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This summary of interagency comments contains comments on the EGU MACT Preamble, RIA, 

the October 2002 EPA Study, and the TSD titled “RESOURCE ADEQUACY AND RELIABILITY 

IN THE IPM PROJECTIONS FOR THE TOXICS RULE.” Comments on Chapter 9 of the RIA 

are forthcoming. These comments are subject to further policy review.

Applicability

The preamble indicates that only coal-fired and oil-fired EGUs are covered under the EGU 

MACT. Is this correct, or are other fuels (e.g., biofuels, etc.) and co-firing also covered by these 

standards?

If other fuels are not covered by these standards, how will EPA handle units firing multiple 

fuels? Could fuel mix be a control strategy for meeting the emissions standards to be developed 

under this rule?

Response: EPA has addressed this issue through its proposed 

definition of “fossil fuel-fired” where a defined amount of coal 

or oil must be fired in order for a unit to be considered 

“fossil fuel-fired and, thus, subject to the rule.

Compliance Timeframe and Reliability

Attention needs to be given to the required industrial capacity and the time needed for electric 

generating units (EGU’s) to comply with the full spectrum of proposed and pending EPA 

regulations. Issues associated with the short time frame allowed by law for compliance with this 

rule will be compounded by the need for the electric power sector to install environmental 

compliance equipment to meet other pending regulations during the same time period. Factors 

that need to be addressed are the supply chain and work force issues associated with future 

retrofits of EGUs. A comprehensive assessment of all regulations (for all media air, water, and 

solids – including greenhouse gas regulations) requiring installation of new equipment or 

modification of existing equipment at EGU’s needs to be conducted to determine if there is 

sufficient time to allow utility companies to secure equipment (often from foreign suppliers), in a 

cost effective manner (supply/demand pricing for the equipment) while also having sufficient 

skilled labor available to install it. For example, welders and other trades are in short supply in 

some regions. The impact of the statutory requirement to comply with the Toxics Rule within 3 

to 4 years on the reliability of the electric grid also needs to be determined. Assumptions about 

when retrofits could be completed may impact the availability of power plants and reserve 

margins due to the maintenance outages, potential for permit violations, and delays caused by 

labor shortages or delayed delivery of equipment. Therefore, it could be useful for EPA to 

describe its options for addressing the operation of non-compliant plants at the end of 

the compliance period. For example, if NERC issues an advisory that taking the plant 

offline could create a justified reliability concern, what options would EPA have for 

implementing the policy at that point?

Response: With regards to further analysis of issues related to 

industrial capacity and the time needed for EGUs to comply, 

while we believe that our analysis does show that based on 

historical installations, the variety of options for compliance 

and large reserve margins that there are enough resources and 

time. However we are happy to continue to work with you on 
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these issues between the proposal and final to further 

investigate these issues. With regard to describing options for 

addressing the operation of non-compliant plants, if we properly 

understand your question, the answer in short is that EPA’s 

options depend upon the specific circumstances. There are many 

different kinds, and degrees of significance, of reliability 

issues. The more significant reliability issues in each system 

are well known by both the generation sources and system 

operators and are specifically addressed in system operating 

plans. With the three years (or four years for installation of 

controls at the discretion of the permitting authority) that 

power plants have to determine and install their selected method 

of compliance with the Utility MACT, it is our expectation that 

most, if not all, of the reliability issues that are related to 

whether a specific unit will comply through unit retirement will 

be identified and addressed by the system operator and the 

source prior to the compliance deadline. We recognize that it 

is possible that a reliability issue may arise close to the MACT 

compliance deadline. Again, our expectation is that normal 

prudent system planning activities will both identify these 

issues as well as a solution in time to allow for any necessary 

unit retirement without unacceptable impacts on reliability. 

Where an operator continues to operate a unit after the MACT 

deadline without meeting the requirements of the Rule, it is 

subject to enforcement action. If NERC issues an advisory that 

taking the plant offline could create a justified reliability 

concern, EPA would work with NERC (and any other pertinent 

regulatory bodies) and together look to the statutory criteria 

set out in the Clean Air Act and other applicable statutes and 

implementing regulations and evaluate all relevant factors 

including any whether the unit is required for reliability and 

the steps taken by the owner/operator of the unit to come into 

compliance.

EPA cites assurances that the industry can fully install all necessary equipment within three 

years, and separately states that outages usually occur during off-peak seasons when reserves 

are higher. However, the two statements don’t necessarily relate to each other. If over 88% of 

the productive generating capacity must be upgraded within three years, will EGUs have the 

luxury of waiting until off-peaks seasons to perform the upgrade? Constraints in the production 

of emissions control equipment may require year-round upgrades and may even encourage 

incentives to schedule upgrades during peak periods to maintain a constant workflow.

Response: Historically companies have scheduled outages for 

control installations during off-peak seasons. We have done 

analysis showing that there is enough capacity to allow this to 

happen if all of the installations occur within a one year 

period. Because some of these installations may in fact be 
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completed early (because for certain options lead times are 

shorter and based on the CAIR experience we believe that many 

companies have already begun planning) and there is flexibility 

with the permitting extension for some of these installations to 

occur in the fourth year, we believe it is reasonable to assume 

that companies will continue to conform to their historical 

practice of installing controls during off peak periods.

o EPA states: “Reliability concerns cause by local transmission constraints can be addressed 

through a range of solutions including the development of new generation and/or demand 

side resources, and/or enhancements to the transmission system.” Has EPA developed 

cost estimates with these local constraints in mind? To what extent do the reserve 

margins cited elsewhere account for local variability?

Response: As explained in the preamble, given the relatively 

small number of retirements that EPA projects, we believe that 

there are likely to only be a small number of areas where this 

is an issue.

o Current “large” reserve margins may be a function of the economic downturn. If the 

economy picks up in 2012, what are the projections for the reserve margin? Is there 

any sensitivity analysis of the reserve margins? How are the projected reserve 

margins adjusted to reflect other concurrent regulatory programs that may lead to 

retirement or time off-line to comply, e.g., 316(b) and GHG NSPS?

Response: The projections for the reserve margin incorporate 

EIA projections for electric demand growth that account for 

economic growth. Although neither of the other two regulations 

have been proposed, the timeframe for installing controls is 

likely to be after 2015.

Along with the statement made atop page 464 that EPA will coordinate with DOE and FERC, 

the preamble for the rule can include more discussion of how electric reliability would be 

considered during implementation of the regulation. For instance, EPA can acknowledge 

that as multiple facilities make major modifications to meet new regulatory requirements, 

extensive and ongoing regional coordination between the industry, electric reliability 

organizations, and EPA will be required to ensure adequate generation is available to meet 

load. Adequate safeguards must be in place throughout the policy implementation to achieve 

both the intended environmental protection and to maintain electric reliability.

Response: New language has been added.

Permitting Authorities’ Discretion to Grant One-Year Extension - Under Section 112, 

existing sources may be granted up to 3 years to comply with the final rule. A permitting 

authority has the discretion to grant a 1-year extension, on a case-by-case basis, if such 

additional time is necessary for installation of controls. There could be situations in which a 

source operating a coal-fired facility subject to this MACT rule may find it expedient to replace 

the coal-fired unit with gas-fired simple cycle or combined cycle turbine facility. Any such 
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replacement could be driven by factors such as proximity to supply of natural gas, the large 

costs associated with the operation of an older coal-fired facility, and other factors unique to that 

facility. For such a facility, replacement of the coal-fired unit with a gas turbine may not only be 

cost effective, but also beneficial to the environment in terms of lower emissions of HAPs. 

However, the construction of any such replacement facility may take longer than three years 

after the effective date of this MACT. Accordingly, we recommend that EPA recognize in the 

preamble or elsewhere in the rulemaking record that the one-year extension for 

installation of controls should be made available to sources that have decided to replace

Response: EPA is still evaluating this issue.

Delays Due to NSR Permitting - The pollution control equipment constructed to comply with 

the proposed MACT rule has the potential to trigger NSR permitting, posing further challenges 

to industry’s ability to meet the 3 year compliance schedule. Accordingly, the rule should 

recognize that the time required to obtain any such NSR permit should be one factor that 

permitting authorities take into account in granting the 1-year extension to demonstrate 

compliance with the MACT standards.

Response: EPA believes that inherent in the installation of 

controls is compliance with applicable permitting requirements 

prior to installation of such controls; therefore, permitting 

issues that delay installation of controls could be considered 

by a state in evaluating whether to provide an extension of time 

to comply with the final rule. Sources should, however, quickly 

evaluate to potential need for a permit to avoid if possible any 

delays in obtaining the permits necessary to install controls to 

comply with the standards.

Time to Install Controls

In the preamble on page 467, EPA states: “Although EPA assessed the ability to install the 

controls in 3 years (and determined that the controls could be installed in that time-frame), this 

would require the control technology industry to ramp up quickly”. (emphasis added) 

The attached report entitled Issues Associated with the Acceleration of Tennessee Valley 

Authority’s Clean Air Program, prepared by a TVA expert in conjunction with the nuisance 

lawsuit (North Carolina v. TVA), sheds light on scheduling issues relating to the construction of 

FGDs and SCRs. The report states in pertinent part: 

A typical FGD project installation duration from conceptual design to commercial operation 

averages 5 years. A typical SCR project installation duration from conceptual design to 

commercial operation averages 3 to 4 years depending on the size of the unit and complexity 

with the retrofit installation. There are also schedule implications of the SNCR and SO3 

mitigation projects that must be worked in conjunction with the new installation of FGDs and 

SCRs. TVA is confident in our projections for the time needed to complete FGD and SCR 

projects, which are based on TVA’s actual experience to install FGDs and SCRs on several 

units, input from Advatech (TVA’s FGD partner), benchmarking with other utilities and an 

extensive program review on cost and schedule conducted by Bechtel Power Corporation. 

(Executive Summary, p. 5)
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The above expert report was prepared in February 2007, a period when CAIR was being 

implemented.

The report explains that the scheduling pressures placed on utilities by CAIR stretched the 

market capacity for many critical resources. The rigorous schedules of the proposed EGU 

MACT Rule and that of proposed Transport Rule would further stretch the market capacity for 

these resources to an unsustainable level. The schedules assumed by the EGU MACT Rule for 

construction of SCRs and FGDs are in fact impractical and unachievable. As an example, TVA 

completed the installation of the FGD on Paradise Fossil Plant Unit 3 in approximately 5 years, 

considering the time from conceptual design to commercial operations. The actual project 

schedule for the Paradise FGD is shown as Figure 3 in the attached expert report. Even this 

schedule may not be achievable at some sites due to space and other site specific constraints. 

For plants requiring installation of both FGD and SCR, physical site constraints commonly result 

in sequencing the installations and lengthening schedules approximately 2 years. Since the 

Paradise FGD was completed and TVA’s expert report finalized, the pollution control project 

exclusion in EPA’s NSR regulations was vacated by the United States Court of Appeals for the 

D.C. Circuit in New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005). This vacatur adds additional 

pre-construction air permitting requirements for those air pollution control projects that may 

result in significant emission increases of regulated pollutants. TVA estimates that it would take 

9 to 12 months (and possibly longer) to develop a permit application and obtain a permit for an 

air pollution control project that has the potential for significant emission increases. The 

permitting process would add several months to the overall project schedule. 

Further, permitting and construction of scrubber by-product disposal areas is required for most 

FGD projects, and for virtually all where the FGD is the first FGD for a particular facility. 

Typically this work can be completed concurrently with the normal 5 year period for FGD design 

and construction. If EPA determines, as identified as an option in EPA’s proposed Coal 

Combustion Residuals Rule, that scrubber by-product must be disposed of as hazardous waste 

in landfills permitted under subtitle C requirements, more time will be required. Subtitle C 

landfills have often required 6 to 8 years for permitting and construction. Moreover, schedules 

must also be adjusted to accommodate the permitting process for any modifications to the 

facility’s NPDES permit for the wastewater discharge from the scrubber. Also, as a federal 

agency, TVA must comply with the environmental review requirements under the National 

Environmental Policy Act, Endangered Species Act, National Historic Preservation Act and 

other environmental statutes prior to undertaking these projects, often resulting in additional 

time necessary to complete the projects. 

