Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 1 

Best Available Retrofit Technology (BART) Analysis of Control Options 

For 

Public Service Company – Comanche Station, Units 1 and 2 

I. Source Description

Owner/Operator: Public Service Company 

Source Type: Electric Utility Steam Generating Unit 

SCC (EGU): Unit 1: 10100226 Unit 2: 10100222 

Boiler Type: Three Dry-Bottom Pulverized Coal-Fired Boilers, two 

tangentially fired (Units 1 and 3) and one wall-fired (Unit 

2) 

Comanche Station is located at 2005 Lime Road in Pueblo, CO, which is located 

within Pueblo County. Comanche Station commenced operation in the early 

1970s. The facility originally consisted of two coal fired boilers, driving steam 

turbines used to generate electricity and associated support equipment (cooling 

and service water towers and coal and ash handling equipment). Unit 1 

commenced operation in 1972 and serves a generator rated at 325 MW. Unit 2 

commenced operation in 1975 and serves a generator rated at 335 MW. The 

boilers burn sub-bituminous coal from the Powder River Basin (PRB) as fuel and 

use natural gas for startup, shutdown and flame stabilization. 

In August of 2004, Public Service Company of Colorado (PSCo) proposed to 

construct and operate a new coal-fired boiler (Unit 3) at Comanche Station. As 

part of that project, PSCo proposed to install control devices on the existing units. 

PSCo entered into a Settlement Agreement in December 2004 with various citizen 

groups and voluntarily agreed to install additional control devices and take 

emission limitations. In addition to the new unit (Unit 3), additional support 

equipment was proposed including a cooling tower, coal and ash handling 

equipment and various support equipment for the control device reagents (e.g., 

silos for lime, recycle ash and sorbent). Construction permits for the project were 

issued on July 5, 2005. 

Low NOX burners with over-fire air and a lime spray dryer were installed in 

November 2008 on Unit 1 and low NOX burners with over-fire air and a lime 

spray dryer were installed in November 2007 on Unit 2. Operation of the SO2

controls did not commence until June 3, 2009 for Unit 1 and January 10, 2009 for 

Unit 2. Unit 3 commenced operation in January 2010. 

Units 1 and 2 are considered BART-eligible because the units were in existence 

on August 7, 1977 and not in operation prior to August 7, 1962 and are located at 

a fossil-fuel-fired steam electric plant greater than 250 MMBtu/hr, with the 

potential to emit of more than 250 tons or more of any visibility impairing air 

pollutant (NOX, SO2, PM10). The results of the initial BART modeling analysis, 

indicated that the visibility impairment exceeded 0.5 deciviews (98% percentile - 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 2 

8th high), at federal Class I areas. Therefore, since Units 1and 2 “cause or 

contribute” to visibility impairment BART applies to these units. 

Table 1 below lists the units at Public Service Company Comanche Station that 

are subject to BART and are addressed in this BART analysis as well as the 

control efficiency of the controls currently installed on Units 1 and 2 (note SO2

and NOX controls were installed within the baseline period). 

Table 1: Comanche Units 1 and 2 Technical Information 

 Unit 1 Unit 2 

Placed in Service December 1973 November 1975 

Boiler Rating, 

MMBtu/Hr for 

coal 

3,531 3.482 

Electrical Power 

Rating, Gross 

Megawatts 

325 335 

Description Combustion Engineering Tangentially 

Fired Dry Bottom Boiler. Coal-Fired with 

Natural Gas Used for Startup, Shutdown 

and/or Flame Stabilization. 

Babcock and Wilcox Wall-Fired Dry 

Bottom Boiler. Coal-Fired with Natural 

Gas Used for Startup, Shutdown and/or 

Flame Stabilization. 

Air Pollution 

Control 

Equipment 

PM/PM10 – Baghouse – Installed 1993 

NOX – Low NOX Burners with Over-Fire 

Air – Installed November 2008 

SO2 – Lime Spray Dryer – Installed 

November 2008, fully operational 6/3/09 

PM/PM10 –Baghouse – Installed 1991 

NOX – Low NOX Burners with OverFire Air - Installed November 2007 

SO2 – Lime Spray Dryer – Installed 

November 2007, fully operational 

1/10/09 

Emissions 

Reduction (%)* 

NOX – 62.7% 

SO2 – 76.1% 

PM – 99.7% 

PM10 – 99.0% 

NOX – 44.1% 

SO2 – 81.9% 

PM – 99.8% 

PM10 – 99.3% 

*Emissions Reduction estimated by comparing pre-control 2005 – 2007 CAMD data (2005 – 2006 for NOx

on Unit 2) to controlled 2009 data. For PM/PM10., uncontrolled AP-42 factor were compared to actual 

average emission factors (2006 – 2008). See “Comanche APCD Technical Analysis” for further details. 

Not based on actual testing.

PSCo submitted a BART analysis to the Division on August 1, 2006, with 

revisions to that analysis submitted on August 15, 2006 (editorial corrections), 

October 19, 2006 and January 8, 2007. At the Division’s request, PSCo 

submitted additional information dated January 19, February 24, March 1, April 

12, April 21, May 25, July 14, and July 22, 2010. These documents are included 

as “PSCo BART Submittals”.

II. Source Emissions

In PSCO’s August 1, 2006 BART application, baseline emissions were based on 

calendar year 2004 and 2005 emissions. Several years have passed since the 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 3 

original BART submittal, in which the Division has updated modeling and 

technical analyses. Additionally, PSCo, as detailed in Table 1, has installed air 

pollution controls on both units at Comanche in 2008. Therefore, the Division 

used years 2009 (annual averages and 30-day rolling) for baseline emissions for 

reduction and cost calculations. The highest 24-hour peak emission rate during 

this timeframe was used for modeling visibility results. The Division verified 

these emissions using Colorado’s Air Pollutant Emission Notices and EPA’s 

CAMD database. 

Controls were installed on Unit 2 in November 2007 and controls were installed 

on Unit 1 in November 2008. While the SO2 controls did not commence full 

operation until 2009, the NOX controls did commence operation upon installation. 

In addition, PSCo has indicated that lime was initially injected into the lime spray 

dryers in December 2008 for Unit 1 and July 2008 for Unit 2 in order to test the 

controls. The baseline emissions are summarized in Table 2. 

Table 2: PSCo Comanche Units 1 & 2 Baseline Emissions 

Pollutant 

Unit 1 Unit 2 

Annual 

Emissions* (tpy) 

Average Emissions** 

(lb/MMBtu) 

Annual 

Emissions* (tpy) 

Average Emissions** 

(lb/MMBtu) 

NOx 1,511 0.124 2,349 0.165 

SO2 1,557 0.128 1,244 0.091 

PM10 80 0.007*** 40 0.005*** 

*Using daily CEMs data from 2009 calendar year (CAMD data).

**The Division calculated average emission rate or used the CAMD reported rate (lb/MMBtu) 

from the 2009 calendar year (CAMD data) based on average daily reported data for each unit for 

NOx and SO2 emissions. 

***The PM10 emission factor is determined from the most recent Title V permit compliance stack 

tests (March 2003). 

III. Units Evaluated for Control

According to PSCo’s August 1, 2006 BART application sub-bituminous coal 

from the Powder River Basin (PRB), Belle Ayr mine in Wyoming is typically 

used as fuel. The characteristics of the Belle Ayr PRB coal presented in the 

August 1, 2006 BART application are presented below in Table 3. 

Table 3: Comanche Station Coal Specifications (From August 1, 2006 BART Application) 

Coal Mine/Region PRB – Belle Ayr 

Coal Rank Classification Sub-bituminous 

Proximate Analysis 

H2O (Moisture weight %) 29.9 

Ash (weight %) 4.6 

Sulfur (weight %) 0.31 

Ultimate Analysis 

Nitrogen (weight percent %) 0.68 

Other 

Heating Value (HHV Btu/lb) 8,550 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 4 

Uncontrolled emission factors are outlined in Table 4. The factors are based on 

firing bituminous coal as well as the highest ash and sulfur content from the two 

coals for conservative estimates. 

