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Averaging Time for Standards

 Can EPA please explain why it uses 30-day averaging as the basis for emissions limits? What 

alternative periods did it consider, and what was the rationale for choosing 30 days? Does the 

averaging period have to be the same length of time for all pollutants? Companies have shared 

data with us demonstrating considerable variation in emissions on a 30-day rolling average 

basis, even when average emissions over longer periods are low. Certainly for mercury, my 

understanding is that it is cumulative rather than acute exposure that matters, which would 

argue for longer averaging periods. 

 Can EPA please clarify how the startup and shutdown periods are incorporated into the 30-day 

averaging periods? The draft rule states that work practice standards will be used for 

compliance during startup and shutdown, but it also says that “the rule requires sources to 

measure and report their emissions at all times, including periods of startup and shutdown” (p. 

330). The mention of compliance measurement, at least in the summary, mentions 30 

consecutive boiler operating days without addressing startup/shutdown. Does this suggest that 

emissions during startup and shutdon will be included in the 30-day rolling averages for 

purposes of compliance?

Emissions Averaging

 Can EPA provide the interagency reviewers with an explanation for why it did not elect to allow 

averaging between units in the same subcategory? If appropriate, that explanation should also 

be included in the preamble.

Limited Use Units

 Can EPA explain why it chose a 5 percent annual capacity factor as the threshold for defining the 

limited-use oil-fired subcategory, rather than 10 percent? Can EPA please provide data to 

support its choice? 

Monitoring and Compliance

 Several commenters in the regulated industry raised concerns about the testing procedures. Can 

EPA please clarify how the changes in the rule since proposal have addressed concerns about 

the relationship between stack testing requirements and CEMS, and the frequency of required 

stack tests?

 Has EPA considered the costs associated with using and replacing CEMS equipment, as well as 

the man hours necessary in completing the monitoring and submitting the data in their cost 

analysis?

 Page 355: We refer to a statement on this page: “Where a CEMS (including a sorbent trap 

monitoring system) is used for demonstrating initial compliance, you also must use the CEMS on 

a continuous basis to demonstrate ongoing compliance.” Sorbent traps are not continuous 

monitoring devices, and should not be characterized as such. A sorbent trap requires long 

sampling times (for low-level HAPS such as Hg), transport to an analytical facility (which are 
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frequently not located on site) and analysis in a laboratory. All this is required for a single 

reading. It is not unreasonable for long periods of time to lapse before the sample reading can 

be returned. This would not qualify as a continuous technology that reports real-time 

emissions, which allows operators to tune boiler operation so as to minimize these emissions. 

Therefore, any reference to sorbent traps as a continuous monitoring technology should be 

eliminated. 

 Page 358: This comment refers to the requirements pertaining to use of Hg CEMS or sorbent 

trap monitoring systems. On page 436, the draft final rule says, “we have determined that there 

are adequate test methods to measure the regulated HAP at the new source levels.” We seek 

information on the EPA determination that sorbent trap monitoring systems can support an 

adequate test method for Hg. 

Sorbent traps are not a continuous monitoring technology, as they are designed to take 

readings in batch (intermittent) mode. They are a poor fit for measuring HAPs that occur at 

such low concentrations (like Hg) because such long sampling times are needed to collect 

sufficient mercury on the trap. Furthermore, due to the long sampling time, it has been shown 

that sulfur can begin to also collect on the trap, and “kick off” mercury, leading to inaccurately 

low Hg readings. For this reason, sorbent traps are a poor fit for mercury monitoring and should 

not be included here.

 Page 359, Section V.G.(2): This section requires monthly stack tests or use of PM CPMS for 

proving compliance with the PM emission limits. It appears that costs involved with conducting 

monthly stack tests would be expensive, especially for small power plants. The operating 

permits for most of the existing plants may require use of opacity monitors for compliance with 

PM emission limits that may be more stringent than those in the MATS rule. Would these plants 

now have the extra burden of maintaining dual monitoring/testing programs for the same 

pollutant?

Mercury Emissions Standard

 Can EPA explain the basis for its mercury standard and in particular the sample of units it used 

to determine the standard?How does that set of units compare to the set of units used to 

calculate emission standards for other pollutants?

 More specifically, EPA used a different number of units to set the new unit MACT floor for acid 

gas and PM (131) than it did to set the new unit MACT floor for Hg (40). Many submitted public 

comments that EPA did in fact possess the data to base the new unit MACT floor for Hg on 127 

units. EPA failed to address this comment in the final rule.

This comment was repeatedly submitted but was well articulated in particular by Duke Energy. 

The comment is summarized here for EPA to address. 

“Section 112(d)(3)(A) of the CAA specifies that EPA must set a MACT limit for existing units that 

is at least as stringent as the average emission limitation achieved by the best performing 12 

percent of the existing sources (for which the Administrator has emission information). EPA 
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determined that it needed additional information on HAP emissions to conduct the current rule 

making to set MACT limits. EPA undertook an information collection request (ICR), sending it to 

all coal- and oil-fired EGUs and requiring extensive reporting of historic emissions information. 

In designing the stack testing portion of the ICR, EPA considered choosing plants either on a 

purely random basis or selectively choose only units that it believed were best performing units 

and would have the lowest emissions of a given HAP. EPA chose to follow the second option in 

its 2010 EGU MACT ICR. However, to ensure that it collected data from the best performing 

units, EPA elected to require stack sampling for mercury, acid gases, and non-mercury metallic 

HAPs from what EPA considered was the best performing 15% of the 1,091 coal fired units. In 

addition, EPA collected a large amount of existing emissions data under Part II of the ICR, 

particularly for mercury.

Before EPA submitted the ICR to OMB, representatives from EPA and industry met to discuss the 

scope of the ICR and how units would be selected for testing. EPA‘s preferred approach was to 

require testing by units that EPA thought were the best performing for emissions of mercury, 

trace metals, HCl, organic HAPs and dioxins. Industry argued that if EPA selected plants in this 

manner, then it must use data from a number of sources representing 12% of the entire industry 

to calculate the MACT floor. Assuming a total of 1,091 coal-fired units, 131 units would 

represent 12% of sources. As a result, EPA stated in its Supporting Statement for the ICR:

For 3 of the HAP groups or individual HAP, to the extent the Agency can establish that is 

has in fact collected data from all of the existing sources that represent the best 

performing 12 percent of the existing sources, we intend to use data from sources 

representing the best performing 12 percent of all sources in any category or 

subcategory to establish the CAA section 112(d) standards.

On this basis, OMB approved EPA‘s Utility MACT ICR and sources conducted the required 

testing.

In the proposal, EPA used emissions from 131 units -- 12% of the 1091 coal-fired EGUs -- to 

calculate the MACT floor HCl and total PM. Because EPA intentionally selected what it thought 

were the best performing units, Duke Energy strongly agrees with EPA‘s use of 131 units to 

calculate the MACT floors for these HAPs. However, Duke Energy strongly disagrees with EPA‘s 

use of 40 units to determine the MACT floor for mercury emissions. In the preamble to the 

proposed rule, EPA now stated: “For Hg from coal-fired units, we used the top 12 percent of the 

data obtained because, even though we required Hg testing for the units testing for the non-Hg 

metallic HAP, we did not believe those units represented the top performing 12 percent of 

sources for Hg in the category at the time we issued the ICR and we made no assertions to that 

effect.”

This runs counter to EPA‘s position when it sought approval of the ICR from OMB when EPA 

stated: “For Hg and other non-mercury metallic HAP group, EPA believes that units with the 

newest PM controls installed represent those units meeting the lowest PM emission limits, and, 

thus, are believed to be among the top performers with respect to Hg and other non-mercury 

metallic HAP emissions. Therefore, EPA has selected 175 units with the newest PM controls 

installed; of these 175, the newest 170 operating units will be required to conduct Hg and other 

non-mercury metallic HAP testing. This number includes units with ACI installed and other 

control configurations are also included (e.g., for SO2 and NOx control.”

Given these conflicting statements, the question becomes whether EPA did collect mercury data 

from the best performing units during the ICR. After the proposed rule was released, various 

errors were identified in the derivation of the mercury standard. Once these errors are 

corrected, the mercury ICR data do show that the best performing units were tested during the 
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ICR. The most significant error involved converting Part II ICR data that had been reported in 

terms of lb/GWh. When these data were converted to lb/MWh, EPA divided by a factor of 

1,000,000 instead of the correct divisor of 1,000. Because of this error, many units that reported 

Part II data appeared to be among the top units because their actual reported mercury 

emissions were understated by 1,000 times. Of the 40 existing units that EPA identified as the 

best performing for mercury emissions, 20 were incorrectly listed among the best units because 

of this single conversion error. Looking at the original list of best performing units, it is easy to 

understand why EPA may have questioned whether the ICR testing really targeted the best 

performing units for mercury emissions. Once the error is corrected, the result is clear – EPA did 

select the best units for ICR testing.

After the conversion factor is corrected, all but six of the top 40 units submitted Part III test 

results. Looking at the broader group of 131 best performing units, the Part III testing bias for 

the best performing mercury units becomes inescapable. Of the top 131 units, only 22 did not 

submit Part III results. There are several other reasons to conclude that the Part III testing 

focused on units with the lowest mercury emissions. One indication is the disproportionately 

high number of units equipped with activated carbon injection (ACI) that were tested. ACI is 

installed on coal-fired EGUs for the sole purpose of controlling of mercury emissions. EPA‘s 

spreadsheet of the Part II ICR data lists 45 EGUs as having installed ACI systems. Of those 45 

units, 33 reported Part III mercury test results. Had the Part III testing for mercury been 

completely random, as EPA‘s present choice of 40 units to set the MACT floor suggests, then 

only 15% of all ACIs units would likely have been selected for Part III testing -- or 7 units. In fact, 

73% of the units equipped with ACI were required to conduct Part III mercury testing. 

Ultimately, EPA had a much larger database to establish the MACT Floor. Using 40 units to 

represent 12% of the population (1,091) indicates that EPA had a data from approximately 330 

units or almost a third of the entire industry. Considering all these factors shows that EPA‘s data 

set robustly represents the very best performing of all of units. EPA is therefore incorrect when 

it states” For Hg from coal-fired units, we used the top 12 percent of the data obtained because, 

even though we required Hg testing for the units testing for the non-Hg metallic HAP, we did not

believe those units represented the top performing 12 percent of sources for Hg in the category 

at the time we issued the ICR.”

As a result, the only appropriate action is for EPA to use 127 units to determine the MACT floor 

for Bituminous and Sub-bituminous subcategory.

Area Sources

 EPA received many comments supporting GACT standards for area sources. Can EPA explain 

why they cannot establish GACT standards for area sources under the authority of 112(d)(6)? Is 

EPA prohibited from establishing area source standards? What impact would GACT standards 

for area sources have on the costs, benefits, and standards for the major sources?

 Responding to comments about the need for area source standards (page 480), EPA notes 

“Commenters indicate that many EGUs owned by small entities are potential area sources. 

However, commenters fail to note that there are also EGUs owned by small entities that are 

NOT potential area sources, and, thus, would not accrue any “lessened regulatory burden” 

benefit from a decision by the EPA to establish area source standards.” This is not a strong 
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response to the argument that area source standards would reduce burdens on many small 

entities. Please revise to more directly address the comment

Compliance Deadline

 EPA appears to be essentially delegating all authority to extend a fourth compliance year to 

State permitting authorities. Can EPA explain why it is not simply using its own authority under 

112(3)(B), which it appears to retain even when States have Title V permitting authority (“The 

Administrator (or a State ... ) may issue a permit that grants an extension ....”), to give broadbased extensions?

 A three year implementation timeline for multiple emissions controls upgrades seems extremely 

aggressive. This has been noted in the comments section. However, I am concerned that a 

large number of non-compliant coal plants would suddenly need to design, construct, test and 

operate emission control devices within three years. One issue is that the A/Es, various 

equipment providers, labor, etc. could probably not handle this sudden influx of business. This 

can result in extended lead times for emissions controls equipment, shortages of qualified 

designers, shortages of specialized construction, etc. When there is a surge in need for these 

suppliers several issues typically arise. 1) The price of equipment and services increases to 

reflect demand, 2) The design and construction schedules extend beyond original estimates 

and/ or 3) The quality of the emission controls design and construction is compromised by 

rushed work. Also, supply and demand applies here as the greater the need for the controls 

increases the overall cost associated with these emission controls which could easily result in 

costs greater than EPA originally estimated. Has EPA evaluated this effect on the cost and 

availability of control technology? In particular, rural cooperatives often have relatively smaller 

generating units. The best qualified A/Es, equipment suppliers and construction outfits will seek 

to work with the projects that have the greatest potential for profit (larger and multiple coal 

units) which could put small G&T cooperatives at a disadvantage when seeking support to build 

the new emissions controls. Investor owned utilities would probably be first in line for vendor 

and consultant support.

