Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. 

Subject to Further Policy Review. 

Page 1 of 6

Page Referenced Passage from Rule Comment

325/1,021 TABLE 3. EMISSION 

LIMITATIONS FOR COALFIRED AND SOLID OILDERIVED FUEL-FIRED EGUS, 

New - unit not low rank virgin 

coal, 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). A 

commenter is not aware of commercial CEMS 

technology that can accurately measure at this limit, 

which is almost two orders of magnitude below what 

a commenter is aware that 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). 

If continuous emissions monitors cannot accurately

measure down to this level, then this mercury limit 

should be reconsidered. 

EPA has specified that sorbent traps are an 

acceptable technology for confirming compliance. A 

commenter believes that sorbent traps are not a 

continuous monitoring technology and should 

therefore not be considered for this application.

450/1,021 The EPA believes that the data 

used to conduct the beyond-thefloor analysis for Hg are 

consistent with the 2010 ICR data 

and with results achieved in U.S. 

DOE Hg control technology

demonstration projects.

The referenced U.S. DOE NETL project is not 

representative of a unit that burns low rank, virgin 

coal for the following reasons:

 

The report clearly indicates that for approximately 

10% of the time during testing, the unit was firing 

100% PRB (heating value >8,300 Btu/lb). 

Further, the MATS Hg emission limit established by

EPA is not on a percent removal basis, it is on an 

emissions basis (Lb/GWh). Therefore while the 

percent reductions noted in this section by EPA are 
Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. 

Subject to Further Policy Review. 

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accurate, they are not relevant since they do not 

describe what the emission rate was at the stack. 

The beyond-the-floor limit established by EPA for 

this subcategory of units is 0.04 Lb Hg/GWh, 

however during the long-term testing in the DOE 

project cited by EPA, controlled Hg emissions were 

as high as 0.06 Lb/GWh, 50% above the proposed 

limit. 

The U.S. DOE project cited by EPA is not 

representative of the performance of this subcategory

of units. If the beyond-the-floor analysis by EPA 

depends on its interpretation of the results achieved 

in the DOE study, then it is recommended that EPA 

revisit the methodology to more accurately reflect the 

operation of existing units.

520/1,021 The EPA considered the impact 

that potential retirements in 

response to this rule will have on 

resource adequacy in order to 

gauge the rule’s impact on 

reliability. In considering these 

impacts, the EPA considered both 

the analysis it has conducted as 

well as analyses conducted by a 

number of other groups. 

Because concerns have been 

raised that the use of DSI may not 

be as prevalent as the Agency has 

predicted and because this could 

lead to more coal retirements, the 

Agency also performed a 

sensitivity analysis in which fewer

DSI systems and more scrubber 

systems were installed. In that 

sensitivity, we see approximately

1 more GW of retirement.

Modeling of DSI continues to mask the worst case 

potential of the MATS rule on coal plant retirements 

and reliability: EPA in response to comments 

criticizing the projected deployment of DSI at 53 GW 

as too much ran a sensitivity case limiting DSI 

deployment to 35 GW. If DSI does not turn out to be 

a technical or economic option for compliance, 30-40 

GW of capacity could be highly at risk of retirement 

due to the rule.

CERA's report "EPA’s Air Toxics Rule: Stimulating 

a New Wave of US Coal Plant Emission Control 

Retrofits" was one of the first projections to include 

the use of DSI and predicted around 35 GW of 

retirements, while during testimony to Congress, the 

CEOs of DTE and Southern Company predicted 50 to 

80 GW of retirements and did not think DSI would be 

applicable. The 35 GW limit applied to the model by

EPA is exactly the difference between analysts who 

think DSI is an acceptable option and those who do 

not.
Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. 

Subject to Further Policy Review. 

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544/1,021 A commenter has the position that assuming 

widespread adoption of DSI for MATS acid gas 

control is overstated, and unlikely to occur. While 

DSI for SO3 control has been studied, its use for HCl 

and/or SO2 control has not. The technology lacks 

sufficient experience and industry acceptance. In 

addition, there are still significant knowledge gaps 

(such as removal efficiency, interaction with other 

control technologies like activated carbon injection 

for Hg control, effectiveness according to coal type 

and pollution control technology interactions, and 

many others) that need to be resolved before industry

may be comfortable adopting this technology. 

540-1/1,021 The EPA agrees that DSI 

technology is proven and ready

for commercial use in controlling 

acid gases from coal combustion. 

One of the largest coal-burning 

electric utilities in the U.S, 

American Electric Power (AEP), 

pioneered the practical use of DSI 

with trona, a sodium-based 

sorbent, for SO3 mitigation. 

American Electric Power has 

implemented trona injection for 

that purpose across its entire 

bituminous coal-fired fleet where 

both SCR and wet FGD systems 

are in place.1Examples of coalfired EGUs already using trona 

DSI to control SO2 emissions 

include NRG Energy’s Dunkirk 

Generating Station Units 1-4 and 

CR Huntley Units 67 and 68 in 

New York.2The Dunkirk units 

The AEP project cited by EPA was for DSI control 

of SO3, not the acid gases being addressed by this 

rule (HCl, or alternatively, SO2). It is inaccurate to 

assume that HCl and SO2 will behave similarly to 

SO3 when subject to control by dry sorbent injection. 

