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Memorandum

Subject: Economic Impact Analysis for the Final Reconsideration of the Mercury and 

Air Toxics Standards

Date: March 21, 2013

From: Amanda Curry Brown

Economist

Air Economics Group (C439-02)

To: Bill Maxwell

Environmental Engineer

Energy Strategies Group (D243-01)

This document addresses the economic impacts of the final reconsideration of the Mercury and 

Air Toxics Standards. Based on our analysis, we anticipate that there will be minimal compliance 

costs, emission changes, or economic impacts associated with this reconsideration.

Background

In December 2011, the U.S. Environmental Protection Agency (EPA) finalized the Mercury and 

Air Toxics Standards (MATS). Following promulgation of the final rule, the EPA received 20 

petitions for reconsideration of numerous provisions of the National Emission Standards for 

Hazardous Air Pollutants (NESHAP) portion of the rule pursuant and 4 petitions for 

reconsideration of numerous provisions of the New Source Performance Standard (NSPS) 

portion of the rule. The EPA granted reconsideration of the NESHAP new-source emission limits, 

including filterable PM monitoring and one issue raised in the NSPS portion (notice and 

comment for the definition of natural gas). These issues are discussed in detail in the preamble 

for the reconsideration.

This document focuses on the analysis of impacts for the revised emission limits in this 

reconsideration. For the NSPS, the EPA simply took comment on the definition of natural gas 

that was previously finalized. As such, there would be no costs or emission changes associated 

with this issue. 

Costs and Emission Impacts

To determine whether there would be any change in compliance costs or emissions resulting 

from the revised standards finalized in this reconsideration, the EPA considered the level of 

control required to meet each standard at a model 500 megawatt (MW) electricity generating 

unit (EGU) operating at 85 percent capacity. The analysis then considered the implications of 

the revised standard for the installation of control technology. More detail can be found in the 
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technical support document “Analysis of Control Technology Needs for Revised Proposed 

Emission Standards”.

Mercury (Hg) from EGUs burning non-low rank virgin coal

For the analysis of the revised Hg standard, the EPA assumed the model plant burns coal with 

an average Hg content of 11.10 lb/trillion British thermal units (TBtu). This is equivalent to the 

average Hg content reported for non-low rank virgin coals in the information collection request 

(ICR) for MATS.

Table 1. Hg Standards for New EGUs Burning Non-low Rank Virgin Coal

Standard % control

Final New Source Hg Standard 0.00020 lb/GWh 99.8%

Revised New Source Hg Standard 0.0030 lb/GWh 97.0%

While the level of control required decreases from 99.8 percent under the finalized Hg standard 

to 97.0 percent under the revised standard, this does not reflect a change in the control 

technology that would be required to achieve the standard. An EGU would need to install 

advanced Hg controls, such as activated carbon injection (ACI) with a fabric filter, selective 

catalytic reduction (SCR), or flue-gas desulfurization (FGD) in order to comply with either 

standard. This means there would be no significant incremental change in costs resulting from 

the revised standard. 

While mathematically the revision of the standard would result in an increase in emissions at 

this hypothetical plant, in practice any increase would be minimal. The control devices needed 

to comply with the Hg standard cannot be fine-tuned to achieve a precise level of emission 

reductions, but instead are used to achieve reductions within a range. For this reason, the 

revision of the Hg standard and subsequent selection and installation of control equipment 

should not result in a significant increase in emissions beyond what was estimated for the final 

MATS rule.

While EPA did not conduct a separate analysis for new EGUs burning low rank virgin coal, the 

changes in this reconsideration package for these units would not impact the anticipated 

control installations, nor do they significantly change the costs and benefits of the final MATS 

regulations. 

Particulates (PM) from coal-fired EGUs

For the analysis of the revised filterable PM (fPM) standard, the EPA assumed the model plant 

burns coal with an ash content of 10 percent. This is at the high end of expected values for 

bituminous coals and, therefore, a conservative estimate.
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Table 2. fPM Standards for New Coal-fired EGUs

Standard % control

Final New Source fPM Standard 0.0070 lb/MWh 99.99%

Revised New Source fPM Standard 0.090 lb/MWh 99.88%

Both the previously finalized fPM standard and the revised standard would result in the 

installation of high efficiency fabric filters, so there would be no significant change in cost 

relative to the previously finalize standard. As noted for the Hg standard, in practice, the 

revision of the fPM standard would not result in a significant increase in emissions over what 

was estimated for the final MATS rule.

While the EPA did not conduct a separate analysis for solid oil-derived fuel (pet coke) fired 

units, there are a limited number of these EGUs and the same technology choices would apply, 

resulting in no significant change in costs or emission reductions. 

Sulfur Dioxide (SO2) from coal-fired EGUs

For the analysis of the revised SO2 standard, the EPA assumed the model plant uses coal with a 

range of sulfur content from 0.6 lbs/MMBtu to 2.5 lbs/MMBtu.

Table 3. SO2 Standards for New Coal-fired EGUs

Standard % control

Final New Source SO2 Standard 0.4 lb/MWh 92.6 - 98.2%

Revised New Source SO2 Standard 1.0 lb/MWh 81.5 - 95.6%

The EPA believes that many units will choose to meet the alternative SO2 emission standard in 

lieu of meeting the HCl emission standard because they are already required to monitor for 

SO2. Additionally, Prevention of Significant Deterioration (PSD) requirements for SO2 under the 

New Source Review (NSR) program will drive the installation of high performing spray drier 

absorbers (SDAs) or wet-FGD scrubbers, regardless of the level of the MATS new source 

standard.1

While the EPA did not conduct a separate analysis for solid oil-derived fuel (pet coke) fired 

units, there are a limited number of these EGUs and the same technology choices would apply, 

resulting in no significant change in costs or emission reductions. 