Table 4: Uncontrolled emission factors for Comanche BART-eligible sources1

 Pollutant (lb/ton)* 

Emission Unit NOx SO2 PM 

(filterable) 

PM10

(filterable) 

Unit 1 8.4 9.5 46.6 10.7 

Unit 2 7.4 9.5 46.6 10.7 

*SO2 and PM/PM10 factors are determined by the applicable AP-42 equation, where %S and %A 

are the % of sulfur and ash present in the coal supply, respectively, averaged from APEN data 

(2006-2009). Please refer to “Comanche APCD Technical Analysis” for more details. 

Emission limitations that apply to these boilers are as follows: 

• Colorado Regulation No. 1, III.A.1.c limits particulate matter emissions to 

0.1 lb/MMBtu, for each boiler. 

• Colorado Regulation No. 1, VI.A.3.a.(ii) limits sulfur dioxide emissions to 

1.2 lb/MMBtu, for each boiler. 

• 40 CFR, Part 76-Acid Rain Nitrogen Oxides Emission Reduction Program 

limits NOX emissions to 0.40 lb/MMBtu and 0.46 lb/MMBtu, both on an 

annual average basis for Units 1 and 2, respectively. 

• 40 CFR Part 60 Subpart D §§ 60.44(a)(3) and 60.45(g)(3), as adopted by 

reference in Colorado Regulation No. 6, Part A limits NOX emissions to 

0.7 lb/mmBtu, on a 3-hr rolling average. Applies to Unit 2 only. 

• Colorado Construction Permits 11PB859, IA, mod 1 (Unit 2) and 

04PB1429, IA (Unit 1) both issued July 5, 2005) 

o NOX emissions shall not exceed 0.20 lb/MMBtu, on a 30-day rolling 

average, for each unit. 

o SO2 emissions shall not exceed 0.12 lb/MMBtu, on a 30-day rolling 

average, for each unit. 

These limits shall be met no later than 180 days after the initial startup of 

the SO2 and NOX control equipment for each unit or by July 1, 2009, 

whichever is earlier 

o NOX emissions from both Units 1 and 2 together shall not exceed 0.15 

lb/MMBtu, on an annual rolling average basis (rolling on a daily basis) 

o SO2 emissions from both Units 1 and 2 together shall not exceed 0.10 

lb/MMBtu, on an annual rolling average basis (rolling on a daily basis) 

PSCo shall begin calculating compliance with these limits no later than 

180 days after initial startup of the SO2 and NOX control equipment for the 

last unit. 

o Filterable PM emissions shall not exceed the following limits: Unit 1: 

393 tons/quarter and 1,546 tons/yr and Unit 2: 390 tons/quarter and 

1,525 tons/yr. 

 

1

 EPA AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.1, Tables 1.1-3 and 1.1-4. 

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 5 

o Filterable PM10 emissions shall not exceed the following limits: Unit 

1: 363 tons/quarter and 1,423 tons/yr and Unit 2: 357 tons/quarter and 

1,403 tons/yr. 

o SO2 emissions from Units 1 and 2 together shall not exceed 939.3 

tons/quarter and 3,686 tons/yr. 

o NOX emissions from Units 1 and 2 together shall not exceed 1,564.4 

tons/quarter and 6,142 tons/yr. 

The above limitations take effect 180 days after initial startup of the last 

control device for the last unit or upon startup of Unit 3, whichever is 

earlier. Note that the quarterly limits apply for the first year of operation 

only. 

IV. BART Evaluation of Units 1 and 2

A. Sulfur Dioxide (SO2)

Step 1: Identify All Available Technologies

Semi-Dry FGD Upgrades – As discussed in EPA’s BART Guidelines2

, electric 

generating units (EGUs) with existing controls achieving removal efficiencies of greater 

than 50 percent are not required to remove these controls and replace them with new 

controls. The Division interprets this to include fuel switching to natural gas, which 

would require significant boiler modifications, including removing the semi-dry FGD. 

However, based on Appendix Y [70 FR 39171], the following dry scrubber upgrades 

should be considered for Comanche Units 1 and 2 if technically feasible. These upgrades 

include: 

-Use of performance additives 

-Use of more reactive sorbent 

-Increase the pulverization level of sorbent 

-Engineering redesign of atomizer or slurry injection system 

The current Construction Permit limits are depicted in Table 5. 

Table 5: Comanche Units 1 & 2 SO2 Operating Permit Limits 

SO2 limits (lb/MMBtu)

30-day rolling Annual rolling (combined)

Units 1 & 2 0.12 0.10

As indicated in EPA’s BART Guidelines [70 FR 39171], for dry-FGD (i.e., LSDs) the 

following scrubber upgrades should be considered. 

• Use of performance additives 

 

2

 EPA, 2005. Federal Register, 40 CFR Part 51. Regional Haze Regulations and Guidelines for Best 

Available Retrofit Technology (BART) Determinations: Final Rule. Pgs. 39133. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 6 

• Use of more reactive sorbent 

• Increase the pulverization level of sorbent 

• Engineering redesign of atomizer or slurry injection system 

In addition to upgrades to the scrubbers, the Division also asked PSCo to look into the 

feasibility of achieving a lower 30-day SO2 emission limitation with the existing controls 

(i.e., SO2 emission limit tightening) and/or other potential upgrades, including improved 

operations and maintenance, use of more reagent, and keeping more spare parts on hand. 

Step 2: Eliminate Technically Infeasible Options

At the Division’s request, PSCo submitted an SO2 upgrade analysis to the Division on 

May 25, 2010 and additional information on July 22, 2010 regarding potential upgrades 

for the LSDs installed on Comanche Units 1 and 2. The following summarizes PSCo’s 

submittal and the Division’s analysis of the information provided. 

FGD: Flue gas desulfurization removes SO2 from flue gases by a variety of methods. 

The most common dry FGD system is a lime spray dry absorber uses that slaked lime 

slurry sprayed into the flue gas, which is subsequently dried by the heat of the flue gas, 

and then collected in a particulate control device. Generally, FGD control systems need 

to be located in close proximity to the boiler exhaust gas stream to prevent condensation 

(e.g. cooling of the exhaust gases) that result in acidic precipitation in the duct which 

results in corrosion issues. 

Dry FGD Upgrades: Dry FGD systems are commonly known as spray dry absorbers 

(SDA) or lime spray dryers (LSD), and currently make up about 12% of FGD systems at 

U.S. power plants3

. SDA systems are typically utilized at units that burn lower-sulfur 

coal in the western U.S., where water resources are limited. A SDA system must be 

located before the boiler flue gases enter the baghouse. Each reactor vessel requires a 

“foot print” area comprising about 2,000 to 4,000 square feet (depending on volume of 

flue gas treated) along with additional space for support equipment access, slurry 

preparation, mixing and associated tanks. 

As indicated previously, as part of a permitting action to construct and operate a new unit 

(Unit 3) at Comanche Station, PSCo committed to installing both NOX and SO2 controls 

on Units 1 and 2. Permits were issued on July 5, 2005 for Units 1 and 2 which addressed 

the controls and the associated emission limitations that these units would be required to 

meet prior to commencing operation of the proposed new unit. To that end, a lime spray 

dryer (LSD) was installed on Unit 1 in November 2008 and a LSD was installed on Unit 

2 in November 2007. Full operation of the LSDs commenced in June 2009 and January 

2009 for Units 1 and 2, respectively. Table 1indicates that the LSDs are achieving 

 

3

 Electric Power Research Institute: A Review of Literature Related to the Use of Spray Dryer Absorber 

Material – Production, Characterization, Utilization Applications, Barriers, and Recommendations, 

Technical Report, September 2007. University of North Dakota: Energy & Environmental Research Center 

– Coal Ash Resources Research Consortium. 15 North 23rd Street, Stop 9018. Grand Forks, ND, 58202. 

Pg. v. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 7 

emission reductions at approximately 76% for Unit 1 and 82% for Unit 2 in comparison 

with the permit limits4 depicted in Table 5. It should be noted that since July 1, 2009, 

when the SO2 limits became applicable, Unit 1is achieving emission reductions at about 

86.5% and Unit 2 at 85.3%. This system exceeds EPA’s presumptive limits stated in 40 

CFR Part 51 Appendix Y of 0.15 lb/MMBtu, although the current permit limit is higher 

than the presumptive limits. Therefore, since Comanche Units 1 and 2 are equipped with 

existing FGD and are achieving removal efficiencies greater than 50%, the BART 

analysis need not consider replacement of the SO2 controls but should consider upgrades 

to the existing FGD. 