 Page 508: “Permitting authorities should be familiar with the operation of the 1-year extension 

provision because EPA established regulations to implement the provision and the provision 

applies to all NESHAP. See 40 CFR 63.6(i)(4)(i).” Is applying for and granting a 1-year extension 

easy or simple to do? If so, it would be very helpful for EPA to explain.

 Page 513: We refer to a statement on this page: “However, other commenters requested that 

no additional time be granted for compliance. These commenters reference a number of reports 

(e.g., by the URS Corporation, by M.J. Bradley & Associates and the Analysis Group, and by the 

Bipartisan Policy Center) to indicate that not only is technology readily available, but that the 

technology can typically be installed in less than 2 years and that the electric industry is wellpositioned to comply with the EPA’s proposed air regulations without threatening electric system 

reliability.” The comment that EPA is referring to is almost certainly from Exelon Corporation 

(Exelon submitted public comments to this effect, and also referenced the reports noted here by 

EPA).

Exelon’s power generation portfolio is weighted heavily toward non-coal generation. As of late 

2009, Exelon held full or majority ownership of 17 nuclear reactors in 10 nuclear power plants. 

In the spring of 2011, Exelon announced a merger with Constellation Energy. The combined 
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company will own nearly 19 GW of nuclear generation,8.2 GW of natural gas generation, and 

nearly 3 GW of renewable generation including hydroelectric.

Exelon’s power generation business would likely benefit tremendously from as many coal plant 

retirements as possible. Therefore, it is not surprising or credible that they have submitted 

comments stating that the compliance period is reasonable, and the technology can be installed 

in less than two years. Other utilities (such as American Electric Power and Southern Company) 

with actual experience in pollution control retrofits disagree strongly with the assertions made 

by Exelon, based on their submitted public comments.

None of these reports confirms that control technologies (specifically dry sorbent injection) 

are readily available. The referenced report by URS Corporation was commissioned by Exelon 

Corporation (this is specifically stated in the executive summary of the report). As noted 

previously, Exelon would benefit from a large number of coal retirements brought on by the 

aggressive compliance period due to their heavy nuclear and gas portfolio. The referenced 

report by Bipartisan Policy Center also explicitly states that their assumptions regarding the cost, 

effectiveness, and availability of DSI were completely informed by EPA, not their own 

assessment. Finally, the referenced report by M.J. Bradley was funded by the Clean Energy 

Group’s Air Policy Initiative, whose members include Exelon Corporation and PG&E (both heavily 

invested in nuclear generation as well as natural gas), Constellation Energy (who has merged 

with Exelon Corporation), and Calpine Corporation (whose portfolio is weighted heavily toward 

natural gas). All three of these reports were funded by organizations that have a stake in coal 

retirements, and they all lack the independent research, development and demonstration that 

would actually indicate that DSI could be installed as widely as EPA has assumed. 

 Page 513: We refer to a statement on this page: “Another commenter noted that utilities that 

failed to plan ahead “should not be permitted to use their own inaction to justify more time.” 

Commenters noted that several major utility companies have anticipated the EPA’s rules and are 

already taking action to ensure a reliable supply of electricity in their service territory and 

beyond.” The aggressive MATS compliance period almost requires utilities to immediately start 

making decisions regarding retrofits. Failure to do so may result in getting caught up in a wave 

of other utilities that wait until MATS becomes final, possibly resulting in cost premiums due to 

supply chain pressure, or inadequate time remaining to complete the project. The issue with 

starting early is that utilities run the risk of making wrong decisions because the rule changes, 

either due to litigation, vacation by the court, or other factors. A utility that initiates a fabric 

filter or FGD installation, ultimately to learn that it is not needed because the rule changed, will 

prove to have made a costly decision. Given the current economic times, utility executives are 

more likely to be risk averse and may instead opt for retirement, rather than make the wrong 

retrofit decision. A more appropriate compliance period would avoid this issue by giving utilities 

adequate time to make retrofit decisions, and allowing for a more reasonable project schedule, 

while still achieving the stated EPA goal of pollution reduction.
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 Pages 515: We refer to a statement on this page: “Clean Air Act section 112 specifies the dates 

by which affected sources must comply with this rule. New or reconstructed units must be in 

compliance immediately upon startup or [DATE OF PUBLICATION OF THIS FINAL RULE IN THE 

FEDERAL REGISTER], whichever is later. Existing sources may be provided up to 3 years to comply 

with the final rule; if an existing source is unable to comply within 3 years, a permitting authority 

has the ability to grant such a source up to a 1-year extension, on a case-by-case basis, if such 

additional time is necessary for the installation of controls.” Numerous sources such as

American Electric Power and Southern Company, have repeatedly stated that while 4 years (3 

years, plus a one year extension) may be adequate to physically install the equipment, it does 

not allow for permitting (which can take up to a year alone), design, procurement, installation, 

testing, and startup. It is worth nothing that these are institutions in the electric power industry 

and have a great deal of experience in pollution control retrofits.

According to AEP, a fabric filter retrofit typically takes 3 and a half years, while an FGD requires 

nearly 6 years from project conception to startup. Southern Company has confirmed these 

estimates. These schedules also do not account for the constraint in labor and construction 

resources that will most likely occur under a 3 – 4 year MATS compliance period as proposed.

The compliance periods for MATS, as well as other pertinent regulatory initiatives (including the 

Cross State Air Pollution Rule (CSAPR), 316(b), and Coal Combustion Byproducts) are 

overlapping, and plants will likely have multiple projects occurring simultaneously, to comply 

with several different rules. This high demand for services in a relatively short period of time 

will put a strain on the construction and engineering firms that are available to perform the 

work.

A likely outcome of these overlapping timelines is that there will be a large amount of retrofit 

activity in the fossil power generation sector during the 2012-2016 timeframe, causing the 

supply chain to become constrained, and substantially increasing project costs. 

Don Broelis, Vice President of Fluor Power Group, described the impact of the proposed MATS 

compliance period:

“If it is a three-year program, we believe we are going to see an extreme peak in activity 

and that’s going to be the complete supply chain. That will be tightening the supply for 

environmental technologies such as SO2 scrubbers, selective catalytic reduction, 

baghouses, chimneys and then some of the typical bulk materials like steel and 

components such as pumps, motors, transformers and so forth. There will be a 

tightening even with contractors to perform the work.”

 Page 522, Section VII.F, Response: In EPA’s response throughout this section, the issue related 

to the adequacy of compliance timing and its effect on grid reliability has been addressed. 

However, a part of this issue brought up in the public comments is to do with the ability of the 

affected sources to install the required environmental controls by the compliance deadline 

(including the one-year extension allowable by this rule). Several commenters provided 

estimates of the installation timing required that exceeded the allowable time for some 

controls, including wet FGD scrubbers and baghouse filters. Many commenters also pointed to 
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the inadequacy of resources within the industry to build the required controls within the 

allowable time. One commenter (Utility Air Regulator Group) submitted a detailed study on the 

issue of adequacy of the available industry resources, especially the skilled labor. It appears that 

EPA’s responses do not fully address these concerns in the preamble. Please advise if there is 

another rule document where these issues are covered.

 Page 515: We refer to a statement on this page: “The EPA has considered the concerns raised 

by commenters and has concluded that given the flexibilities further detailed in this section, the 

requirements of the final rule for existing sources can be met by most sources without adversely 

impacting electric reliability. In particular, EPA believes that the flexibility of permitting 

authorities to allow a fourth year for compliance should be available in a broad range of 

situations (as discussed below), and that this flexibility addresses many of the concerns that have 

been raised. Furthermore as indicated below, in the event that an isolated, localized concern 

were to emerge that could not be addressed solely through the 1-year extension under CAA 

section 112(i)(3), the CAA provides flexibilities to bring sources into compliance while 

maintaining reliability.” Unscrubbed coal units burning either bituminous or subbituminous 

coal, in states affected by CSAPR are the units that are most likely to be impacted by MATS, in 

addition to CSAPR, the coal combustion byproducts rule and 316(b). Consequently, there is 

likely to be significant activity within select geographic areas, which can potentially be 

problematic for attracting and retaining skilled labor.

Many engineering cost estimates frequently include incentives beyond a typical 40-hour 

workweek. Often, these monetary incentives are required to retain a skilled labor force on a 

jobsite. Without an extra financial incentive, there is little that can be done to prevent skilled 

craftsmen (such as pipefitters, welders, or ironworkers) from going to a nearby, competing job 

that pays better. Such an exodus of craft labor can be devastating to the successful completion 

of a project, on time, and within budget.

Given the proximity of the coal-fired power plants that are likely to require engineering and 

construction services, and the high demand for such services during a short period of time, 

there is likely to be a premium put on the existing labor force during 2012-2016 (assuming the 

one-year extension is granted). This could seriously hamper the ability of the coal-fired power 

generation industry to comply with MATS during the proposed timeframe. A more relaxed 

schedule would likely alleviate the pressure on this resource, and increase the likelihood of 

achieving MATS compliance.

 Page 531: “While the ultimate discretion to provide a 1-year extension lies with the permitting 

authority, EPA believes that all three of these cases may provide reasonable justification for 

granting the 1-year extension if the permitting authority determines based on information from 

the RTO or other planning coordinator for the relevant region, and/or NERC or one of its regional 

entities, and/or the Federal Energy Regulatory Commission (FERC) or the DOE, that continued 

operation of a particular unit slated for retirement for some or all of the additional year is 

necessary to avoid a violation of applicable FERC-approved or state electric reliability standards.” 

Again, since units have no economic motivation to announce retirements early, the situation 

may arise where plants announce retirement with as little as 45 days notice of January 1, 2015 

to the RTO. If EPA grants the RTO the 1-year extension to complete transmission upgrades, then 

the RTO essentially has 1 year plus 45-120 days (depending on the RTO) to implement 

transmission upgrades. Since these upgrades can take 1-3 years as even identified by EPA in this 
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preamble (Page 507), this does not give the RTO adequate time to respond to a transmission 

security reliability issue by the compliance deadline. A 1-year extension to the permitting 

authority may not be adequate for alleviating reliability concerns. 

 Page 535: “The EPA believes that the number of cases in which a unit is reliability critical and in 

which it is not possible to either install controls on the unit or mitigate the reliability issue 

through construction of new generation, transmission upgrades, or demand-side measures, 

within 4 years, is likely to be very small or nonexistent. This view is echoed by commenters 

explicitly mandated with ensuring grid reliability.” These commenters made this statement 

under the presumption that EPA would incentivize early retirement announcements by granting 

compliance extensions only to units who announce their retirement with at least 2 years 

advanced notice (see Corrected Comments of PJM Interconnection, L.L.C., August 4, 2011). Most 

commenters recognize that reliability issues are a very really problem, especially from a 

transmission security standpoint, and absent EPA providing early retirement incentives, these 

regions may be required to make system upgrades in a little more than one year. This limited 

timeframe is counter to public comments and public documents outlining historic timelines to 

install transmission upgrades. 

 EPA should, in the final rule, grant a blanket 1-year extension to all existing EGUs under Section 

112(i)(3)(B) of the CAA. We believe this section of the CAA allows the Administrator to issue a 

Title V permit that grants a 1-year extension. Since EPA ultimately can approve or veto any Title 

V permit, even one issued by a State permitting authority, Section 112(i)(3))(B) should be 

construed as granting EPA the authority to issue such a 1-year blanket exemption. A blanket 

extension will result in the fair and uniform exercise nationwide of the discretion provided by 

the Act to grant an extension for installation of controls.

Further, Section 112(i)(4) contains the option that authorizes the President to grant an 

extension of 2 years (which may be renewed) if the President determines that the “technology 

to implement [MACT] standards is not available and that it is in the national security interest of 

the United Sates to do so.” The proposed MACT standards require large-scale installation of 

new control technologies to meet HAP limits. The installation of controls on such a massive 

scale within 3 years is not feasible. Accordingly, we recommend that EPA seek a Presidential 

exemption that could then be implemented through qualifying criteria enumerated in the final 

rule. Once granted, EPA would use the Presidential exemption extension where additional time 

beyond 4 years is required in order to maintain electrical system reliability. The use of this 

Presidential exemption would be vastly preferable to the use (as currently proposed) of EPA’s 

enforcement discretion to allow operation of sources in non-compliance beyond the 4-year 

timeframe. 

