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

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 1 

Best Available Retrofit Technology (BART) Analysis of Control Options 

For 

Colorado Energy Nations, Golden, Colorado 

I. Source Description

Owner/Operator: Colorado Energy Nations Company (CENC) (formerly Trigen 

 Colorado Energy Corporation) 

Source Type: Steam Generating Unit 

Boiler Type(s): Boiler 4 – Pulverized Coal Dry-Bottom Tangentially-Fired 

 (SCC: 10200222 for coal) 

 Boiler 5 – Pulverized Coal Dry-Bottom Tangentially-Fired 

 (SCC: 10200222 for coal) 

 

The CENC facility is located in Jefferson County on 10th Street in the town of Golden, 

Colorado. Figure 1 below provides an aerial perspective of the CENC site. The two 

large buildings are separated by Clear Creek to the south and US Highway 58 borders the 

northern side of the CENC site. The large building to the north of CENC and south of 

Highway 58 is the Coors Brewery. 

Figure 1: CENC facility Aerial Perspective 

The CENC facility consists of five (5) boilers and the associated equipment for coal and 

ash handling. The boilers provide steam for one (1) 20 MW generator, two (2) 10 MW 

generators, and for industrial use. The boilers are rated at 228 MMBtu/hr (Boilers 1 and 

2), 225 MMBtu/hr (Boiler 3), 360 MMBtu/hr (Boiler 4) and 650 MMBtu/hr (Boiler 5). 

Boilers 1 and 2 normally operated in hot standby mode or when one of the coal boilers 

(Boilers 3, 4, or 5) is down. Boilers 3, 4, and 5 are controlled for PM/PM10 by separate 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 2 

fabric filter baghouses, which were installed at the time of construction for each boiler. 

The boilers were installed as follows: 

• Boiler 1 – 1962 

• Boiler 2 – 1962 

• Boiler 3 – 1962 – updated to coal in 1981 

• Boiler 4 – 1974 – last modification in 1975 

• Boiler 5 – 1979 – reached full capacity in 1980 

 No coal processing is performed on-site. The coal is received ready for feed to the 

boilers. Boilers 4 and 5 are equipped with pulverizers that process the coal directly into 

the fire zone. The ash and flyash from the boilers may be sold or transported off-site for 

disposal. Therefore, all fugitive dust sources at the facility are related to coal conveying 

or ash handling. There is also one Detroit Diesel engine (<100 HP) at the facility for 

maintenance of equipment and/or backup operation of air compressors that was installed 

prior to 1970. This engine is tested weekly. The Coors Brewery currently contracts for 

the purchase of the total electricity and steam output. 

Boilers 4 and 5 are considered BART-eligible, being industrial boilers with the potential 

to emit 250 tons or more of haze forming pollution (NOx, SO2, PM10), and commenced 

operation in the 15-year period prior to August 7, 1977. Initial air dispersion modeling 

performed by the Division demonstrated that the CENC facility contributes to visibility 

impairment (a 98th percentile impact equal to or greater than 0.5 deciviews) and is 

therefore subject to BART. Trigen (now CENC) submitted a BART Analysis to the 

Division on July 31, 2006. CENC also provided information in “NOx Technical 

Feasibility and Emission Control Costs for Colorado Energy Nations, Golden, Colorado” 

Submittal provided on November 16, 2009 as well as additional information upon the 

Division’s request on February 8, 2010 and May 7, 2010. These documents are all 

provided as “CENC BART Submittals”. Table 1 depicts technical information for each 

BART-subject boiler at the CENC facility. 

Table 1: CENC Facility BART-eligible Emission Controls and Reduction (%) 

 Unit B004 Unit B005 

Placed in Service 1975 1979 

Boiler Rating, MMBtu/Hr for 

coal 

360 650 

Electrical Power Rating, Gross 

Megawatts 

35 65 

Description Combustion Engineering Model 

CE-VU40 360 MMBtu/hr (coal), 

tangential fired, firing coal, 

natural gas, #2 fuel oil, ethanol, 

on-site generated on-spec used oil 

and sludge from WWTP 

Combustion Engineering Model 

CE-VU40 650 MMBtu/hr (coal), 

tangential fired, firing coal, 

natural gas, #2 fuel oil, ethanol, 

on-site generated on-spec used oil 

and sludge from WWTP 

Air Pollution Control Equipment Wheelabrator-Frye Model 264 

fabric filter baghouse with 8 

compartments 

Carter Day fabric filter baghouse 

with 12 modules 

Monitoring Equipment COM 

CEMs for SO2, NOx, CO2, and 

stack gas 

COM 

CEMs for SO2, NOx, CO2, and 

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

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 3 

Emissions Reduction (%) NOx – None 

SO2 – None 

PM/PM10 – 99+% 

NOx – None 

SO2 – None 

PM/PM10 – 99+% 

II. Source Emissions

CENC estimated that a realistic depiction of anticipated annual emissions for Boilers 4 

and 5, or “Baseline Emissions”, to be conservative, was the maximum historical (2000 – 

2005) 12-month (rolling) emissions experienced in the July 31, 2006 analysis. CENC 

also provided 2-year annual average emissions for comparison purposes. 

Several years have passed since the original BART submittal, in which the Division has 

updated modeling and technical analyses. Therefore, the Division used years 2006 – 

2008 (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 baseline emissions are used as the basis for estimating 

annual emission reductions for the various control technologies evaluated and 

determining the annualized costs to achieve those reductions. . The Division verified 

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

database as applicable. These emissions are summarized in Table 2. 

Table 2: CENC Boilers 4 and 5 Baseline Emissions 

Pollutant 

Boiler 4 Boiler 5 

Annual 

Emissions* (tpy) 

30-day rolling 

average 

emissions** 

(lb/MMBtu) 

Annual 

Emissions* (tpy) 

30-day rolling 

average 

emissions** 

(lb/MMBtu) 

NOx 600 0.50 691 0.34 

SO2 781 0.64 1,406 0.71 

PM10 11 0.003*** 18 0.01*** 

*Using most recent three calendar years (CEMs data). 