-Use of performance additives: The supplier (Babcock & Wilcox) of PSCo’s Colorado 

dry scrubbing equipment does not recommend the use of any performance additive. 

PSCo is aware of some additive trials, using a chlorine-based chemical, which have been 

used on dry scrubbers. Chlorides are used to slow the drying time of the fly ash/lime 

mixture used to capture the gaseous SO2. The chemistry of the calcium sulfate/sulfite 

reaction is much more effective when liquid water droplets exist. By slowing the drying 

time the theory is that the lime sorbent will be more efficient and the lime use could be 

decreased to obtain the same SO2 reduction capability of the equipment unless the unit is 

limited on the total amount of lime slurry injection. There are cases on units that use high 

sulfur coal (significantly greater than 1.2 lbs/MMBtu) where the total amount of lime 

slurry injection is limited by the solids content of the slurry. When the total limit 

injection for a unit is limited, additives may allow some increase in SO2 removal. 

However, because the Hayden boilers burn low sulfur western coals, PSCo is not limited 

on lime slurry injection and the use of performance additives on the scrubbers would not 

be expected to increase the SO2 removal. Therefore, this upgrade is not technically 

feasible. Based on the information provided by PSCo, the Division agrees that the use 

performance additives are not likely to increase SO2 removal and therefore warrants no 

further consideration. 

-Use of more reactive sorbent: All PSCo dry scrubbers were designed to use a highly 

reactive lime with 92% calcium oxide content. The scrubbers were also designed to 

inject fly ash to maximize available surface area and allow efficient lime reagent use. 

Some dry scrubbers used by other companies were designed to use a lower quality lime, a 

dry hydrated lime product, or operate on lime without fly ash. On these scrubbers, the 

option of using a higher quality lime or injecting fly ash possibly could improve SO2

removal. The only other common reagent option for a dry scrubber is sodium-based 

products which are more reactive than freshly hydrated lime. Sodium has a major side 

effect of converting some of the NOx in the flue gas into NO2. Since NO2 is a visible gas, 

large coal-fired units can generate a visible brown/orange plume at high SO2 removal 

rates, such as those experienced at Hayden. 

Lime is the reagent of choice in modern spray dryer systems on utility scale units. PSCo 

is aware of only one exception that was designed to use sodium carbonate to remove SO2. 

The Coyote Station, a 420MW unit located near Beulah, North Dakota and operated by 

Otter Tail Power Company, was placed in service in 1981. The spray dryer was supplied 

 

4

 Colorado Operating Permit Number 96OPROB132 Last Revised 5/14/10. Pgs. 6, 9. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 8 

by Rockwell and used rotary atomizers. The unit was designed to obtain 70% SO2

removal. This unit was reported to have a visible plume at times likely due to the 

conversion from NO to NO2 due to the sodium reagent. This unit was converted from 

sodium carbonate to lime after a number of years in service. PSCo verified with the two 

major suppliers of utility sized spray dryers, B&W and Alstom, and confirmed that there 

are no other operating utility spray dryers in the United States. B&W also states that in 

theory the sodium based reagents are more reactive as they have a slower drying time 

than lime reagents. However, because of their slower drying time, the spray dryer 

absorber would need to be larger to ensure the product was dry when leaving the 

scrubber. Thus, the use of sodium reagent in a unit designed for lime would not allow 

higher SO2 removal and it may not even be possible to convert to a sodium reagent with 

the existing equipment. 

PSCo is using a highly reactive reagent that maximizes SO2 removal; there are no known 

acceptable reagents without side effects that would allow additional SO2 removal in the 

dry scrubbing systems present at Comanche Station. The Division agrees with PSCo’s 

assessment and considers that use of a more reactive sorbent does not warrant further 

consideration. 

Increase the pulverization level of sorbent: PSCo indicated that Colorado’s dry scrubbers 

are designed with either horizontal or vertical ball mills to obtain optimum particulate 

size and reduce lime grit generation. Although PSCo notes that there have been some 

technical papers presented by pulverizer suppliers, that state vertical ball mills may 

provide a smaller particulate size and reduce lime use. Their experience has been that 

there is no SO2 removal benefit in using vertical ball mills versus horizontal ball mills 

and there is also no measurable reduction in lime use. PSCo considers that they already 

uses the best available grinding technologies and that there are no improvements that can 

be done to further decrease lime particle size to reduce SO2 emissions. The Division 

agrees that upgrades to grinding technologies are unlikely to produce additional SO2

reductions and therefore no further consideration is warranted. 

Engineering redesign of atomizer or slurry injection system: The Comanche dry scrubber 

systems are from B&W and use the same size and general design atomizer, a Model 

F800. While there are differences in the motor size and exact atomizer wheel 

construction that relate to the total slurry injection rate, the atomizer design is based on 

the vendor’s experience to maximize both SO2 removal and lime use efficiency. B&W 

offers no upgrade in atomizer design to improve SO2 removal. There are certain thirdparty suppliers who offer different atomizer nozzle designs that they claim can reduce 

lime use or provide longer maintenance life. To PSCo’s knowledge, no vendors claim an 

improved SO2 removal. PSCo has tried some of these different nozzle designs and 

doesn’t believe any of the designs improve the SO2 removal level, although some have 

improved wear life and reduced maintenance costs. Given that the LSDs installed on 

Units 1 and 2 were installed recently, the Division would agree that changes to the design 

of the atomizers are unlikely to result in a higher SO2 removal. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 9 

Emission limit tightening: In addition to considering upgrades to the existing FGDs on 

Units 1 and 2, the Division asked PSCo to consider whether tightening of the existing 

BART 30-day limits was feasible. Comanche Units 1 and 2 are subject to the following 

SO2 emission limitations: 

Table 6: Comanche Units 1 & 2 SO2 Emission Limitations 

 SO2 Emission Limitations 

 Emission Rate (lb/MMBtu) Mass Emissions (tons) 

3-hr rolling 30-day 

rolling* 

365-day 

rolling 

Quarterly Annual 

Unit 1 1.2 0.12 N/A N/A N/A 

Unit 2 1.2 0.12 N/A N/A N/A 

Units 1 and 2 

Together 

N/A N/A 0.10 939 3.686 

*Included as limits in the BART construction permit (07PB0112B) issued September 12, 2008. 

In their May 25, 2010 submittal, PSCo addressed the feasibility of tightening their 30-day 

SO2 emission limits. In their submittal, PSCo indicated that based on operating 

experience for Comanche Units 1 and 2, as well as other PSCo units equipped with 

LSDs, that the primary factor affecting the SO2 control efficiency for short-term averages 

are startups, equipment malfunctions and low load operations. In order to begin injecting 

lime/recycle ash slurry into the scrubber, a minimum inlet scrubber temperature must be 

achieved so the lime/recycle ash slurry dries when it hits the hot flue gas. When the 

scrubber inlet temperature is below the minimum level, the lime slurry drops out in the 

scrubber and forms concrete-like deposits that eventually plug the scrubber vessel. PSCo 

indicated that this had actually occurred while operating Comanche Unit 2 and Valmont 

Unit 5 and resulted in extended maintenance outages in order to clean the scrubbers. In 

addition, during unit start-ups, it can take anywhere from between 12 and 24 hours to get 

the inlet scrubber temperature up to the level necessary for safe slurry injection. The 

scrubber can be run at higher levels of SO2 reduction in order to offset the effects of a 

startup during a 30-day period, but the more startups that occur during that 30 day permit 

the more difficult it will become to offset the higher emissions during startup. PSCo also 

indicated that during low load operations, especially in the winter, the inlet temperature at 

the baghouse approaches the minimum acceptable level, subsequently lowering the 

overall SO2 control efficiency during low load operations. PSCo indicated that due to the 

increased use of wind resources, the boilers will be required to cycle more frequently to 

accommodate intermittent wind resources and therefore, the units will run at low loads 

more frequently and as a result the SO2 reduction levels will be lower during those times. 