 EPA’s assumed installation timeframes do not include the time necessary for conceptual and 

detailed design and permitting. We are providing below the timeframes for control equipment 

installation based on TVA’s extensive experience designing and constructing such control 

systems. As detailed below, the times required for the three main acid gas removal options 
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(DSI, Dry FGD, and Wet FGD) as well as for control via onsite replacement Combined Cycle (CC) 

generation and transmission upgrades range from 39 to 59 months for back end controls and 

replacement generation and up to 7 years for transmission upgrades. EGU’s representing 

approximately one half of the coal-fired generating capacity in the US do not currently have 

FGD or DSI systems installed for acid gas control. All of these units will either have to be 

controlled or retired based on the proposed rule. 

The installation timeframes described below for the alternative control options do not include 

the anticipated schedule impacts associated with the large number of equipment installations, 

replacement generation construction, and transmission upgrades that will be ongoing during the 

same time period. Equipment suppliers will be critically challenged to meet the national 

demand for controls, new generating units, and transmission upgrades in a timely manner, 

adding further uncertainty to installation timeframes. The number of units that can be offline 

simultaneously for controls installation/tie-in and the number of transmission facilities that can 

be offline simultaneously for transmission upgrades is limited due to system reliability 

requirements.

The above uncertainties and limitations notwithstanding, installation timeframes for selected 

control devices based on TVA’s direct experience are provided below and in the attachments.

DSI: DSI may be a viable acid gas control option only for those units burning lower sulfur coals in 

conjunction with a baghouse. TVA does not believe that DSI will be adequate for medium to 

high sulfur coals. Importantly, DSI may also not be adequate for meeting other anticipated 

regulatory requirements, such as SIP requirements to meet the NAAQS for SO2 and fine 

particulate (PM2.5), or for achieving SO2 reductions needed for compliance with the Cross State 

Air Pollution Rule(CSAPR) . The Shawnee plant is TVA’s only plant currently equipped with 

baghouses. Where both a baghouse and DSI would be needed, we expect installation of the 

baghouse and associated fans and other equipment would present a critical path for the project. 

The time required to select, design, permit, and construct DSI system with baghouse would be 

similar to the dry FGD schedule, which is a minimum of 50 months as described further below. 

For units where a suitable baghouse is already installed, we expect a minimum of 39 months 

would be required to select, design, permit, and install DSI. 

Dry FGD: TVA expects the use of Dry FGD with baghouse to be a viable acid gas and particulate 

control option for some units burning medium to low sulfur coal, depending on the emission 

limits in the final rule. As described in the attached report by George Farina and Donald 

Houston, Attachment 1, we estimate 50 months are required to select, design, permit, and 

construct a Dry FGD with baghouse. The report also shows that where an offsite disposal facility 

must be located, acquired, permitted, and constructed, the total project duration increases to 

63 months because activities relating to establishing a disposal facility would be critical path. 

Wet FGD: TVA expects the use of wet FGD to be a viable acid gas control option for most coalfired units, but also the most expensive and time consuming controll equipment to install. As 
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described in the additional report by George Farina and Donald Houston (Attachment 2) we 

estimate 59 months are required to select, design, permit, and construct a wet FGD. As noted 

above, we estimate 63 months will be required where an offsite disposal facility is required. 

Replacement Power: Depending on the emission limits in the final rule, TVA expects the best 

emission control option in some cases will be to retire the coal-fired units and replace that 

generation with Combined Cycle (CC) units. As described in the report by Dan Tibbs and 

Donald Houston (Attachment 3) we estimate 48 months are required to select, design, permit, 

and construct a CC plant on site to replace retired coal units. We agree with EPA’s 

understanding that the 1-year extension provided for in the CAA for the installation of controls 

should apply to the installation of on-site or off-site replacement power. 

transmission Upgrades: TVA expects the best emission control option in some cases may be to 

retire some coal-fired units, and through construction of transmission upgrades, deliver the 

power generated by the remaining units to customers, thus resulting in an overall reduction in 

fleet emissions. 

Pursuant to Section 215 of the Federal Power Act, as a user, owner, and operator of bulk power 

system, TVA is required to meet certain performance criteria established in Reliability Standards 

promulgated by the North American Electric Reliability Corporation (NERC) and approved by the 

Federal Energy Regulatory Commission. As a result, compliance with those criteria is not 

optional. The NERC requirements are very stringent, and we do not anticipate any additional 

upgrades beyond those required by NERC for reliability purposes. 

TVA built and continues to operate one of the largest high voltage transmission systems in the 

country, and our in-house Electric Systems Projects group has extensive experience upgrading 

and extending the system. Current lead time for delivery of large transformers typically is 2 

years, and environmental review and land acquisition alone for transmission lines can take 

several years. As shown in Attachment 4, TVA estimates that a typical 20 mile single circuit 161 

kV transmission line project will take approximately 56 months from initial planning studies to 

completion. A project for a 30 mile 500 kV line would require approximately 84 months.

We agree with EPA’s understanding that the 1-year extension provided for in the CAA for the 

installation of controls should apply to transmission upgrade projects associated with retirement 

of coal-fired units. We expect in some cases additional operating time beyond 1 year for units 

being retired will be needed to maintain power system reliability. 

Startup/Shutdown

 Additional leeway must be given during periods of startup or shutdown. A 5 percent rate of 

capacity requirement does not account for the variability associated with starting up or shutting 

down a facility.

 On page 341, requiring sources to use either natural gas or distillate oil ignition during startup 

may be an undue burden. Will EPA have/allow exemptions? How does a source demonstrate 

compliance with §63.10011 (g)(2)?
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 Page 340, 1st Paragraph The definition of startup in this paragraph is restricted to cold startup 

only, with no discussion of warm and hot startup modes. The turbine is also not connected to 

the grid during these warm and hot startup modes. Please note that, during warm and hot 

startups, the boiler and turbine surfaces are warmer and, therefore, the startup times are 

shorter than those during cold startups. However, the unit operation is still unstable during the 

warm and hot startup modes, and the emissions of various pollutants may still be higher than 

those achievable during stable loads. Does EPA have emissions data for warm and hot startups 

to confirm that affected sources can meet the same emission limits during these startups as 

during the full/stable load operation? If not, we recommend that EPA consider these points in 

clarifying the definition of startup, which is also discussed on pages 338 and 339.

 The rule preamble describes cold startup as starting from the point of no fuel being fired in the 

boiler and the boiler at ambient temperature. Heat from adjacent units and other sources 

prevents out of service boilers from reaching outside ambient temperatures, and due to their 

large mass, several days can be required for cooling to near ambient power house 

temperatures. Startup of a boiler that has cooled sufficiently to allow for human entry, which is 

to approximately 120 degrees Fahrenheit, should be considered a cold startup. 

 Work practice standards should apply for all startups and shutdowns, and not be limited to 

only cold startups. The rule appropriately requires work practice standards instead of 

numerical limits during cold startups and shutdowns, acknowledging the highly variable 

emissions and lack of appropriate emissions data during these periods. However, emissions 

during warm and hot startup periods are also highly variable and, likewise, little emissions data 

is available for these time periods. Accordingly, work practice standards should apply, instead of 

numerical limits, for all startups and shutdowns. 

 EPA also considers that startup ends when the turbine-generator is synchronized to the grid and 

is requiring sources to operate using either natural gas or distillate oil for ignition during startup. 

TVA operating procedures for safe startup generally require establishing a coal fire shortly prior 

to synchronization and then prompt initial loading of the generator after synchronization. Oil 

and coal are then co-fired as load increases until normal minimum load is reached, where a 

stable coal fire is established and the oil fire can be safely removed. Startup should be 

considered to continue until a stable coal fire is established and the oil fire can be removed. 

Combustion of coal during startup should be allowed consistent with manufacturers’

recommendations. 

 EPA is requiring sources to operate all control devices necessary to meet the normal operating 

standards under the final rule (with the exception of SCRs) when coal or residual oil is fired in 

the boiler during startup or shutdown. Baghouses and some other control devices, in addition 

to SCRs, have minimum temperature and other requirements that limit their operation during 

startup. The work practice standard should require operation of control devices during startup 

and shutdown to the extent allowed by manufacturers’ requirements. 
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Impacts of the Rule on Ratepayers

 It does not appear as though EPA took into adequate consideration the real potential utilities 

will close and the surrounding communities experience economic hardship due to these 

regulations. 

 The coal units affected by this regulation would be faced with a large investment of funds that 

will result in no added production from the plants. On the contrary, the parasitic load 

(electricity necessary to run the equipment in the plant itself) that each plant normally requires 

would increase substantially due to the installation of emission controls devices that require 

power to operate. So, in essence, the power plants will ultimately produce fewer megawatts 

due to the increased parasitic load and associated revenues would be decreased. Has this effect 

been accounted for in the costs of the rule and effect on ratepayers?

 Page 555: We refer to a statement on this page: ““The EPA’s estimates of increase in the retail 

electricity price range from 1.3 percent to 5.9 percent regionally in 2015...Low-income 

households will thus see some increase in electricity price, but this increase should be modest.” 

This percent price increase does not take into account the cumulative effect of numerous EPA 

rules that could place upward pressure on electricity prices. Additionally, it is unclear why a 

price increase as high as 5.9 percent would not be considered a major increase to a low-income 

consumer

 We strongly recommend that EPA consider providing context for the projected change in 

electricity prices by comparing either the projected prices or the magnitude of the projected 

increase to recent historical data. For example, based on a quick look at EIA 

data(http://38.96.246.204/electricity/monthly/excel/epmxlfile5_3.xls), it appears that EPA 

could explain its projected average price of electricity with the EGU MACT rule would still be less 

than average electricity prices for 2008-2010 (EPA should confirm that those numbers are 

comparable). Alternatively, EPA could say that the 3% increase is on par (or even less) than 

typical year-to-year price variability (again, after verifying that is in fact the case).

Noncompliance

 Additional details need to be provided on what the penalties are for non compliance. Can EPA 

explain to the reviewers how non-compliance is treated? Is there an appeals process? 

Appropriate and Necessary Finding

 Given the scrutiny that can be expected for EPA’s “appropriate and necessary” finding, We 

recommends that EPA provide a simple and succinct plain language explanation of its rationale 

at the beginning of Section III, before describing in greater detail the “appropriate and 

necessary” finding. A plain language explanation that “connects the dots” would be very helpful 

for the lay reader. 

Applicability

 Does EPA have a guidance manual that will be available on their website of all the entities that 

will be regulated under this regulation? The statement that an entity must reach out to their 

regional representative to find out if they must comply with this regulation is not ideal.
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 Why were 10 and 15 percent production levels selected as the cut off point for coal fire? What 

is the rational?

 Page 593: We refer to the statement on this page: “Only those units that begin construction, 

modification, or reconstruction after May 3, 2011, will be affected by the final rule.” For units 

meeting this criteria, but who already have air quality permits, will this apply to them 

retroactively? There is a legal precedent for preventing retroactive application of new permit 

levels for units that have already obtained permits (Xcel Energy case cited above).

Tone

Page 314 (and elsewhere), regarding EPA’s response back to UARG -- though we can understand EPA’s 

argument, the response is combative and unnecessary. Suggesting softening the tone.

Impact on Rural Utilities

 The regulation will have a disproportionate impact on smaller generating units (such as those 

owned by rural G&Ts). This will cause an increase in electricity rates. These small rural utilities 

have limited ability to recoup investment through rate adjustments due to the relatively small 

size of consumers within the respective service territory. EPA suggests that the cost for smaller 

generators is proportional to larger generators. Has EPA modeled higher costs for smaller 

generators? 

Emissions Limits

 Page 318, Table 3: Clarifications are requested for the following emission limits:

 Existing Unit designed low rank, virgin coal, Mercury, 4.0E0 lb/Tbtu (4.0E-20 lb/GWh): 

Possible typo, 4 x 10^-20 Lb/GWh? Suspected that this should read 4 x 10^-2 Lb/GWh,

which would be a gross heat rate unit of 10,000 Btu/kWh.

 New unit designed for coal > 8,300 Btu/lb, Mercury, 2.0E-4 lb/GWh: For bituminous 

coal, this limit of 0.0002 Lb Hg/GWh converts to approximately 0.027 microgram/dry 

normal cubic meter (corrected to 3% O2). This is almost two orders of magnitude below 

what commercial CEMS can accurately measure. Discussions with University of North 

Dakota’s Energy and Environmental Research Center (EERC) indicate that measurements 

in the range of 0.5 – 1 microgram/dry normal cubic meter were accurate, however 

below this, the readings became less accurate due to extremely low Hg levels. EERC also 

indicated that they have never tested mercury CEMS at or below 0.1 microgram/dry 

normal cubic meter (which is still nearly four times above the proposed limit). 