**The Division calculated 30-day rolling average rate (lb/MMBtu) from the most recent three calendar 

years (CEMs data) based on maximum daily reported data for each unit for NOx and SO2 emissions. Days 

with zero emissions/heat input were not included in these averages. 

***The PM10 emission rate is determined from calculating the maximum heat input and annual operating 

hours.

Boiler 4 is mainly fired on coal and can be fired on natural gas. Fuel oil may be used as a 

backup fuel, but has not been used in recent years. Boiler 5 is fired on coal, with backup 

oil firing. Either boiler also may fire ethanol or sludge from the Coors Brewery. Both 

units are subject to Colorado Regulation 6 Part A and NSPS 40 CFR Subpart D. 

III. Units Evaluated for Control

As documented by CENC, these boilers fire low sulfur, high heating value bituminous 

coal from western Colorado. The specifications for the coal are listed in Table 3. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 4 

Table 3: Coal Specifications (2006 – 2008 Averaged APEN data) 

 Specifications 

Emission Unit Fuel Heating Value 

(Btu/lb) 

Sulfur (% by weight) Ash (% by weight) 

B004 11,703 0.42 9.14 

B005 11,833 0.42 9.17 

Table 1 lists the units at the CENC facility that the Division examined for control to meet 

BART-eligible requirements. Controlled and uncontrolled emission factors and CEMs 

data were used to evaluate the control effectiveness of the current emission controls. 

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

bituminous coal. 

Table 4: Uncontrolled emission factors for CENC BART-eligible sources 

Emission 

Unit Pollutant 

Fuel 

Natural Gas 

(lb/MMscf) 

Coal (bituminous) (lb/ton) #2 Fuel Oil 

(lb/Mgallons) 

Boiler 4 & 

Boiler 5 

NOx 280 8.4 24 

SO2 0.6 35 x %S = 14.7* 157 x %S = 67.5* 

PM/PM10 7.6 PM – 10 x %A = 91.4** 

PM10 – 2.3 x %A = 21.0** 

PM – 2 

PM10 – 1 

*%S = % of sulfur present in coal supply. For example, 35 x 0.42 = 14.7 

**%A = % of ash present in coal supply. For example, 10 x 9.14 = 91.4 

IV. BART Evaluation of Boiler 4 and Boiler 5

A. Sulfur Dioxide (SO2)

Step 1: Identify All Available Technologies

CENC identified four SO2 control options: 

Flue gas desulfurization (FGD): 

 Lime spray dry absorber (SDA or dry FGD) 

Dry sorbent injection – Trona (DSI) 

SO2 emission management 

The Division also identified and examined additional control options for these units: 

Lime or limestone-based (wet FGD) 

Emission limit tightening (no control) 

Step 2: Eliminate Technically Infeasible Options

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

scrubbing uses a slurry of alkaline sorbent, either limestone or lime, to scrub the gases. 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 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 5 

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. 

Wet FGD: Wet FGD control systems must be located after the baghouse because the moist 

plume resulting from the wet scrubber system would create baghouse plugging issues if the 

control is placed ahead of the baghouse. Each absorber tower requires a similar “foot print” area, 

along with additional space for support equipment access, slurry preparation, mixing, associated 

tanks, dewatering and a chimney. 

Dry FGD: 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 plants1

. SDA 

systems are typically utilized at smaller units that burn lower-sulfur coal in the western U.S., 

where water resources are limited. Additionally, Controlling SO2 Emissions: A Review of 

Technologies2 evaluates various SO2 control technologies and shows that for low-sulfur coal 

applications, LSDs can meet comparable emission rates to wet systems. 

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. 

The plant is bounded to the north by US Highway 58 and Coors Brewery buildings, to the west 

by 12th street and a small parking, to the east by Coors rail yard lots, and the south by Clear 

Creek and the Coors Brewery. Train tracks also bound the facility to the north and east. Figure 

1 illustrates these boundaries. Figure 2, depicting a detailed view of the boilers, respective 

baghouses, and available spaces for FGD systems, indicates that available physical space is 

severely constrained at the CENC facility, due to locations as well as pollution control retrofits 

for particulate matter. The entire site is very congested, with limited access and limited room for 

major retrofits of new capital equipment. CENC asserts that in order to allow sufficient 

residence time for evaporation and reaction with SO2, the design gas residence time in a SDA is 

approximately 10 seconds. For Boilers 4 and 5, a SDA vessel for each boiler, not including other 

associated equipment, would be approximately 35 feet in diameter by 60 feet high. In addition, 

in order to provide high reagent utilization, the unreacted lime mixed with ash form the baghouse 

must be recycled. This would increase solids loading in each baghouse by a factor of 3 and 

require extra baghouse capacity and a complete reconstruction of the ash handling system. 

Subsequently, CENC determined that it is not technically feasible to install dry FGD systems on 

either Boilers 4 or 5 (B004/B005). 

In 2007, the Division conducted an on-site visit to determine the technical feasibility of potential 

SO2 controls on Units 4 and 5. The Division noted: 

 

1

 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. 

2 Srivastava, R.K. Controlling SO2 Emissions: A Review of Technologies. U.S. Environmental Protection Agency, 

Washington, DC, EPA/600/R-00/093 (NTIS PB2001-101224), 2000.
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 6 

• CENC determined dry FGD controls are not technically feasible as discussed above, 

therefore control effectiveness and impacts are not evaluated in this analysis. After the 

site visit, the Division concurred with this conclusion. 

• Traditional wet FGD controls are possible considering that there is adequate space near 

the baghouse to allow for the installation of controls, but are eliminated based on other 

considerations within the five factors (i.e. energy and non-air quality impacts). Refer to 

the energy and non-air quality impact section for the Division review regarding wet FGD 

controls for Boilers 4 and 5. 