The controls and new capacity required nationwide to comply with the proposed EGU MACT 

Rule will require a significant increase in skilled labor, manufacturing, and material resources for 

the construction of pollution control equipment and will cost billions of dollars. We anticipate 

scheduling impacts and cost increases due to resource constraints. Unit outages for controls 

installations must be staggered and avoid peak demand seasons to ensure reliability. With the 

final EGU MACT Rule expected in late 2011, the earliest that construction of the required FGDs, 

SCRs, and new gas fired units could be achieved is late 2016. The resource and schedule 

constraints described above, including permitting and environmental review, may result in even 

later completion dates for many pollution control projects. If the rule becomes final in November 

2011, the final compliance date would be in 2015. We believe this compliance date is not 

achievable even with the CAA provision which allows permitting authorities the discretion to 

grant extensions to the compliance time-line of up to 1 year for installation of controls.
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Response: EPA’s analysis suggests that most of the controls to 

be installed will be, dry scrubbers, sorbent injection, 

activated carbon injection, baghouses and particulate device 

upgrades. These typically take less time to install than the 

SCRs and wet FGDs cited in the report.

Area Sources

The SBAR SERs recommended that EPA consider a GACT alternative, but this has not been 

addressed. Althoughwe do not know that a GACT would benefit small entities, it is a legitimate 

significant regulatory alternative that should be considered for its impact on small entities. This 

is particularly true given EPA’s assertion that there are relatively few sources that would qualify 

as area sources. We recommend that EPA do the following:

 Specify regulatory details of a GACT alternative for area sources.

 Identify natural and synthetic area sources that could be subject to a GACT 

alternative.

 Compare the costs and benefits of imposing a MACT on these sources instead of 

a GACT.

Response: In the preamble, we note that the Small Entity 

Representatives (SERs) serving on the Small Business Advocacy 

Review Panel (SBAR) established under the Small Business 

Regulatory Enforcement Fairness Act (SBREFA) suggested that EPA 

consider developing an area-source (i.e., those EGUs emitting 

less than 10 tpy of any one HAP or less than 25 tpy of any 

combination of HAP) vs. major-source (i.e., those EGUs emitting 

10 tpy or more of any one HAP or 25 tpy of more of any 

combination of HAP) distinction for this source category. The 

proposed rule treats all EGUs the same.

In section 112(a)(8), Congress defined an EGU as “...any fossil 

fuel fired combustion unit...” (Emphasis added). A reasonable 

interpretation of this definition is that Congress intended the 

Agency to regulate EGUs together in the same manner, if we 

determined that regulation under CAA section 112 was appropriate 

and necessary. In this case, we are proposing to set MACT 

standards for all EGUs. 

In any event, nothing in the CAA requires that we issue GACT 

standards for area sources. Indeed, here, the data show that 

similar HAP emissions and control technologies are found on all 

sources greater than 25 MWe. In fact, because of the 

significant number of well-controlled EGUs of all sizes, we 

believe it would be difficult to make a distinction between MACT 

and GACT. Moreover, EPA believes the standards for area sources 

should reflect MACT, rather than GACT, because there is no 
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essential difference between area source and major source EGUs 

with respect to emissions of HAP. There are EGUs that are 

physically quite large that are area sources, and EGUs that are 

small that are major sources. Both large and small EGUs are 

represented in the MACT floor pools for acid gas, Hg, and non-Hg 

metal HAP.

Given that EPA is developing major and area source standards at 

the same time in this rulemaking, a common control strategy 

consequently appears warranted for these emissions. 

Accordingly, we believe it is appropriate to set MACT standards 

for both major and area source EGUs. EPA is soliciting comment 

on its proposed approach.

Further, the sources preliminarily identified as being natural 

and synthetic area sources are both large and small EGUs owned 

by both “large” and “small” entities. Commenter has not 

indicated how EPA could make a meaningful distinction between 

large EGUs (e.g., 500+ MWe) that are owned in small proportion 

(e.g., 1.5%) by a number of small entities along with entities 

that are not “small” vs. single EGUs, regardless of unit size, 

that are owned entirely by small entities.

HBEL

EPA’s authority to establish health-based emission limits under Section 112(d)(4) is 

discretionary. It would be appropriate for EPA to use this discretion to establish a health-based 

emission limit for HCl and other acid gases. The compliance cost savings from establishing 

such a health-based standard would be substantial. In fact, we suggest estimate the costs 

and environmental effects of a health-based emission limit compared to the conventional 

MACT standard that it has proposed. The current economic climate dictates a balancing of 

economic and environmental interests.

EPA presents a number of reasons it does not develop a regulatory alternative under 112(d)(4), 

including the presence of cumulative emissions from entities not regulated by this rule and the 

substantial co-benefits.

o EPA cites to the significant co-benefits as a basis for declining to use the 

Administrator’s discretion. If the Administrator has the discretion to consider factors 

other than the level of HAP emissions from the regulated industry, then EPA should 

be complying with EO 12866, EO 13563, and the RFA and considering costs and 

benefits of this regulatory alternative.

o EPA asserts very firmly that it does not have the discretion to decline to regulate, 

even when allowed to consider cost, where there are lower cost alternatives affecting 

different sectors of the economy. However, here, emissions from other sources not 

regulated by this rulemaking are presented as crucial to the Administrator’s ability to 

exercise this discretion. This appears to be a statement that (d)(4) can only be used 
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when every sector of the economy can meet a health based standard. Since (d)(4) 

is not supposed to be NAAQS for HAPs, there must be a way of regulated only one 

set of facilities at a time.

o If proximity to other HAP sources is the basis for refusing to set health-based 

standards, then EPA should be open to an optional standard at the facility 

boundaries. Some EGUs won’t be able to use the standard because of their 

neighbors, but others may be able to.

o It is unfortunate that EPA decided early on that it would not exercise (d)(4) discretion 

because of the massive co-benefits, particularly since it gave EPA a reason to not 

seek the information it now states it would need. 

As the preamble confirms (p. 438), EPA has already created regulatory precedence for 

addressing HCl as a threshold pollutant in developing the Pulp and Paper NESHAP (1998) and 

the Lime Manufacturing NESHAP (2002). In those earlier instances, EPA exercised its 

discretion to exempt HCl from the MACT requirement altogether. Here, EPA should use its 

discretion to set an emission standard based on the health threshold in view of EGUs being the 

largest anthropogenic emitters of HCl in the United States. Such regulation based on health 

thresholds would be far more preferable to the proposed approach of setting MACT standards 

for acid gases regardless of the incremental health benefits. Likewise, while accrual of 

collateral benefits from the control of criteria pollutants is noteworthy, other provisions of the 

CAA, such as Sections 108 to 110 addressing the establishment and achievement of National 

Ambient Air Quality Standards, are the proper vehicles for mitigating the impacts of emission of 

criteria pollutants.

Response: We address in the preamble the factual, legal, and 

policy-related issues associated with the establishment of 

health based emission standards for the acid gas HAP (HCl, HF, 

HCN, and SeO2).

Regulatory Flexibility Compliance

EPA does not appear to have considered regulatory flexibilities for small entities, as required by 

the Regulatory Flexibility Act and the President’s Memorandum of January 18, 2011 (“. . . I 

hereby direct executive departments and agencies and request independent agencies, when 

initiating rulemaking that will have a significant economic impact on a substantial number of 

small entities, to give serious consideration to whether and how it is appropriate, consistent with 

law and regulatory objectives, to reduce regulatory burdens on small businesses, through 

increased flexibility.”)

Even in those circumstances where statutory authority or practical requirements make 

flexibilities difficult, EPA should directly address them.

In particular, EPA has not consider different compliance standards, different reporting 

recordkeeping requirements, compliance date extensions for small entities (except 

through the case-by-case discretionary review available to all), or exemptions for small 

entities. We suggest that EPA address this by considering alternatives.
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It appears that EPA has rejected significant regulatory alternatives identified by the SBAR panel 

SERs and Advocacy without reference to the benefits such alternatives may have for small 

entities and without explaining how the alternatives would fail to accomplish the “stated 

objectives” of the CAA.

Response: EPA has considered alternatives “consistent with law 

and regulatory objectives,” and is proposing several of them 

that we believe are within our statutory authority and 

consistent with our regulatory objectives. Some of the 

alternatives that are being, or have been, considered include:

a. Statutorily mandated “floor” alternative for each HAP or HAP 

group and subcategory -- proposing and taking comment.

b. Beyond-the-floor alternative for mercury emissions from 

lignite-fired units -- proposing and taking comment.

c. Consideration of beyond-the-floor for the remaining HAP or 

HAP groups and subcategories -- considered and not proposing, 

but taking comment.

d. Use of HBEL's -- considered and not proposing, but taking 

comment.

e. Distinction between area and major sources -- considered and 

not proposing, but taking comment. 

f. Additional subcategories -- considered and not proposing, 

but taking comment.

g. Emissions averaging within affected facilities -- considered 

and proposing.

h. Reduced emissions testing for “low emitting EGUs” (LEEs) –

considered and proposing.

As noted by the commenter, we are not considering any compliance 

date extensions beyond those being considered for all sources. 

Section 112(i)(3) sets clear limits on the compliance time 

frames and EPA cannot deviate from those time frames for any 

subcategories or regulated entities. Absent legal basis for the 

regulatory alternatives, there is little merit in assessing 

benefit.

Unfortunately, where EPA does discuss regulatory alternatives, it does not provide sufficient 

information for a regulated entity to evaluate the alternative, either for costs or fidelity to the 

statute, making public comment on the flexibilities and the IRFA extremely difficult.

Response: We are not sure to what alternatives the comment 

refers.

The description of “any significant alternatives” is missing from the IRFA in Chapter 10 of the 

RIA. The block quote of chapter 9 of the panel report does not fulfill this obligation. The panel 

report describes mostly factors for EPA to consider in its rulemaking, not “any significant 
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alternatives to the proposed rule which accomplish the stated objectives of applicable statutes 

and which minimize any significant economy impact of the proposed rule on small entities.” 

The description of alternatives in the UMRA section also does not fulfill this IRFA requirement 

because describes the regulatory alternative selected, with some of the presented options, but 

not a reasonable range of regulatory alternatives not proposed.

Response: See general answer above, no addition planned.

EPA must provide the IRFA or a summary of the IRFA in the preamble (see 5 USC 603(a)).

Response: See general answer above, no addition planned.

Footnote 5 in the IRFA (“Results for small entities discussed here do not account for the reality 

that electricity markets are regulated in parts of the country. Entities operating in regulated or 

cost-of-service markets should be able to recover all of their costs of compliance through rate 

adjustments.”) should be discussed in more detail. Not all costs can be recovered and not all 

processes are timely or complete.

Response: See general answer above, no addition planned.

Subcategorization

EPA’s consideration of alternative subcategorization is lacking. EPA does not present data to 

support its contentions that no other subcategorization scheme can be supported. In particular, 

the argument that all various technologies appear in the top 12% is not itself an argument 

against subcategorization, but rather an argument that subcategorization might generate small 

emissions control difference between technologies. However, EPA does not present data or 

alternative emissions standards to support that contention, so EPA’s dismissal of regulatory 

options is premature. This is particularly pointed in this case, since EPA’s request for comment 

demands of the public a scope and degree of information EPA itself doesn’t present in support 

of its own decision.

Response: EPA may not subcategorize strictly on the basis of 

the use of different control technologies. Therefore, 

commenter’s suggestion to that extent is unmerited. The fact 

that all of the various control technologies appear in the top 

12% is, in fact, an indication that there are no emissions 

differences and, thus, no basis for seeking a subcategorization 

scenario that would be based on control technologies. See 

preamble section V.A. Where the data indicated such differences 

(e.g., for mercury and boilers designed to burn lignite coals), 

EPA developed a subcategory for proposal and comment. All of 

the 2010 ICR data are currently available to the public and 

EPA’s analysis spreadsheets will be available at proposal for 

use by the public. 