The Division reviewed available SO2 emission data from CAMD for 2009 and for part of 

2010 (January – October 2010). As previously indicated although the LSDs were 

installed in 2007 and 2008, they only recently commenced full operation, Unit 1 in June 

2009 and Unit 2 in January 2009. As a result there is limited data available to determine 

post-control achievable emissions. In addition, if as PSCo indicates, the units are cycled 

more frequently to accommodate increased wind energy resources, it is not clear how 

well the data represents future operation. In addition, since the LSDs came on line 

recently, PSCo has limited operating experience with these units. Although PSCo has 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 10 

other units that are equipped with LSDs and have been operating those units with LSDs 

for some time (e.g., Valmont Unit 5, Hayden Units 1 and 2), those units are not using 

PRB coal. Comanche Units 1 and 2 represent the first units in PSCo’s system with LSDs 

that are firing PRB coal as fuel. After startup of the LSDs in 2009 both units have had a 

number of days indicating zero emissions, presumably due to a unit shutdown. In 

addition, in many cases, emissions data shows that frequently for one or more days 

following these events, the daily SO2 emission rate is well above 0.12 lb/MMBtu. Unit 1 

averaged 0.07 lb/MMBtu during this period, with a maximum rate of 0.10 lb/MMBtu in 

December 2009. Unit 2 has had several months (December 2009, May 2010, October 

2010) during the 2009 – 2010 timeframe that either exceed or are within 0.01 lb/MMBtu 

of the existing 0.12 lb/MMBtu 30-day rolling average limit. A review of annual data 

showed that in 2009, the SO2 annual average from both units was approximately 0.11 

lb/MMBtu. In 2010 thus far, the annual average is 0.07 lb/MMBtu, but it is important to 

note that it is apparent from the data on both units historically that lower inlet 

temperature(s) to the scrubber(s) in the winter months result in increased SO2 emissions. 

As explained above, the Division projects 30-day rolling SO2 emission rates to be 

approximately 5% higher than annual average emission rates. The uncertainty of 

evaluating a “maximum” emission rate warrants a similar 5% buffer or greater to be 

applied in this case, especially due to the facts stated above, including uncertainty 

regarding load operations, cold-weather operating, start-up, and cycling for renewable 

energy. Therefore, the Division concurs that tighter 30-day rolling average and annual 

average SO2 emission limit is not feasible at this time for either unit. 

Additional equipment and maintenance: As discussed in the emission limit tightening 

section, PSCo reviewed actual operating experience on Comanche along with possible 

changes to the systems necessary to achieve lower emission rates on a 30-day average 

basis. The primary factors that affect SO2 control efficiency for short-term averages are 

start-ups, equipment malfunctions, and low load operation. In order to begin injecting 

lime/recycle ash slurry into the scrubber, a minimum inlet scrubber temperature must be 

achieved so the lime/recycle ash slurry dries when it hits the hot flue gas. When the 

scrubber inlet temperature is below this minimum level, the lime slurry drops out in the 

scrubber and forms concrete-like deposits that eventually plug the scrubber vessel. This 

situation actually occurred while operating PSCo’s Comanche Unit 2 and Valmont Unit 5 

scrubbers and resulted in extended maintenance outages to clean the scrubbers. During 

unit start-ups, it can take anywhere from 12-24 hours to get the inlet scrubber 

temperatures up to the level necessary for safe lime slurry injection. 

During these start-up periods, SO2 emissions rates are at uncontrolled levels based on the 

sulfur content in the coal. Typically, if the unit only starts once during a 30-day period, 

operators can over-control SO2 by running the scrubber below the 30-day average 

emission rate to "make-up" for higher emission rates during start-up. If the unit has more 

than one start-up in a 30-day period, which certainly happens with older units, it becomes 

nearly impossible to scrub hard enough to achieve the 30-day rolling emission rate limits. 

The same situation occurs under low load operation, especially during winter months. 

Inlet temperature to the baghouse due to air heater in-leakage can approach minimum 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 11 

acceptable levels, thus lowering overall SO2 control efficiency during low load operation. 

PSCo coal-fired units will be required to cycle (under 60% load) more in the future to 

accommodate the intermittent nature of ever increasing wind generation on the electric 

grid and thus requiring the boilers to operate more frequently at low loads. 

PSCo sent confirmation to the Division on July 22, 2010 that an extra scrubber module 

on Comanche Units 1 and 2 is not feasible due to the current layout of the ductwork and 

space constraints around the scrubbers. The Division concurs with this assessment. 

Therefore, since it is not technically feasible to install an extra scrubber module, 

additional spare atomizer parts and increased operating and maintenance will not result in 

decreased SO2 emissions. The Division concludes that this option is not technically 

feasible for Comanche Units 1 and 2. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

PSCo indicated and the Division concurred that upgrades to the LSDs installed on 

Comanche Units 1 and 2 were unlikely to result in increased SO2 reductions and 

therefore, would not be considered further. Therefore, there are no remaining 

technologies for which to conduct a control effectiveness evaluation. 

Step 4: Evaluate Impacts and Document Results

PSCo indicated and the Division concurred that upgrades to the LSDs installed on 

Comanche Units 1 and 2 were unlikely to result in increased SO2 reductions and 

therefore, would not be considered further. Therefore, there are no remaining 

technologies for which to conduct an evaluation of the cost, energy and non-air 

environmental impacts, and remaining useful life. 

Step 5: Evaluate Visibility Results

CALPUFF modeling was used to determine the projected visibility improvement 

associated with various potential emission rates. The modeling guideline requires that 

modeled baseline emission rate is the 24-hour peak emission rate. The modeling 

guideline also requires that, at a minimum, the presumptive emission rate scenario be 

modeled. Table 6 shows the number of days pre- and post-control. Table 7 depicts the 

visibility results (98th percentile impact and improvements) as well as cost effectiveness 

in $/deciview and the calculation methodology utilized by the Division. 

Per the April 2010 modeling protocol5

, to isolate the effects of a given unit for controls 

on a given pollutant, the Division has judiciously constructed each emissions scenario to 

isolate the impact of a given BART control on a given unit. For example, to determine 

the effect of a SO2 BART control technology on a given unit, emission rates for the other 

pollutants (NOx and PM/PM10) and other BART-eligible units are held constant at pre-

 

5

 Colorado Air Pollution Control Division, Technical Services Program, 2010. “Supplemental BART 

Analysis CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling Analysis.” 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 12 

control levels. For BART sources with more than one BART unit, modeling the units 

individually would ignore important atmospheric chemical reactions that occur when 

units operate simultaneously. The combination scenario assumed Units 1 and 2 with NOx

emissions at 0.07 lb/MMBtu and SO2 emissions at 0.12 lb/MMBtu. 

In situations where the BART-eligible units at a given BART-eligible source operate 

simultaneously, the sulfate and nitrate estimates from the modeling system will be more 

realistic, in general, if all BART units and all pollutants at a BART-eligible source are 

modeled together. 

Table 6: Visibility Results – Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

SO2 

Control 

Scenario 

Unit(s) 

SO2 

Emission 

Rate 

(lb/MMBtu)* 

Class I 

Area 

Affected 

3-year totals 3-year totals 

PreControl 

Days 

>0.5 dv 

PostControl 

Days 

>0.5 dv 

∆days

PreControl 

Days 

>1.0 dv 

PostControl 

Days 

>1.0 dv 

∆days

Max 24-

hour 

1 0.75 

Great 

Sand 

Dunes 

National 

Park 

60 --- --- 27 --- --- 

2 0.74 

Dry 

FGD 

1 

0.12 

60 49 11 27 21 6 

2 60 50 10 27 21 6 

Dry 

FGD 

1 

0.10 

60 48 12 27 21 6 

2 60 49 11 27 21 6 

Dry 

FGD 

1 

0.08* 

n/a 

2 n/a 

Dry 

FGD 

1 

0.07 

60 48 12 27 20 7 

2 60 48 12 27 21 6 

Combo 

1 

0.12 60 4 56 27 1 26 

2 

* Denotes that output was interpolated by the Division and is not an actual modeled output. See 

“Comanche BART Modeling Summary” for more details. 