Figure 2: Aerial Zoom of CENC Facility 

DSI: Dry sorbent injection involves the injection of typically a sodium based reagent, either the 

mineral trona (sodium sesquicarbonate) or refined sodium bicarbonate, into the flue gas. The 

injected reagent reacts with the SO2 present in the flue gas to create sodium sulfate, which is then 

collected in the particulate control device, in the case of CENC. CENC asserts that the flue gas 

temperatures present upstream of the boiler airheaters are in the appropriate range to allow for 

DSI application. A very important factor in DSI application is the ability for the boiler’s 

particulate control device to accommodate the added particulate loading of the DSI reagent in 

addition to the flyash loading. CENC’s preliminary review indicates that even with the added 

loading of DSI reagent, the CENC baghouses would be operating within the design specification 

for particulate loading, but the ash collection system(s) would require modifications. The flue 

gas is not cooled nor saturated with water, so reheating of desulfurized flue gas is not required. 

No gas-sorbent contacting vessel is required to be installed. DSI requires less capital equipment, 

less physical space, and less medication to existing ductwork compared to a SDA system. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 7 

However, reagent costs are much higher and depending upon the absorbent and amount of 

sorbent injected, control efficiency is lower when compared to a SDA system. Lime, soda ash, 

and Trona (sodium sesquicarbonate) are possible. Lime is the least reactive reagent resulting in 

low efficiencies even at high injection rates. Trona is a very reactive reagent that can be used to 

achieve a range of efficiencies depending on the amount of sorbent injected, and would likely be 

the chosen reagent. 

Due to variability of boiler configurations, coal composition, NOx to SO2 ratios, and other 

factors, it is difficult to arrive at a precise estimate of the maximum SO2 removal rate that is 

achievable while minimizing the brown plume condition. However, based on literature review, 

CENC estimated the maximum SO2 removal rate that can be achieved while minimizing the 

creation of the brown plume condition to be 65% SO2 removal. In practical application, a higher 

SO2 removal rate may be possible, while it is also possible that a lower SO2 removal rate may be 

necessary to limit the brown plume formation. This determination would require actual SO2

removal real-time testing. CENC consulted with PPC Industries to determine the feasibility and 

emission reduction potential associated with installing DSI-Trona controls. Therefore, DSITrona is technically feasible for the CENC facility Boilers 4 and 5. 

SO2 Emissions Management: CENC is subjected to variations in as-received coal sulfur content. 

Figure 3 provided by CENC shows that there are clearly historical (2000 – 2005) short-term 

peaks in SO2 emissions that can be attributed to infrequent deliveries of high-sulfur coal. CENC 

has no capability or additional storage space on site to store coal or to blend with other lower 

sulfur coals in order to manage SO2 emissions to lower levels, and has not had a regulatory need 

to do so. Once delivered, the facility has no choice but to use the coal delivered before a 

subsequent lower sulfur shipment can be obtained and burned. 

Figure 3: Boilers 4 and 5 SO2 lb/hour daily average (2000 - 2005) 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 8 

Using alternative approaches to operations management, CENC proposes a new, enforceable 

permit limit to reduce peak lb/hr SO2 emissions. CENC can employ a variety of options to 

reduce emissions: dispatch natural gas-fired capacity, reduce total system load, and/or reduce 

coal firing rate to maintain a new peak SO2 limits. Since these two boilers already have CEMs 

and stack flow monitors installed, the CEMs could be used to demonstrate continuous 

compliance. CENC proposes reducing peak levels with limits at 280 lb/hr for Boiler 4 and 500 

lb/hour for Boiler 5 on a 24-hour average basis. This option is technically feasible for Boilers 4 

and 5. 

Emission limit tightening: The Division and CENC conducted technical analyses of sulfur % and 

heat content in historical coal supplies to determine whether the current SO2 emission limit could 

be more stringent based on actual emissions (2006 – 2008) from the units. This option is 

technically feasible for Boilers 4 and 5. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

CENC provided the Division annual average control estimates. In the Division’s experience, 30-

day SO2 rolling average emission rates are expected to be approximately 5% higher than the 

annual average emission rate. The Division projected a 30-day rolling average emission rate 

increased by 5% for CENC Boilers 4 and 5 to determine control efficiencies and annual 

reductions. 

The Division has reviewed the data supplied by CENC as well as other control techniques 

applied to pulverized coal boilers. A Division review of the EPA’s RBLC revealed recent BACT 

SO2 determinations range from 0.06 – 0.167 lbs/MMBtu. The Division narrowed down this 

range depending on the averaging time, permit type, facility size, and fuel type. This narrowed 

range is 0.095 – 0.161 lbs/MMBtu, with an average of 0.119 lbs/MMBtu rounded to 0.12 

lbs/MMBtu. 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. The Division 

notes that for CENC, any RBLC determinations apply for DSI only, since SO2 emissions 

management is unit-specific. 

DSI: CENC asserts that the maximum SO2 removal rate that can be achieved to be 65% SO2

removal due to the small size of the boilers, and non-ideal gas/solids residence time. The 

Division adjusted this removal rate to 60%, based on other Colorado submittals3 and to be 

conservative since this technology is relatively novel. 

SO2 Emissions Management: Table 5 summarizes current Title V permit limits and projected 

emission reductions using CENC’s proposed limits. 

 

3

 Colorado Springs Utilities, 2010. “RE: Question Regarding the Application of Dry Sorbent Injection to Martin 

Drake Power Plant Unit 5.” Submitted to the Colorado Air Pollution Control Division on May 10, 2010. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 9 

Table 5: CENC Boiler 4 and 5 Current vs. Proposed SO2 Permit Limits and Emissions Reduction 

Unit Current Title V SO2 permit 

limits 

Actual Emissions 

(2000 – 2005) 

Actual Emissions 

(2006 – 2008) 

CENC proposed 

SO2 limits 

Boiler 4 1892.0 tons/year (approx. 