Therefore, this mercury limit should be reconsidered since 1) continuous emissions 

monitors cannot accurately measure down to this level, and 2) sorbent traps are not a 

continuous monitoring technology and should therefore not be considered for this 

application.
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 New Units designed for coal > 8,300 Btu/lb: While the emission limits for most sources 

are higher than those included in the proposed rule, the PM emission limits for the new 

coal units are significantly below the proposed levels. The new limits also appear to be 

well below the levels ever permitted in the US for coal-fired boilers. Based on a rough 

calculation for a boiler firing a coal with 10% ash and a heating value of 12,000 Btu/lb, 

the fly ash loading assumed to be 80% of the total ash at the inlet to the particulate 

control device would be approximately 6.7 lb/MMBtu. With a stack emission limit of 

0.007 lb/MWh (or roughly 0.0007 lb/MMBtu), a device with a particulate control 

efficiency of 99.99% would be required to meet this limit. Since the coal ash content 

can be higher or the heating value of coal can be lower, the efficiency requirement for 

such coals would be even higher. A plant may not be able to procure such a device. If 

the new PM emission limits are based on ICR data from a small number of units, EPA 

may want to look at the tested operating conditions, such as coal ash contents, and 

potential errors in reporting to confirm the validity of these limits. 

Coal subcategories

 Page 389: We agree with EPA on creating the coal subcategories based on high- and low-rank 

coals. However, this does not cover a situation where a plant decides to burn a mix of these two 

coal types (e.g., lignite and western coals). This could potentially happen, if a plant is aiming to 

control the coal mercury or chlorine contents to meet the specific emission limits in this rule. If 

a mix of the two coal types were fired in a boiler, under what subcategory would it fall?

 Page 394: We refer to a statement on this page: “We were particularly concerned about the CFB 

units because other CFB units are well represented among the best performing EGUs for Hg in 

the >8,300 Btu/lb subcategory, but the CFB units burning low rank, virgin coal are not achieving 

the same levels of control.” It is known that CFB’s, which have a higher percentage of unburned 

carbon (due to a more course fuel grind) than pulverized coal (PC) units, have lower emissions of 

Hg (due in large part to Hg capture by the unburned carbon). It is also known that fuels with 

higher concentrations of halogens (such as chlorine) are capable of high inherent levels of 

mercury removal, resulting in low emissions. Circulating fluidized beds burning coal >8,300 

Btu/lb have all the necessary elements to achieve high levels of inherent mercury control, and 

should therefore be in a separate subcategory. This would ensure that all new and existing 

CFB’s meet the low Hg emissions that they are truly capable of. It would also ensure that new 

and existing PC units are not held to an unattainable standard set by failing to subcategorize 

CFB’s.

 Page 397: The first Coal-fired EGU subcategory is based on units that fire coals with heating 

values of less than 8,300 Btu/lb and that are constructed and operated at or near the mines that 

produce such coals. Please note that certain types of units, e.g., cyclone-fired boilers, may use 

low rank virgin coals and may not be located close to the coalmines for these coals. EPA should 
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consider either deleting the distance requirement or establishing a new requirement for plants 

that do not meet the distance criterion.

 Pages 445: We refer to a statement on this page: “The EPA believes that the data used to 

conduct the beyond-the-floor analysis are consistent with results achieved in U.S. DOE Hg control 

technology demonstration projects. The DOE’s National Energy Technology Laboratory (NETL) 

sponsored a project entitled “Mercury Control for Plants Firing Texas Lignite and Equipped with 

ESP-wet FGD”. In this project, URS Group evaluated sorbent injection for Hg control in an 85/15 

blend Texas lignite/PRB-derived flue gas. The authors of the final project.........” We would like to 

consult with EPA on the conditions of these tests and the interpretation of the data from the 

test results cited. 

For the short-term test:

 What was the blend of coal being used? It should be confirmed whether this is a blend 

that would be representative of a unit that burns low rank, virgin coal.

 The relative amount of removal (90%) is not the basis for justifying an emissions limit, 

but rather the actual Hg emissions. What was the absolute level of Hg emissions in units 

of Lb/GWh for the tests that achieved 90 percent removal? Does that data support the 

EPA selection of the Hg emissions limit for this category?

 The authors wrote at the bottom of page 3-16: “Three of the brominated sorbents 

(DARCO Hg-LH, B-PAC, and CPAC) performed bery similarly with results indicating that 

90% reduction of mercury was attainable at 2-3 lb/Macf.” However, data for the shortterm tests presented in Table 3-7 and Figure 3-7 indicate that one (not three) 

technology was able to achieve 90% reduction in Hg emissions at injection rates of 2-3 

lb/Macf. If the tests are determined to be a valid basis for supporting an Hg emissions 

limit for this category, DOE would like to consult on interpretation of the data. point.

For the long-term test:

 The report clearly indicates that for approximately 10% of the time during the long-term 

test, the unit was firing 100% PRB (heating value >8,300 Btu/lb.) Would this invalidate 

the results as a basis for setting the emissions limit for units burning low rank, virgin 

coal?

 Assuming that the coal blend does not invalidate the results as a basis for setting an Hg 

emissions limit for low rank, virgin coal: Would the test results over a 30 day 

compliance period demonstrate that the EPA emissions limit for this category is 

attainable? During the long-term test, controlled Hg emissions were as high as 0.06 

Lb/GWh, 50% above the proposed limit.
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 Page 466: We refer to a statement on this page: “Commenters assert that FBC units are 

disproportionately represented among the best performers, with the inference being that they 

were selected because of their boiler design.” CFB boilers represent approximately 3% of the 

entire installed coal capacity in the U.S. However, CFB’s represent 35% of the MACT floor units. 

If CFB’s did NOT have unique properties with respect to Hg emissions than the number of CFB’s 

in the floor would be much closer to 3%. The fact that such a large proportion of floor units are 

CFB’s is evidence that this is a unique boiler design that may warrant its own subcategory.

The benefit of creating a separate subcategory is that CFB’s may be held to a higher standard 

with respect to Hg emissions. In addition, other coal boiler technologies such as pulverized coal 

will be subject to a more appropriate emission limit that has not been skewed by including CFB 

emissions in the MACT floor calculation.

 Page 467: We refer to a statement on this page: “The fact that FBC units have “vastly dissimilar 

ash properties” that may contain higher levels of lime or unburned carbon in the fly ash than 

conventional PC EGUs does not indicate that the overall system behaves any differently with 

regard to emissions to the atmosphere (the key metric) than a conventional PC EGU with add-on 

controls.” This is accurately stated by EPA. However, the fact that an uncontrolled CFB is 

emitting similar levels of Hg as that of a controlled PC unit is the exact reason that they should 

be included in a separate subcategory. FBC is a unique combustion design that lends itself to 

low Hg emissions, and this should be recognized by creating an appropriate subcategory.

Establishment of the Floor

 We suggest EPA consider including an explanation of EPA’s rationale for why, when it regulates 

one HAP under section 112, it must regulate all HAPs for a source category, beyond just citing to 

National Lime case. Given the fundamental importance of EPA’s interpretation of this legal 

issue and because the supporting documentation for the rule does not provide the level of 

scientific evidence for the health risks associated with EGU emissions of acid gases (HCl and HF) 

as it does for mercury, providing a cogent response on this point would be helpful (see comment 

on page 119). 

 Page 412: We refer to a statement on this page: “The language of the Act does not address 

whether floor levels can be established HAP-by-HAP or by any other means. The reference to 

“sources” does not lead to the assumption the commenters make that the best performing 

sources can only be the best-performing sources for the entire suite of regulated HAP. Instead, 

the language can be reasonably interpreted as referring to the source as a whole or to 

performance as to a particular HAP.” Contending that the floor can in fact be established on a 

HAP-by-HAP basis is one possible interpretation; however, it does not seem to be a reasonable 

one. The floor is supposed to represent the top performing 12% of units. However, the 64 

existing units that can meet the proposed limits represent less than 5% of all coal units in the 

United States.
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 Page 412: We refer to a statement on this page: “The EPA agrees that this language refers to 

sources’ actual operation, but again the language says nothing about whether it is referring to 

performance as to individual HAP or to single facility’s performance for all HAP.” While the 

language in the Clean Air Act may not have been specific on this issue, a reasonable 

interpretation of the language would be that the intention was that of a single facility’s 

performance for all HAPs. The alternative, which was the approach taken here, resulted in limits 

that are not representative of the performance of the top 12% of similar units. It is therefore 

suggested that EPA abandon their HAP-by-HAP approach and adopt what was most likely 

intended by the Act, which was a unit-by-unit approach.

 Page 412: We refer to a statement on this page: “The fact that Congress did not do so does not 

compel any inference that Congress was sub-silentio mandating a different result when it left the 

provision ambiguous on this issue. The argument that MACT floors set HAP-by-HAP are based on 

the performance of a hypothetical facility, so that the limitations are not based on those 

achieved in practice, just re-begs the question of whether CAA section 112(d)(3) refers to whole 

facilities or individual HAP.” Perhaps Congress was not in fact sub-silento mandating a “plant by 

plant” HAPs approach by failing to specifically address this issue when the law was written. It 

certainly is not clear, and EPA acknowledges this: “The argument...re-begs the question of 

whether CAA section 112(d) (3) refers to whole facilities or individual HAP.” The likely scenario 

is that the law never considered that such a possibility would arise, and therefore did not 

explicitly address it. However, it seems unlikely that Congress intended for a HAP-by-HAP 

approach that results in hypothetical limits based on the performance of a facility that does not 

exist. It is therefore suggested that EPA abandon their HAP-by-HAP approach and adopt what 

was most likely intended by the Act, which was a unit-by-unit approach.

 Pages 414: We refer to a statement on this page: “The EPA’s long-standing interpretation of the 

Act is that the existing and new source MACT floors are to be established on a HAP-by-HAP basis. 

One reason for this interpretation is that a whole plant approach could yield least common 

denominator floors – that is floors reflecting mediocre or no control, rather than performance 

which is the average of what best performers have achieved. See 61 FR at 173687 (April 19, 

1996); 62 FR at 48363-64 (September 15, 1997) (same approach adopted under the very similar 

language of CAA section 129(a)(2)). Such an approach would allow the performance of sources 

that are outside of the best-performing 12 percent for certain pollutants to be included in the 

floor calculations for those same pollutants, and it is even conceivable that the worst performing 

source for a pollutant could be considered a best performer overall, a result Congress could not 

have intended. Inclusion of units that are outside of the best performing 12 percent for particular 

pollutants would lead to emission limits that do not meet the requirements of the statute” There 

are alternative ways to interpret the MACT floor requirements that would avoid the pitfalls 

described by EPA (best performing unit for one HAP may also be worst-performing for another), 

as well as the problems associated with the HAP-by-HAP approach interpreted in this rule 

(which results in emission limits of a theoretical plant which does not exist). We have suggested 
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to EPA that they rank the HAPs emissions (for Hg, PM, and acid gas) of each plant relative to the 

best performing unit based on a HAP-by-HAP approach. Such a method would take into 

consideration actual emissions from plants (rather than performance of a non-existent 

hypothetical plant), while also avoiding the EPA’s concerns. Based on this approach, we 

estimated that for existing units burning coal > 8,300 Btu/lb, the limits would change as follows: 

PM: 0.048 Lb/MMBtu (increase from the proposed limit of 0.03 Lb/MMBtu); HCl: 0.01 

Lb/MMBtu (increase from the proposed limit of 0.002 Lb/MMBtu); Hg: 1.5 Lb/TBtu (increase 

from the proposed limit of 1.2 lb/TBtu).

 Page 417, 2nd Paragraph: This paragraph cites one coal-fired EGU that meets all of the final newsource emission limits. It would be helpful if you provide the number of EGUs that meet each of 

the new-source limits separately. A small number of EGUs, especially if there is only one EGU, 

may not address the variability that may exist due to differences in coal characteristics, unit 

designs, ambient conditions, and other site-specific factors. The new-source emission limits are 

out-put based and all of these design factors would play a large role in the ability of a unit to 

meet the specified limits.

 Page 429, Item 5: It should be noted that the public comments being discussed in this item

were based on some of the very stringent emission limits included in the proposed rule. These 

limits have now been revised upward in the final rule.

Reliability 

 It would be helpful if the agency responded with greater specificity to the public comments 

received regarding EPA’s reliability analysis. Specifically, EPA received public comment on 

several key aspects of reliability analysis but EPA’s response appears to only generally touch on 

some but not all of these issues. 

 EPA’s resource adequacy analysis does not reach local or intra-regional levels and the 

Agency has not analyzed system security.

 Transmission delivery not adequately addressed. Commenters noted that EPA has not 

analyzed any transmission or delivery constraints within regions or on the local level, 

including system upgrade requirements. More specifically, commenters pointed out that 

even if EPA’s analysis found capacity is adequate in individual areas, RTO/ISOs would

consider that capacity adequate unless it could be delivered. 

