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Date: November 6, 2012

Subject: National Emission Standards for Haza rdous Air Pollutants (NESHAP) Analysis of Control Technology Needs for Revised Proposed Emission Standards for New Source Coal-fired Electric Utility Steam Generating Units

From: Nick Hutson, U.S. EPA Of fice of Air and Radiation

To: Docket No. EPA-HQ-OAR-2009-0234

Introduction

The EPA has evaluated the levels of control that would generally be needed to meet the proposed revised emission limits for new sources and has compar ed those to the levels of control needed to

meet the new source emission limits that were promulgated in the final MATS rule. The EPA compared the level of control needed by analyzing requirements for a new model coal-fired 500 MW facility. The comparison has led the EPA to conclude that new units would need to be designed to use the same or very similar types of emission control technologies to meet the revised proposed new source limits as would have been required to meet the promulgated final

MATS new source limits.

Controls for Mercury Emissions

For mercury (Hg) emissions from the subcategor y of new EGUs not desi gned to burn low rank virgin coal, the model facility was assumed to bu rn coal with a Hg content of 11.1 lb/TBtu (the average Hg content of non low rank virgin coals sampled in the 2010 Utility Information Collection Request, ICR). An existing source, burning the same coal and subject to the promulgated existing source MATS limits, would need to remove a minimum of approximately 89.2 percent of the Hg (coal-to-st ack) in order to meet the 1.2 lb /TBtu existing source standard. By comparison, the new model facility would have needed to remove a minimum of 99.8 percent of the Hg (coal-to-stack) in or der to meet the final 2.0E-4 lb/GWh output-based emission limit. That same model facility, if subject to the proposed revised new source Hg emission limit of 3.0E-3 lb/GWh, would need to remove a mini mum of 97.0 percent of the mercury (coal-tostack).

Control technology providers, including some that petitioned for reconsideration, have indicated that facility operators normally target an opera ting level that is 25 to 50 percent lower than the emission limit in order to create a “margin of error.” In petitions, the Institute of Clean Air Companies (ICAC) suggested a margin 25 to 50 percent below the limit, while Babcock & Wilcox suggested a margin of 20 to 30 percent be low the limit. In that case, the new source would target a Hg removal of 97.6 to 98.5 percent (coal-to-stack). Any level of control above 95 percent at a new coal-fired EGU will certainly require advanced Hg control technology or optimized co-benefit control from other installed control equipment. The level of control for the proposed revised new source standards should be th e same or very similar to the high performingDRAFT

control technologies that would ha ve been expected if the new un it was subject to the finalized

MATS limit.

Controls for Filterable PM Emissions

For filterable particulate matter (fPM) emissions from coal-fired EGUs, the model facility was

assumed to burn a coal with an ash content of 8.6 lb/MMBtu (approximately 10 percent, which is the upper range of typical bituminous coals). Some of the ash can be expected to be removed as bottom ash while a much greater fraction would be expected to exit the combustor with the flue gas as fly ash and would be captured using a particulate control device such as a fabric filter (FF) or high efficiency electrostatic precipitator (ESP). An existing facility that is burning the same fuel and subject to the promulgated existing s ource standard for fPM (3.0E-2 lb/MMBtu), would need to control fPM at a level of approximately 99.65 percent (coal-to-sta ck). In comparison, the new facility would have had to remove a minimu m of 99.99 percent of the fPM (coal-to-stack) in order to meet the 7.0E-3 lb/MWh output-based emi ssion limit. That same facility, subject to the

revised new source fPM emission limit of 9.0E-2 lb/MWh, would need to remove a minimum of 99.88 percent of the fPM (coal-to-stack). However, again, if operators targ et an operating range that is 25 to 50 percent lower than the emission li mit in order to create a “margin of error” as petitioners have claimed, then the new s ource would target a fPM removal of 98.91 to 99.94 percent (coal-to-stack). Any of these stated control le vels would requir e modern, highperforming PM control technology such as high efficiency FF.

Controls for Hydrochloric Acid (HCl) Emissions

For HCl emissions from coal-fired EGUs, two anal yses were done. In one, the model facility was assumed to burn a higher-chlorine (Cl) content coal of 0.064 lb/MMBtu. In the other analysis, the model plant was assumed to burn a lower-C l coal with a Cl c ontent of 0.0114 lb/MMBtu. 1
These values roughly correspond to 830 parts pe r million (ppm) in the higher-Cl coal and 125 ppm in the lower-Cl coal. The Cl content of co al tends to vary by coal rank and by geographic origin. Some western subbituminous coals have such low Cl content that little to no HCl control

is needed to meet the exis ting source emission limit.