EPA does in fact provide the level of detail we request from 

commenters for the subcategories for which we established 
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standards. EPA could not reasonably evaluate all of the 

potential different subcategory options and, because we believe 

the data do not support additional subcategories, we determined 

not to evaluate in detail other subcategories. However, if a 

commenter has a specific subcategory they would like considered, 

the data are available for the commenter to evaluate the 

subcategory and provide the information we request in the 

proposed rule. We are not requiring commenters to evaluate all 

of the potential subcategories in detail before they comment.

EPA has proposed to subcategorize coal-fired EGUs into two categories based on the calorific 

value, using 8300 BTU/lb as the demarcating point. The MACT standard is 1 lb/TBTU for 

existing coal-fired boilers designed for coal ≥ 8300 BTU/lb, and 2 lb/TBU for existing coal-fired 

boilers designed to burn coal ≤ 8300 BTU/lb. There is a wide range (a 2:1 ratio) between the 

standards for Hg in these two subcategories, based merely on a rough categorization relying on 

calorific value. One commenter believes it would be more appropriate to subcategorize EGUs 

based on the type of coal being fired. Further, the categorization should be based on the coal 

fired historically instead of the coal designed to be fired. Can EPA propose or solicit 

comment on this subcategorization approach?

Response: It is the Agency’s policy that the rank of the coal 

being used (or other material input) not be the basis for 

subcategorization. This is consistent with the approach taken 

in the Portland Cement NESHAP where a separate subcategory was 

not developed for separate feedstocks. Consideration has also 

been given to comments received during and subsequent to the 

CAMR rulemaking that the use of coal rank alone as a basis for 

subcategorization is illegal. In addition, the data are not 

showing a difference in emissions among the various coal ranks 

except for Hg emissions from the subcategory at issue, thus we 

do not think additional subcategorization based on coal rank 

would be consistent with the statute.

EPA has selected the ASTM designation of lignite vs. 

subbituminous coal (i.e., the less than or greater than 8,300 

Btu/lb designation) as the basis for subcategorization because 

units that are designed to burn the lower Btu coal are larger 

and thus of a different type. EPA is taking comment on this 

approach. EPA has reassessed its analysis of the lignite data 

and has made the appropriate changes in the preamble.

MACT Standards – Existing Units

EPA’s discussion of setting the MACT floor is ambiguous as to how it treated the ICR data to 

ensure that the top 12% represented the top 12% of all EGUs in the subcategory rather than 

only the 12% of those that provided data in response to the 2010 ICR. This issue was 

addressed in the SBAR panel report, and EPA’s response should be clearer to avoid 

controversy.
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Response: EPA does not believe that there is any ambiguity in 

its selection of the top performing units. The selection was 

fully explained in the Supporting Statement to the ICR and 

reiterated in the preamble. Further information on the use of 

the 2010 ICR data is provided in the MACT Floor TSD.

In previous MACT rules, there has been concern from industry that the data sample did not 

provide an accurate analysis of the ‘12% floor’. Essentially, the claim was that the 12% was 

cherry-picked from the “best of the best” and not actual technologies in use at a given location.

How was the data collected for this rule, and can the analytical approach taken here be subject 

to similar criticism? Did desired outcomes (i.e. co-benefits) impact the MACT floor that has been 

established?

Response: As noted in the previous response, EPA believes that 

it has fully and adequately described how it selected the units 

for testing for the 2010 ICR. It did, in fact, make an attempt 

to select the “best of the best” for three groups of HAP from 

coal-fired EGUs - acid gas HAP, non-mercury metal HAP and nondioxin/furan organic HAP - so as to be able to use a number of 

units equal to 12% of the entire population in the MACT floor 

pool, rather than just use 12% of the data obtained. We in fact 

intend to propose standards based on data from sources 

representing 12% of the category for acid gas HAP and nonmercury metal HAP consistent with the statements in the ICR (we 

intend to propose work practice standards for organic HAP, 

including dioxin/furan). The control technologies in the MACT 

floor pool are technologies that are in use throughout the 

industry. Co-benefit impacts had no bearing in the selection of 

the units to be tested or in selection of the MACT floor pool of 

sources.

Notwithstanding EPA’s adjustment for variability, the MACT floors still appear to be too stringent 

since they have been established on a pollutant-by-pollutant basis. The use of a 

pollutant-by-pollutant approach results in the creation of hypothetical standards that bear little 

resemblance to standards achieved in practice by existing facilities.

Response: EPA maintains that the pollutant-by-pollutant 

approach is consistent with the CAA. We are currently defending 

the approach in the U.S. Court of Appeals for the D.C. Circuit.

The proposed formula for calculation of 30 day averages sums the hourly emission rates for the 

30 day period, and then divides by the number of hours in the period. This equally weights each 

hour’s emission rate. Hours of low load operation and startup are at reduced levels of fuel burn 

and should not be weighted equally with full load operation. The appropriate 30 day average 

calculation method should be the sum of the emissions for each hour of operation divided by the 

number of hours of operation.
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Response: The ICR sought and obtained data over a 30 boiler 

operating day period (where a boiler operating day is any 24 

hour period in which fuel is combusted), in order to obtain 

variable emissions performance data across many periods of 

operation, including periods of changing loads. To the extent 

these periods occurred – and they should have, if EGU operation 

and associated emissions performance is variable – the emissions 

performance data were collected and included in developing the 

MACT floors. The proposed formula - in which 30 boiler 

operating day average rates are calculated from daily rates 

based on mass emissions rates, flow rates, and heat input or 

electrical output from each hour that fuel is combusted –

represents exactly how the data were produced from 

representative sources over representative periods of operation. 

There is no need to revise this formula to compute a 30 boiler 

operating day average.

Is it possible that EPA intended to propose a mercury MACT standard for new sources of 

0.00001 lb/MWh rather than 0.00001/GWh? Based on a quick analysis, this standard appears 

to be three orders of magnitude more stringent than the standard for existing plants and would 

require greater than 99% total mercury removal at all new PC-fired power plants. This 

proposed standard is also below the detection limit of CEMS instrumentation – has EPA

considered this in requiring Hg CEMS?

Response: There are four new source mercury MACT emissions 

limits; 0.00001 lb/GWh is the correct value for coal-fired units 

designed for coal with heat contents equivalent with or greater 

than 8,300 Btu/lb and for IGCC units. The fact that the 

proposed new-source limit is three orders of magnitude more 

stringent than the limit for existing sources is a reflection of 

the data. The fact that the new-source limit is significantly 

more stringent should be expected given the language of the 

statute (i.e., “average of the top performing 12%” for existing 

sources vs. “emission limitation exhibited by the best 

performing similar source” for new sources) and the differential 

becomes larger the more data that are included in the existing 

source MACT floor pool. Further, based on the data received 

through the 2010 ICR, greater than 99% mercury removal is being 

achieved by many EGUs within (and outside) the MACT floor pool. 

Further, based on the data received through the 2010 ICR, 

greater than 99% mercury removal is being achieved by many EGUs 

within (and outside) the MACT floor pool.

As explained in the preamble, the Agency applied a technique to 

adjust MACT floor levels – when necessary – to improve 

measurement accuracy near detection levels to a value consistent 

with accuracy values for other measurement techniques, so that 
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existing instrumentation can be used to demonstrate compliance 

with emissions limits. Should an owner or operator of an 

affected EGU believe that a mercury CEMS would be unable to

detect emissions at or below the proposed standards, the 

proposal allows him the ability to choose another measurement 

technology, such as the sorbent trap monitoring system, that is 

able to detect emissions at or below the proposed standards. 

There appears to be little justification for an averaging period of only 30 days for the mercury 

standard. The health effects for mercury are those resulting from bio-accumulation occurring 

over a long period. Accordingly, we suggest an annual averaging period for Hg seem to be 

more appropriate.

Response: An averaging period of longer than 30 days for 

mercury emissions was considered but rejected. Although some 

may claim that health effects of mercury occur over a long 

period, devices that control mercury emissions are in continuous 

use during EGU operation. Without frequent checks of 

appropriate and continuous control device operation, such as the 

amount of activated carbon injection, EGU owners or operators 

could find themselves spending too much money for mercury 

emissions control, either through the use of too much sorbent or 

through neglect of performing routine maintenance or repair. 

Moreover, by lengthening the period over which compliance is 

averaged, EGU owners or operators could increase their risk of 

non-compliance and the liability associated with that noncompliance. A problem of insufficient mercury control device 

operation found and corrected within 30 days poses less 

environmental impact and source cost than the same problem found 

and corrected over a 12-month period. 

The decision to set beyond-the-floor mercury MACT standards for existing sources designed for 

coal < 8,300 Btu/lb (i.e., lignite-fired units) is based on limited data that includes only six lignitefired units (5 FBCs; 1 PC) and based on the assumption that ACI systems were not operated at 

their full capability. We suggest EPA provide more data is needed to support the rationale 

for a beyond-the-floor standard and seek comment on this, along with a request for more 

data.

Response: EPA is providing more rationale and taking comment on 

this. However, through the 2010 ICR, EPA required EVERY EGU 

(including lignite EGUs) to provide all data, including that for 

mercury, obtained over the past 5 years. Thus, sources will 

likely have to test their units to provide additional data for 

the Agency to consider.

Floor Determination – New Units
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Section 112(d)(2) instructs the Administrator to take into consideration the cost of achieving 

emission reductions. However, EPA’s discussion in the preamble cites to and relies solely on 

(d)(3) to set a standard based on the sole best-performing unit. EPA needs to demonstrate that 

it has considered the cost of Hg-emissions controls down to such an extreme level (given the 

high level of variability identified in the Existing Unit MACT Floor) and whether it is, in essence, 

mandating a particular emissions control technology and particular fuel source in order to meet 

this standard.

Response: The statute authorizes consideration of costs in the 

beyond-the-floor analysis under section 112(d)(2), which occurs 

after EPA has established the MACT floor consistent with section 

112(d)(3).

We suggest EPA consider whether the subcategorizations for new units should be different than 

those for existing units if the performance standard is to be based on the single best performer 

in each subcategory. The argument that multiple different technologies appear in the top 12% 

doesn’t mean anything when only the top performer is relevant to the standard.

Response: EPA does not believe that more subcategories are 

either warranted or appropriate for new sources vs. existing. 

New sources are starting from scratch whereas existing sources 

are tied to their current location, physical structure, etc. 

Therefore, new sources can be sited at a location most 

advantageous to their compliance with the standards, can 

construct a unit and controls that will most likely lead to 

their compliance with the standards, and can contract for the 

fuel that will most likely lead to their compliance with the 

standards.

Emission limits for new units are so stringent we expect they will effectively stop new coal unit 

construction, an impact not adequately addressed in the impact analysis. Can EPA include a 

discussion of this outcome and its likelihood?

Response: Based on the 2010 ICR data, the proposed new-source 

limits for coal-fired EGUs are currently being met by a number 

of existing units for each of the HAP groups, thus we do not 

think the limits will stop the construction of new coal-fired 

EGUs.

The decision to set beyond-the-floor mercury MACT standards for new IGCC and lignite-fired 

power plants is not supported by the data – in particular, the MACT floor for new IGCC plants is 

more stringent than the Taylorville IGCC permit, which EPA references in the preamble. Can 

EPA explain why the new IGCC and lignite-fired plants limits are so stringent?

Response: The new source limit is to be set based on the 

“emission limitation exhibited by the best performing similar 

source”. We did not feel that the existing IGCC sources were 

representative of the performance of a new constructed IGCC 
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facility. In general, new IGCC facilities are expected to have 

emissions that are as low as, or even lower, than newly 

constructed coal-fired EGU facilities. We have requested 

comment on this approach.

Startup/Shutdown

It is not clear that continuous emission monitoring (CEM) data for all the HAPs covered by this 

rulemaking were available for 12 percent of the best performing units. If CEMS data were not 

available for all HAPs for 12% of best performing units in setting particular standards for existing 

facilities, we recommend that accommodation for the higher emissions during startups 

and shutdowns be built into those standards. Such accommodation would be necessary for 

standards based on intermittent data generated during normal operation of a facility.

