Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. Subject to Further Policy Re view.

Page **1** of **6 Page**  **Referenced Passage from Rule Comment** 
325/1,021 TABLE 3. EM IS SI ON

LIM ITATIONS FOR COAL

FIRED AND SOLID OIL

DERIVED FUEL

- FIRED EGUS, New

- unit not low rank virgin coal , Mercury , 2.0E

- 4 lb/GWh For bituminous coal, this limit of 0.0002 L b 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 accuratel y measure at this limit, whic h is almost two orders of magnitude below what a commenter is aware that commercial CEMS can accuratel y 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 ex tremely 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 s orbent traps are an acceptable technology

for confirming compliance. A commenter believes that sorbent traps are not a continuous monitoring technology and shou ld therefore not be considered for this application.
450/1,021 The EPA believes that the data

used to conduct the bey ond

- the

floor anal ys is 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 te sting, 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 (L b/GWh). Therefore while the percent reductions noted in this section by EPA areSummary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. Subject to Further Policy Re view.

Page **2** of **6 Page**  **Referenced Passage from Rule Comment** 
accurate, they

are not relevant since they do not descr ibe what the emission rate was at the stack. The bey ond

- the

- floor limit established by EPA for this subcategory

of units is 0.04 L b Hg/GWh, however during the long

- term testing in the DOE project cited b y 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 bey ond

- the

- floor anal ys is by EPA depends on its interpretation of the results achieved in the DOE s tudy , then i t 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 ga u ge the rule’s impact on reliability

. In considering these impacts, the EPA considered both the anal ys is it has conducted as well as anal ys es 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

anal ys is in which fewer DSI s ys tems and more scrubber sy stems were installed. In that sensitivity , we see approximately 1 more GW of retirement. Mod eling of DSI continues to mask t he worst case potential of the MATS rule on coal plant retirements and reliability : EPA in response to comments criticizing the pr ojected deploy ment of DSI at 53 GW as too much ran a sensitivity case lim iting DSI deploy ment to 35 GW. I f DSI does not turn out to be a technical or economic option for compliance , 30

- 40 GW of capacit y could be highl y at risk of retirement due to the rul e

. 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 Compan y 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 anal ys ts 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 Re view.

Page **3** of **6 Page**  **Referenced Passage from Rule Comment** 
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 lack s 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 co al t yp e 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 SO 3 mitigation. American Electric Power has implemented trona injection for that purpose across its entire bituminous coal

- fired fleet where both SCR and wet FGD sy stems are in place. 1 Examples o f coal

fired EGUs alread y using trona DSI to control SO 2 emissions include NRG Energy ’ s Dunkirk Generating Station Units 1

- 4 and CR Huntley

Units 67 and 68 in New York. 2 The Dunkirk units The AEP project cited b y EPA was for DSI control of SO 3 , not the acid gases being addressed b y this rule (HCl, or alternatively , SO 2 ). It is inaccurate to assume that HCl and SO 2 will behave similarly to SO 3 when subject to control by dry sorbent injection. This can only

be determined through research, development, and demonstration programs.

The Domini on study

referenced b y EPA is a screening anal ys is, where an SO 2 emission rate of 0.02 L b SO 2 /MMBtu was an input assumption , rather than a testing result. Th us , this citation offers no information on the effectiveness of DSI to control acid gas emissions dow n 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 analy sis. One of the key conclusions of this study was “The ability for an SO 2 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 SO 3 Control: AEP Pioneers and Refines Trona Injection Process for SO 3 Mitigation , Coal Power, March 2007, http://www.coalpowermag.com/plant_design/SO3

- Control

- AEP

- Pioneers

- and

Refines

- Trona

- Injection

- Process

- for

- SO3

- Mitigation_29.html 2 NRG Energy letter to R GGI, Inc, November 22, 2010,Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. Subject to Further Policy Re view.

Page **4** of **6 Page**  **Referenced Passage from Rule Comment** 

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 ec onomic when using DSI for SO 2 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 thes e units appear in the acid gas floor. Rather, i t does not appear that there are an y 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 Emplo yi ng 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 SO 3 control, not HCl or SO 2 . 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 ty pe 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, respectiv el y). 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/bart

kincaid.pdfSummary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. Subject to Further Policy Re view.

Page **5** of **6 Page**  **Referenced Passage from Rule Comment** 
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) ha s 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 SO 2 emissions until retirement.Summary of Additional Interagency Working Comments on Draft Language under EO 12866 Interagency Review. Subject to Further Policy Re view.

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 u** **l a** **t i** **v e** **C a** **p a** **c i** **t y** **( %** **)**



### Uni **t Si**  **ze (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 likel y being used as cheap compliance solution until retirement Arapahoe Unit 3: Proposed 2013 retirement 480 MW NGCC pending CO PUC approval DSI likel y being used as cheap compliance solution until retirement