432 lb/hour) 

911.8 tons/year 

(approx. 208 lb/hour) 

780.6 tons/year 

(approx. 178 lb/hour) 

280 lb/hour (CEM 

24-hr rolling avg.) 

Coal – 1.2 lb/MMBtu 

(CEM 3-hr rolling avg.) 

Fuel Oil – 0.8 lb/MMBtu 

(CEM 3-hr rolling avg.) 

Boiler 5 3,416.0 tons/year (approx. 

780 lb/hour) 

1,954.7 tons/year 

(approx. 446 lb/hour) 

1,406.0 tons/year 

(approx. 321 lb/hour) 

500 lb/hour (CEM 

24-hr rolling avg.) 

Coal – 1.2 lb/MMBtu 

(CEM 3-hr rolling avg.) 

Fuel Oil – 0.8 lb/MMBtu 

(CEM 3-hr rolling avg.) 

Combined 

limit 

4,888.0 tons/year (approx. 

1,116 lb/hour) 

(PM10 SIP Agreement) 

2,866.5 tons/year 

(approx. 655 lb/hour) 

 780 lb/hour (CEM 

24-hr rolling avg.) 

*Refer to pages A-31, A-34, and A-35 of CENC BART Submittal (July 31, 2006) for detailed SO2 emission 

documentation. 

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

minimal, if any, reductions from baseline period (2006 – 2008) SO2 emissions. The Division 

found that the maximum 30-day rolling emission rate was 0.80 lb/MMBtu for Boiler 4 and 0.9 

lb/MMBtu for Boiler 5. However, for these small industrial boilers with very limited coal 

storage capacity, the Division and CENC agree that reviewing sulfur % and heat content is a 

better basis for determining an appropriate SO2 emission limit. CENC submitted supplemental 

information on October 26 and November 10, 2010 to support this methodology. Refer to Table 

6 for more details. 

Table 6: Coal Supply Analysis for SO2 Emission Limit 

 2006 – 2008 

Minimum (Btu/lb) 9.997 

Maximum (% Sulfur) (30-day period) 0.52 

Theoretical lb/MMBtu 

Boiler 4 Sulfur to SO2 conversion averages at 99%* 1.03 (rounded to 1.0) 

Boiler 5 Sulfur to SO2 conversion averages at 100%* 1.04 (rounded to 1.0) 

*CEMs data vs. theoretical 

Based on the boiler sulfur to SO2 conversions, the appropriate emission limit based on actual fuel 

supply data for the baseline period is 1.0 lb/MMBtu (30-day rolling average). This option serves 

as assurance that CENC will be able to both continually comply with an appropriate emission 

limit while simultaneously eliminating future potential emission increases. 

Table 7summarizes each available technology and technical feasibility for SO2 control. 

Table 7: CENC Boilers 4 and 5 SO2 Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 10 

Wet FGD 52-98%, median 

90%4

Y

Dry FGD (SDA) 70-90% (CENC) Y

DSI (Trona) ~60% Y

SO2 Emissions Management 30% Y

Emission Limit Tightening Minimal Y 

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance

Wet FGD: The significant cost issue associated with securing sufficient water supplies (a costly 

and scarce resource in the Front Range) to support a wet FGD control system along with the cost 

of disposing the sludge byproduct at an approved landfill since on-site storage is not an option. 

There are other costs and environmental impacts that the Division also considers undesirable 

with respect to wet scrubbers. For example, the off-site disposal of sludge entails considerable 

costs, both in terms of direct disposal costs, and indirect costs such as transportation and 

associated emissions. Refer to the energy and non-air quality impact section for the Division 

review regarding wet FGD controls for Boilers 4 and 5. 

DSI: PCC Industries provided the cost to CENC for the basic equipment required for Trona 

injection. DSI requires less capital equipment, less physical space, and less medication to 

existing ductwork compared to a SDA system. However, reagent costs are much higher and 

depending upon the absorbent and amount of sorbent injected, control efficiency is lower when 

compared to a SDA system. Additional costs for equipment redundancy, modifications to the 

facility’s ash handling system, and increased transformer capacity were estimated by CENC 

based on the need to maintain continuous compliance with a short-term emission rate (30-day 

rolling) and past experience with retrofits at other CENC facilities. CENC derived total installed 

costs from the purchased equipment cost using USEPA factors (EPA’s Cost Control Manual). 

Operating costs were based on estimated Trona requirements of 2.8 lb Trona per lb of SO2

collected for 65 percent control. The theoretical minimum requirement is 2.4 lb Trona per lb of 

SO2 collected. Detailed capital and annual cost data are presented in “CENC APCD Technical 

Analysis”. 

The Division compared CENC’s costs for DSI to other Colorado facilities similar in size that 

analyzed DSI, shown inTable 8. 

Table 8: DSI Cost Comparisons 

Facility & Unit Size 

(MW) 

Annualized Costs 

($/year) 

Cost Effectiveness 

($/ton) 

Ratio 

($/kW) 

Colorado Energy Nations – 

Boiler 4 

35 $1,766,000 $3,774 $50.46 

Colorado Springs Utilities – 

Drake Unit 5 

51 $1,746,172 $2,293 $34.33 

 

4

 U.S. EPA, 2000. “Controlling SO2 Emissions: A Review of Technologies.” Prepared by Ravi K. Srivastava for 

the U.S. Environmental Protection Agency, Office of Research and Development. Office of Research and 

Development. Washington, D.C. 20460. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 11 

Colorado Energy Nations – 

Boiler 5 

65 $2,094,000 $2,485 $32.22 

Colorado Springs Utilities – 

Drake Unit 6 

85 $2,910,287 $1,741 $34.24 

The Division considers CENC’s DSI costs to be within a reasonable cost range that is 

comparable to other Colorado facility submittals.5

 CENC Boiler 4 is more expensive compared 

to other units because of the small size of the boiler and the increased difficulty of the retrofit. 