Response: CEMS data for HAPs were not included in the floor 

analysis because no such data were provided by units in the MACT 

floor pool, despite requests for such data. EPA believes that 

the size of the MACT floor pool of sources along with the use of 

the 99% UPL and the 30-day averaging period provides the 

necessary “cushion” for periods of startup and shutdown; 

however, should commenters provide relevant data during the 

comment period, we will review it to determine its impact, if 

any, on the 30-day averaging period.

EPA has not addressed the full SBAR panel recommendation: “The panel members 

recommend that the Agency evaluate whether establishing work practice requirements during 

periods of startup and shutdown would be consistent with CAA section 112(h) . . . .” Can EPA

explain why this recommendation has not been addressed?

Response: Section 112(h) requires the Agency to find that “the 

application of measurement methodology to a particular class of 

sources is not practicable due to technological and economic 

limitations” before the Agency may establish a work practice 

standard in lieu of a MACT standard. EPA cannot satisfy that 

requirement for emissions during startup and shutdown, in part, 

because as the commenter notes CEMS can function during startup 

and shutdown periods. Even though CEMS can function during 

these periods, without use of default values, calculations can 

prove problematic in that denominators tend to approach zero, 

yielding infinite emissions. For the purposes of this rule, we 

propose use of a default diluent value of 10.0 percent O2 or the 

corresponding fuel specific CO2 concentration for calculating 

emissions in units of lb/MMBtu or lb/TBtu during startup or 

shutdown periods. For calculating emissions in units of lb/MWh 

or lb/GWh, we propose source owners use an electrical production 

rate of 5 percent of rated capacity during periods of startup or 
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shutdown. We are requesting comment and suggestions for 

resolving this concern.

[Page 322, Section IV.G, Last Paragraph]: It is indicated that CEMS data were used in 

establishing the emission limits, which apply to all unit operating modes, including startup and 

shutdown. How much of such data reflect startup and shutdown of the tested units? It is 

well known that certain emissions will be higher during shutdown and startup periods. Since the 

future mix of power generators (including renewables) may make it necessary for the fossil units 

to cycle more frequently, some units may not be able to maintain the emission limits, even if 

averaged over a period of 30 days.

Response: Although EPA received CEM data from over 100 units, 

none of these units were among the top performing 12 percent 

and, thus, were not used in the data analysis.

Discounting factor in averaging

[Page 461] Please clarify how this 10% discount factor would apply. Would this require the 

average emission rate measured to be 90% of the required emission rate?

This provision does not seem to be necessary to ensure averaging is at least as stringent as the 

MACT floor. In fact, it seems to be an unnecessary penalty on averaging, particularly when 

combined with the anti-backsliding measure. What is the basis for this penalty?

Response: The use of the 10% discount factor has been removed 

from the draft preamble, so the comment is moot. We are 

requesting comment on whether or not the use of a discount 

factor is appropriate, as well as the appropriate value of a 

discount factor. 

Alternative Equivalent SO2 Limit to Control Acid Gases

EPA is proposing to set an alternative equivalent SO2 emission limit for coal-fired EGUs with 

some form of FGD system because (1) the controls for SO2 are also effective controls for acid 

gases, and (2) most EGUs already have SO2 CEMS in place. EGUs without an FGD system 

installed would not be able to use this alternative emission limit. The preamble grafts the 

additional requirement that “EGUs must operate their FGD at all times to use the alternate SO2 

emission limit.” (p. 388) The basis for the latter requirement (to operate the FGD “at all 

times”) is not clear. It is conceivable that a source may not be able to operate the FGD at 

optimum levels, or at all, for short periods because of conditions beyond its control. However, 

the mere fact that the FGD was not operated for a short period should not be a basis to make 

the source ineligible to use the alternate SO2 limit so long as the source demonstrates that this 

alternate SO2 limit is met. This is all the more true since demonstration of compliance with the 

SO2 alternate limit is on the basis of a monthly average.

Response: The basis for establishing SO2 as a surrogate for the 

acid gas HAP (e.g., HCl, HF) is the fact that FGD systems remove 

not only SO2 but also the acid gas HAP. There is, however, no 

correlation between the sulfur content of a coal and the 
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chlorine and fluorine content of coal. Therefore, in order for 

SO2 to be “available” as a surrogate, some form of FGD control 

must be employed at all times. The CAA requires continuous 

compliance with standards and rules often have continuous 

parametric monitoring requirements for pollution control 

equipment. We see no basis for a different approach in this 

case.

Controls for Hg and SO2 Standards

One reviewer agrees with EPA that the proposed DSI (direct sorbent injection) system is 

applicable, especially for plants with few years of remaining operation and plants with readily 

available facilities to handle ash storage leachate, but questions its application to the large 

number of facilities being considered by EPA. We recommend that EPA investigate this 

issue further as well as raise it for public comment.

Response: The Agency is aware of concerns about DSI effects on 

fly ash leaching characteristics and usability when sodium-based 

sorbents (e.g., trona, sodium carbonate) are used primarily for 

SO2 control. In those cases, much more sorbent must be added 

than when HCl is the target pollutant because of the increased 

reactivity with HCl. EPA IPM modeling runs used sorbent 

injection rates that specifically targeted HCl emission limits. 

EPA is also aware of existing facilities that are using sodium 

based sorbents for SO3 mitigation and are storing the fly ash 

and, in some cases, selling the fly ash for concrete 

manufacturer.

Monitoring Requirements

We are not aware of any HCL monitors that are commercially available and can measure in the 

range of the proposed limit of .002 lb/MMBtu for existing EGUs, and we are not aware of any 

currently being installed at utilities to measure HCl in utility boiler flue gas. The proposed new 

unit limit is even lower. Did EPA consider the availability of these monitors when setting the 

standards or determining the compliance requirements?

Response: Yes, as mentioned earlier (and in the preamble), the 

proposed emissions limits were adjusted, when necessary, to 

account for measurement instrument capabilities. Should an 

owner or operator find that an HCl CEMS is unable to make these 

measurements, he will be able to demonstrate compliance via 

surrogate monitoring (e.g., SO2 CEMS or parametric monitoring, 

where applicable) fuel analysis, or emissions testing.

It is our understanding that analyzer type mercury CEMs have proven much less reliable than 

CEMs for conventional pollutants. We suggest that mercury monitor requirements should be 

based on demonstrated mercury monitor availability for a significant number of monitors 

operating in both wet and dry stacks – is this true for this rule?
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Response: We disagree with the assertion that mercury CEMS are 

viewed as being less reliable than other CEMS, noting that as 

with any newly-acquired measurement system, it can take owners 

or operators some time to become familiar with their equipment. 

As mentioned earlier, should an owner or operator of an affected 

EGU believe that a mercury CEMS would be unable to detect 

emissions at or below the proposed standards or be concerned 

with the reliability of an Hg CEMS, the proposal allows him the 

ability to choose to use a sorbent trap monitoring system.

Work Practice Standards

EPA’s proposal subjects EGUs to work practice standards for controlling organic HAPs. This 

standard requires the source to conduct an annual inspection and performance tune-up of the 

EGU. The burner inspection may be delayed until the next scheduled outage, but must be 

conducted at least once every 12 months. 

Utility units routinely operate continuously for many months and in many cases over 12 months. 

Accordingly, we suggest that these standards be so written that all burner inspection 

and repair may be conducted annually or during the next scheduled planned outage, 

whichever is later. Inspection of other components that can be conducted without 

shutting down the boiler may still be conducted on an annual basis.

Response: Many, if not most, EGUs have planned annual outages. 

The inspection and tune up procedure was designed to occur 

during this normal occurrence. We will to extend the time 

between inspection and tune ups from 12 to 18 months to account 

for those EGUs with an unusual planned outage schedule, and we 

will take comment on the appropriateness of this period.

GHG Emissions Increase as a Result of Compliance

The preamble and the RIA make reference to the electricity requirements for emissions control 

technology and the possibility that some equipment would increase GHG emissions. Where is 

that information presented?

Response: Chapter 8.

Appropriate and Necessary Finding

Unless EPA is seeking comment on its new and reasserted necessary and appropriate finding, 

EPA should remove this discussion (parts of section II and section III) from the preamble. It is 

confusing, and distracts from the major points of the preamble, which should be the regulatory 

decisions surrounding the establishment of emission standards and the data used to support 

them. EPA should outline the major points and finding of the previous rulemakings and court 

cases, then proceed from the assumption that the 2000 finding is current law because of the 

court cases. The additional information and new necessary and appropriate finding can be a 

separate documented finding for the docket.
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Response: EPA will seek comment on all aspects of the 

appropriate and necessary finding. We think it is important to 

include this in the preamble given the history of this finding 

and the fact that the finding and attendant listing will be 

subject to judicial review when the final rule is issued.

PREAMBLE Specific Comments:

Section IV. Summary of this Proposed NESHAP

[Page 317, Section IV.G, First Paragraph] EPA has used the boiler height-to-depth ratio for 

establishing unit categories. Please provide a clear definition of how such a ratio would be 

measured. In general, the overall height and depth of a boiler are set based on the number of 

burners, burner spacing, required furnace residence time, fuel characteristics, etc. It may be 

possible that a unit with less than a 3.82 ratio used by EPA and firing a coal with less than 8,300 

Btu/lb heating value would have the same problem controlling Hg as do the boilers with a ratio 

greater than 3.82. It may also be possible that the tested units were unable to show high Hg 

removal rates, because of certain fuel characteristics. Also, by using this same ratio for setting 

emission limits for new units, EPA appears to be assuming that the boiler design standards will 

not change in the future. We also recommend that EPA seek comments on this issue.

Response: The ratio is based on information provided in an 

industry comment made during the CAMR effort and is premised on 

the fact that low Btu coal boilers are physically larger than 

those for use with higher Btu coals. The industry comment 

provided a diagram of a boiler designed to burn each rank of 

coal. EPA is basing its definition on “information available to 

the Administrator” and solicits additional means for “defining” 

a unit designed to burn low Btu coal vs. one designed for high 

Btu coal. EPA is soliciting comment on all of its subcategory 

determinations.

[Page 318, Section IV.G, Table 14] Please note the following comments on this Table:

 What is the basis for the output-based limits: gross or net unit output capacity? Does 

EPA plan to have both input- and output-based limits for the existing units in the final 

rule?

 What conversion factors (heat rates) are used for converting from input to output based 

limits?

 It appears that inconsistent input-to-output conversion factors have been used for 

different pollutants for the same boiler category. In addition, some conversion rates 

reflect unit heat rates that cannot be justified because they are well below what can be 

achieved by these plants.
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 Why are both floor and below-the-floor Hg limits shown for the new coal-fired units firing 

coals less than 8,300 Btu/lb? How can a below-the-floor limit that is three orders of 

magnitude smaller than the floor limit be justified?

 The emission limits selected for new units appear to be far more stringent than those 

imposed in recent air permits. Has EPA taken the data from these permits into 

consideration before setting the limits for this rule?

Response: The proposed output-based emission limits are based 

on gross capacity. EPA plans on proposing that an existing EGU 

could select from either the input- or the output-based emission 

limits (as was done with CAMR). No conversion factor was used 

in establishing the output-based emission limits; the limits 

were based on data provided through the 2010 ICR and developed 

independently of the input-based emission limits (although the 

pool of top performing units is similar). Both floor and 

beyond-the-floor limits for mercury are shown for the <8,300 

Btu/lb subcategory because we have in the past consistently 

shown both limits and are taking comment on both limits. EPA 

does not use permit levels in establishing MACT floors but, 

rather, the emission data provided. The emissions data reflects 

what is “achieved in practice” whereas the permit levels may be 

desired goals that may be bettered in practice.

[Page 331, Section IV.I.5.b] Please clarify what pressure drop and flowrate are being 

measured for the wet scrubber. The pressure drop would normally change with flowrates, 

and the operator may not have any control over them. The sorbent may not be directly injected 

into the scrubber, as it may be added to the system as a makeup stream, which will vary.

