On September 20, 2013, the EPA proposed new source performance standards for greenhouse gas emissions for new power plants. Although the agency repackaged and fine-tuned an earlier proposal, issued in April 2012, it continues to hold the coal industry’s feet to the fire. The proposal makes clear that new coal-fired power capacity cannot be built without major reductions in carbon emissions. The agency’s new proposed rule continues to convey a critical message to utilities contemplating new energy-generation investments: utilities can no longer develop uncontrolled high-emission energy sources; future energy investments must either be lower-carbon or control carbon. The agency’s proposal provides clear parameters for future investments that set the nation on a more sustainable energy path.
This essay focuses on a critical difference between the September 2013 proposal and the earlier April 2012 proposal: how EPA has categorized electricity-generating units (EGUs). In this essay, I first explain the standard setting process, and then explain EPA’s decision to combine coal and natural gas facilities in its April 2012 proposal and its retreat from that approach in the September 2013 proposal. I then discuss the legal and policy implications of that shift. Although the change in categories did not make much difference in the standards set, it did shift the likely areas of legal controversy, and marks a shift in the agency’s posture in shaping utilities’ energy choices.
Because fossil fuel fired EGUs have been classified as industrial facilities that generate pollutants, and because greenhouse gases (GHGs) have been classified as air pollutants that endanger public health and welfare, EPA is obligated to establish new source performance standards (NSPSs) for EGU’s GHG emissions. For each industrial category EPA has identified, the NSPSs are to reflect the “best system of emission reduction” (BSER) that has been adequately demonstrated.
In EPA’s first power plant proposal, issued in April 2012, EPA combined most types of fossil-fuel EGUs into a single subcategory and determined that the BSER for all of them was 1,000 lb CO2/MWh, a level that reflects the uncontrolled emissions of a modern combined-cycle natural gas (NGCC) plant. The agency noted that a NGCC facility would reduce carbon emissions to a greater degree and at a much lower cost than use of any coal-fired technology, and so used the performance of an NGCC plant to set the standard for all fossil-fuel fired EGUs designed to meet base load or intermediate demand. The agency made clear that the rule did not preclude coal-fired power, but emphasized that such facilities would still have to meet the performance standard deemed “best” for the fossil-fuel subcategory, a standard based upon natural gas, not coal-fired power. (The agency observed that a coal-fired facility could meet the standard by using carbon capture and storage technology (CCS).)
The combination of coal and natural gas facilities into one subcategory was controversial because it differed from the approach taken for criteria pollutants: for criteria pollutants, the agency has established subcategories based on fuel type and set separate NSPSs for coal-fired and natural gas facilities. The agency had three primary justifications for combining coal and natural gas into one subcategory for GHG regulation: First, all of the plants in the combined category “perform the same essential function, which it to provide generation to serve baseload or intermediate demand.” (77 Fed. Reg. 22410) The agency explained that, as long as EGUs were all serving the same function, it was “sensible” to put them in the same category “regardless of their design or fossil fuel type.” (Id.) Second, the agency noted that builders of new EGUs all had the option of choosing either natural gas or coal, and so “could readily comply with the proposed emission standards by choosing to construct a NGCC unit.” (Id.) Third, in addition to these legal justifications for combining the categories, the agency concluded that the combination would not have an adverse policy impact by increasing energy costs or changing the diversity of energy supplies because so few new coal-fired power plants were projected.
The September 2013 proposal, in contrast, separates natural gas and coal-fired facilities. The BSER for large natural gas facilities remains the same as in the April 2012 proposal, and the new proposal creates a slightly more lenient standard for smaller, less efficient, natural gas facilities (1,100 lb CO2/MWh). In contrast to the April 2012 proposal, coal-fired power plants now have their own subcategory and their own BSER. Rather than basing the requirements for all fossil-fuel power plants on the performance of natural gas, EPA evaluated the control options for coal-fired power directly. EPA concluded that coal-fired power coupled with partial carbon capture and storage (CCS) constituted the BSER for coal. With the application of CCS, coal-fired power could achieve emissions of 1,100 lb CO2/MWh, averaged over a 12-month operating period, the same as the standard for smaller natural gas facilities. (The agency also proposed an alternative compliance option for coal-fired plants of 1,000-1,050 CO2/MWh over a 7-year operating period.) The ultimate standards for natural gas and coal facilities remains similar, but the basis for setting the standard differs from the April 2012 proposal. In the new proposal, the standard for coal-fired EGUs is based on an assessment of BSER for coal-fired power itself, not on a calculation of BSER for all fossil-fuel generated power.