Table 7: Visibility Results – SO2 Emission Rates 

SO2 

Control 

Scenario 

Boiler(s) 

SO2 Emission 

Rate 

(lb/MMBtu)* 

Output (@ 98th

Percentile 

Impact)* 

98th Percentile 

Impact 

Improvement 

98th Percentile 

Improvement from 

Maximum 

(dv) (∆ dv) (%) 

Max 24-

hour 

1 0.75 

2.05 --- --- 

2 0.74 

Dry FGD 

1 

0.12 

1.71 0.35 17% 

2 1.72 0.33 16% 

Dry FGD 

1 

0.10 

1.69 0.36 17% 

2 1.71 0.35 17% 

Dry FGD 1 0.08* 1.68 0.37 18% 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 13 

2 1.69 0.36 18% 

Dry FGD 

1 

0.07 

1.67 0.38 18% 

2 1.69 0.37 18% 

Combo 

1 

0.12 0.36 1.69 82% 

2 

* Denotes that output was interpolated by the Division and is not an actual modeled output. See 

“Comanche BART Modeling Summary” for more details. 

Step 6: Select BART Control

Based upon its consideration of the five factors summarized herein, the state has 

determined that SO2 BART is the following existing SO2 emission rates: 

Comanche Unit 1: 0.12 lb/MMBtu (30-day rolling average) 

 0.10 lb/MMBtu (combined annual average for units 1 & 2) 

Comanche Unit 2: 0.12 lb/MMBtu (30-day rolling average) 

 0.10 lb/MMBtu (combined annual average for units 1 & 2) 

The state assumes that the BART emission limits can be achieved through the operation 

of existing lime spray dryers (LSD). A 30-day rolling SO2 limit of 0.12 lbs/MMBtu 

represents an appropriate level of emissions control associated with semi-dry FGD 

control technology. 

B. Filterable Particulate Matter (PM10) 

Comanche Units 1 and 2 are each equipped with fabric filter baghouses to control 

PM/PM10 emissions. In a baghouse, the particle laden flue gas passes through a series of 

fabric bags. The bags accumulate a filter cake that removes the particles from the flue 

gas, and the cleaned flue gas passes out of the fabric filter. The filter cake increases both 

the filtration efficiency of the cloth and its resistance to gas flow. The bags are 

periodically cleaned when too much filter cake builds up and increases the pressure drop 

across the fabric filter. A baghouse is considered the best particulate matter control 

device particularly for boilers burning low sulfur western coals. 

As indicated previously in Table 1, estimated control efficiencies for the baghouse are 

over 99% for both PM PM10. These control efficiencies are based on the allowable postcontrol emissions rate of 0.1 lb/MMBtu for PM and 0.092 lb/MMBtu for PM10 (assumes 

PM10 = 92% of PM). Actual performance test data shown in Table 8 indicates that PM 

emissions from Comanche Units 1 and 2 are well below the allowable levels. The 

results of performance tests conducted in 2003 indicate the following emission rates: 

Table 8: Comanche Units 1 and 2 Stack Test Results (2003) 

Pollutant Unit 1 (lb/MMBtu) Unit 2 (lb/MMBtu) 

Filterable PM10* 0.003 0.003 

PM10 Control efficiency 99.6% 99.6% 

*PM10 = 0.92 x PM 

The BART construction permit (07PB0112B) issued on September 12, 2008 for 

Comanche Units 1 and 2 set a PM emission limitation of 0.03 lb/MMBtu, which is more 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 14 

stringent than the limit of 0.1 lb/MMBtu that currently applies to these units. Although 

test results indicate that emissions below the 0.03 lb/MMBtu BART limit are certainly 

achievable, the 2003 performance test is just one 3-hour test and does not necessarily 

represent achievable emission rates over all operating conditions. Therefore, the Division 

considers that the PM limit set the BART permit is still appropriate. Using the allowable 

post-control PM BART limit of 0.03 lb/MMBtu BART limit, the control efficiency of the 

baghouses are indicated in Table 8 above. 

A Division review of EPA’s RBLC revealed recent BACT PM/PM10 determinations 

ranging from 0.010 – 0.1 lbs/MMBtu, which are dependent on a number of factors, 

including PSD netting, EGU type and age, coal type, and adjacent controls (i.e. wet and 

dry FGD systems). The above stack test results are well below the range of recent BACT 

determinations. While determinations made by other states do not dictate the emissions 

rate choice made by the Division, they do provide information on the range to validate 

the emissions rate chosen by the Division. Refer to “Division RBLC Analysis” for more 

details. 

Based on recent BACT determinations, the state has determined that the existing Unit 1 

and 2 emission limit of 0.03 lb/MMBtu (PM/PM10) represents the most stringent level of 

available control for PM/PM10. The units are exceeding a PM control efficiency of 95%, 

and the state has selected this emission limit for PM/PM10 as BART. The state assumes 

that the BART emission limit can be achieved through the operation of the existing fabric 

filter baghouses. Thus, as described in EPA’s BART Guidelines, a full five-factor 

analysis for PM/PM10 is not needed for Comanche Units 1 and 2. 

C. Nitrogen Oxide (NOx) 

Step 1: Identify All Available Technologies

In various submittals with respect to installing additional NOX controls on Comanche 

Units 1 and 2, PSCo looked at two options: 

• Selective Non-Catalytic Reduction (SNCR) 

• Selective Catalytic Reduction (SCR) 

As part of this BART evaluation, the Division identified and examined the following 

additional control options for these units: 

• Powerspan Electro-Catalytic Oxidation (ECO)® 

• Rich Reagent Injection (RRI) 

• Rotating Opposed Fired Air (ROFA), ROFA with SNCR 

• Low NOX Burners (LNB) with Separated Overfire Air (SOFA) 

• Reburning 

• Emission limit tightening 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 15 

Since low NOX burners with over-fire air (LNB-OFA) were recently installed on Units 1 

and 2 (November 2008 for Unit 1 and November 2007 for Unit 2), the Division considers 

that further upgrades to the LNB-OFA would provide little in the way of additional 

reductions and therefore upgrades to the existing LNB-OFA were not considered. 

Step 2: Eliminate Technically Infeasible Options

Selective non-catalytic reduction (SNCR): The SNCR process is based on a gas-phase 

homogeneous reaction, within a specified temperature range, between NOX in the flue 

gas and either injected ammonia or urea to produce gaseous nitrogen and water vapor. 

SNCR systems do not employ a catalyst; the NOX reduction reactions are driven by the 

thermal decomposition of ammonia and the subsequent reduction of NOX. Consequently, 

the SNCR process operates at higher temperatures than the SCR process. Critical to the 

successful reduction of NOX with SNCR is the temperature of the flue gas at the point 

where the reagent is injected. The necessary temperature range is 1,600 - 2,100°F. SNCR 

can typically achieve NOX reductions on the order of 40-70%. 

PSCo has indicated that SNCR is feasible for Unit 1. According to their April 6, 2009 

submittal, PSCo conducted testing in the fall of 2008 on Unit 2 using a temporary SNCR 

system. The testing was done following the installation of LNB-OFA to determine if 

additional reductions could be achieved. Testing was conducted primarily at full load 

over a seven-day period using a single-level urea based-SNCR system. The SNCR 

system is sensitive to temperature and average exhaust temperature in the injection area 

for Unit 2 was nearly 2,200 oF, which exceeds the optimal temperature for the 

technology. During the test periods, NOX reductions were less than 10%, and in some 

cases during testing, an actual increase in NOX emissions was seen. Therefore, PSCo 

considers that SNCR is not feasible on Unit 2 and the Division concurs. 

Selective Catalytic Reduction (SCR): SCR systems are the most widely used postcombustion NOX control technology on pulverized coal-fired boilers. The SCR process 

is an add-on control which uses a catalyst bed and ammonia injection for removal of NOX

emissions. In the SCR process, ammonia injected into the exhaust gas reacts with 

nitrogen oxides and oxygen to form nitrogen and water. The reactions take place on the 

surface of a catalyst. The function of the catalyst is to effectively lower the activation 

energy of the NOX decomposition reaction. SCR systems can achieve NOX reductions in 

the range of 60 – 90%. SCR is technically feasible for Comanche Units 1 and 2. 