Response: The comment is not clear. The proposed rule contains 

operating parameter monitoring for two types of wet scrubbers 

(PM and acid gas) as well as for dry scrubbers (or dry sorbent 

injection). Proposed operating parameters include the pressure 

drop across and the liquid flow rate going through the wet PM 

scrubber; the liquid flow rate going through and the pH of the 

liquid in the wet acid gas scrubber; and the sorbent injection 

rate for the dry scrubber. For acid gas HAP control, 

determination of and maintenance of the pH of the wet acid gas 

scrubber liquid or the sorbent injection rate for the dry 

scrubber should address the locational concern expressed by the

commenter.

[Page 332, Section IV.I.5.c] This section describes a procedure for establishing the minimum 

sorbent injection rate, which must be the average of the maximum injection rates during the 

performance tests. Assuming that the maximum injection rates would occur at the 

maximum operating loads, using the same rates at low loads may result in unreacted 

sorbent in the flue gas stream. This will increase costs and may be environmentally 

harmful.
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Response: Sorbent rates can be defined to be independent of the 

load. For example, activated carbon injection rates are often 

reported in mass of sorbent per volume of flue gas (e.g., pounds 

per million actual cubic feet of flue gas). This sorbent rate –

as opposed to a mass per time (e.g., pounds per hour) rate –

should be independent of load and can, thus, avoid overuse of 

sorbent. Moreover, EGU owners or operators establish the 

minimum hourly average sorbent injection rate for each sorbent 

as measured during performance testing; should the owners or 

operators desire to have differing average sorbent injection 

rates depending on load, they are able to conduct testing at 

those other loads to determine those other rates.

[Page 333, Section IV.I.5.e] This section requires that precipitator voltage and current of each 

collection field be measured during the performance tests to establish the minimum voltage and 

current values that must be maintained during all precipitator operation. Please note that the 

secondary current and voltage in each electrical bus section of a precipitator do change with the 

flue gas characteristics, and the operator may not have any control over these parameters. 

Also, most precipitators are built with design margins, which may allow them to take one or 

more mechanical fields or electrical bus sections out of service and still maintain the stack limits. 

Does the requirement in this section require that all precipitator fields be operational at 

all time? By default, this may amount to mandating tighter controls than the MACT 

limits.

Response: The proposal has been revised so that data on the 

number of fields in operation is no longer required. Rather, 

minimum hourly average secondary voltage and secondary amperage 

data, as well as a calculation of the total secondary power, is 

required in the proposal.

Section V. Rationale for this Proposed NESHAP

[Pages 394-395 and 418-421] EPA rejects the option of fuel switching based its concerns about 

natural gas availability and environmental impacts of hydraulic fracturing associated with shale 

gas production. FERC’s seasonal market reports have found adequate natural gas supplies to 

meet U.S. generation requirements. We suggest that EPA acknowledge FERC’s forecasts 

and clarify the concerns about long-term availability.

Response: EPA could remove this from the justification for the 

rejecting the beyond-the-floor analysis if FERC believes there 

is sufficient gas for all coal- and oil-fired electric 

generation to be replaced by natural gas without the use of 

hydraulic fracturing.

[Page 408, Section V.D, Last Paragraph] Did EPA consider any measurement uncertainty

in the instruments that were used during the ICR performance tests? These uncertainty 

values are easily available in the industry. In addition, there are large measurement 
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uncertainties in the methods plants generally use for establishing parameters, such as fuel 

flowrates, etc. If EPA has used such data received from the plants for establishing heat rates, 

etc., there is a potential for large inaccuracies in these values.

Response: Yes, as discussed in the preamble, the proposed MACT 

floors were adjusted as necessary to provide a measurement 

uncertainty (or accuracy) of the methods used consistent with 

the measurement uncertainties of other established Agency 

methods.

[Page 411, Section V.D., First Paragraph] Please clarify how variability in fuel-related HAP 

inputs was taken into account in establishing the emission limits. If EPA has only relied 

on the data collected during the short-term ICR tests, such data may not account for the 

variation in the characteristics of the fuels being burnt in power plants affected by this rule. EPA 

does cite some data that lists US coal characteristics affecting PM, HCl, and Hg emissions (ref. 

Documentation Supplement for the IPM Case v.4.10), and such data can be used to verify the 

reasonableness of the emission limits being proposed. For example, a review of these data for 

HCl reveals that, for certain coals, the proposed emission limits require as much as 99.9% HCl 

removal for new units and 97% and higher removal for existing units. Reviewers are not 

aware that such reduction levels are achievable with technologies being considered in 

this rule. This is an important issue that should be raised when seeking public 

comments.

Response: EPA did not have every EGU test for everything over a 

long period of time so as to fully be able to characterize fuelrelated HAP variability. Absent that, we have incorporated such 

variability through use of as much of the data provided as 

allowed by the statute. That is, we have used either 131 units 

(for the acid gas and non-mercury metallic HAP) or 40 units (for 

the mercury) in the MACT floor pool. We have, therefore, 

incorporated as much fuel-related variability as possible, to 

the extent it is exhibited either across the 131/40 units or 

across the additional variability data used for a given unit 

within the MACT floor pool. EPA does not believe that it can 

use historic coal constituent data (e.g.,1999 ICR) absent 

corresponding emissions data for those same units. However, we 

did require that EGUs conduct fuel sampling concurrent with 

their 2010 ICR emissions testing. Based on that data, EGUs 

among the MACT floor pool are achieving in excess of 99.9% HCl 

removal (and units in the MACT floor pool are meeting the 

proposed limit without achieving 99.9% HCl removal).

[Page 427] The methodology used to set the mercury MACT floor for new sources, which uses 

individual emission test runs rather than the 3-run average, may be flawed. This approach 

yields a MACT floor of 0.00001 lb/GWh for all new coal-fired power plants. Based on a 

quick analysis, this would require greater than 99% total mercury removal at all new PC-fired 

power plants. In addition, the 0.00001 lb/GWh limit is well below the detection limit for CEMS.

In a recently completed DOE project, this detection limit was set from 0.1 to 0.4 micrograms per 
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dry normal cubic meter of flue gas. The 0.00001 lb/GWh emission limit equates to 0.0015 

micrograms per dry normal cubic meter of flue gas. Is it possible that EPA intended the MACT 

floor for new sources to be 0.00001 lb/MWh rather than 0.00001 lb/GWh?

Response: EPA conducted these analyses consistent with the 

approach taken on other NESHAP actions (e.g., Portland Cement, 

Industrial Boilers). As noted in the response to an earlier 

question, the proposed 0.00001 lb/GWh value is correct and is 

based on the data available to the Agency. If EPA were to only 

use a 3-run average for new sources, there would be no basis for 

accounting for variability and, thus, the resultant emission 

limit would be even more stringent than it is now. Also, as 

noted earlier, the 2010 ICR data indicate that there are EGUs in 

the MACT floor pool achieving greater than 99% mercury 

reduction.

[Page 430, Table 17] The mercury data provided below raises a couple of questions. For 

sources designed for coal ≥ 8,300 Btu/lb, the top performer average is equivalent to the 

proposed MACT floor (0.00001 lb/GWh), which raises the concern that this MACT floor is 

based on a single data point. At the very least, the MACT floor appears to be based on 

limited sampling at a single top-performing source. This is concerning because this MACT 

floor will apply to all new coal-fired power plants (IGCC and PC regardless of coal rank), 

which may be unrealistic for compliance across the entire fleet of new coal plants.

Response: In fact, the proposed new-source mercury floor 

value for this subcategory is based on data from six 

individual runs from the given EGU (i.e., the unit provided 

two data sets). However, the commenter is correct in that 

some of the proposed new-source MACT floors are based on data 

from a single set of three runs. However, EPA is constrained 

to use the data it has.

For sources designed for coal < 8,300 Btu/lb, a mercury emission level of 0.000007 lb/GWh 

is provided for the top performer average. However, no EGUs in this category were among 

the top 12% performers, and this is the lowest mercury emission level provided anywhere in 

the preamble.

Response: As noted in the response to a previous question, 

EPA has reassessed its analysis of the MACT floor for mercury 

for this subcategory and has made the appropriate changes in 

the preamble.

Using Aspen models developed by DOE/NETL for the Bituminous and Low-Rank Baseline 

studies, the percent total mercury removal required at representative coal-fired power 

plants to meet the proposed MACT floor was calculated. These representative coal-fired 

power plants are designed for a net output of 550 MW and are equipped with the latest air 

pollution control devices. The following table provides the percent total mercury removal 

required to achieve the proposed MACT floors for new and existing sources. To align this 
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analysis with the source categories proposed by EPA, the MACT floor assigned to units 

firing bituminous and PRB coals correspond to sources designed for coal ≥ 8,300 Btu/lb, 

while the MACT floor assigned to the ND lignite-fired unit corresponds to sources designed 

for coal < 8,300 Btu/lb.

Coal Btu/lb 

(as 

received)

Inlet 

Hg 

(lb/hr)

Outlet 

Hg 

(lb/TBtu)

Outlet 

Hg 

(lb/GWh)

% Total 

Hg 

Removal

Illinois #6 Bit –

Existing

11,666 0.058 1 0.008685 91.25%

Illinois #6 Bit – New 11,666 0.058 0.0011 0.00001 99.99%

Rosebud PRB –

Existing

8,564 0.034 0.997 0.008294 85.8%

Rosebud PRB –

New

8,564 0.034 0.0007 0.00001 99.99%

ND Lignite –

Existing

6,617 0.056 1.995 0.01706 82.2%

ND Lignite - New 6,617 0.056 0.0011 0.00001 99.99%

As shown in the table, the percent total mercury removal required at existing sources 

(91.25% for bituminous; 85.8% for PRB; 82.2% for ND lignite) is stringent, but achievable at 

well-controlled coal-fired units. However, the proposed MACT floor of 0.00001 lb/GWh for 

new coal-fired power plants would require greater than 99% total mercury removal at these 

representative units, which seems impractical under real-world operating conditions. This is 

especially true in light of the fact that new EGU’s will need to meet this extremely high level 

of performance during periods of startup, shutdown and malfunction (SSM).

Response: Based on the data received through the 2010 ICR, 

EGUs using bituminous and subbituminous coal ranks are 

achieving in excess of 99.9% mercury removal and lignitefired EGUs are achieving in excess of 95% mercury removal. 

As noted elsewhere, EPA has reassessed its MACT floor 

analysis for the <8,300 Btu/lb subcategory and made the 

appropriate changes in the preamble.

[Page 452, Section V.K, Last Paragraph]: Do the requirements for monitoring operating 

parameters apply to units that are already utilizing CEMS? If so, why would EPA need this 

information when CEMS are already there? As indicated in previous comments, establishing 

minimum values for these parameters would raise several operating issues and would result in 

unnecessary costs.

Response: Yes, as discussed in the preamble, the proposed MACT 

floors were adjusted as necessary to provide a measurement 

uncertainty (or accuracy) of the methods used consistent with 

the measurement uncertainties of other established Agency 

methods.

[Page 463] EPA says it will work with DOE, FERC and others to reduce the adverse health 

impacts of power generation “while continuing to assure electric reliability is achieved.” Given 
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that FERC generally uses the term “maintain” with respect to reliability, we suggest EPA use 

this as well (since we currently “achieve” reliability).

Response: We will edit the text.

[Page 465, Section V.M, First Paragraph] EPA describes the “public health impacts of power 

generation” as “very significant adverse.” Recognizing that there are very significant public 

health benefits of the proposed rule, this terminology may unwittingly be establishing a burden 

of proof for the agency, and suggest that the sentence could accomplish its purpose by deleting 

“very significant” and using the phrase “adverse public health impacts in the power generation 

sector.”

Response: We will make this edit.

[Page 465, Section V.M, Second Paragraph] EPA’s analysis shows a large number of new 

baghouses being retrofitted for compliance with this rule and while baghouses may be 

necessary for many units to comply with the required emission limits, we note the following 

concerns regarding the use of baghouses:

 The proposed rule does not indicate that EPA has confirmed that sufficient space exists 

in plants to install baghouses. Many plants may have used available spaces around the 

chimney to install scrubbers required by previous rules.

 The plants that have installed wet scrubbers around the chimney may have space 

available behind these scrubbers. However, a baghouse cannot be installed 

downstream of a wet scrubber, due to the potential for pluggage of bags, etc. This is 

especially an issue for plants that have scrubbers but no SCRs and that may require 

baghouses for control of Hg.