Therefore, the Division did not adjust CENC’s DSI cost estimates. 

SO2 Emissions Management: CENC notes that the costs for implementing a SO2 Emission 

Management Plan are based on essentially zero capital cost with increment variable operating 

costs based on the replacement of a portion of coal boiler capacity with natural gas as needed to 

reduce historical 24-hour SO2 peaks. The emission level projected for this alternative was 

derived from the analysis of historical emission level variability detailed in Figure 3. 

The Division verified CENC’s calculated costs for SO2 Emission Management based on SO2

hourly CEMs data (06/29/2000 through 01/04/2006), the amount of curtailment that will be 

required, and average natural gas costs ($10/MMBtu). In reviewing CENC’s DSI estimate, the 

Division found that the ratio of annual costs to the total capital costs for the control technology 

option projected by CENC to be higher than those projected by other facilities that were 

amortized over the same 20 year time frame. The annualized costs for DSI are about 35% of the 

total capital investment. The EPA found that other facilities in Arizona, New Mexico, and 

Oregon presented annual costs that ranged from 12 – 15% of total capital investments6. 

However, CENC is a much smaller facility than the facilities in Arizona, New Mexico, and 

Oregon, which can significantly increase costs. CENC also clearly followed the Cost Control 

Manual methodology for estimating operation and maintenance costs. Therefore, the Division 

did not adjust CENC’s cost estimates. 

Emission limit tightening: There are no costs associated with this option. This option is 

considered equivalent to the “baseline” row in the tables below, and is not considered as a 

separate cost option. 

Table 9, Table 10,Table 11, and Table 12 depict controlled SO2 emissions and control cost 

comparisons. 

Table 9: Boiler 4 Control Resultant SO2 Emissions 

Alternative Control 

Efficiency (%) 

Resultant Emissions 

Annual Emissions 

(tons/year) 

Annual Average 

(lb/MMBtu) 

30-day Rolling Average 

(lb/MMBtu) 

Baseline --- 780 0.64 0.74 

 

5

 ENSR, 2006. BART Analysis for the TriGen Colorado Energy Corporation Facility in Golden, Colorado. 

Prepared for Trigen. Document No: 10279-017-700. 

6

 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 – Colorado Energy Nations Company Page 12 

SO2 Emissions 

Management 

0.13 767 0.64 0.74 

DSI - Trona 60 312 0.26 0.30 

Table 10: Boiler 5 Control Resultant SO2 Emissions 

Alternative Control 

Efficiency (%) 

Resultant Emissions 

Annual Emissions 

(tons/year) 

Annual Average 

(lb/MMBtu) 

30-day Rolling Average 

(lb/MMBtu) 

Baseline --- 1,406 0.71 0.82 

SO2 Emissions 

Management 

0.06 1,448 0.71 0.82 

DSI - Trona 60 562 0.29 0.33 

Table 11: Boiler 4 SO2 Cost Comparison 

Alternative Emissions 

Reduction (tpy) 

Annualized Cost 

($)* 

Cost Effectiveness 

($/ton) 

Incremental Cost 

($/ton) 

Baseline 0 $0 $0 --- 

SO2 Emissions 

Management 

1.0 $44,299 $43,690 $43,089 

DSI - Trona 468 $1,766,000 $3,744 -$85 

Table 12: Boiler 5 SO2 Cost Comparison 

Alternative Emissions 

Reduction (tpy) 

Annualized Cost 

($) 

Cost 

Effectiveness 

($/ton) 

Incremental Cost 

($/ton) 

Baseline 0 $0 $0 --- 

SO2 Emissions 

Management 

0.8 $65,882 $78,095 $92,572 

DSI - Trona 844 $2,094,000 $2,482 -$90 

Energy and Non-Air Quality Impacts

Traditional Wet FGD: Based upon its experience, and as discussed in detail below, the Division 

has determined that wet scrubbing has several negative energy and non-air quality environmental 

impacts, including massive water usage. This is a significant issue in Colorado, where water is a 

costly, precious and scarce resource. In the arid West, securing sufficient water supplies to 

support a wet FGD control system is a difficult undertaking that precludes other beneficial uses 

for such water. In Colorado, water law is based upon the doctrine of prior appropriation or “first 

in time - first in right,” and the priority date is established by the date the water was first put to a 

beneficial use. Thus, depending upon whether and when a power plant first secured a water 

appropriation and whether such appropriation is adequate to supply the demand, there may be 

insufficient water appropriations available in some areas of the state, particularly in the Front 

Range, to accommodate the added demands of wet FGD controls. At a minimum, the water 

demands of wet FGDs will compete for what is already a scarce resource needed for Colorado’s 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 13 

domestic, agricultural and industrial demands. Wet scrubbers consume approximately 23% more 

water than LSD scrubbers, depending on boiler size.7

There are other environmental impacts that the Division also considers undesirable with respect 

to wet scrubbers. On-site storage of wet ash is an increasing regulatory concern, as evidenced by 

the recent Tennessee Valley Authority spill. In addition, the steam plume resulting from a wet 

FGD control system in such a confined creek bed will produce a noticeable cloud that will hang 

over a densely populated area (City of Golden). The Division has received complaints regarding 

the more visible plumes associated with wet scrubbing; a potential irony in light of the visibility 

issues at the heart of the BART program. The Division largely focused its BART SO2 control 

technology consideration on commercially available once-through dry FGD controls, 

specifically, “lime spray dryers” (LSD), that have an established record of reliable performance 

on boilers burning low-sulfur coal. Generally, wet FGD controls can achieve a higher level of 

SO2 control on a percent capture basis that exceeds the capabilities of LSDs but, as noted above, 

there are a number of non-air quality and other environmental impacts including increased water 

usage, sludge disposal and wet plume issues that often overshadow any incremental 

improvement in SO2 emission reductions. Recent PSD applications in Colorado have 

demonstrated lime spray dryer systems to be BACT. 