 

1 NSR permit requirements include, among other things, the application of BACT (best available 

control technology) under PSD. BACT control technology determinations and associated 

emission limit establishment involve case-by-case analyses and such analyses take into account 

site-specific factors such as energy, environmental and economic impacts. For that reason, it is 

impossible to strictly predict the outcome of such analyses. However, based on recent BACT 

determinations for SO2 emissions from coal-fired EGUs, it is reasonable to expect that in most, 

if not all, cases, advanced flue gas desulfurization control technologies (such as wet-FGD 

scrubbers or high efficiency spray drier absorbers) would be required.
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Hydrochloric Acid (HCl) from coal-fired EGUs

For the analysis of the revised HCl standard, the EPA assumed the model plant uses coal with a 

range of chlorine content, based on the averages reported in the MATS ICR.

Table 4. HCl Standards for New Coal-fired EGUs

Standard % control

Final New Source HCl Standard 0.00040 lb/MWh 99.6 – 99.9%

Revised New Source HCl Standard 0.020 lb/MWh 81.0 – 96.6%

Revised New Source HCl Standard * 0.010 lb/MWh 90.5 – 98.3%

*Beyond-the-floor (BTF) emission standard

Some low-chlorine coals have high native capture due to the natural alkalinity of the fly ash and 

may only require limited incremental control, such as dry sorbent injection (DSI), to achieve 

either the final or revised new-source HCl limit. Units burning higher chlorine coals would need 

high performing FGD to achieve the previously finalized HCl limit, while the adjusted limit could 

possibly be met with lower performing controls. As explained for the SO2 standard, the EPA 

believes that many units will choose to meet the alternative SO2 emission standard in lieu of 

the HCl emission standard and that PSD requirements for SO2 will drive the installation of high 

performing SDAs or wet-FGD scrubbers, regardless of the level of the MATS new source 

standard. For that reason, the EPA conducted a beyond-the-floor analysis to determine the 

level of control achieved by applying expected FGD controls. Units with SDAs in the MATS ICR 

database were examined to determine the level of control achieved for low-chlorine and highchlorine coals. The analysis showed that the average level of control for units firing low-chlorine

coals was approximately 90 percent while that of units firing high-chlorine coals was 

approximately 98 percent (coal-to-stack control).2The new source HCl emission standard was 

then adjusted downward so that the model plant burning a range of coals met that expected 

level of control. In this case, there is likely to be no significant change in cost or emissions 

resulting from the revised HCl limit.

Filterable PM Monitoring

The EPA is finalizing the use of the same PM continuous parameter monitoring system (CPMS)

approach employed in the proposed Portland cement NESHAP. This CPMS approach, which 

requires emissions testing after each deviation of the operating limit, is a procedural change 

and will not impact the monitoring technology employed by affected sources. The EPA 

anticipates there will be negligible compliance costs or emission changes associated with this 

revision.

Economic, Employment, and Energy Impacts

 

2 Note that the differences in level of control are simply due to the fact that coals may have a 

range of chlorine contents. The emissions in either case are expected to be the same.
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Based on the analysis presented here, the EPA expects that the revisions to the MATS standards 

for Hg from EGUs firing non-low rank virgin coal, and for PM, SO2, and HCl from coal-fired EGUs, 

along with revisions to the filterable PM monitoring requirements, will not result in significant 

changes in costs or emission reductions relative to the previously finalized standards. As a 

result, the EPA does not anticipate any impacts on the price of electricity or energy supply. 

Additionally, for the reasons described above, the reconsideration is not expected to raise any 

reliability concerns, since reserve margins will not be impacted and the revisions do not impose 

new requirements on new or existing facilities.

The EPA typically presents the economic impacts to secondary markets (e.g., changes in 

industrial markets resulting from changes in electricity prices) and impacts to employment or 

labor markets associated with regulations based on the estimated compliance costs and other 

energy impacts, which serve as inputs to such analyses. However, because we do not estimate 

any significant change in cost in response to this reconsideration, there would also be no 

macroeconomic or employment impacts expected as a result of this rule.

Small Entity Impacts

The Regulatory Flexibility Act generally requires an agency to prepare a regulatory flexibility 

analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the agency certifies that the rule will 

not have a significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small not-for-profit enterprises, and small governmental jurisdictions.

According to the SBA size standards for NAICS code 221122 Utilities-Fossil Fuel Electric Power 

Generation, a firm is small if, including its affiliates, it is primarily engaged in the generation, 

transmission, and or distribution of electric energy for sale and its total electric output for the 

preceding fiscal year did not exceed 4 million MWh.

The EPA has determined that no small entities will experience a significant impact because the 

notice of reconsideration imposes no additional regulatory requirements on owners or 

operators of affected sources. We have therefore concluded that today's notice of 

reconsideration will not result in a significant economic impact on a substantial number of small 

entities.

Conclusions

Our analysis shows that new EGUs would choose to install the same control and monitoring 

technology in order to meet the revised emission limits as would have been necessary to meet 

the previously finalized standard. Under the relevant assumptions, we project that this rule will 

result in no significant change in compliance costs or emission reductions relative to the 

previously finalize standards and, as a result, no economic, energy, or employment impacts.

Additionally, there will be no impact on small entities.