 Transmission system upgrades not adequately addressed. Transmission system upgrades 

could include new transformers, circuit breakers, and line reconducting. Typical delay 

factors related to transmission upgrades include environmental permitting, siting issues, 

and financing. In addition, commenters noted that transmission upgrade costs did not 

appear to be included in EPA’s analysis and would be passed on to utility consumers.

 Load pockets not addressed. EPA has not addressed transmission issues for urban centers 

for which inadequate local generation exists. These load pockets import the bulk of their 

electricity via transmission lines.

 Frequency response not addressed. In order to provide stability, the system requires 

regulation and a uniform frequency response (60 Hz). Since at risk coal units are capable of 
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providing frequency response to balance out small changes that may take place on an 

hourly basis, retirement of certain units could degrade interconnection of the frequency 

response. 

 Relationship to Black Start Services not addressed. EPA has not addressed the rule’s impact 

on generation that can provide power to start other generation on the system in order to 

aid in system restoration. Black Start Service is very location specific. 

 Renewable energy transmission requirements not addressed. Within EPA’s resource 

adequacy analysis, the Agency’s assumptions regarding renewable energy offsets for coal 

retirements did not address the potentially long lead time necessary for pipeline siting and 

construction, and should not assume the offsets are 1:1 replacements for coal. 

 In the Response to Comments section where EPA talks about the common flaws in industry 

retirement analyses, we suggests also explaining the fact that many of these studies ignore 

lower cost compliance options such as dry sorbent injection (DSI). This could be included as 

another example of overstating the stringency and impact of the rules, and it is more directly

relevant than the cooling water intake rule assumptions.

 In response to retirement projections and reliability concerns cited by a commenter, EPA 

responds that most studies projecting over 10 GW of retirements do not hold up to scrutiny and 

that many tools exist to maintain reliability (including new generation, demand response, 

energy efficiency, transmission upgrades, and energy storage). First, EPA’s retirement analysis 

relied heavily on the installation of DSI for compliance, which few of the many studies 

disparaged by the EPA did. More detail on EPA’s sensitivity case where “less DSI systems and 

more scrubber systems were installed” is required. In this case, DSI was limited to 35GW on 

installation and only one more GW is retired as compared to the base analysis. However, in 

modeling frameworks, it is likely that the most optimal units for DSI will get the technology, then 

other units will install FGD. Where the real sensitivity would become apparent is limiting DSI by 

size and coal type, which would show the limitations of the technology. In addition, the 

retirement projections rely heavily on low natural gas prices – a higher gas price sensitivity 

analysis is required. In addition, many of the reliability measures cited by the EPA are still in the 

developmental stages or potentially very costly – EPA should have also factored the costs of 

maintaining reliability into their analysis.

 Page 514: We refer to a statement on this page: “Commenters cite recent electricity forward 

capacity market auctions in the PJM and ISO-New England markets for the period of 2014 and 

2015 that indicate that the capacity markets cleared with electricity reserve margins of 20 

percent in PJM and greater than 14.4 percent in ISO-New England; these reserve margins are 

well in excess of the default reliability targets used by the North American Electric Reliability 

Corporation (NERC) for the year 2015.” Please note that reserve margins are not within NERC 

limits. While the actual reserve margins from the capacity auctions are accurate – the NERC 

target reserve margin is 15%, so ISO-NE will be below accepted ranges. NERC Working Groups 

have identified 2015 as when ISO-NE will drop below reserve targets. The phrase referencing 

ISO-NE should be revised to correctly capture the results of the auction. The ISO-New England 
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2014-2015 capacity markets cleared with more than 3,000MW of capacity in excess of its 

standard reserve margin for installed capacity of 14.4%. 

 Page 514: We refer to a statement on this page: “One commenter quoted NERC, stating that 

NERC does not see impacts from the proposed climate legislations or anticipated EPA regulation 

as a reliability concern.” We note that NERC may not have made a blanket statement that 

proposed regulations are not a reliability concern. What NERC has publicly stated in the 

Executive Summary of the Special Assessment: “The results of this assessment show a significant 

potential impact to reliability should the four EPA rules be implemented as proposed.” and a 

headline of “Proposed EPA regulations may have significant impacts on forecast planning 

reserve margins” and numerous other similar comments.

 Page 517:“ Although such an analysis does not address the potential for more localized reliability 

concerns associated with transmission constraints or the provision of location-specific ancillary 

services (such as voltage support and black start service), the number of retirements projected 

suggests that the magnitude of any local reliability concerns should be manageable with existing 

tools and processes.” While local reliability concerns may be addressed with existing tools and 

processes, this requires early notification by power plants of their intent to deactivate. Absent 

early announcement of plant retirements, regions may not be adequately prepared to handle 

reliability concerns given current limited announcement obligations within their regions. This is 

addressed in subsequent comments. 

 Page 522: We refer to a statement on this page: “As a preliminary matter, none of these 

situations, either alone or in combination, will necessarily lead to an electric reliability problem.” 

We note that NERC and the various ISO/RTOs have identified potentials for local reliability issues 

as any of these situations occur. (Source: NERC LTRA 2010. 

http://www.nerc.com/files/2010_LTRA_v2-.pdf.

 Page 522: We refer to a statement on this page: “As explained above, our modeling of the 

impact of this final rule at the regional level projects retirements of less than one percent of 

nationwide generating capacity and confirms that there will continue to be adequate capacity in 

all 32 sub regions of the country as sources comply with the rule.” Already 26+ GW have been 

publically announced for retirement – SNL data shows 27.5 GW publicly announced as of Oct 5.

 Page 522: “As a preliminary matter, none of these situations, either alone or in combination, will 

necessarily lead to an electric reliability problem. There is excess generating capacity in the U.S. 

today and in most cases an EGU that closes, either temporarily until it comes into compliance or 

permanently, will not cause a reliability problem.” Using resource adequacy to blanketstatement that electric reliability problems are not a concern is different than the public 

comments provided by those entities in charge of ensuring bulk reliability of the power system. 

Moreover, the EPA has not conducted any analyses using advanced power flow models to 

identify potential localized reliability impacts. To state that excess generating capacity is 
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indicative of a secure power system is flawed. 

To cite comments from PJM (see Corrected Comments of PJM Interconnection, L.L.C., August 4, 

2011) “It is not sufficient to assume that because the region as a whole has sufficient resources, 

that local reliability is automatically maintained.”

NERC defines reliability as addressing both resource adequacy and system security (see 

http://www.nerc.com/page.php?cid=1|7|114). The EPA has only addressed resource adequacy 

in their evaluation of the rule’s impact on reliability. The EPA has not conducted analyses which 

evaluate transmission security. As such, the EPA can only comment on reliability from a resource 

adequacy standpoint, not as a whole.

 Page 524: We refer to a statement on this page: As we said before, in most places a closing 

plant will not be a cause for concern. To the extent there is concern, however, early notification 

will provide an opportunity for transmission planners, market participants, and state authorities 

to develop solutions to avoid a reliability problem. In RTOs with forward capacity markets, 

owner/operators that do not bid generating capacity that they plan to close will provide an 

advance signal to market participants to take action to assure adequate future capacity.” That 

signal has not yet occurred. For several years of forward capacity auctions, minimal new 

generation and transmission have been built. In most instances, DSR has been the largest 

resource to take advantage of the lack of Generation & Transmission Resources and is almost 

over-saturated. 

 Page 523:“First as we said in the proposal, early planning is key.” 

Page 524:“Second, companies that intend to retire EGUs should formally notify their RTO (or 

comparable planning coordinator in the case of non-RTO regions), state regulatory agencies, and 

regional reliability entities as soon as possible that they will retire.”

Page 525:“Although EPA does not have the authority to require such early notification, it strongly 

encourages it and believes that responsible owner/operators should and will do the early 

planning for compliance and provide early notification of their compliance plans, especially 

where such plans include retiring one or more units.”

Wholesale markets do not have the ability to force units to announce retirements. Their tariffs, 

as approved by FERC, obligate units to announce retirements with as little as 45 days notice. If 

the RTO/ISO’s cannot identify which units will retire, and if units have a motivation to remain 

operational as long as possible, then there is no mechanism to provide early planning in the 

competitive wholesale electricity markets. 

Units that wait to decide whether or not to retire until obligated to do so have a competitive 

advantage, since the retirement of other generating units may result in larger revenue shares via 

additional transmission congestion charges paid to a unit or through overall higher locational 

marginal prices (LMPs) that result from the retirement of a unit with lower production costs. 

Thus, a unit that waits to announce retirement until the last possible chance gains two 

advantages: either it realizes that the retirement of other units nearby increases the costs on 

the system, thereby increasing the revenue for such a generator to continue operation, and thus 
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making it economical for the generator to retrofit control technologies if feasible from a time 

perspective, or, if the economics of the unit are still not realized to retrofit control equipment 

then the unit announces its retirement at the last moment and has benefited from energy 

payments received up to that point in time. Therefore, there is no advantage for generators to 

announce retirements early in a competitive wholesale electricity market since this 

disadvantages the generating unit from potentially benefitting from the increased system costs 

resulting from the retirement of other units. This is consistent with public comments from PJM.

EPA’s comments do not provide justification for units to announce retirements in competitive 

markets as early as would be beneficial for regional grid reliability planning purposes. 

Therefore, EPA should acknowledge the limits to its authority and recognize the other sources of 

authority that are responsible for the minimum notification periods for retirement.. 

 Page 526: “With regard to transmission, recent experience also shows that, in many cases, 

transmission upgrades to address reliability issues from plant closures can be implemented in 

less than 3 years.” While this is true, the rule does not provide incentives for plants to announce 

retirements prior to RTO tariff obligations. As stated in EPA’s comments, RTO’s only obligate 

plants to announce retirements with 45 to 120 days notice, depending on the region. Absent 

incentives from the EPA to announce early retirement, and in considering competitive market 

advantage to delay announcing retirement, plants may continue to operate until obligated to 

retire. As such, even though transmission upgrades can be completed in less than 3 years, there 

is no guarantee that RTO’s will be afforded that amount of time based on when units announce 

their retirement. 

Moreover, while there as some cases of transmission upgrades being completed in less than 3 

years, there are other cases which can be cited as taking longer, up to 5 years or more (see 

Corrected Comments of PJM Interconnection, L.L.C., August 4, 2011 in reference to Buzzard Point 

and Benning Road Deactivation Studies). 

 Page 556: We refer to a statement on this page “The Agency has studied possible impacts on 

reliability as a result of this rule, and has determined that these impacts should not be significant 

and industry, along with relevant Federal Agencies, have the tools needed to address any 

reliability concerns.” The problem, once again, is the EPA analysis does not take into account 

the cumulative effect of various EPA rules that could affect reliability

 Page 556: We refer to a statement on this page: “The Agency did not prepare a cumulative 

impact analysis to accompany the rule for the following reasons...2) decision makers and the 

public need to know the impacts specific to a particular rule in order to judge the merits of the 

regulation.” Decision makers and the public also need to know the cumulative impacts of 

various rules in order to judge the merits of the group of regulations. Additionally, Executive 

Order 13563 directs each agency to tailor its regulations to take into account the costs of 

cumulative regulations.
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 Page 563: “the commenter states, some claims linking retirements to the Toxics Rule are 

overstated and misleading. The commenter gives the example of the American Electric Power 

attempt to link its planned plant closures to the Toxics Rule, but those plants already are slated 

to either close or to upgrade controls to comply with existing laws... Response: EPA thanks the 

commenter for these observations and agrees with the findings of the independent studies 

mentioned by the commenter.” While these plants were already slated to eventually retire due 

to compliance with existing laws, the MATS rule resulted in these plants retiring much sooner 

than expected. Hence, this comment is misleading (and EPA’s agreement with the commenter) 

since the MATS rule did in fact push the retirement date up for such units. Therefore, the EPA 

should consider such retirements as being impacted by the MATS rule, and at the very least, 

consider them in a reliability analysis of the rule.

While some debate may center around whether these plants will retire due to MATS, it is 

unclear whether EPA considered these planned retirements and other more recently announced 

retirements in their analysis, ultimately leading to their presumption that electric reliability is 

not impacted. 

Moreover, the recent study from the MISO (EPA Impact Analysis; Impacts from the EPA 

Regulations on MISO, October 2011) identifies up to 13 GW of at risk plants when considering 

the cumulative impact of EPA regulations (CSAPR, CWA, CCR, MATS). While this analysis 

considers the cumulative impact of EPA regulations, it does note: “compliance associated with 

the Mercury and Air Standards (MATS) produces the most at-risk units, since its compliance 

costs and emission reductions have the greatest impact of the proposed regulation.” This 

conclusion is counterintuitive to the above claim that retirements due to MATS is overstated. 