Powerspan Electro-Catalytic Oxidation (ECO)®: The Powerspan electrostatic oxidation 

process (ECO)® is an integrated air pollution control process that achieve reductions in 

multiple pollutants from coal-fired power plants, included NOX, SO2, mercury and fine 

particulate matter (particulate matter less than 2.5 microns). The Powerspan ECO® 

system is installed downstream of a coal-fired power plants’ existing baghouse and 

consists of an ECO reactor (to oxidize pollutants), absorber vessel (saturates and cools 

the flue gas, removes SO2, NO2 and oxidized mercury) and a wet electrostatic precipitator 

(removes acid aerosols, air toxics and fine particulate matter). To date the ECO® system 

has been used on a slipstream (50 MW) from a 156 MW boiler equipped with an 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 16 

electrostatic precipitator and low NOX burners6

. While the technology may be considered 

commercially available, it has only been demonstrated on the portion of the exhaust of a 

smaller boiler. Therefore, the Division considers that this technology is not feasible. 

Rich Reagent Injection (RRI): Rich reagent injection is the process of adding NOX

reducing agents in a staged lower furnace to reduce the formation of NOX, accomplished 

by injecting urea into the fuel-rich region of a furnace, where the reducing conditions in 

the lower furnace make RRI ideal for NOX reductions. The combustion process is then 

completed with the use of overfire air. RRI is similar to SNCR but the reagent at the 

lower furnace at significantly higher temperatures (2400 – 3100oF).7 The RRI process 

was originally developed for coal-fired cyclone boilers and the Division is not aware that 

RRI has been utilized on other types of coal-fired boilers. Therefore, the Division 

considers that RRI is technically infeasible for Comanche Units 1 and 2. 

Rotating Opposed Fire Air (ROFA) and ROFA with SNCR: With ROFA air in injected 

into the furnace first which breaks up the fireball and creates a swirling air flow to 

increase combustion. The swirling air results in better mixing of the fuel and air and 

distributes the temperature more evenly throughout the furnace, which improves 

combustion and reduces NOX emissions. Typical NOX reductions from ROFA alone 

range from 45 – 60 percent.8 As indicated in Table 3, the estimated NOX reductions for 

Units 1 and 2 with LNB-OFA are over 55% percent. Since ROFA is not expected to 

provide more NOX reductions than the current controls on Units 1 and 2, further review 

of ROFA is not warranted. 

That same ROFA system can be used to inject urea or ammonia into the furnace. 

However, since the NOX reduction efficiency for the Comanche Unit 1 and 2 LNB-OFA 

systems are comparable to ROFA, combining ROFA and SNCR is not likely to result in 

NOX reductions significantly above the level achieved by the Unit 1 existing LNB-OFA 

in conjunction with SNCR (note that SNCR is not feasible on Unit 2). Therefore, ROFASNCR will not be considered further. 

Low NOX Burners (LNB) with Separated Over Fire Air (SOFA): Over-fire air (OFA) is a 

combustion control technology where a portion of the total combustion air is diverted 

from the burners and injected later in the combustion process, typically above the 

combustion zone. There are specific OFA configurations that are typically associated 

with tangentially-fired boilers, close-coupled to the burner, separated from the burner and 

combination. The high end of the NOX reduction ranges for the various OFA 

configurations for tangentially fired boilers are lower than the range for LNB-OFA on 

wall-fired units.9

 Since alternate OFA configurations will not result in significant NOX

reductions beyond LNB-OFA, they will not be considered further. 

 

6

 http://www.powerspan.com/FirstEnergy_ECO.aspx 7

 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. 

http://www.ftek.com/apcRRI.php 8

 Nalco-Mobotec, ROFA Technology, 1992-2009, http://www.nalcomobotec.com/technology/rofatechnology.html

9

 Srivastava et. al, September 2005. Nitrogen Oxides Emission Control Options for Coal-Fired Electric 

Utility Boilers. Journal of Air & Waste Management Association, volume 55, pg 1370. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 17 

Reburning: In reburning, a portion of the total heat input (up to 25%) is provided by 

injecting a secondary (reburning) fuel above the main combustion zone. Combustion of 

the reburning fuel results in hydrocarbon fragments, which react with a portion of 

incoming NOX which form nitrogen containing compounds which are ultimately reduced 

to N2. The fuel used for reburning need not be the primary fuel. Natural gas has 

frequently been used as reburning fuel, as there are more issues to consider with coal as 

the reburn fuel (e.g. particle size). In general reburning can achieve greater than 50% 

NOX reduction, but many reburning demonstration projects are no longer operating.10

Reburning can be used in conjunction with other NOX control technologies, such as 

LNB-OFA, SCR and SNCR. Given that the control efficiency with reburning alone is 

similar to the NOX reduction efficiency of Comanche Units 1and 2 with LNB-OFA (see 

Table 4), the Division considers that further evaluation of reburning is not warranted. 

Emission limit tightening: The Division conducted technical analyses to determine 

whether the current NOx emission limit(s) could be more stringent based on actual 

emissions after installation of the low NOx burners with over-fire air (Unit 1 – December 

2008 – Oct. 2010 and Unit 2 - December 2007 – October 2010). This option is 

technically feasible for both units. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

PSCo provided the Division 30-day rolling average control estimates. The Division, 

from experience and other state BART proposals11, determined that 30-day NOx rolling 

average emission rates are expected to be about 5 -15% higher than the annual average 

emission rate. To be conservative, the Division projected an annual average emission 

rate at 15% for Comanche to determine control efficiencies and annual reductions. 

The Division considered that two additional NOX reduction options warranted further 

consideration. Although some of the identified control technologies were not considered 

technically infeasible, they offered similar NOX reduction levels that are already achieved 

with the LNB-OFA installed on Comanche Units 1 and 2. The two additional NOX

reduction technologies warranting further review are SCR and SNCR (Unit 1 only). \ 

SNCR: In their April 20, 2010 submittal, PSCo indicated that a NOX emission rate of 0.10 

lb/MMBtu was achievable on Unit 1. The Division calculated the control effectiveness 

based on the difference between the baseline (2009) and expected emission rate. This 

calculated control effectiveness for Comanche Unit 1 is 29.5%. This control 

effectiveness estimate is roughly equivalent to EPA’s SNCR Air Pollution Control 

Technology Fact Sheet between 30 – 50% control efficiency for tangentially fired boilers. 

SCR: In their April 20, 2010 submittal, PSCo indicated that a NOX emission rate of 0.07 

lb/MMBtu was achievable on both Units 1 and 2. Again, the Division calculated the 

control effectiveness based on the difference between the baseline (2009) and expected 

 

10 Srivastava et. al, pp 1371-1372. 

11 State of North Dakota BART Determination for Leland Olds Station Units 1 and 2. Page 16. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 18 

emission rate. This calculated control effectiveness for Comanche Unit 1 is 51% and for 

Comanche Unit 2 is 63%. These control efficiencies are lower than EPA’s AP-42 

emission factor tables, which estimate SCR as achieving 75 – 85% NOx emission 

reductions and also with a recent AWMA study citing SCR as achieving 80 – 90% 

reduction.12,13 However, the resultant emission rate of 0.07 lb/MMBtu is consistent with 

the rates cited in the AWMA study. PSCo and the Division recognize and concur that the 

lower initial emission rates of 0.124 and 0.165 lb/MMBtu for Units 1 and 2 respectively 

result in reduced SCR control efficiencies. 

Emission limit tightening: Since emission limit tightening is based on actual data, there 

will be minimal, if any, reductions from current NOx emissions. The Division found that 

the maximum 30-day rolling emission rate for Unit 1 from December 2008 – October 

2010 was about 0.15 lb/MMBtu and the average 30-day rolling rate was around 0.13 

lb/MMBtu. For Unit 2, from December 2007 to October 2010, the maximum 30-day 

rolling emission rate was about 0.17 lb/MMBtu and the average 30-day rolling rate was 

around 0.17 lb/MMBtu. As explained above, the Division projects 30-day rolling NOx

emission rates to be approximately 15% higher than annual average emission rates. The 

uncertainty of evaluating a “maximum” emission rate warrants a similar 15% buffer to be 

applied in this case, especially due to the facts stated above, including uncertainty 

regarding load operations, cold-weather operating, start-up, and cycling for renewable 

energy. 

The Division also found that for 2009, the annual average emission rate for both units 

was approximately 0.15 lb/MMBtu, and a review of January – October 2010 found that 

annual average emission rate thus far is about 0.16 lb/MMBtu. The existing annual limit 

of 0.15 lb/MMBtu for both units is an appropriate NOx emission limit at this time. 