 For some plants with scrubbers and firing high-sulfur coals, sufficient space may be 

available upstream of the scrubbers to install baghouses (or to upgrade existing ESPs). 

However, the flue gas temperatures for these plants must be sufficiently high to avoid 

corrosion and baghouse pluggage issues. This is a significant issue with baghouse 

application on high-sulfur coal facilities, because of flue gas temperature stratification 

caused by air heater rotation. Usually, these plants may install flue gas mixing devices 

that cause as much as two inches of pressure drop (mainly an O&M cost item).

We suggest EPA investigate the above issues and suggest that additional information 

should also be sought as part of public comments.

Response: We will continue to look at these issues between 

proposal and final.

[Page 465, Section V.M, Second Paragraph] EPA’s analysis shows a large number of units 

incorporating a trona-based dry sorbent injection (DSI) system for controlling HCl. While this 

type of a DSI technology has been available for many decades, its use in the power plant 

industry has been restricted to a few plants, because of the high sodium content of trona. Since 

most of this sodium is collected with ash, it mostly ends up being part of the ash in storage piles. 

Eventually some of this sodium will dissolve in rain water and any leachate thus formed would 
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be subjected to strict wastewater discharge regulations. In this situation, the ash storage site 

would be required to install leachate collection and ground water monitoring systems. 

Ultimately, the collected leachate would have to be treated/destroyed. It may be very difficult or 

expensive for many plants to find facilities where treatment of this leachate would be feasible. 

Therefore, while we understand that the proposed DSI system is applicable, especially for 

plants with few years of remaining operations and plants with readily available facilities to 

handle ash storage leachate, its application on the large number of facilities being considered 

by EPA is questionable. We recommend that EPA investigate this issue further as well as raise 

it for public comments.

Response: The Agency is aware of concerns about DSI effects on 

fly ash leaching characteristics and usability when sodium based 

sorbents (e.g., trona, sodium carbonate) are used primarily for 

SO2 control. In those cases, much more sorbent must be added 

than when HCl is the target pollutant because of the increased 

reactivity with HCl. EPA IPM modeling runs used sorbent 

injection rates that specifically targeted HCl emission limits. 

EPA is also aware of existing facilities that are using sodium 

based sorbents for SO3 mitigation and are storing the fly ash 

and, in some cases, selling the fly ash for concrete 

manufacturer.

[Page 466, Section V.M, First Paragraph] The three-year implementation period with a potential 

one-year extension may be adequate for installing the controls described in this section on a 

single unit. However, some industry participants are concerned that a large number of 

concurrent retrofits precipitated by multiple environmental regulations will be slowed down by 

bottlenecks in the supply-chains for equipment and skilled labor. Information related to this 

issue could be requested as part of seeking public comments on the proposed rule.

Response: We will add specificity generally taking comment on 

the timing issues.

[Page 466, Section V.M, Last Paragraph] This section mentions upgrade of existing 

precipitators (ESPs) to fabric filters (FF) as the main choice for acid gas control. Please note 

that upgrade of an ESP is a long-lead construction activity, possibly requiring a unit outage of 

two or more years. If this option is used for a significant number of units, it is likely to have a 

large adverse impact on the grid reliability.

Response: We believe that there are a number of options to 

improve ESP performance that can be performed much more quickly.

[Page 476] EPA invites comments on the impact of the proposed rule on reliability and the 

authority available to EPA and other agencies to ensure compliance with EPA requirements 

while maintaining grid reliability. Similarly, on page 561, EPA in addressing the impact of the 

regulations on grid reliability, asks for comments on the scope of various authorities to ensure, 

and to exercise discretion in relation to, compliance with the regulations. We have some 

concern with EPA asking commenters to opine on the scope of our authority to ensure 

compliance with our regulations.
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Response: EPA will remove this request for comment.

VI. Background Information on the Proposed NSPS (482)

[Page 487] Of the roughly 44 coal-fired power plants installed in the U.S. since 2003, only 3 

have been equipped with wet ESP’s, and none have been in operation longer than 2009. We

suggests that this technology has not yet been demonstrated at a sufficient scale to serve as 

the basis of the rule and EPA should seek comment on this. Does EPA have any further data to 

support the discussion of wet ESP? Referenced Text: In addition, both wet ESP and FGD 

control both filterable and condensable PM emissions and a combined standard allows for 

optimal design of the control equipment.

Response: Multiple existing facilities use WESP including the 

AES Deepwater and Xcel Energy’s Sherco facilities in the U.S.,

along with the New Brunswick Power Coleson Cove facility and 

numerous applications in Japan. In addition, the technology has 

been used on multiple new facilities and WESP have not been 

ruled out as a technology choice in preliminary BACT 

determinations for new facilities. Considered as a whole, these 

data adequately support the conclusion that the use WESP has 

been adequately demonstrated as an appropriate basis for the 

rule. To the extent we receive comments that it is not a viable 

technology for new facilities, we will take that into 

consideration for the final rule.

VII. Summary of the Significant Proposed NSPS Amendments

[Page 489] Please clarify whether this refers to modifications that would result in an increase in 

the PM, SO2, and/or NOx levels? All three? Only one?

Response: Modifications are pollutant specific and are 

triggered by an increase in the maximum hourly emissions rate 

resulting, in general, from any physical or operational change 

at an existing facility. Upon modification, the facility must 

comply with the standard for the pollutant or pollutants for 

which there has been an emissions increase applicable to new 

units. 

[Page 489] The affected units need to be clearly defined. Referenced Text: Only those units 

that begin construction, modification, or reconstruction after [INSERT DATE OF PUBLICATION 

OF THE PROPOSED AMENDMENTS IN THE FEDERAL REGISTER] would be affected by the 

proposed amendments.

Response: The Affected facility is defined in the rule. It 

essentially is comprised of the utility boiler. Any affected 

facility on which construction, reconstruction, or modification 

is commenced after the amendments are proposed is subject to the 

revised standards per CAA section 111. 
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[Page 490] The emission standard of 0.055 Lb/MWh (gross) is approximately equal to 0.006 

lb/MMBtu based on a gross heat rate of 8,760 Btu/kWh for subcritical or 8,230 Btu/kWh for 

supercritical. This level of control is roughly 3-4times as stringent as recently permitted coal 

plants which have been equipped with fabric filters:

1. Council Bluff Unit 4 (MidAmerican Energy) – 2007 startup – 0.025 lb/MMBtu PM limit –

FF (B&W)

2. Desert Rock supercritical (New Mexico) – on hold but permit issued for 0.02 Lb/MMBtu

3. Franklin County CFB (Illinois) – on hold but permit issued for 0.015 Lb/MMBtu

4. Longview supercritical (WV) – 2011 startup – 0.018 Lb/MMBtu

5. Matagorda County (TX) – 2015 startup, permit for 0.016 Lb/MMBtu

Response: We are requesting comment on a range for the final 

rule, but believe, based on the data which we currently have, 

that the proposed emission standard is achievable by a properly 

constructed and operated facility.

[Page 491] Should this be 0.7 lb/MWh instead of 0.07? 0.7 is referred to elsewhere in this 

document. Referenced Text: Alternatively, we are proposing to amend the NOX emission 

standard for new, modified, and reconstructed electric utility steam generating units to 90 ng/J 

(0.070 lb NOX/MWh) gross energy output regardless of the type of fuel burned.

Response: Yes, and the error has been corrected.

[Page 492] Please clarify criteria that can identify when an “innovative” technology becomes 

“proven”. At that point, do the more stringent limits kick in? Referenced Text: We are 

proposing several amendments that would exempt owners/operators from certain of the 

proposed amendments. First, we are proposing that owners/operators of innovative emerging 

technologies that apply for and are granted a commercial demonstration permit by the 

Administrator be exempt from the proposed amended standard.

Response: The alternative standard is permanent for an affected 

facility for which it is approved regardless of whether the 

technology becomes “proven.” The standard applicable when a 

commercial demonstration permit is issued would be updated 

similar to other NSPS.

[Page 492] Please clarify whether a successful applicant would be granted the higher limit for 

all 3 (SO2, PM, NOx), or just for the pollutant that their innovative technology addresses. For 

instance, would a plant with an approved, innovative SO2 scrubber also be granted higher NO2

emission limits? Referenced Text: We are proposing several amendments that would exempt 

owners/operators from certain of the proposed amendments. First, we are proposing that 

owners/operators of innovative emerging technologies that apply for and are granted a 

commercial demonstration permit by the Administrator be exempt from the proposed amended 

standard.

Response: Commercial demonstration permits are granted on a 

case-by-case basis and the alternative limit(s) in the permit 
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are pollutant specific based on the pollutant or pollutants 

controlled by the innovative technology.

VIII. Rationale for this Proposed NSPS

[Page 500]: We suggest EPA release the emissions data used to establish the standards, and 

encourage EPA to seek public comment on whether transient operations have been treated 

appropriately in the floor calculation. Referenced Text: To establish a robust data set on which to 

base the proposed amendments, we analyzed emissions data from both older plants that have 

been retrofitted with controls and recently operational facilities. We did not attempt to filter out 

periods of startup or shutdown and the proposed standards, therefore, account for those periods.

Response: The data will be available in the docket when the 

proposed rule is published and we are specifically requesting 

comment on periods of startup/shutdown.

[Page 500-502] If a mathematical average (steady state and transient activity) was used to 

determine baseline emissions, then units will almost certainly be out of compliance during 

startup/shutdown/transient operation. Since the proposed amendments were based on 

operation that did not attempt to filter out transient periods, there should be concern about a 

plant’s inability to meeting emission standards during startup and shutdown – which is a 

reasonable part of plant operation – and not operator intoxication or insanity. These are extreme 

examples and don’t really characterize the nature of startup/shutdown, which will naturally have 

higher emission rates due to reduced plant efficiency. Referenced Text: Our proposed 

approach is to not consider malfunctions as a distinct operating mode. Under this approach, all 

periods would be included when determining compliance with the applicable standard. Neither 

CAA section 111 nor any case law require that EPA anticipate and account for the innumerable 

types of potential malfunction events in setting emission standards. See, Weyerhaeuser v 

Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (“In the nature of things, no general limit, 

individual permit, or even any upset provision can anticipate all upset situations. After a certain 

point, the transgression of regulatory limits caused by ‘uncontrollable acts of third parties,’ such 

as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must 

be a matter for the administrative exercise of case-by-case enforcement discretion, not for 

specification in advance by regulation.”)

We recommend that EPA specifically address treatment of startup and shutdown and 

distinguish the basis for that treatment from the discussion of malfunction and seek 

comment for data on multi-year removal levels from more plants.

Response: The multi-year emissions data used to establish the 

proposed standards includes periods of startup and shutdown in 

calculating the 30-day averages. If we filtered out those 

periods the standards would likely be more stringent. Thus, we 

believe that the proposed standards adequately account for 

periods of startup and shutdown. We think that it is clear that 

the discussion in the referenced text is limited to 

malfunctions.
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[Page 506] EPA says that potential uncontrolled SO2 emissions were calculated using monthly 

delivered fuel receipts and fuel quality data from EIA forms EIA-923, EIA-423 and FERC-423.

While historical data is available from FERC Form No. 423, the Commission discontinued use of 

the Form in March, 2008, pursuant to Order No. 709. We suggest EPA check their data source 

and clarify this information if necessary.

Response: We used delivered fuel data from the 423 forms prior 

to 2008 and used the 923 data for 2008 & 2009.

[Page 512] Some might argue that to propose a broad removal level (97%) that is going to 

apply to an entire fleet of plants, based on multi-year performance of only three coal units, is 

perhaps insufficient background data. We strongly suggest gathering more data on multiyear removal levels and specifically seek comment on this issue and the need for 

additional data in the preamble. Referenced Text: Of the identified best performing facilities, 

we only have multiple years of performance data for the Harrison, Trimble County, and 

Mountaineer facilities. Based on the performance of these facilities, we have concluded that 97 

percent reduction in potential SO2 emissions has been demonstrated and is achievable on a 

long term basis.