An existing facility burning the higher Cl bitu minous coal (and choosing to show compliance by monitoring HCl rather than the alternative sulfur dioxide (SO 2 )), would need to control HCl at a level of approximately 97.0 percent (coal-to-s tack). This would likely require a wet-FGD scrubber or a good performing spray drier absorber (SDA). By comparison, an existing facility burning the lower Cl subbituminous coal would need to control HCl at a level of approximately 83.0 percent. Because the fly ash from most we stern subbituminous coals (and many lignites) contains natural alkalinity, many of those facilities get considerab le native acid ga s neutralization from the fly ash. Some may get sufficient native HCl capture such that no additional add-on control technology is needed.

A new facility would have needed to remove a minimum of 99.6 percent for the lower-Cl coal and a minimum of 99.9 percent for the higher-Cl co al in order to meet the final MATS output-

1 These values are the average Cl contents of b ituminous and subbituminous coals from the Utility ICR

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based emission limit of 4.0E-4 lb/MWh. Those same facilities, s ubject to the proposed revised new source HCl emission limit of 2.0E-2 lb/MWh, would need to remove a minimum of 81.0 percent of the HCl when burning the lower Cl subbituminous coal and a minimum of 96.6 percent when burning the higher Cl bituminous co al. However, again, if operators target an operating range that is 25 to 50 percent lower th an the emission limit in order to create a “margin of error,” then the new source w ould target HCl removal in the range of 86 to 98 percent (coalto-stack, depending on the coal that is burned).

It is important to note that in most cases, a ne w fossil fuel-fired EGU would be required to obtain a preconstruction permit under the New Source Review (NSR) program. 2 The NSR program, including both Preventio n of Significant Deterioration (PSD ) and Nonattainment New Source Review (NNSR), applies to major new sources a nd major modifications at existing sources on a pollutant-specific basis depending on the attainme nt status of the area. NSR permit requirements include, among other things, the ap plication of BACT (best ava ilable control technology) under

PSD and Lowest Achievable Emission Rate (LAER) under NNSR. BACT and LAER control technology determinations and associated emi ssion limit establishment involve case-by-case analyses and, for BACT, such analyses take in to account site-specific factors such as energy, environmental and economic impacts. For that re ason, it is impossible to strictly predict the outcome of such analyses. However, base d on recent BACT determinations for SO 2 emissions from coal-fired EGUs, it is reasonable to expect th at in most, if not all, cases, advanced flue gas desulfurization control technologies (such as we t-FGD scrubbers or high efficiency spray drier absorbers) would be required. For th is reason the EPA has determined that it is cost effective to set a beyond-the-floor (BTF) emission limit for HCl. This is described in the Technical Support

Document “MATS Reconsider ation: Beyond-the-Floor Memo randum” (available in the rulemaking docket, EPA-HQ-OAR-2009-0234). In orde r to meet the BTF emission limit, a new facility would need to contro l HCl at a level of 90.5 percent to 98.3 percent (c oal-to-stack, depending upon the coal). This level of control will require the use of an SDA system at a

minimum.

Although an emission limit for HCl has been fina lized and now re-proposed, affected sources may instead choose to meet an alternative emission limit for SO 2 . A similar analysis was performed under the assumption that the model new unit would choose to meet the alternative

SO 2 emission limit. For this case three analyses were done. In one analys is, the model facility

was assumed to burn a low-sulfur coal with an equivalent SO 2 content of 0.60 lb/MMBtu. In another analysis, the model plant was assumed to burn a medium-sulfur coal with an equivalent

SO 2 content of 1.67 lb/MMBtu). A third analysis had the model plant burning a high-sulfur coal with an equivalent SO 2 content of 2.5 lb/MMBtu.

An existing facility w ould need to control SO 2 at approximately 67 perc ent to 94 percent (coalto-stack, depending on the type of coal burned) in order to demonstrate compliance for acid gas

HAP emissions. This level of control would require a wet-FGD scr ubber or a good performing

2 We indicate that NSR is required in most cases because it is possi ble that a new fossil fuel-fired EGU constructed at an existing st ationary source could “net out” of major NSR for one or more regulated pollutants if sufficien t qualifying reductions are available (e.g., from the shutdown of an existing EGU at the same source).DRAFT

SDA. A new facility would have had to remove SO 2 in a range of 93 percent to 99 percent (depending on the coal) in order to meet the 4.0E -1 lb/MWh output-based emission limit in the final MATS rule. That same facility, now subject to the revised new source SO 2 emission limit of 1.0 lb/MWh, would need to remove SO 2 in a range of 82 percent to 96 percent (depending on the coal – and even higher with high- S coals). This level of control would certainly require wet-FGD scrubber or SDA technology. And, as st ated earlier, it is reasonab le to assume that PSD BACT

determinations for new fossil fuel-fired EGUs will result in a requirement to install modern, high performing FGD technology.