 Page 599: We refer to the statement on this page: “Under the provisions of this proposed rule, 

the EPA projects that approximately 5.5 GW of coal-fired generation (less than 2 percent of all 

coal-fired capacity and 0.5 percent of total generation capacity in 2015) may be uneconomic to 

maintain and removed from operation by 2015. These units are predominantly smaller and less 

frequently used generating units dispersed throughout the country.” The EPA retirement 

estimate of only 5.5 GW does not consider the numerous other regulatory initiatives being 

pursued by EPA, including NSPS, MATS, 316(b), coal combustion residuals, and CO2. When 

considered collectively, the actual retirements are likely to be much higher. It is recommended 

that EPA consider the full suite of regulatory proposals to obtain a more accurate estimate of 

coal retirements.

DSI Costs

 Page 516, 1st Paragraph: We agree with EPA’s approach in performing a sensitivity analysis to 

evaluate the impact of the affected sources installing fewer DSI systems and more wet 

scrubbers on the grid reliability. We recommend that EPA report the cost increase (both 

capital and annual costs) for this sensitivity case in the preamble.

 Page 537: EPA has quoted in detail one commenter who appears to have provided no data 

to back up the claims on the efficacy of DSI technology for HCl removal. This commenter also 
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states that DSI may not provide full HCl control in some situations (without defining those 

situations). In addition, in EPA’s response, there is only a mention of DSI being used for SO2

control and nothing about HCl control. We recommend that EPA provide more HCl-related 

information.

 Page 541: We refer to a statement on this page: “Non-sodium based sorbents such as 

hydrated lime (calcium based) could also be used.” At the Air Quality VIII Conference in 

October 2011, Jim Dickerman, Director of Flue Gas Treatment Applications at Lhoist North 

America, gave a presentation on the use of dry sorbent injection using hydrated lime for 

MATS acid gas control. He explicitly stated that for units that are equipped with ESP’s, they 

could not achieve the acid gas compliance standard (0.02 Lb/MMBtu) and would provide no 

such performance guarantees. For units with fabric filters, he stated that limited testing 

indicated that the acid gas limit may be achievable, but only at extremely high sorbent 

injection rates (no figures were given). A high sorbent injection rate adds to the flue gas 

particulate loading, causing problems for other downstream control technologies. For this 

reason, EPA should not assume that hydrated lime could be used for acid gas control. This 

again raises the issue of only trona being available to use for DSI, which has serious supply 

and distribution constraints as noted previously.

 Page 543, 2nd Paragraph: It is stated that, for units with EPSs and burning western coals, HCl 

limit can be obtained with DSI, without the addition of a baghouse. We recommend that a 

potential need for the existing ESP upgrade be mentioned here.

Employment Effects

 Page 549: We refer to a statement on this page: “The Agency found that the impact on 

employment nationally should be small on net...” EPA should also note that there would be a 

decrease in labor productivity (i.e., more labor required to produce the same amount of 

electricity), which would cause the short-run aggregate supply curve to shift to the left, 

resulting in higher prices and businesses producing less (i.e., lower GDP).

 Pages 569 and 550, Last Paragraph: Please confirm if any of the commenters has referenced 

a study or provided any data to back up their claims on the adequacy of labor availability. 

We would also appreciate receiving a copy of the TSD referenced in EPA’s response.

 Page 603: We refer to the statement on this page: ““...each additional $1 million spending on 

pollution abatement results in an small net increase of 1.6 jobs; the estimated effect is not 

statistically significant different from zero.” It seems better to simply state the study finds 

spending on pollution abatement does not have a statistically significant effect on jobs. EPA’s 

analysis should also point out that there would be a decrease in labor productivity (i.e., more 

labor required to produce the same amount of electricity), which would cause the short-run 

aggregate supply curve to shift to the left, resulting in higher prices and businesses producing 

less (i.e., lower GDP).
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Cumulative Effects of EPA Rules

 Page 557: We refer to a statement on this page: “...the direct benefits from the 1990 Clean 

Air Act Amendments reach almost $2 trillion for the year 2020...” What was the effect on 

real GDP? This is a more relevant measure for decision makers than social costs, as changes 

to GDP growth are what determine whether the economy is experiencing a recession. We 

suggest EPA delete the discussion of this report, since it is not relevant to the rulemaking at 

hand.

Benefits 

 For the final rule, the only mercury benefit that can be quantified either in economic terms or 

by a widely understood measure – the total nationwide increase in IQ which results from a 

90% reduction in utility mercury emissions – are removed from the main body and are put in 

an appendix. These findings are replaced by a “hazard quotient.”

People understand what IQ points mean: if the MATS rule were to have caused children born 

of mothers who ate fresh caught fish (whose mercury levels were influenced by power plant 

emissions) to gain an average IQ of 5 points when power plant mercury emissions were 

sharply reduced, we would all have understood what an important public health gain had 

been achieved. No explanation would have been needed.

However, EPA has now found that of the 240,000 children born of mothers who eat fish 

influenced by power plant emissions, the total IQ gain nationwide from the 90% reduction in 

power plant emissions is 510 IQ points, also expressed in the documents as 2/1,000 of an IQ 

point per child. EPA calculates the monetized benefit of this increase of 510 IQ points 

nationwide to be between $500,000 and $6 million, depending on assumptions such as 

discount rates. The benefit is based upon total lower lifetime wages due to the reduction of 

510 IQ points, and contrasts with costs of the regulation of about $11 billion.

This finding is good news. It means that pregnant women can now be told that US mercury 

emissions will not harm the intelligence of their unborn child. Wouldn’t it be a good idea to 

make sure that readers of this document now know that they are safer than they might have 

previously thought? Public health findings aren’t always about harm we have found, but also 

about harm we suspected but later found not to be of concern.

In contrast, the use of a “hazard quotient” has no intuitive meaning to people. Further, it 

isn’t clear what actual harm exists if the hazard quotient is above 1.5 (the level at which a 

hazard is said to exist). There is suggestion of risk, but is the risk of a similar magnitude of 

the IQ risks, now quantified? Of less risk of harm to health than the IQ risks? 

Therefore the suggestion is to also include, in the body of the Final Rule (instead of in an 

Appendix), the quantifiable (and positive) findings that virtually no adverse effect on IQs have 

occurred from US mercury emissions (because virtually no benefit occurs from a 90% 

reduction in such emissions). This appears to be news which anyone interested in health 

effects of mercury would want to know. 

 Page 619: Table 9: Since some studies have found no significant effect of PM2.5 on mortality, 

perhaps zero should be included in the range of PM2.5 benefits, as Electric Power Research 
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Institute has suggested. EPRI indicated: “Since some models in some studies do not find a 

statistically significant effect of PM2.5 on mortality, the effects range could even include zero...” 

(Source: EPRI PM2.5 Reductions and Impact on Premature Death: An EPRI perspective; Issue Brief 

1018632.) Also, the same EPRI briefing states the EPRI-Washington University Veterans Study 

did not find any statistically significant mortality associations with PM2.5, but found some PM 

components that were significantly associated with mortality. The EPRI briefing goes on to say: 

“Of great significance for CAIR, this study did not find a significant association between the 

sulfate component of PM and mortality...if this study were used to derive estimates of health 

benefits attributable to reductions in SO2 emissions, the numbers would differ from those 

derived from the Pope et al...some studies have shown that estimated impacts of PM diminish 

when other co-pollutants are considered in the analyses. If the co-pollutants are indeed 

associated with increased mortality and are correlated with PM levels, then the PM effects 

estimated from this single pollutant model approach can be biased upwards.”

 Page 628: We refer to the statement on this page: “The fourth value is the 95th percentile of the 

SCC from all three models at a 3 percent discount rate.” Why not include a fifth value at the 5th

percentile in order to represent lower-than-expected impacts from temperature change

 We strongly recommends that EPA provide a much clearer explanation regarding the mercury 

benefits of this rule. The mercury benefits quantified in the cost/benefit sections include only a 

small portion of the total benefits of the mercury reductions projected from the rule – only the 

IQ loss from children exposed to recreationally-caught freshwater fish. It is entirely unclear 

from the preamble to the rule, the executive summary in the RIA and other summaries of the 

costs/benefits of the rule that the “Hg-related benefits” represent such a small subset of the Hg 

benefits. We strongly suggest clarification of these benefits by, for example, changing tables to 

read “Partial Hg-related benefits (recreational freshwater fish IQ effects only)” or some other 

similarly explicit language.

Comments on the Regulatory Impact Analysis

 Industry does not make retirement decisions based upon one regulation, but on the entire 

group of regulations. Therefore, a more accurate and comprehensive RIA would look at the 

aggregate effect of proposed and recently promulgated EPA rules. EPA should include these 

aggregate costs for all proposed and recently promulgated rules. Executive Order 13563 

directs each agency to tailor its regulations to take into account the costs of cumulative 

regulations.

 EPA may want to include in the RIA an analysis of the effect of the regulation on U.S. Gross 

Domestic Product (GDP). Such an analysis would be a useful measure of whether the policy 

is cost-effective. Similarly, it would also be useful to estimate the economic effect of the rule 

at the state level (e.g., state GDP). This would serve to satisfy Executive Order 13563, which 

states that the regulatory system should promote economic growth.
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 Employment Impacts Due to Increases in Electricity Prices Are Not Accounted For

The Executive Summary (ES) of the RIA (and ensuing portions of subsequent chapters of the 

RIA) discuss two types of employment impacts stemming from these regulations – see pg. 14 

of the ES. The first type is changes in employment over time in the effected industry, in this 

case the electric utility industry. The second type is short term increases in employment for 

construction of pollution control equipment prior to compliance dates. 

These impacts are summarized in Table ES-6. Long term employment changes in the electric 

utility industry are estimated to be about 8,000 jobs, but the estimate is said to be not 

statistically different than zero. Short term employment gains are estimated to be about 

47,000 jobs. Both these estimates are for increased employment.

The comment is that by far the largest employment effect due to the MATS regulation is 

likely to be a substantial increase in unemployment because of increased electricity prices. 

Regulations which increase electricity prices result in lost jobs because of reduced purchasing 

power across the economy because of these higher electricity prices. Many firms across the 

US will do marginally less business because households and businesses will have less 

disposable income, as a result of paying more for electricity. And when these firms do less 

business, they need fewer workers. Thus fewer workers will be hired in expanding 

businesses and more workers will be let go in contracting ones; some such firms will close 

down. 

Deschenes (2010) finds that every 1% increase in electricity prices causes a nationwide 

reduction in employment of between 0.1% and 0.16%. The total US civilian labor force as of 

Oct. 2011 is 154.2 million. In his preface, Deschenes thanks Michael Greenstone, the Obama 

Administration’s first Research Director of the Council of Economic Advisors for helpful 

advice.

The RIA ES states (pg. 14): “Retail electricity prices are projected to increase in the contiguous 

US by an average of 3.0% in 2015 with the final MATS Rule.” It also states that natural gas 

prices will be higher than they would otherwise be, but we do not try to estimate 

unemployment impacts of higher natural gas prices. 

Multiplying 154 million US workers by 0.3% and by 0.48% (three times 0.1% to 0.16% to 

reflect the estimated 3% increase in electricity prices) gives a total unemployment increase of 

from 462,000 (low end) to 739,000 workers (high end). These would be the dominant 

estimated unemployment effects caused by the MATS regulations. If instead of total number 

of employed people, the 154 million person civilian work force, we used Full Time Equivalent 

(FTE), as in Deschenes (2010), the unemployment estimates would be lower by about 43%; 

however, FTE would not include self employed workers (Deschenes, 2010), so FTE estimates 

of unemployment would be biased low. Thus the estimate of the number of unemployed 

workers as a result of the higher electricity prices stemming from MATS would be between 

the FTE and Civilian Work Force estimates.

Presumably there are other estimates of the cross elasticity of unemployment with respect 

to energy prices, so these estimates using cross elasticities from Deschenes (2010) may be 

low or high. The important point is that the unemployment created by higher electricity 
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prices should be included in the RIA. 

Reference: Deshenes, O. 2010. Climate Policy and Labor Markets. Working Paper 16111. 

National Bureau of Economic Research.

 Electricity Price Increases (and thus Increased Unemployment) from MATS May Be 

Understated When Interaction with Other Electricity Rate Impacts from Other Regulations 

are Taken Into Account

According to the ES, only 5.5 MW of coal units are expected to retire as a result of the MATS 

rule (pg. 14). Does this estimate include retirements which might occur when a unit which 

must comply with the new MATS rule must also comply with other new air quality and water 

quality rules, including (for air quality) rules regarding (1 through 3) NO2, SO2, and PM 

National Ambient Air Quality Standards, (4) Visibility Rule, and (5) Cross State Air Pollution 

Rule?

