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Memorandum

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

    Air Toxics Standards

Date:    November 16, 2012

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 proposed 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

proposed 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 is granting reconsideration of two issues raised in the NESHAP

portion of the rule (startup and shutdown provisions and 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 are discussed in detail in the preamble for the proposed

reconsideration.

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

this reconsideration. For the NSPS, the EPA is simply taking 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. Additionally, the revisions to the startup and shutdown provisions

are primarily clarifying and would also not result in changes to the costs or emission reductions

previously estimated for the final MATS rule.

Costs and Emission Impacts

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

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

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 proposed 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 high‐

chlorine 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).2 The 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 proposing to use 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.

                                                      

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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Economic, Employment, and Energy Impacts

Based on the analysis presented here, the EPA expects that the proposed 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 proposed reconsideration is not expected to

raise any reliability concerns, since reserve margins will not be impacted and the proposed

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 proposed rules 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 proposed reconsideration, there

would also be no macroeconomic or employment impacts expected as a result of this proposed

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
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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.