Therefore, appropriate NOx emission limits assuming existing low NOx burner with overfire air technology for Units 1 and 2 are 0.20 lb/MMBtu on a 30-day rolling average for 

each unit and 0.15 lb/MMBtu annual average for both units. A re-evaluation of these 

emission limits will occur for the next regional haze planning period. 

Table 9 summarizes each available technology and technical feasibility for NOx control. 

Table 9: Comanche Units 1 and 2 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

SNCR 20 – 50% Y

SCR 50 – 90% Y

Electro-Catalytic Oxidation 

(ECO)®

n/a N

Rich Reagent Injection (RRI) n/a N

Low NOx Burners (LNB) 10-30% Y – installed 

LNB + OFA 25-45% Y – installed

 

12 EPA AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.1, Table 1.1-2. 

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf 13 Srivastava et. al, 2005. Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers. 

Journal of Air & Waste Management Association 55:1367 – 1388. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 19 

Air Staging – overfire air 

(OFA)

5-40% Y – installed

Rotating overfire air (ROFA) 45 – 65% N

Coal reburn+SNCR n/a N

Step 4: Evaluate Impacts and Document Results

Cost of Compliance

SNCR and SCR: In their January 19, 2010 submittal, PSCo provided cost information 

associated with SNCR for Unit 1 and SCR for both Units 1 and 2. PSCo used EPA’s 

Coal Utility Environmental Costs (CUECost) workbook model to estimate capital and 

ongoing operating and maintenance costs. The costs were then levelized at 2016/2017 

dollars based on a 20-yr life to determine annual costs. The levelized costs were reported 

in 2016/2017 dollars on the assumption that SNCR would be installed by 2015 and SCR 

would be installed by 2016, with an additional year to optimize operation of the new 

control equipment. PSCo submitted the inputs and outputs from CUECost to the 

Division in a March 1, 2010 e-mail to the Division. The levelized cost methodology and 

results were provided in Xcel internal memos dated February, 24, 2010 (submitted to the 

Division via e-mail on March 1, 2010) and April 16, 2010 (submitted via e-mail to the 

Division on April 21, 2010). According to PSCo’s April 20, 2010 submittal, the cost per 

ton for SNCR for Unit 1 was estimated to be $ 4,342/ton and the cost per ton for SCR 

was estimated to be $15,173/ton for Unit 1 and $9,558/ton for Unit 2. 

Although the Division does not dispute the levelized annual costs for SNCR and SCR, 

the baseline emission rates used to determine the cost per ton for the incremental 

reduction are not appropriate. For Unit 1, PSCo presumed baseline emission rates of 0.12 

lb/MMBtu for SNCR and 0.13 lb/MMBtu for SCR and for Unit 2 PSCo presumed a 

baseline emission rate of 0.18 lb/MMBtu. The Division has set a baseline period of 2009. 

The baseline emission rates are shown in Table 1. 

SNCR: A typical breakdown of annualized costs for SNCR on industrial boilerswill be 15 

– 25% for capital recovery and 65 – 85% for operating expenses.14 The PSCoestimated SNCR costs for operating expenses is about 69% for Comanche Unit 1. 

Since SNCR is an operating expense-driven technology, its cost varies directly 

with NOx reduction requirements and reagent usage. There is a wide range of 

cost effectiveness for SNCR due to different boiler configurations and sitespecific conditions, even with a given industry. Cost effectiveness is impacted 

primarily by uncontrolled NOx level, required emission reductions, unit size and 

thermal efficiency, economic life of the unit, and degree of retrofit difficulty.15 

 

 

14 ICAC, 2000. Institute of Clean Air Companies, Inc. “White Paper: Selective Non-Catalytic Reduction 

(SNCR) for Controlling NOx Emissions.” Washington, D.C. 2000. 15 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 20 

The Division-calculated cost effectiveness for SNCR on Unit 1 is $3,644 per ton. Recent 

NESCAUM studies estimate SNCR retrofits on tangentially fired boilers (similar 

to Unit 1) achieving NOx emission rates of 0.30 – 0.40 lb/MMBtu and emission 

reductions of 30 – 50% as costing $630 - $1,300 per ton of NOx reduced, 

depending on initial capital costs and capacity factor.16,17 It should be noted that 

PSCo is estimating resultant emission rates much lower than 0.30 lb/MMBtu for 

this boiler. EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 

per ton of NOx reduced. 18 PSCo’s estimates are above this range. However, the 

Division concludes that PSCo’s cost estimates for SNCR are reasonable due to the 

low input NOx emission rate and degree of retrofit difficulty. 

SCR: Recent NESCAUM studies estimate SCR retrofits on tangentially fired boilers 

achieving NOx emission rates of 0.10 – 0.15 lb/MMBtu and emission reductions 

of 75 – 85% as costing $2,600 - $5,000 per ton of NOx reduced, depending on 

initial capital costs and capacity factor.19,20 In reviewing PSCo’s estimates, the 

Division found that the ratio of annual costs to the total costs for LNBs, which at 

15.3% is just slightly higher than an EPA assessment that concluded that other 

facilities in Arizona, New Mexico, and Oregon presented annual costs that ranged 

from 12 – 15% of total capital investments.21 PSCo’s cost estimates are above the 

NESCAUM study ranges due to the lower control efficiencies explained earlier. 

The Division concludes that PSCo’s cost estimates for SCR are reasonable due to 

low emission reductions and retrofit difficulties. 

Table 10, Table 11, Table 12, and Table 13 depict controlled NOx emissions and control 

cost comparisons. Refer to “Comanche APCD Technical Analysis” for more details.

Table 10: Comanche Unit 1 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions 

Annual Emissions 

(tons/year) 

Annual Average 

(lb/MMBtu) 

30-day 

Rolling Average 

(lb/MMBtu) 

Baseline --- 1,511 0.124 

 

16 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

http://www.epa.gov/ttn/nsr/gen/u3-26.pdf

17 Amar, Praveen, 2000. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial 

Boilers, Internal Combustion Engines: Technologies & Cost Effectiveness.” Northeast States for 

Coordinated Air Use Management, 129 Portland Street, Boston, MA 02114. 

18 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 19 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

http://www.epa.gov/ttn/nsr/gen/u3-26.pdf

20 Amar, Praveen, 2000. “Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial 

Boilers, Internal Combustion Engines: Technologies & Cost Effectiveness.” Northeast States for 

Coordinated Air Use Management, 129 Portland Street, Boston, MA 02114. 

21 Environmental Protection Agency, 2009. 40 CFR Part 49: Assessment of Anticipated Visibility 

Improvements at Surrounding Class I Areas and Cost Effectiveness of Best Available Retrofit Technology 

for Four Corners Power Plant and Navajo Generating Station: Advance Notice of Proposed Rulemaking. 

Pg. 44318. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 21 

SNCR* 29.5 1,065 0.087 0.100 

SCR** 51 740 0.061 0.070 

 *Determined based on difference between baseline (2009) and PSCo’s expected emission rates 

 **The Division calculated SCR reductions using a consistent baseline whereas PSCo uses an 

adjusted baseline depending on the control technology which results in different control costs. 

Table 11: Comanche Unit 2 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions 

Annual Emissions 

(tons/year) 

Annual Average 

(lb/MMBtu) 

30-day 

Rolling Average 

(lb/MMBtu) 

Baseline --- 2,349 0.165 

SCR** 63 869 0.061 0.070 

 **The Division calculated SCR reductions using a consistent baseline whereas PSCo uses an 

adjusted baseline depending on the control technology which results in different control costs. 

Table 12: Comanche Unit 1 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 --- 

SNCR 445.6 $1,624,100 $3,644 --- 

SCR 770.4 $12,265,014 $15,920 $32,762 

Table 13: Comanche Unit 2NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 --- 

SCR 1,480 $14,650,885 $9,900 --- 

Energy and Non-Air Quality Impacts

SNCR and SCR: SCR retrofit impacts the existing flue gas fan systems, due to the 

additional pressure drop associated with the catalyst, which is typically a 6- to 8-inch 

water gage increase for the high temperature applications, and potentially somewhat 

lower for the low temperature alternatives. In addition, any flue gas reheat requirements 

for the low temperature applications may require significant energy input to heat the flue 

gas. SCR reagent injection systems have minimal power requirements. 