The Division finds that the non-air quality environmental impacts outweigh the visibility benefits 

from this technology. Therefore, the State has eliminated this option as BART. 

SO2 Emissions Management: The Division has determined that there are not any negative energy 

or non-air quality related impacts related to the proposed SO2 emission management scenario. 

DSI: CENC documents additional collateral impacts of applying DSI include enhanced removal 

of halogenated acid gases, and reduced mercury capture in the baghouse. DSI ahead of the 

baghouse would contaminate the flyash with sodium sulfate, rendering the ash unsalable as a 

replacement for concrete and render it landfill material only. Currently, there is moderate 

removal of acid gases in the baghouse due to the alkaline nature of the flyash. 

The dry sorbent injection system does result in an ash by-product. This by-product does not 

require additional treatment before being deposited in a landfill. However, a study conducted by 

the Department of Energy found arsenic and methylene chloride in the ash,8

 which could become 

a problem if more stringent regulations are imposed in the future. However, it is not known yet 

if these levels are considered hazardous or if the levels vary depending on the ash; therefore, this 

issue requires future research. Otherwise, the DSI does not have any negative energy or non-air 

quality related impacts. Thus, this factor (regarding DSI) does not influence the selection of 

controls. 

 

7

 2008. “Revised BART Analysis for Unit 1 & 2 Gerald Gentleman Station Sutherland, Nebraska: Nebraska Public 

Power District.” Prepared by: HDF 701 Xenia Avenue South, Suite 600 Minneapolis, MN 55416 With control 

technology costs provided by: Sargent & Lundy. 

8

 Department of Energy, 2001. LIFAC Sorbent Injection Desulfurization Demonstration Project: A DOE 

Assessment. U.S. Department of Energy: National Energy Technology Laboratory. P.O. Box 880, 3610 Collins 

Ferry Road Morgantown, WV 26507-0880. 

http://www.netl.doe.gov/technologies/coalpower/cctc/resources/pdfs/lifac/LIFAC_PPA.pdf 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 14 

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. 

Remaining Useful Life

CENC asserts that there are no near-term limitations on the useful of these boilers, so it can be 

assumed that they will remain in service for the 20-year amortization period. 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 13 shows the number of days pre- and 

post-control. Table 14 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 protocol9

, 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 and other 

BART-eligible units are held constant at pre-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 both 

boilers with NOx emissions at 0.07 lb/MMBtu (SCR control) and SO2 emissions (DSI control) at 

0.258 lb/MMBtu for Boiler 4 and 0.286 lb/MMBtu for Boiler 5. 

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 BART-eligible source. 

Table 13: 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-

hr 

4 0.90 Rocky 

Mountain 33 --- --- 10 --- --- 

5 0.98 

 

9

 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 – Colorado Energy Nations Company Page 15 

DSI 

4 0.258 National 

Park 

33 29 4 10 7 3 

5 0.286 33 28 5 10 7 3 

Combo 4&5 0.361 

0.392 33 3 30 10 0 10 

Table 14: Visibility Results – SO2 Control Options 

Scenario Boiler(s) 

SO2 Emission 

Rate 

(lb/MMBtu) 

Output (@ 

98th Percentile 

Impact) 

98th Percentile 

Impact 

Improvement 

98th Percentile 

Improvement from 

Maximum 

Cost 

Effectiveness 

(dv) (∆ dv) (%) ($/dv) 

Max 24-

hr 

4 0.90 

1.07 --- --- --- 

5 0.98 

DSI 4 0.258 0.99 0.08 8% $21,802,469 

5 0.286 0.94 0.13 12% $16,752,000 

Combo 4 

5 

0.361 

0.392 0.28 0.79 74% $18,393,225 

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 SO2 emission rates: 

 CENC Boiler 4: 1.0 lb/MMBtu (30-day rolling average) 

 CENC Boiler 5: 1.0 lb/MMBtu (30-day rolling average) 

The state assumes that the BART emission limits can be achieved without additional control 

technology. Although dry sorbent injection does achieve better emissions reductions, the added 

expense of DSI controls were determined to not be reasonable coupled with the low visibility 

improvement afforded. 

B. Filterable Particulate Matter (PM10) 

CENC Boilers 4 and 5 are each equipped with fabric filter baghouses to control PM/PM10

emissions. Baghouses, or fabric filters, operate on the same principle as a vacuum cleaner. Air 

carrying dust particles is forced through a cloth bag. As the air passes through the fabric, the 

dust accumulates on the cloth, providing a cleaner air stream. The dust is periodically removed 

from the cloth by shaking or by reversing the air flow. The layer of dust, known as dust cake, 

trapped on the surface of the fabric results in high efficiency rates for particles ranging in size 

from submicron to several hundred microns in diameter. Additionally, fabric filters are the best 

PM control for western coals, due to the higher electrical resistivity. 

Colorado Operating Permit 96OPJE143 Conditions 3.5 and 4.4 require Boilers 4 and 5 to each 

meet a PM/PM10 emission limit of 0.1 lb/MMBtu. Additionally, Condition 18.1 mandates that 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 16 

each baghouse be equipped with an operating pressure drop measuring device and outlines the 

Continuous Opacity Monitor requirements. 

Table 15 shows the most recent stack test data (August 23, 2007 for Boiler 4 and October 10, 

2007 for Boiler 5). It is important to note that the most recent stack test, which at a minimum, 

occurs every five years in accordance with Colorado Operating Permit 96OPJE143 Condition 

18.2, and more frequently depending on the results, demonstrates that these baghouses are 

meeting >95% control. 