Response: We are requesting comment on a range for the final 

rule, but believe that the data we do have adequately supports 

the proposed standard. We will request comment on the 

availability of additional data and will review any additional 

data we receive prior to issuing the final rule.

[Page 515] Even though they are both coal-based technologies, a requirement to switch to 

IGCC could be viewed as “redefining the source.” Please clarify. Referenced Text: 

Owners/operators of new and reconstructed facilities burning coals with higher uncontrolled SO2

emissions would either have to use IGCC with a downstream process to control sulfur prior to 

combustion, fluidized bed combustion, or a wet SO2 scrubbing system to comply with the 

standard.

Response: We are not requiring anyone to specifically consider 

IGCC, we are merely pointing out a number of options for meeting 

the standard when using high sulfur coal and one such option is 

the use of IGCC.

[Page 524; Table 24] The four plants referenced in Table 24 represent a total of 1.8 GW of 

generating capacity, and there are about 339 GW (EIA) of installed coal capacity in the United 

States. It appears that EPA is establishing an emission limit that is based on the performance 

of only 0.5% of the capacity. More data would help support the policy conclusion that 1.2 

lb/MWh is an appropriate figure for the standard. Referenced Text: Although 2 of the facilities 

shown in Table 25 are operating below 1.0 lb/MWh, there are 4 that are operating in the 1.1 to 

1.2 lb/MWh range. To provide a compliance margin and to account for situations where NOX

might be more of a priority pollutant than CO, we are proposing a combined standard of 1.2 

lb/MWh.

Response: Certified CO CEMS data has been challenging to find 

and we are specifically requesting additional data. We believe, 
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however, that the data considered adequately supports the 

proposed standard. Additional data will be considered as it is 

available.

[Pages 524-525] The performance of 4 units may be inadequate to serve as a basis for setting 

an emissions limit applicable to the entire fleet. Referenced Text: All 4 of the WA Parish 

facilities have demonstrated a standard of 230 ng/J (1.8 lb/MWh) is achievable and we are 

therefore proposing that standard for modified facilities.

Response: Same as previous response.

[Pages 537-538] Does fixed capital cost include installation labor? Who determines what the 

cost of a new design is? Also, the term “economically feasible” needs clarification. Referenced 

Text: Reconstruction means the replacement of components of an affected facility such that; (1) 

the fixed capital cost of the new components exceeds 50 percent of the cost of an entirely new 

steam generating unit of comparable design, and (2) it is technologically and economically 

feasible to meet the applicable standard (40 CFR 60.15).

Response: This section has been deleted since we are not 

proposing changes to the general provisions.

[Page 540]: EPA asks for comments on the impact of reliance on combined heat and power 

and whether it is appropriate to recognize the environmental benefit of distributed generation in 

reducing line losses. Line loss has been a controversial issue in our wholesale markets and it 

isn’t clear whether EPA intends to make recommendations to FERC on wholesale market 

design based on comments in this rulemaking. We suggest that EPA clarify why it is asking this 

question. 

Response: We do not intend to make any recommendations to FERC. 

The proposed approach would divide the electrical output of CHP 

facilities by 0.95 (increasing the electric output used in 

determining compliance) and make compliance “easier” for 

owner/operators of CHP facilities.

IX. Summary of Cost, Environmental, Energy, and Economic Impacts of the Proposed 

NSPS

[General Comment] Has EPA conducted a review to verify whether or not the required plant 

modifications under this rule would trigger NSR for certain plants? There is a potential for this to 

occur, since some emission increases may result from the increased parasitic loads. A unit 

triggering NSR may be a candidate for improving plant efficiency (upcoming GHG BACT) and 

for converting from once through cooling to closed cooling [recently proposed 316 (b) rule]. 

Cost implications of such impacts could be very high.

Response: We will consider these issues as we move forward with 

all three actions.

[General Comment] Many reviewers would like to have further discussion of the compliance 

costs of this proposed rule. In particular, cost estimates for upgrading existing scrubbers is of 
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interest. Also, installing multiple controls in series downstream of the boiler would subject the 

flue gas system to higher pressures, and this could require structural strengthening, which EPA 

has considered in previous rules.

Response: We are happy to further consider these issues between 

proposal and final.

[General Comment] The use of a multi-market model does not seem appropriate for the social 

cost estimates. We suggest that EPA discuss why they did not use CGE modeling, and commit 

to issuing a NODA with the CGE model results within the next few months. We also suggest 

that EPA seek comment on alternative approaches for estimating the social cost of the rule.

Response: EPA used the multi-market model for the boilers rule. 

We preferred to used our CGE model (EMPAX) for this rule but 

recent advice from our SAB about the need to incorporate the 

benefit-side effects caused us to defer use of the EMPAX model. 

We explain this in the revised RIA chapter and plan to use the 

upgraded EMPAX model for the final RIA. We do not expect the 

model to be updated in time for a NODA.

[Page 551; Paragraph 1] EPA states that owners/operators of new EGUs subject to the 

requirements of the Clean Air Transport Rule will likely elect to minimize operating costs by 

operating at SO2 and NOX emission rates lower than what is required by the existing NSPS. 

Accordingly, EPA believes the EGU NESHAP PM and SO2 standards for new facilities are as 

stringent or more stringent than the proposed NSPS amendments so they have concluded that 

there are no costs or benefits associated with these amendments. These statements need to 

be confirmed by specifically requesting public comment on these issues.

Response: We will specifically request comment on these issues.

[Page 552; Paragraph 1] Analysis of the proposed rule predicts 2,000 MW of new near term (by 

2015) coal-fired capacity additions. All of the capacity is assumed to include carbon capture 

and storage (CCS) that is funded by some government mechanism but does not get into any 

details. This assumption is tenuous. Can EPA explain why the CO2 capture status is relevant? 

Additionally, this begs the question of what kind of regulatory regime was used in the IPM run –

does it include CO2 or the other regulations that EPA is developing?

Response: These projections are all based on existing ARRA and 

EISA funding and are consistent with EIA projections. We will 

delete references to CCS because it is not relevant

[Page 552] Edit: Should this be “the use of a steam turbine”? Referenced Text: Because the 

use of natural gas in EGUs is an inefficient use of natural gas to generate electricity...

Response: Yes, use of natural gas in a steam turbine-based EGU 

is inefficient. The language will be clarified.

X. Impacts of these Proposed Rules
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[Page 554] Should air impacts of the proposed rule be discussed here?

Response: This section has been added to the 03/10/2011 

version of the draft package.

[Page 555] Should water and solid waste impacts of the proposed rule be discussed here?

Response: This section has been deleted.

[Page 555; Paragraph 1] EPA expects an increase in electricity consumption and total national 

annual energy usage as a result of the rule but does not detail a specific amount. It would also 

be insightful to describe how EPA would expect such increased energy usage would be 

distributed among each category of EGUs subject to the rule (e.g., existing and new sources.)

Response: This language was erroneously included in the Toxics 

Rule and has been replaced with economic impacts language 

directly tied to RIA Chapter 8 findings.

[Page 555] Efficiency projects have been available at existing plants for years, and NSR among 

other impediments have stymied them. Please clarify the basis for the expectation that work 

practice standards will improve. The assumption of a percent increase is important, and it may 

be a point of contention. Referenced Text: Additionally, EPA expects work practice standards 

such as boilers tune-ups and combustion controls will improve the efficiency of boilers, resulting 

in an estimated fuel savings of {__} trillion BTU each year from existing sources and an 

additional {___} million BTU each year.

Response: This language was erroneously included in the Toxics 

Rule and has been replaced with economic impacts language 

directly tied to RIA Chapter 8 findings. The Toxics Rule 

analysis does not assume any efficiency increases at utility 

boilers. However, the IPM power sector analysis shows an 

increase of 2,350 GWh in generation in 2015, which is a 0.06% 

increase over the base case projection.

[Page 556; Paragraph 2] EPA assumes the statutory time available (3 years, with discretion for 

the permitting authority to provide up to 1 additional year) is sufficient to comply with the 

requirements of this rule yet this timeframe may be unrealistic for industry given grid reliability 

issues that may result from closing old coal-fired plants, extended periods of down time required 

to modify equipment, and the availability of labor and materials needed. We suggest EPA 

explain their analysis of how many facilities they expect to be in compliance after 3 years and 

how many they expect to need the additional year.

Response: EPA’s analysis does not break out these numbers, 

because of unit-specific issues, as it is difficult to project 

how many units may take advantage of the 1-year compliance 

extension.

[Page 557] DOE suggests (and requests) that the sentence be revised to say, “...will continue 

to work...” instead of “has worked closely”. DOE has not evaluated the potential impact of the 
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rule on the grid, but it has generated some proxy scenarios, which were developed before 

seeing the proposed rule. Referenced Text: In developing this proposed rule, EPA has worked 

closely with other agencies, including the Federal Energy Regulatory Commission (FERC) and 

the Department of Energy (DOE), to evaluate the potential impact of the final regulation on the 

grid.

Response: We will make the edit.

[Page 558; Paragraph 2] To remedy reliability issues, EPA assumes transmission upgrades, 

targeted demand side management strategies, and construction of new generation; we suggest 

that if this discussion remains, EPA should also discuss funding availability or permitting issues 

associated with such steps and the time that it would take to implement them, as well as 

seeking comment on this topic.

Response: We will add specificity to language generally taking 

comment on the timing issues.

[Page 561] Should compliance cost be included in this discussion?

Response: This will be included. The annual compliance cost is 

$10.9 billion (2007 dollars).

[Page 561; Table 26] The table summarizing capital and annual costs is blank in the version of 

the proposed rule received for interagency review. Can EPA provide these tables?

Response: Yes, we will. The table will be similar to what is 

in the executive summary of the RIA.

[Page 563] The following sentence appears to suggest that the labor intensity of a power plant 

increases after it is retrofit (i.e. more jobs to operate the same plant). Presumably, the retrofit 

plant is operated by staff who already hold the jobs at that plant. Referenced Text: The job 

gains due to new retrofit requirements are likely to be tempered by some job losses due to plant 

retirements, though, as discussed below, many of these workers who lose their jobs due to plant 

retirements could find replacement jobs operating these new retrofits at nearby units.

Response: The entire employment discussion is being rewritten.

[Page 564] It is our understanding that coal mining is more labor intensive than natural gas 

extraction – can EPA provide a citation to the following statement “Finally, job losses due to 

reduced coal demand are likely to be offset by job gains due to increased natural gas demand, 

resulting in minimal net change in jobs due to fuel demand changes.”

Response: As stated in the Employment Effects TSD.

[Page 568; Table 28] EPA analysis in Table 28 appears to indicate employment may actually 

decrease following the rule (possible 68,000 jobs lost due to demand effect), which can be 

noted in the text.
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Response: Such a result will be noted in the text, along with 

other results.

[Page 568; Paragraph 1] Using the Morgenstern, et al. four industry average parameters and 

standard errors and EMPAX models, it is possible that EPA did not quantify all associated job 

losses associated with the proposed rule. Indirect jobs such as industries that use electricity 

and face higher electricity prices as the result of the proposed rule could reduce output, and 

demand less labor may not be factored into EPA calculations.

Response: We mention the lack of indirect job impact estimates 

from our analysis in Chapter 9 of the RIA, and we will include 

such language in the preamble.

[Page 568] Even though the impact on jobs of higher electricity prices cannot be easily 

quantified, the higher prices themselves should be reported from the results of the IPM analysis 

Referenced Text: Also, industries that use electricity will face higher electricity prices as the 

result of the proposed rule, reduce output, and demand less labor. Although EPA has 

considered some economy-wide changes in industry output as estimated using the EMPAX 

model as shown earlier, we do not currently have sufficient information to quantify these 

associated job gains and losses for this proposed rule.

Response: We will include the electricity price changes here 

that are already reported in the EO 13211 section of the 

preamble.

REGULATORY IMPACTS ANALYSIS

The emission limit tables in Chapters 2 and 8 are different. The tables in Chapter 8 appear to be 

the correct limits since they match the limits in the proposed rule.

Response: The correct emission limits will be included in 

Chapter 2.