EPA explains that it decided to re-separate coal and natural gas facilities in the new proposal because of increased projections of new coal-fired investments. That explanation rings somewhat hollow, however. The agency’s primary legal justifications for initially combining the categories—that both types of facilities are designed for the same purpose and utilities have the capacity to choose either—remain true whatever the projections of utilities’ planned activities. And, although the last justification for combining the categories—that low numbers of projected coal-fired power plants meant that there would be few adverse policy consequences to the combination—is impacted by projections of greater numbers of future coal-fired facilities, the new proposal makes clear that the number remains quite small relative to natural gas. Thus, the small increase in projected new coal-fired facilities also does not appear to fully explain the decision to separate coal and natural gas. Ultimately, the agency appears to have either feared a legal challenge to its decision to combine categories, or identified political benefits to treating natural gas and coal-fired power separately.
From a legal standpoint, EPA appears to have traded one legal risk for another. Separating the categories avoids a legal challenge to the earlier proposal’s combined subcategory. At the same time, the creation of separate subcategories means that EPA now has to justify CCS as the BSER for coal-fired power. Under the April 2012 proposal, EPA had only to show that combined cycle natural gas was BSER for fossil-fuel based EGUs, a relatively easy showing since it is well-demonstrated and cost-effective. In the earlier proposal, the agency made clear that it was not claiming that CCS was BSER for coal-fired power; it provided the CCS option only to show that the natural gas-based standard would not preclude the development of coal-fired power because a utility could still build a coal-fired power plant if it chose, so long as it adopted CCS. Under the new proposal, in contrast, with coal-fired power in its own category, EPA will have to confront industry arguments that CCS is neither sufficiently demonstrated nor economically feasible. EPA’s proposed rule provides an extensive justification for CCS as BSER, but the conclusions are likely to be contested. And if EPA loses, then the standard for coal-fired power is likely to allow much higher emissions than the standard for natural gas because the most efficient supercritical and ultra-supercritical coal-fired power plants have carbon emissions in the range of 1,800 lb/MWh, much higher than the 1,100 lb/MWh established for coal in the current proposal.
In sum, it’s not clear whether combined categories or separate categories plus CCS for coal present the greater net legal risk. The April 2012 proposal combining types of EGUs into one category created a high risk of litigation regarding the combination of categories but low risk over the BSER determination. In contrast, the September 2013 proposal’s separation into two categories lessens the risk of litigation over categories but increases the risk of litigation over BSER (namely, whether CCS is BSER).
Aside from the legal issue, the shift in categorization presents a conceptual shift, and it’s possible that the decision to separate the categories had as much to do with politics as law. When EPA combined categories in the April 2012 proposal, the agency defined the category by the objective of providing baseload or intermediate demand energy and told utilities that the way to meet that objective was through building NGCC facilities. The agency was careful to note that that did not preclude using coal because coal plus CCS could meet the standard, but the agency made clear that the standard was based on and justified by the expectation that facilities would and could choose natural gas. In separating the categories again, EPA defers the decision about what fuel to use to the utilities, and simply indicates that if they use natural gas, they must meet “x” standard and if they use coal, they must meet “y” standard. The standards come out looking relatively similar, but, by separating the categories, the agency does not appear to be suggesting, as it did in the earlier proposal, that utilities are expected to adopt a particular fuel and technology.
By separating the categories, EPA may have avoided political fallout, but it also lost the strength of the political statement made by combining categories. The risks of climate change are enormous. EPA is responsible for controlling carbon pollution. If two technologies will accomplish the same purpose, then, arguably, EPA’s earlier combination sent the important message that its standard would reflect the more effective and cheaper choice: natural gas. Utilities could choose to pursue coal, but then the cost and effort of doing so would be “on them;” the standard itself was set by the cheaper and more effective natural gas alternative. By separating the categories, EPA has stepped back from playing any role in technology choice. The agency should be applauded for the strength of the standard it established for coal-fired power, but it has lost a bit of the “edge” of its message.
In the new source context, it is not clear how much is at stake; this may be a tempest in a teapot given coal’s fading future. Even if EPA loses the legal battle over CCS as BSER and the NSPS standard for coal-fired power becomes significantly weaker, few coal-fired power plants are projected given existing market trends toward natural gas and so the emissions impact may not be large. Nonetheless, given the significant risks posed by carbon pollution and the risk of an unanticipated resurgence, the legal defensibility of the agency’s strong coal standards is not irrelevant.
And however rhetorical the debate over categories might be in the new source context, it could be more significant when EPA develops power plant guidelines for existing sources, where the “category” question is likely to be of central importance. If EPA proceeds along traditional category-based lines, then the reduction options are likely to be quite limited. EPA has projected, for example, that existing coal-fired power plants can achieve only about a 5-percent reduction in emissions, largely from on-site efficiency improvements. (At least so far, EPA has made clear that it does not consider CCS to be a viable option for existing coal-fired power plants.) However, if the fossil-fuel sector is treated as a single category, then EPA could set emission reduction expectations to encourage shifts in current supply. For example, an averaging approach would encourage utilities to shift energy production to the lowest-emitting facilities, presumably natural gas rather than coal. That could accomplish much more significant reductions than a category-specific approach. Hopefully, EPA’s reticence in establishing a single subcategory in the new source context will not impede its willingness to devise new and more effective subcategories in the existing source context.
Originally posted on CPRBlog.