Table 15: CENC 2007 Stack Test Results 

Pollutant Boiler 4 (lb/MMBtu) Boiler 5 (lb/MMBtu) 

Filterable PM10 0.013 0.012 

PM10 Control efficiency 98.4% 98.3% 

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. The current stack test results above 

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 regarding BACT determinations. 

These boilers are subject to National Emission Standards for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, more commonly 

known as the Boiler MACT, which was proposed on June 4, 2010.10 As currently proposed, the 

boilers will be subject to a PM limit of 0.02 lb/MMBtu (monthly average).11

Other commercial EGUs must meet a PM limit of 0.03 lb/MMBtu, so the Division evaluated the 

possibility of tightening the existing PM limit of 0.07 lb/MMBtu on CENC units 4 and 5 based 

on the idea that there may not be any cost associated with a tighter limit. However, compliance 

with the PM limit is demonstrated through periodic performance tests, where compliance is 

unknown until the test results are evaluated. Consequently, a tighter emission limit has the effect 

of increasing the likelihood of non-compliance without any possibility of remedy until after the 

test is complete. This dilemma is further complicated by the presumption that any noncompliance is assumed backward in-time until the last performance test indicating compliance. 

Thus a tighter PM limit has the effect of forcing sources into more frequent performance testing 

to ensure that any unanticipated non-compliance is of shorter duration and thus less costly for 

any associated enforcement actions. Consequently, a tighter emission limit does have an 

associated increase in costs to the source. 

Furthermore, the Division conducted sensitivity analysis of the CALPUFF model for several 

sources that indicated that tightening of PM emissions by 0.07 lb/MMBtu resulted in negligible 

 

10 EPA, 2009. 40 CFR Part 63 [EPA HQ-OAR-2002-058; FRL-RIN 2060-AG69]. National Emission Standards for 

Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. 11 EPA, 2009. 40 CFR Part 63 [EPA HQ-OAR-2002-058; FRL-RIN 2060-AG69]. National Emission Standards for 

Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. 

Pg. 34 – Table 1 – Existing Coal Stoker. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 17 

(less than a tenth to several hundredths of a delta dv) visibility improvement. Since a tighter PM 

emission limit does increase costs and does not result in any appreciable visibility improvement, 

the Division concludes a PM emission limitation of 0.07 lb/MMBtu is appropriate level of 

control that satisfies BART. 

The Division has determined that an emission limit of 0.07 lb/MMBtu (PM/PM10) represents the 

most stringent control option. The units are exceeding a PM control efficiency of 95%, and the 

control technology and emission limits are BART for PM/PM10. 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 CENC Boilers 4 and 5. 

C. Nitrogen Oxide (NOx) 

Step 1: Identify All Available Technologies

CENC identified four NOx control options: 

 Selective catalytic reduction (SCR) 

 Selective non-catalytic reduction (SNCR) 

 Combustion modifications/low-NOx burners (LNB) 

 Low-NOx burners + Separated Overfire Air (LNB+SOFA) 

The Division also identified and examined the following additional control options for these 

units: 

 Electro-Catalytic Oxidation (ECO)® 

 Rich Reagent Injection (RRI) 

 Fuel Switching – Natural Gas 

 Coal reburn +SNCR 

Step 2: Eliminate Technically Infeasible Options

SCR: SCR systems are the most widely used post-combustion NOx control technology. In 

retrofit SCR systems, vaporized ammonia (NH3) injected into the flue gas stream acts as a 

reducing agent. The NOx and ammonia reagent form nitrogen and water vapor. The reaction 

mechanisms are very efficient with a reagent stoichiometry of approximately 1.0 (on a NOx

reduction basis) with very low ammonia slip. 

CENC estimated that the retrofit SCR systems on Boilers 4 and 5 could achieve 0.06 lb/MMBtu. 

The SCR reaction occurs within the temperature range of 600°F to 750°F where the extremes are 

highly dependent on the fuel quality. There are three different types of SCR arrangements – 

high-dust, low-dust, and tail-end. The pre-dominant arrangement applied in the United States 

has been high-dust. In most circumstances, a high-dust SCR system is the most economical 

arrangement alternative and would likely be the arrangement for Units 4 and 5 if applicable. For 

high- and low-dust arrangements, the catalyst, because of its location directly downstream of the 

boiler and upstream of the air heater, can impact the boiler through its effect on the air heater. 

The magnitude of this effect is dependent on the power plant configuration, air quality control 

components, type of fuel, and overall emission control requirements. For retrofit applications, 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 18 

adequate space between the economizer outlet and the air heater inlet to allow boiler outlet and 

air heater return duct is a prerequisite for the installation of a high-dust system and is the case for 

the CENC boilers. Therefore, high-dust SCR is a technically feasible alternative for CENC 

Boilers 4 and 5. 

SNCR/SNCR+LNB/SOFA: Selective non-catalytic reduction is generally utilized to achieve 

modest NOx reductions on smaller units. With SNCR, an amine-based reagent such as ammonia 

or urea is injected into the furnace within a temperature range of 1,600°F to 2,100°F, where it 

reduces NOx to nitrogen and water. NOx reductions of up to 60% have been achieved, although 

20-40% is more realistic for most applications. Reagent utilization, a measure of the efficiency 

with which the reagent reduces NOx, can have a significant impact on economics, with higher 

levels of NOx reduction generally resulting in lower reagent utilization and higher operating cost. 

SCNR is considered a technically feasible alternative for CENC Boilers 4 and 5.

LNB/LNB+SOFA: Low NOx burners are designed to control fuel and air mixing at each burner in 

order to create large and more branched flames. Peak flame temperature is thereby reduced, and 

results in less NOx formation. The improved flame structure also reduces the amount of oxygen 

available in the hottest part of the flame thus improving burner efficiency. Combustion, 

reduction and burnout are achieved in three stages within a conventional low NOx burner. In the 

initial stage, combustion occurs in a fuel rich, oxygen deficient zone where the NOx are formed. 