Post-combustion add-on control technologies like SNCR do increase power needs, in the 

range of 100 – 300 kilowatts (kW) depending on the boiler size, to operate pretreatment 

and injection equipment, drive the pumps and fans necessary to supply reagents, 

overcome additional pressure drops caused by the control equipment, and provide steam 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 22 

in some cases. 100 – 300 kW is enough energy to power about 10 homes for a year. 

These energy requirements are minimal and were confirmed by PSCo in the January 19, 

2010 submittal. 

SCR systems require additional auxiliary power or power from the existing flue gas fan 

systems to overcome the pressure loss across the catalyst, to supply dilution air for 

mixing with the ammonia, and to pump ammonia into the vaporizer. PSCo noted that the 

retrofit installation of an SCR typically requires the installation of new, larger induced 

draft fans to over-come the additional pressure drop created by the SCR catalyst. In 

addition, although PSCo acknowledged that the energy requirements for SCR are more 

significant than SNCR they did not quantify these impacts since the increase in house 

power usage are included in the ongoing operating costs for each technology in the 

CUECost model. 

Installing SNCR or SCR increases levels of ammonia, and may create a ‘blue plume’, if 

ammonia rates are not adequately controlled. Other environmental factors include 

ammonia storage and transportation, particularly for anhydrous ammonia. Anhydrous 

ammonia is clear in the liquid state and boils at a temperature of -28°F. With its low 

boiling point, liquid anhydrous ammonia must be stored under pressure at ambient 

temperatures to remain a liquid. With anhydrous ammonia, an invisible vapor or gas is 

formed as the liquid evaporates during depressurization. Accidental atmospheric release 

of anhydrous ammonia vapor can be hazardous; therefore, stringent requirements for 

safety are enforced, and obtaining the permits to allow the storage of large quantities of 

anhydrous ammonia may prove difficult in densely populated areas. 

PSCo did identify the change in operating mode for the coal fired boilers as more wind 

energy is brought onto the PSCo system as a non-air quality impact that would affect any 

NOX control technology. PSCo noted that typically coal-fired boilers are operated as 

base-loaded units and as such they typically run at full load 24-hours a day, with only 

minor load reductions at night when demand is lower or during off-peak periods in the 

spring and fall. However, with more wind resources replacing other conventional power 

sources, the load may be dropped further since demand for power is less. Therefore, the 

load on coal-fired units may be further reduced, particularly during peak wind generating 

periods. PSCo considers that operating these units at lower loads may affect the NOX

control technologies and result in lower NOX reductions than those that would be seen at 

high loads. 

Emission Limit Tightening: There are no known non-air quality or energy impacts 

associated with emission limit tightening. Thus, this factor does not influence the 

selection of this option. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 23 

Remaining Useful Life

In their January 19, 2010 submittal PSCo indicated that the remaining useful life of 

Comanche Units 1 and 2 are each in excess of 20 years, which is the maximum 

amortization period allowed in the BART analysis. Thus, this factor does not influence 

the selection of controls. 

Step 5: Evaluate Visibility Results

CALPUFF modeling was used to determine the projected visibility improvement 

associated with various control technologies. The modeling guideline requires that 

modeled baseline emission rate is the 24-hour peak emission rate. The modeling 

guideline also requires that, at a minimum, the presumptive emission rate scenario be 

modeled. Table 14 shows the number of days pre- and post-control. Table 15 depicts the 

visibility results (98th percentile impact and improvements) as well as cost effectiveness 

in $/deciview and the calculation methodology utilized by the Division. 

Per the April 2010 modeling protocol22, to isolate the effects of a given unit for controls 

on a given pollutant, the Division has judiciously constructed each emissions scenario to 

isolate the impact of a given BART control on a given unit. For example, to determine 

the effect of a NOx BART control technology on a given unit, emission rates for the other 

pollutants (SO2 and PM/PM10) and other BART-eligible units are held constant at precontrol levels. For BART sources with more than one BART unit, modeling the units 

individually would ignore important atmospheric chemical reactions that occur when 

units operate simultaneously. The combination scenario assumed Units 1 and 2 with NOx

emissions at 0.07 lb/MMBtu and SO2 emissions at 0.12 lb/MMBtu. 

In situations where the BART-eligible units at a given BART-eligible source operate 

simultaneously, the sulfate and nitrate estimates from the modeling system will be more 

realistic, in general, if all BART units and all pollutants at a BART-eligible source are 

modeled together. The combined unit approach has the added benefit of allowing 

Colorado to estimate the net degree of visibility improvement from the simultaneous 

operation of BART controls on multiple units for multiple pollutants at a given BARTeligible source. 

Table 14: Visibility Results – Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

NOx 

Control 

Scenario 

Boiler(s) 

NOx 

Emission 

Rate 

(lb/MMBtu)*

Class I 

Area 

Affected

3-year totals 3-year totals 

PreControl 

Days 

>0.5 

dv 

PostControl 

Days 

>0.5 

dv 

∆days

PreControl 

Days 

>1.0 

dv 

PostControl 

Days 

>1.0 

dv 

∆days

Max 24-

hour 

1 0.40 Great 

Sand 

Dunes 

National 

60 --- --- 27 --- --- 

2 0.53 

NOx @ 1 0.20 60 57 3 27 24 3 

 

22 Colorado Air Pollution Control Division, Technical Services Program, 2010. “Supplemental BART 

Analysis CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling Analysis.” 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 24 

0.20 

lb/MMBtu 

Park 

NOx @ 

0.20 

lb/MMBtu 

2 0.20 60 51 9 27 21 6 

SNCR @ 

0.10 

lb/MMBtu 

1 0.10 60 51 9 27 22 5 

SNCR not 

feasible 2 n/a 60 n/a n/a 27 n/a n/a 

SCR @ 

0.07 

lb/MMBtu 

1 0.07 60 51 9 27 21 6 

SCR @ 

0.07 

lb/MMBtu 

2 0.07 60 47 13 27 18 9 

Combo 

1 

0.07 60 4 56 27 1 26 

2 

* Denotes that output was interpolated by the Division and is not an actual modeled output. See 

“Comanche BART Modeling Summary” for more details. 

Table 15: Visibility Results – NOx Control Options 

NOx 

Control 

Scenario 

Boiler(s) 

NOx 

Emission 

Rate 

(lb/MMBtu)* 

Output 

(@ 98th

Percentile 

Impact) 

98th

Percentile 

Impact 

Improvement 

98th

Percentile 

Impact 

Improvement 

from new 

LNB (2009) 

98th

Percentile 

Improvement 

from 

Maximum 

Cost 

Effectiveness

(dv) (∆ dv) (∆ dv) (%) ($/dv) 

Max 24-

hour 

1 0.40 

2.05 --- --- --- --- 

2 0.53 

New 

LNB 

(2009) 

1 0.20 1.90 0.16 n/a 8% n/a 

2 0.20 1.75 0.31 n/a 15% n/a 

SNCR 1 0.10 1.79 0.26 0.11 13% $6,175,284 

SNCR 

not 

feasible 

2 n/a 

SCR 

1 0.07 1.76 0.30 0.14 14% $41,576,317 

2 0.07 1.58 0.47 0.17 23% $31,172,095 

Combo 

1 

0.07 0.36 1.69 n/a 82% n/a 

2 

* Denotes that output was interpolated by the Division and is not an actual modeled output. See 

“Comanche BART Modeling Summary” for more details. 

Step 6: Select BART Control

Based upon its consideration of the five factors summarized herein , the state has 

determined that NOx BART is following existing NOx emission rates: 

 Comanche Unit 1: 0.20 lb/MMBtu (30-day rolling average) 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Comanche Station Page 25 

 0.15 lb/MMBtu (combined annual average for units 1 & 2) 

 Comanche Unit 2: 0.20 lb/MMBtu (30-day rolling average) 

 0.15 lb/MMBtu (combined annual average for units 1 & 2) 

The state assumes that the BART emission limits can be achieved through the operation 

of existing low NOx burners. Although the other alternatives achieve better emissions 

reductions, the added expense of achieving lower limits through different controls were 

determined based on the high cost/effectiveness ratios to not be reasonable coupled with 

the low visibility improvement (under 0.2 delta deciview) afforded.