Some EGUs which might be able to continue to operate economically while installing 

technology to meet MATS may no longer be able to operate economically if they also have to 

add additional technologies to meet other rules noted above. If each rule analyzes coal unit 

retirements based upon the impact of each rule only by itself, e.g., if the MATS rule does not 

take into account costs that will occur due to other regulations, then plant retirements due 

to the combination of new regulations, and thus electricity price increases, may both be 

greater than impacts analyzed for MATS alone, or on a rule by rule basis. 

It would therefore be crucial for EPA to estimate the number of coal units retired based upon 

the combined rules, and the resulting electricity price increases. Further, the increase in 

unemployment as a result of the combined rules should also be calculated. Pg. 14 (not a 

typo) of the RIA for the Cross State Air Pollution Rule states: “Retail electricity prices are 

projected to increase nationally by an average of 2.5 % in 2012 and 1.5 % in 2014 with the 

proposed Transport Rule.”

This appears to be an additional 4% increase in electricity costs, relative to the MATS rule. 

Would these costs increase, and added coal plants (other than those assumed to be retired in 

the Cross State [Transport] rule) retire, when MATS requirements are added to those of the 

Cross State rule on a plant by plant basis? The same argument pertains when other air 

quality rules (such as the upcoming PM rule) are promulgated. Thus the actual electricity 

price increases, and the actual unemployment estimates due to higher electricity prices, may 

be understated when interactive effects are considered. We would like to ask EPA to clarify 

whether costs impacts on individual EGUs from rules other than MATS are considered when 

determinations are made as to whether MATS will cause such units to retire. If the answer is 

affirmative, which of the new rules are considered in this context? If the answer is negative, 

would EPA be willing to consider joint effects, in order to re-estimate the number of coal 

units retired, and the resulting additional electricity price increases?

 Estimated Benefits in MATS Include Reduction in Mortality from PM2.5 at Levels Below the 

National Ambient Air Quality Standard (NAAQS) for PM2.5

The current NAAQS as well as the new NAAQS that is under consideration both set levels for 
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daily and annual PM2.5 concentrations which are said to be protective of public health. If 

PM2.5 concentrations are above either the daily or annual level in a given locality, states must 

create a plan to reduce concentrations down to that regulatory permissible level. If PM2.5

concentrations are below these legal concentrations, then nothing more need be done to 

protect the public health. NAAQS standards are subject to public review.

In estimating benefits from MATS, EPA assumes that PM2.5 concentrations at levels well 

below the NAAQS standards, down to nearly background levels, cause premature mortality. 

In making this assumption, EPA essentially changes the level of harm in the PM2.5 NAAQS to 

levels far below those in the NAAQS. Two questions thus arise:

 Should the assumption of a linear dose-response function down to roughly 

background levels be subject to public review before being used in a RIA?

 What would be the benefits (and cost to benefit ratios) in the RIA if only mortality 

above, but not below, the NAAQS were included?

 Determining Toxicity of Individual PM2.5 Species, Relevance to MATS RIA

 Since 1996, scientific advisory bodies to EPA (such as the National Research Council of the 

National Academy of Sciences) have suggested that different PM2.5 species are likely to have 

different toxicity, and that EPA should use toxicology and other means to determine which 

PM2.5 species are most, or least harmful.

In March, 2009, on-the-record public comments were submitted to EPA by DOE/FE staff 

suggesting a means by which toxicity of specific PM2.5 species could be determined. In the 

2009 Integrated Science Assessment (ISA) for PM, EPA has established several excellent 

criteria for judging the degree to which PM2.5 may be causally related to various health 

endpoints. The comments suggested that EPA could take advantage of the large number of 

new studies available, then and especially now, and use the criteria in the ISA to estimate the 

degree to which individual PM2.5 species may be causally related to the health endpoints 

considered (such as cardiovascular mortality). To be clear, the suggestion was not that EPA 

create “speciated standards” for particularly toxic PM2.5 species (e.g., black carbon). To do so 

might take several years. Rather, the suggestion was that EPA use its excellent criteria to 

determine the strength of evidence for the toxicity of important PM2.5 species. To do so 

would enable states, in developing plans to reduce PM2.5 concentrations, to preferentially 

reduce the most toxic species.

The suggestions made in March 2009 are relevant to the MATS RIA, because only particular 

PM2.5 species are reduced using the technologies needed to reduce mercury emissions by 

90%. These species are largely inorganic salts. Should an EPA analysis of the degree to which 

individual PM2.5 species may be related to mortality be undertaken, the results could have 

relevance to the benefits estimates in the MATS RIA.

 We will not repeat in detail here why it is crucial to utilize studies which include many PM2.5

species (if an important PM2.5 species is not included in a study, different PM2.5 species might 

rise to the level of a statistically significant risk only in the absence of such species). Nor will 

we repeat in detail why it is important to use pollution data that reflects subject exposure 

reasonably accurately (without good subject exposure, the significance and levels of health 
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risks for pollutants whose concentrations are variable across a city will likely be understated, 

and risks might be “transferred” to pollutants with less spatial variability). We merely note 

the importance of these issues for reference.

Additional RIA Comments

Section ES.2, Page ES-8: “EPA believes these unquantified benefits are substantial...” It is not clear what 

value signifies a cutoff between what is substantial and what is insubstantial

Page ES-3: “We also include in our monetized benefits estimates the effect from the reduction in CO2

emissions resulting from this rule.”

EPA repeatedly makes a point of not analyzing the impacts of other emission rules on coal retirements, 

but does not seem to have a problem assigning the benefits to other emissions from this rule.

Table ES-3: there appears to be discrepancies in the calculated monetary value of avoided IQ loss that 

should be reconciled. Table ES-3 states that, at the 7% discount rate, the estimated monetary value of 

avoided IQ loss associated with methylmercury exposure from self-caught fish consumption among 

recreational anglers is reported between $0.000005–$0.000009 (in billions of 2007$). The Table also 

states that, at the 3% discount rate, the value is reported between $0.004–$0.006. The values at 3% and 

7% appear to be inconsistent with each other.

Section ES.4, Page ES-15: “Of the 83 small entities affected, 49 are projected to have costs greater than 

1 percent of their revenues.” Perhaps EPA should implement a policy to help protect these 49 small 

entities from proportionally large cost increases. 

Chapter 3: 

Page 3-5: “Mercury emissions are modeled as a function of mercury content of the fuel type(s) 

consumed at each plant in concert with that plant’s pollutant control configuration.”

Assuming that EPA uses the USGS’ COALQUAL database, there a some issues that could arise from the 

use of this data. First, COALQUAL is over 10 years old (1998) and second, it does not account for Hg 

reductions that could occur from coal washing, and only has the Hg content of coal as it is in the ground.

Page 3-5: “Total PM emissions are calculated exogenously to IPM, using EPA’s Source Classification Code 

(SCC) and control-based emissions factors.” Combined with ES-1 “The great majority of the estimates 

are attributable to co-benefits from 4,300 to 11,000 fewer PM2.5-related premature mortalities.”

There seems to be a large disconnect between the fact that PM emissions are exogenously calculated 

and the fact that they show the largest portion of the benefits.

Page 3-7: “As noted above, IPM has been used for evaluating the economic and emission impacts of 

environmental policies for over two decades.”

Has any retrospective analysis been done comparing IPM projections and actual reality? There is no 

indication that even though the model has been used for decades that is does a good job predicting 

what will really happen.

Page 3-12, Figure 3-6: Based on information presented during the discussions on the proposed rule, 

EPA was showing a substantial number of existing FGD upgrades resulting from this rule. These 

upgrades have not been mentioned in the preamble or in the RIA. If the number of these upgrades is 

substantial, they should be shown in Figure 3-6 and their impact should be discussed in detail. In the 

IPM manual documents, a cost of a scrubber upgrade is shown as an allowance of $100/kW. However, 

this cost is shown only as a fixed O&M cost. We do not agree with this, since a scrubber upgrade would 

involve expenditure of capital. Such an upgrade would normally require modifications to the scrubber 

vessel, replacement of auxiliary equipment, etc. If a substantial number of such upgrades are required 

under this rule, these capital costs cannot be ignored. In addition, the fixed O&M costs will go up as well 
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as there would be additional variable O&M costs, since sorbent injection rates would generally have to 

be increased and/or injection of additives may be required.

Page 3-12, Figure 3-6: Since ESP upgrade was not an option used in the analyses for the proposed rule, 

we recommend that additional information be provided on this option, either here or in the IPM manual 

document. We would like a confirmation that only those ESP upgrade techniques have been used that 

do not require extended plant outages to install. For example, a project involving extension of ESP 

surface area may require an outage lasting more than two years. Such long outages may become 

another factor contributing to the grid reliability issue.

Page 3-12, Figure 3-6: Please provide the updated IPM manual document that shows how the costs of 

ESP upgrade were estimated. 

Page 3-25: “The direct private compliance cost includes, but is not limited to, capital investments in 

pollution controls, operating expenses of the pollution controls, investments in new generating sources, 

and additional fuel expenditures.”

No accounting for reliability measures in the compliance costs.

Section 4.1, Page 4-1, Paragraph 2: “It is not expected that mercury benefits would be substantially 

changed, and given the small magnitude of the benefits...” It seems odd that the majority of the 

benefits of the rule do not come from Mercury, since a major goal of the rule is to reduce mercury. Since 

the vast majority of benefits come from reducing PM 2.5, is there a more cost-effective approach to 

reducing PM 2.5 than the Mercury and Air Toxics Standard? This would serve to satisfy Executive Order 

13563, which indicates regulations should be chosen that maximize net benefits.

Section 5.2.2, Page 5-11: “The appropriate economic measure is therefore ex ante Willingness to Pay 

(WTP) for changes in a risk.” In general, willingness to pay (WTP) is problematic because there are an 

infinite number of areas individuals could be asked to place a value on, yet individuals have a finite 

budget; thus, it seems likely that WTP would likely overstate what an individual would actually be willing 

and able to pay. Therefore, WTP should be constrained to not exceed a typical individual's budget.

Section 5.3, Pages 5-19 and 5-20: The assumption that all fine particles are equally potent in causing 

premature mortality is important, as changes to premature mortalities make up the vast majority of 

total benefits. Since some studies have found no significant effect of PM2.5 on mortality, perhaps zero 

should be included in the range of PM2.5 benefits, as Electric Power Research Institute has suggested. 

EPRI indicated: “Since some models in some studies do not find a statistically significant effect of PM2.5 

on mortality, the effects range could even include zero...” (Source: EPRI PM2.5 Reductions and Impact on 

Premature Death: An EPRI perspective; Issue Brief 1018632.) Also, the same EPRI briefing states the 

EPRI-Washington University Veterans Study did not find any statistically significant mortality 

associations with PM2.5, but found some PM components that were significantly associated with 

mortality. The EPRI briefing goes on to say: “Of great significance for CAIR, this study did not find a 

significant association between the sulfate component of PM and mortality...if this study were used to 

derive estimates of health benefits attributable to reductions in SO2 emissions, the numbers would 

differ from those derived from the Pope et al...some studies have shown that estimated impacts of PM 

diminish when other co-pollutants are considered in the analyses. If the co-pollutants are indeed 

associated with increased mortality and are correlated with PM levels, then the PM effects estimated 

from this single pollutant model approach can be biased upwards.”

Section 5.4.2.5, Page 5-35: “Although the association was not statistically significant for cough, the 

results were still positive and close to significance; consequently, we decided to include this endpoint...” 

It does not make sense to use a statistically insignificant result in deriving estimates. If the sign had 

been negative, would it have been included?

Section 5.4.4.1, Page 5-42: “Given the mixed theoretical finding and empirical evidence regarding 

adjustments to VSL for risk and population characteristics, we use a single VSL for all reductions in 
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mortality risk.” It seems more logical to use a range of value of statistical life (VSL) estimates, rather than 

a single value, in order to account for the uncertainty in the measure.

Section 5.4.4.1, Page 5-43: “An ideal benefits estimate of mortality risk reduction would reflect these 

human characteristics, in addition to an individual’s WTP to improve one’s own chances of survival plus 

WTP to improve other individuals’ survival rates.” Capturing the WTP to improve other individuals’ 

survival rates would be an example of a non-use value, thus creating a bias. Individuals likely also place 

a value on non-use things such as less government regulation; for instance, Executive Order 13563 

directs Agencies to “identify and consider regulatory approaches that reduce burdens and maintain 

flexibility and freedom of choice for the public.” 