This can only be determined through research, 

development, and demonstration programs.

The Dominion study referenced by EPA is a 

screening analysis, where an SO2 emission rate of 

0.02 Lb SO2/MMBtu was an input assumption, rather 

than a testing result. Thus, this citation offers no 

information on the effectiveness of DSI to control 

acid gas emissions down to the levels proposed by 

EPA, and there is nothing to indicate that DSI can 

control acid gas emissions other than a single 

assumption developed for a screening analysis. One 

of the key conclusions of this study was “The ability

for an SO2 emission rate lower than 0.20 lb/MMBtu 

to be achieved in practice with the use of DSI with 

Trona will be determined from operational 

experience.”

 

1 SO3 Control: AEP Pioneers and Refines Trona Injection Process for SO3

Mitigation, Coal Power, March 2007, 

http://www.coalpowermag.com/plant_design/SO3-Control-AEP-Pioneers-andRefines-Trona-Injection-Process-for-SO3-Mitigation_29.html

2 NRG Energy letter to RGGI, Inc, November 22, 2010, 
Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. 

Subject to Further Policy Review. 

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540-1/1,021 

continued

540-1/1,021 

continued

range in size from 75 MW to 190 

MW. Much larger units may also 

be economic when using DSI for 

SO2 control, as suggested by 

Dominion Energy’s studies of 

adding DSI on two 625 MW units 

at the Kincaid plant in Illinois.3

Although the Dunkirk and Huntley station units may

be using DSI for acid gas control, it is worth noting

that none of these units appear in the acid gas floor. 

Rather, it does not appear that there are any units in 

the MACT acid gas floor that are using DSI as a 

long-term compliance solution for acid gas control.

There is a concern that the willingness of industry to 

adopt dry sorbent injection (DSI) as a viable acid gas 

compliance alternative to flue gas desulfurization 

(FGD) has been overstated in the proposed rule. This 

is based on the pollution control configurations of the 

units in the MATS acid gas floor.

In the proposed rule, there were 130 units used to 

calculate the acid gas MACT floor for existing units 

– this represents the best performing 12%. Of this 

131, 11 units (less than 10%) had DSI installed. 

These units are plotted in Figure 1 (“MATS Acid 

Gas Floor Units Employing DSI”). 

The largest eight units in Figure 1 (Montrose Units 1, 

2, and 3; Ghent Unit 1; Cardinal Units 1 and 2; 

Connersville Unit 4; Mountaineer Unit 1) use DSI 

solely for the purpose of SO3 control, not HCl or 

SO2. For acid gas control (as proposed under 

MATS), all eight of these units have FGD installed. 

The remaining three units with DSI installed 

(Arapahoe Unit 3; Cherokee Units 1 and 2) may not 

be representative of the type of plant that EPA has 

assumed is willing to install this technology. 

Cherokee Units 1 (107 MW) and 2 (106 MW) are 

both smaller, older units that have proposed 

retirement dates (the units came online in 1957 and 

1959, respectively). In addition, there is a 569 MW 

NGCC being constructed onsite which is expected to 

 

http://www.rggi.org/docs/NRG_Nov_2010.pdf

3 Dominion Energy, BART Analysis for the Kincaid Power Plant, January 

2009, http://www.epa.state.il.us/air/drafts/regional-haze/bartkincaid.pdf
Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. 

Subject to Further Policy Review. 

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come online in 2015. Therefore, these units are 

likely using DSI as a cheap compliance option until 

retirement. 

Likewise, Arapahoe Unit 3 (44 MW, online in 1951) 

has DSI installed, but also has an announced 

retirement date. Similar to the Cherokee Power 

Station, there is a 480 MW NGCC pending approval 

by the Colorado Public Utility Commission at the 

Arapahoe Station. Therefore, it may be the case that 

Arapahoe Unit 1 does not view DSI as a long term 

solution, but as a cheap, temporary method to control 

SO2 emissions until retirement.
Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. Subject to Further Policy Review. 

Page 6 of 6

Figure 1 - MATS Acid Gas Floor Units Employing DSI

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 200 400 600 800 1000 1200 1400

C

u

m

ulativ

e

C

a

p

a

city (%)

Unit Size (MW)

Mountaineer Unit 1: 

DSI used for SO3 

control

Connersville Unit 4: 

DSI used for SO3 

control

Cardinal Unit 1, 2: 

DSI used for SO3 

control

Ghent Unit 1: 

DSI used for SO3 

control

Montrose Unit 1, 2, 3: 

DSI used for SO3 

control

Cherokee Unit 1,2:

Proposed 2011 retirement 

569 MW NGCC permitted, online in 2015

DSI likely being used as cheap compliance

solution until retirement

Arapahoe Unit 3:

Proposed 2013 retirement 

480 MW NGCC pending CO PUC approval

DSI likely being used as cheap compliance 

solution until retirement