS costs and the Energy Information Administration’s (“EIA”) figures for nuclear plant costs (on the grounds that NETL’s nuclear costs “were not available or sufficiently recent”). RIA 5-19. According to EPA, NETL’s cost for IGCC coal with partial CCS is $109/MWhr; when combined with the sale of captured CO2 for Enhanced Oil Recovery (“EOR”), that is reduced to between $97 and $101/MWhr, depending on the price of CO2. RIA 5-31. EIA’s comparable cost for nuclear is $107. RIA 5-32.

These numbers are susceptible to challenge. Because there is no such thing today as a coal-fired power plant with CCS, NETL arrived at its “coal with CCS” cost based on modeling of various systems, and concluded that partial (85%) CCS adds only 35% to the cost of an IGCC coal-fired power plant. NETL Table ES-14. NETL’s value is designed to reflect not the “First of a Kind” application of this technology, but rather its “next commercial offering”. NETL p. 35. But in the one real-world example we have (by definition, the First of a Kind), CCS has added almost $2 billion to the cost of Southern Company’s Kemper IGCC plant, and that is for a more modest CCS system designed for 65% capture, not the 85% capture EPA proposes. (Moreover, as we have noted previously there is no actual requirement that Kemper meet this 65% mark; in fact, in awarding a $270 million grant, DOE required Southern to do no more than “design, build and operate” Kemper with the intent of 25% CCS and then “actively work toward” 50% CCS by 2020.) And although EPA cites Kemper no fewer than 10 times in its rule, Southern immediately issued a statement saying that the project’s “unique characteristics . . . cannot be consistently replicated on a national level, the Kemper County Energy Facility should not serve as a primary basis for new emissions standards impacting all new coal-fired power plants.”

Expect that the first legal battle will be over whether NETL’s “First of a Kind” cost is justified in light of Kemper, and whether NETL’s methodology for discounting that cost to the “next commercial offering” value supports EPA’s adoption of NETL’s 35% cost premium for CCS.

The flip side of the fight over the costs of CCS will be the one over the costs of nuclear power. EIA’s estimate of $107/MWhr does not tell the whole story:
“The availability of various incentives, including state or federal tax credits, can also impact the calculation of levelized cost. The values shown in the tables in this discussion do not incorporate any such incentives.”
U.S. EIA, Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013, p. 1.

According to the Union of Concerned Scientists, the federal government subsidizes new nuclear power construction to the tune of between $35 and $65/MWhr via loan guarantees (e.g., Title 17, EPAct of 2005), accelerated depreciation, and subsidized borrowing (i.e., via Build America bonds). That is just for construction, and does not include federal subsidies for nuclear fuel, security, decommissioning/waste management, etc., nor any state-level support. Subtract the midrange of the UCS spread ($50) from the cost of nuclear power and the latter becomes $57/MWhr, compared to the “IGCC plus CCS plus EOR” cost figure of $97-101/MW/hr. Certainly every penny of every federal, state and local subsidy for those five nuclear plants under construction will figure prominently in comments on this rule.

This may be why EPA discusses federal funding for CCS, and concludes that “the availability of these governmental subsidies supports the reasonableness of the costs.” But EPA offers no specific numbers to the amount of this support aside from $1.2 billion apparently still available from DOE, and so the second legal fight will be whether EPA is justified in equating the cost of coal plus CCS to the cost of nuclear power . . . and whether EPA can rely for long-term cost analysis on programs that have a limited Congressional budgetary life.

Apropos of costs, that brings us to the third cost issue that will be litigated: the social cost of carbon (“SCC”). (Before it became fashionable, we said some things about SCC as well). For the first time an agency will have to use SCC to justify to a court the cost-benefit reasonableness of a regulation; in previous regulations where the SCC was used, the value of energy savings (from either electricity or fuel consumption) more than justified the costs imposed by the regulation. EPA tries its best to bury this issue: SCC is not discussed anywhere in the proposed rule, because EPA maintains that no one is planning to build coal without CCS anyway, and thus the rule will result in no “CO2 emission changes, energy impacts, monetized benefits, costs, or economic impacts.” But since coal interests can claim that changes in the price of natural gas vis-à-vis coal could make new coal plants economically feasible, EPA will have to show that the benefits of CCS outweigh the costs, and as the accompanying Regulatory Impact Analysis (“RIA”) shows (although this takes a lot of digging), the largest component on the benefit side is SCC.

Two Other Issues

CCS: Carbon Capture and Something

“The EPA notes that compliance with the standard of 1,100 lb CO2/MWh is determined exclusively by the tons of CO2 captured by the emitting EGU. The tons of CO2 sequestered by the geologic sequestration site are not part of that calculation.” The only requirement that EPA is imposing is that any site that accepts such CO2 must be covered by the GHG Reporting Rule and comply with requirements concerning drinking water aquifers. In other words, once the CO2 is injected, leakage into the atmosphere is irrelevant. While “EPA acknowledges that there can be downstream losses of CO2 after capture, for example during transportation, injection or storage. . . . EPA expects these losses to be modest with incentives due to the market use of CO2 as a purchased product.” Hmmm . . . The idea that regulatory requirements should not be imposed on an environmentally harmful substance because no one would let it get loose because it has market value is novel; we wonder if EPA proposes to extend that thinking to requirements for oil or natural gas wells, for example. More specifically in the case of EOR, its relevance only lasts up to the time the CO2 is injected and forces out the oil; and non-EOR CO2 lacks even this incentive.

“Modified” Coal Plants: Fuel Switching By Another Name?

Given EPA’s statement that this rule will have “negligible” costs, benefits and CO2 reductions, we were very surprised that EPA has effectively taken the position that this ban on new coal-fired plants (without CCS) will also apply to any existing plant that undergoes “modification”. Thus it would potentially apply to dozens of coal-fired plants that will install control equipment necessary to meet standards imposed by other recent rules, most notably EPA’s mercury and air toxics standards (MATS), or a revived Cross-State Air Pollution Rule (now in front of the Supreme Court). And if it does apply, these plants would have to either retrofit with CCS (nightmarishly expensive even when physically possible) or switch to natural gas (still a significant cost).

Officially, EPA says that these plants will be sheltered under a regulation that exempts such plants from the new plant standard if the modification is installing pollution control equipment. Such a regulation does exist, but as EPA pointed out in Version 1.0, a D.C. Circuit decision that overturned an identical and closely-related pollution control project exclusion “may call into question the continued validity” of this regulation as well. EPA could avoid all this by simply saying that modified plants need their own emission standards and propose a schedule for establishing these, presumably aligned with the forthcoming existing plant standard. By not doing so, it appears that EPA is none-too-subtly pushing these plants to fuel-switch to natural gas.

We (and many others) await further developments…..