Section 5.4.4.2, Page: 5-46: WTP for avoiding chronic bronchitis ($340,000) likely exceeds an average 

individual’s budget, especially after considering essentials such as food, clothing, housing, etc. 

$340,000 is greater than six years of income for an individual earning $50,000 per year. 

Section 5.4.4.1, Pages 5-40, 5-42: “The VSL approach is a summary measure for the value of small 

changes in mortality risk experienced by a large number of people.” On page 5-42, EPA indicates it uses 

a VSL of $6.3 million. This seems to be an unreasonably large value. A more practical measure of the 

value attributed to an increase in expected life for the affected individuals would be the amount of 

income these individuals could expect from living longer due to the rule. This would have the effect of 

preventing the number from exceeding an individual’s remaining lifetime income, since one cannot pay 

more than that amount. So, if the average affected individual could be expected to earn $250,000 more 

during his or lifetime, multiplying $250,000 by 11,000 (number of premature deaths), would result in an 

upward bound of total benefits of the rule due to premature deaths of $2.75 billion.

Section 5.4.5.2, Page 5-50, Table 5-12: Willingness to pay (WTP) is problematic because there are an 

infinite number of areas individuals could be asked to place a value on, yet individuals have a finite 

budget; thus, it seems likely that WTP would likely overstate what an individual would actually be willing 

and able to pay. Therefore, WTP should be constrained to not exceed a typical individual's budget.

Section 5.6, Page 5-88, middle paragraph: “The fourth value is the 95th percentile of the SCC from all 

three models at a 3% discount rate. It is included to represent higher-than-expected impacts from 

temperature change further out in the tails of the SCC distribution.” Why not include a fifth value at the 

5

th percentile in order to represent lower-than-expected impacts from temperature change?

Section 5.8, Page 5-99, first paragraph: We estimate that by 2016 the rule will have reduced the 

number of PM2.5-related premature deaths by between 4,300 and 11,000...” It would be useful for 

EPA to provide an estimate of the average amount of time these 4,300 to 11,000 individuals would live 

beyond what would otherwise be a premature death without implementation of the rule. 

Section 6.1, Page 6-1: “From an economic perspective, labor is an input into producing goods and 

services. If regulation requires that more labor be used to produce a given amount of output, the 

additional labor is reflected by an increase in the cost of production.” It should be noted that the 

decrease in labor productivity would cause the short-run aggregate supply curve to shift to the left, with 

the result being that businesses produce less (i.e., lower GDP). 

Section 6.1, Page 6-2: “With significant numbers of workers unemployed, the opportunity costs 

associated with displacing jobs in other sectors are likely to be much smaller.” It seems that even at 

unemployment levels of 9 percent, 91 percent of the labor force is still working and thus the opportunity 

costs associated with displacing jobs in other sectors is not likely to be much smaller.

Section 6.3, Page 6-7, first paragraph: “When a regulation is promulgated, the first response of industry 

is to order pollution control equipment and services in order to comply with the regulation when it 

becomes effective.” It should be noted that an alternative first response is for individual plants to shut 

down in order to avoid the higher costs associated with the pollution control equipment and services.
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Section 6.3, Page 6-7, first paragraph: “Revenue and employment in the environmental technology 

industry...” A clear definition of what industries (e.g., NAICS codes) are included in the environmental 

technology industry is needed.

Section 6.2.1, Page 6-6, Table 6-2: Since the overall results of the Morgenstern et al. study are 

statistically insignificant, it seems more practical to not provide corresponding job estimates, but to 

simply indicate the overall employment impacts were found to be statistically insignificant. Additionally, 

a summary of other studies that have estimated the effects of regulation on the economy would be 

useful.

Section 8.1, Page 2, Table 8-1: It may be more clear to the reader to change “+B” to “+NB,” (Net 

Benefits) because the reader has to search through the various footnotes in order to find that “B is the 

sum of all unquantified benefits and disbenefits.”
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SBA Comments:

Thank you again for the opportunity to comment on EGU MACT draft final rule. The Office of Advocacy 

submitted comments on this proposed rule (see http://www.sba.gov/advocacy/816/19191).

Unfortunately, Advocacy staff believes that EPA has not responded to the many criticisms in our letter 

nor changed the rule sufficiently to reduce the anticipated significant economic impacts on a substantial 

number of small entities. Our comments are nonetheless not limited to concerns expressed in our 

letter. We may also provide additional comments as time allows.

As a general theme, however, Advocacy staff notes that EPA has significant discretion in the 

implementation of the Clean Air Act section 112 as it relates to electric utilities, and that EPA’s approach 

to this rulemaking defies the Administration’s Regulatory Principles, as laid out in EOs 12866 and 13562.

EO 12866 is very specific about the policy criterion that should be applied when an agency has 

discretion:

“In deciding whether and how to regulate, agencies should assess all costs and benefits of available 

regulatory alternatives, including the alternative of not regulating. . . . [I]n choosing among alternative 

regulatory approaches, agencies should select those approaches that maximize net benefits (including 

potential economic, environmental, public health and safety, and other advantages; distributive 

impacts; and equity), unless a statute requires another regulatory approach.” (Executive Order 12866, 

Section 1(a).)

The Executive Order further requires:

“Each agency shall tailor its regulations to impose the least burden on society, including individuals, 

businesses of differing sizes, and other entities (including small communities and governmental entities), 

consistent with obtaining the regulatory objectives, taking into account, among other things, and to the 

extent practicable, the costs of cumulative regulations.” (Section 1(b)(11).)

Nonetheless, EPA declines to consider fully regulatory alternatives. The proposed rule was marked by 

repeated dismissals of legitimate uses of its discretion without developing the alternatives sufficiently 

for the public to comment. In the final rule, EPA disposes of many of these same issues, raised by 

commenters, without discussing whether the various policy options could maximize net benefits.

It is noteworthy that EPA generally does not assert that statute precludes adopting alternate 

interpretations of the CAA or considering additional factors in its policy decisions, as recommended by 

commentors. For example, in the discussion of subcategorization, EPA starts the discussion by asserting 

an obligation (. . . “any basis for subcategorization (i.e., class, type, or size) must be related to an effect 

on HAP emissions that is due to the difference in class, type or size.”), but it cites support for its position 

in court cases that emphasize EPA’s discretion to subcategorize. (“The EPA believes it is not reasonable 

to exercise our discretion without such a difference . . . ” [emphasis added].) Further, EPA emphasizes its 

discretion to refuse to subcategorize. Similarly, with area sources, EPA “exercised the discretion 

afforded the Agency under the statute and declined to set separate standards for area source EGUs,” 

but EPA did not consider net benefits in its decision. (EPA also did not consider public health, distributive 

impacts, or equity.)

Overall, EPA continues to assert that the CAA section 112 does not require it to consider costs. Perhaps 

not, but the Executive Order does.
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Economic Analysis in general: When EPA cites an annualized compliance cost, what is the discount rate 

and what is the time frame? RIA Table 3-5 is particularly confusing on that point.

We continue to be concerned that the primary driver of benefits of the NESHAP is not a HAP at all and 

that the monetized benefits of the NESHAP portion of this rule are small compared to the costs of 

controlling for the target HAP. A tailored approach would require EPA to address Hg for Hg sake, and 

not apply a MACT calculation to PM. We also note continued criticisms of EPA’s PM benefits 

calculations.

How/where does EPA respond to public comments challenging its compliance cost estimates?

RFA: It is unclear whether EPA intends its response to Advocacy’s comments to be self-contained the 

FRFA (Chapter 7 of the RIA) or whether EPA is responding to the various points in the preamble of the 

rule as appropriate. Nonetheless, Advocacy staff is concerned that EPA has not responded to a number 

of important points. For example, Advocacy states that EPA did not meet the requirements of the RFA.

EPA, in response, enumerates actions it did take, but does not respond to Advocacy’s discussion of 

things it did not do. Advocacy also identified areas of significant statutory discretion that EPA declined 

to consider for their impacts on small entities. EPA does not respond to these comments in Chapter 7, 

and it is difficult to see whether EPA responded elsewhere.

EPA has not responded to concerns raised by Advocacy and others that compliance will be significantly

more costly for small entities, both because of competition for scarce compliance resources and the 

potential for penalties (or, in the extreme, shut-down) if unable to complete compliance in 3 (or 4) 

years. 

I’d like to get more information on the revenue impacts of the rule, particularly the impact on Co-ops.

How much of the increase in revenues is a result of higher electricity rates v. higher production? How 

did EPA model the different price setting mechanisms for the various ownership structures? EPA notes: 

“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.” Is this an explanation that 

compliance costs can be covered or that higher revenue will be taken-back by the rate setters?

Area Sources: As Advocacy stated in our comments and mentioned above, EPA has the discretion to set 

GACT for area sources. This discretion is not bound by a consideration of other factors, such as those 

EPA cites in the preamble. EPA should therefore develop a GACT as a significant alternative and 

consider it for both its impact on small entities and marginal net benefits.

In the FRFA, EPA states: “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.” Advocacy staff believes 

that EPA should revisit its understanding of what “Generally Available” means and whether it in fact 

would require as stringent a series of technologies as would be mandated under MACT. We also note 

that GACT may include management practices as an alternative to control technologies.

Subcategorization: EPA’s discussion of establishing a size subcategory is not convincing. First, EPA 

states that it performed an analysis based on 125 MW and that the smaller EGUs would have to meet a 
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MACT floor more stringent than the standard for >8,300 Btu subcategory. This raises an interesting 

question as to (1) why 125 MW when the commenters requested 100 MW as the cut-off, (2) why not 

subcategorize by size and coal type, and (3) how would all of the MACT floor standards be changed by 

making the subcategory? Second, EPA should have performed similar calculations for HCl and PM, 

because the best-performing for each pollutant change. And third, the statement “Thus, units of all sizes 

are capable of achieving the proposed limits . . . .” is not supported by the evidence provided.

APPA’s comments provide an alternate set of standards based on subcategories on size and coal type.

EPA should respond directly to this proposal.

Advocacy staff is also concerned that EPA’s criterion for subcategorization is not appropriate for the 

setting of new source standards. For existing sources, EPA relies on the prevalence of various types of 

EGUs in the top 12% to justify a single subcategory. However, when EPA sets new source standards, it 

looks only at the one top performance unit. The prevalence of other boiler types in the top 12% is 

irrelevant to whether all of those boiler types can meet a standards set on a single boiler type. Leaving 

aside whether a new source standard based on a single example is an appropriate means of setting a 

regulatory standard, the effect of this approach is to limit future investment to the one specified suite of 

technologies under a specified set of circumstances. When combined with the pollutant-by-pollutant 

approach, it is reasonable to question whether any one suite of technologies can accomplish all of the 

various standards. It is not surprising that the EGU GHG NSPS RIA states clearly that EPA does not 

anticipate any future investment in coal-fired EGUs.

EPA should dispose of its artificial test of subcategories, exercise the discretion granted by statute, and 

examine possible subcategories based on difference in boiler design and operation, rather than just the 

emissions profile of the top 12%. This would include, for example, a subcategory for CFB units.

Timing: Advocacy staff is still very concerned about the ability of small entities to meet the compliance 

timeline. Although sensitive to the limits of EPA’s discretion, we are disturbed by EPA’s assurances that 

“most, if not all, units will be able to comply with the requirements of this rule within 3 years” and that 

all will be well “with proper planning.” Leavings aside the debate over reliability, EPA does not directly 

address the comments that challenge its optimism. For example, both the UARG and APPA are very 

specific in their concerns about the actual amount of time it takes to install the necessary emissions 

control equipment, and EPA does not appear to address their comments. If EPA’s optimism is 

misplaced, this will have devastating economic effects on individual entities and expose them to 

significant legal jeopardy.

EPA should also directly address comments raising the possibility of a Presidential delay.

Has EPA directly evaluated the capacity to install the necessary pollution control equipment? The 

assertions that I can recall in my review appear based on past performance within the industry and 

evaluations of the time necessary to install equipment on a single unit in the absence of competition.

Please correct me if I have missed a more detailed TSD.

UPL: Did EPA respond to EPRI’s comments on the UPL calculations (page 2-1 – 2-12)? See also UARG 

comments, attachment 3 (memo to UARG from Ralph Robertson).
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SO2 Emissions control technology: I’m a little unclear on DSI. There seems to be a lot of suspicion 

about it. Commenters seem to be concerned that it is not nearly as successful as EPA has projected, and 

that there may be a need to install wet FGD, at greater time and expense. What is the effect of the CSPR 

rule on installation of DSI and/or wet FGD? If DSI isn’t as prevalent, the operating costs rise significantly 

due to increased demand, or suppliers decline to assure performance, what would be the cost and 

timing effects of greater reliance on wet FGD?