Specific Comments:

Chapter 1: Executive Summary

[Page 0; Section 1.1, through page 1; Section 1.1.1] The findings box and text discussion in 

Section 1.1.1, do not clearly convey that the vast majority of monetized benefits come from cobenefits of PM. For transparency, this fact should not just reside as a footnote to Table 1-1 or 

within data shown in Table 1-3. Additionally, within Table 1-3, the monetized value of avoided 

IQ loss at the 7% discount rate may be erroneous.

[Page 5; Table 1-3] How does EPA plan to account for the social cost of carbon?

Response: We are upgrading entire Executive Summary and will 

clarify the language.

Chapter 5: Mercury and other HAP Benefits Analysis
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[Page 11; Section 5.2.9] The first several sections of Chapter 5 detail numerous studies 

conducted around the world to determine health related issues associated with MeHg. The only 

thing certain in all of these studies is that they are all inconclusive in their findings and that 

MeHg may lead to certain health problems in children and adults. This should be more clear in 

Chapter 5.

EPA response: We have streamlined the health effects sections 

of Chapter 5 to be consistent with the descriptions in Section 

III.D of the preamble.

[Page 6; Section 5.6.2.1.1.2] Why does the proposed rule single out low-income subsistence 

fishers in the southeast region in the proposed rule?

EPA response: One of several studies characterizing high-end 

self-caught fish consumption rates in the U.S. cited in the RIA 

provides data that could be used to characterize self-caught 

fish consumption rates for these two fisher populations (i.e., 

poor whites and blacks living in the Southeast). However, it is 

important to note that the RIA included a number of additional 

high-end self-caught fish consuming populations (e.g., Laotian,

Hispanic and Chippewa/Ojibwe), all of which are supported by 

high-quality study data characterizing consumption rates. In 

addition, consideration for the full set of studies 

characterizing high-end self-caught fish consumption identified 

in designing the RIA supported modeling a low-income female 

recreational/subsistence fisher more broadly across the U.S. In 

considering the nature of risks experienced by high-end selfcaught freshwater fish consumers in the RIA, we consider all of 

the populations modeled and did not place greater emphasis on 

blacks and whites in the Southeast. 

[Page 24; Section 5.8.5] EPA acknowledges that these findings are not perfect and that many 

assumptions and information provided from sources (i.e. states, reports, etc.) may overestimate 

the mercury levels consumed in fish. Can EPA quantify these overestimates or describe the 

uncertainty in the analysis?

EPA response: The uncertainties in the analysis are discussed 

in section 5.8 of the chapter. Further characterizations of 

uncertainty have been added in that section, however, we are not 

able to quantify many of the uncertainties.

[Pages 35-45; Section 5.9.1] The proposed rule discusses several other hazards (other HAP 

than mercury) but does not relate or quantify any findings or studies associated with electric 

generation and the HAP.

EPA response: Due to limitations in modeling and availability 

of concentration-response information for many HAP, we are 
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unable to quantify the direct health benefits associated with 

non-Hg HAP reductions. This is consistent with many recent HAP 

rulemakings.

Chapter 6: Co-Benefits Analysis and Results

[Page 86; Paragraph 2] The study included in determining endpoints used PM10 unlike all other 

studies to that point which only focused on PM2.5, can EPA explain this?

EPA response: When estimating PM2.5-related health impacts EPA 

applies risk estimates drawn from epidemiological studies that 

meet as many of the selection criteria summarized in table 6-4 

as possible. In rare cases, the epidemiological, clinical and 

toxicological literature may indicate that a particular health 

endpoint is causally related to PM2.5, but no suitable 

epidemiological studies exist that report risk estimates based 

on a PM2.5 indicator. In such situations, EPA will apply risk 

estimates drawn from epidemiological studies that consider a 

PM10 indicator.

[Page 121; Paragraph 2] The preamble states that nitrogen and sulfur in the troposphere can 

travel great distances. Has EPA modeled emissions from across US borders? If so, how?

EPA response: The air quality modeling chapter describes in 

detail how the boundary conditions were modeled.

[Page 121; Paragraph 2] When can society expect to receive the detailed benefits in the 

proposed rule? Is there a difference the timeframe for when the rule will start reducing the 

environmental and health effects versus when people will start experiencing the benefits?

EPA response: In general, the benefits occur contemporaneously 

with the year in which the rule requires facilities to reduce 

emissions of mercury and PM2.5 precursors. In the case of PM 

mortality, mortality risk reductions are assumed to occur with a 

distributed lag in the years following the change in PM 

concentrations, and benefits are discounted over the distributed 

lag period. Complete information regarding the assumptions and 

data inputs to the benefits analyses may be found in the 

benefits chapters.

[Page 121] Several sections throughout the chapter are missing (i.e., Sections 1.1.6.1, 1.1.6.2, 

1.1.6.4, etc) with no indication what the section is expected to contribute to the discussion.

Chapter 8: Cost, Economic, and Energy Impacts

[Page 14; Paragraph 2] Unlike the preamble, EPA projects annual incremental compliance 

cost of the proposed Toxics Rule to be $12.4 billion in 2015 ($2007). The proposed rule and its 
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RIA would benefit from disclosed documentation about assumptions that went into the IPM 

model to generate those figures for EPA.

Response: IPM modeling assumptions are fully documented and 

have been circulated in the interagency review process for the 

Toxics Rule proposal. Some of this documentation is already 

publicly available (http://www.epa.gov/airmarkt/progsregs/epaipm/BaseCasev410.html#documentation) and the supplemental documentation 

circulated in the interagency process will also be published on 

our website with the release of this proposed rulemaking.

[Page 16; Paragraph 1] Analysis of the proposed rule suggests that a vast majority (over 95% 

according to table 8-8) of base case coal capacity would remain in service under the proposed 

Toxics Rule. It is critical that EPA perform comprehensive modeling of the impact that all 

proposed rules for all media (water, air, and solids—including greenhouse gases) would have 

on coal plant retirements. Retirement decisions will not be made on a single rule but on the 

total expected investment required for compliance. 

Response: EPA acknowledges this comment and will take it into 

further consideration.

[Page 17; Paragraph 1] The results of the analysis for the rule predict 10.2 GW of coal-fired 

capacity to be uneconomic to maintain by 2015. How was this determined? Can EPA provide a 

list of these modeled shutdowns? The assumptions and the analysis should be identified for 

comment in the preamble.

Response: EPA has circulated full documentation of its IPM 

power sector modeling assumptions and has provided a list of 

planned and modeled retirements for interagency review.

[Page 28; Paragraph 3] How does EPA take into account other associated costs such as 

emissions monitoring, reporting, record keeping, and administrative costs in their annualized 

cost estimates?

Response: The relatively small cost associated with monitoring 

emissions, reporting, and record keeping for affected sources is 

not included in the IPM-projected annualized cost estimates. 

Instead, EPA has done a separate analysis of these costs. 

Estimates of the monitoring, reporting, recordkeeping, and other

administrative costs are found in the preamble (Paperwork 

Reduction Act) and Chapter 10 of the RIA. These costs are 

estimated separately from the control costs estimated by IPM, 

and are presented separately.

[Page 32; Paragraph 2] The rule analysis projects coal production for use by the power sector 

will decrease by 20 million tons from base case levels by 2015. Did EPA model or consider 

whether world demand for coal or natural gas (e.g., U.S. becoming an exporter of these 

resources) could alter calculations associated with expected future prices?
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Response: EPA did not model any sensitivities based on 

alternative demand for fuels in foreign countries.

[Page 32; Paragraph 1] Natural gas consumption is expected to increase 4 to 6 percent by the 

power sector from 2015-2030 but the proposed rule fails to mention whether the necessary 

infrastructure is in place or the cost associated with building new pipelines. We suggest EPA 

clarify this in the preamble and the RIA.

Response: EPA has incorporated this comment in revised 

materials.

[Table 8-13] The historical coal production data for the electric power sector for 2007 appear to 

be incorrect. Although EIA data is referenced, the web page that is sited is probably not the 

best source for these data. The value of 350 million short tons for Appalachia appears to be off 

by the most, being about 70 million short tons too high. The attached file provides estimated 

data for the years 2007 through 2009. I recommend using more recent EIA data for either 2008 

or 2009. The 2009 coal distribution data were posted at the EIA web on February 18, 2011 

(http://www.eia.gov/cneaf/coal/page/coaldistrib/a_distributions.html).

Response: EPA appreciates these data clarifications and have 

incorporated them into the revised RIA for Toxics Rule proposal.

The historical coal price data for 2007 appear to be incorrect. Although EIA data from the 

Annual Energy Outlook 2011 (AEO2011) Early Release (December 16, 2010) are referenced, it 

looks like the data for minemouth and delivered prices were perhaps inadvertently switched. 

The average minemouth coal price for 2007 from the AEO2011 Early Release should be $1.27 

per million Btu (2007 dollars) and the average delivered price of coal to the electric power sector 

for 2007 should be $1.76 per million Btu. [For the average minemouth and delivered coal prices 

(2007 dollars) from the AEO2011 Early Release see rows 352 and 361, respectively, in the 

attached spreadsheet.] 

Response: EPA appreciates this observation and has corrected 

this in the revised RIA for Toxics Rule proposal.

[Table 8-17] Although EIA data from the Annual Energy Outlook 2011 (AEO2011) Early 

Release are referenced, this table doesn’t actually contain any historical data.

Response: EPA appreciates this observation and has corrected 

this in the revised RIA for Toxics Rule proposal.

OCTOBER 2002 EPA STUDY: “ENGINEERING AND ECONOMIC FACTORS AFFECTING 

THE INSTALLATION OF CONTROL TECHNOLOGIES FOR MULTPOLLUTANT 

STRATEGIES”

[General Comment] The construction schedules and other technical information (e.g., for 

mercury controls) in this report are outdated. Some of this information has already been revised 

by EPA in other previous rules (CAIR and CAMR). We recommend a revision of this study or a 

new study concentrating on controls specifically required under the Toxic Rule is recommended.
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Response: This entire section is being rewritten. Note that 

ICF 2011 reference updated 2002 report as needed.

RESOURCE ADEQUACY AND RELIABILITY IN THE IPM PROJECTIONS FOR THE TOXICS 

RULE

"Within each model region, IPM assumes that adequate transmission capacity exists to deliver 

any resources located in, or transferred to, the region." This is a big assumption that needs to 

be tested. 

IPM retires capacity if it is no longer needed to provide energy for load or to provide capacity to 

meet reserve margin during the planning horizon of the projections. But other operational 

issues need to be considered for reliability purposes, such as system stability (inertia, 

frequency, black start capabilities, etc) outside the reserve margin issue.

Coal retirements are distributed throughout the power grid, so there will be only small impacts 

at the regional level. For example, the coal generating areas in western Pennsylvania, West 

Virginia, Ohio and Indiana all have significant excess generation resources: these areas 

combined see a decrease less than 2% in their reserve margins and the reserve margin for the 

combined area remains over 20%. This is a skewed result as the example states are in 

different IPM regions.

Very few new capacity additions are needed to accommodate coal retirements, once excess 

reserves and non-coal retirements relative to the base case are considered. It is not clear for 

how long the impact of not adding capacity. This issue needs to be addressed considering 

the long build times required for new capacity to be brought on line.

In cases where it is economic to transfer reserves from a neighboring region rather than supply 

reserves from within a region, IPM will transfer reserves, subject to summer and winter limits 

that are designed to ensure that these reserves can be transferred reliably. If transmission has 

not been modeled how can this occur? (regarding first bullet above) Some specific IPM regions 

have known congestion constraints (e.g., NYC, NJ/DE, etc.) so if it is not economical to transfer 

reserves, what do those dependent regions do to move forward without a reliability event?

For example, the retired coal capacity in TVA (1,084 MW) is replaced by a net increase in 

transfer of reserves to TVA (1,097 MW). Where is that capacity transferred from? Is it possible 

to transfer power into the TVA region?

Response: EPA’s power sector modeling assumes the ability for 

firm transfers of capacity between modeling regions subject to 

interregional firm transfer constraints based on current 

operation of the grid and known constraints. These assumptions 

can be found in our modeling documentation at 

http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseCasev410.html#documentation.