A reducing atmosphere follows where hydrocarbons are formed which react with the already 

formed NOx. In the third stage internal air staging completes the combustion but may result in 

additional NOx formation. This however can be minimized by completing the combustion in an 

air lean environment. Installing LNB with separated OFA may increase carbon monoxide (CO) 

emissions. LNB/LNB+SOFA are a technically feasible alternative for CENC Boilers 4 and 5. 

Low NOx burners can be combined with other primary measures such as overfire air (OFA) or 

for even greater NOx emission reductions, separated overfire air (SOFA). The SOFA system 

diverts secondary air from the main windbox and injects it into the furnace above the main firing 

zone. This staged combustion process is one of the first principles of aggressive NOx reductions. 

LNB+SOFA is a technically feasible alternative for CENC Boilers 4 and 5. 

ECO®: The Powerspan ECO® system is installed downstream of a coal-fired power plants’ 

existing baghouse. The ECO® Reactor then oxidizes pollutants, which are removed downstream 

in an absorber vessel during cooling and saturation of the flue gas. This technology has not 

been demonstrated on a full-size pulverized coal-fired boiler12 and thus, is considered technically 

infeasible. 

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. Rich reagent 

injection was developed for cyclone boilers13 and has not been demonstrated for other types of 

units. Therefore, RRI is considered technically infeasible for CENC Boilers 4 and 5. 

 

12 Powerspan ECO®: Overview and Advantages, 2000 – 2010. http://www.powerspan.com/ECO_overview.aspx 13 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. http://www.ftek.com/apcRRI.php 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 19 

Coal Reburn + SNCR: Several research and development efforts in the United States evaluated 

using a combination of technologies to reduce NOx emissions, including combining coal reburn 

and SNCR. A novel injection procedure into the fuel-rich, post-combustion zone with staged, 

fuel-rich primary combustion and SNCR injection was found to reduce NOx emissions by 93% 

or well below 0.1 lb/MMBtu14. However, this procedure has not been performed on a full-size 

pulverized coal-fired boiler yet and thus, is considered technically infeasible. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

CENC provided the Division annual average control estimates. In the Division’s experience and 

other state BART proposals,15 30-day NOx rolling average emission rates are expected to be 

approximately 5-15% higher than the annual average emission rate. The Division projected a 

30-day rolling average emission rate increased by 15% for CENC Boilers 4 and 5 to determine 

control efficiencies and annual reductions. 

LNB/LNB+SOFA: CENC estimated that low-NOx burners (Alstom’s Low NOx Concentric Firing 

System (LNCFS) System) are capable of reducing NOx emissions by approximately 10 – 12%, 

which results in annual emission rates of 0.45 and 0.30 lb/MMBtu for Boilers 4 and 5, 

respectively. A similar Colorado facility with installed LNB achieves approximately 0.35 – 0.38 

lb/MMBtu and estimates an additional 20% reduction if OFA is installed to achieve 0.28 – 0.30 

lb/MMBtu. These same burners with Separated Overfire Air were estimated to reduce NOx

emissions by 19 – 35%, resulting in an annualized estimated 0.32 and 0.28 lb/MMBtu for 

Boilers 4 and 5 respectively. 

EPA’s AP-42 emission factor tables estimate low-NOx burners controlling 35 – 55% and LNB 

with OFA controlling 40 – 60% of NOx emissions.16 A recent AWMA study noted that LNB 

with close-coupled OFA firing bituminous coal in tangentially fired boilers achieved, on average, 

35% NOx reduction.17 However, due to the size and configuration (e.g. furnace dimensions) of 

the CENC boilers, the Division concurs that the estimated control efficiency rates are reasonable. 

SNCR/SNCR+LNB/SOFA: CENC noted in the original BART submittal (July 2006) that SNCR 

achieves 30 – 50% control, which is consistent with EPA’s SNCR Air Pollution Control 

Technology Fact Sheet and the Division’s experience. However, when CENC calculated SNCR 

control efficiency in the November 2009 submittal, it was assumed that LNB+SOFA would be 

installed beforehand. CENC estimated that SNCR would reduce NOx emissions 40% with 

LNB+SOFA installed, for resultant emission rates of 0.19 lb/MMBtu and 0.17 lb/MMBtu for 

Boilers 4 and 5, respectively. This equates to 62 – 67% reduction depending on the boiler, which 

 

14 Coal Tech. Corp, 2002. “Tests on Combined Staged Combustion, SNCR & Reburning for NOx Control and 

Combined NOx/SO2 Control on an Industrial & Utility Boilers.” 

http://www.netl.doe.gov/publications/proceedings/04/NOx/summary/h11.50zauderer-summary.pdf 15 State of North Dakota BART Determination for Leland Olds Station Units 1 and 2. Page 16. 16 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 17 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 – Colorado Energy Nations Company Page 20 

is consistent with EPA’s AP-42 emission factor tables (50 – 80%). 18 Therefore, the Division 

concurs with CENC’s control efficiency estimates for LNB+SOFA+SNCR. 

The Division conducted a separate analysis regarding stand-alone SNCR installation (without 

LNB+SOFA installation) for comparison purposes. The Division did not use CENC’s original 

estimate of 40% reduction for SNCR. Instead, the Division estimated control efficiency based 

on a variety of information, including similar Colorado facility estimates, EPA’s SNCR Air 

Pollution Control Fact Sheet and a recent AWMA study19 to conservatively approximate that the 

CENC boilers can achieve 30% control when SNCR is applied. 

SCR: CENC, via their vendor, estimates that each boiler will be able to achieve a 0.06 lb/MMBtu 

emission rate on a 30-day rolling average. CENC estimated control efficiencies on the 

assumption that LNB+SOFA will already be installed. However, this will not change the overall 

SCR resultant emission rate. 

The Division adjusted this emission rate to be 0.07 lb/MMBtu to be consistent with other 

Colorado facility submittals and literature review. This adjusted rate equates to 86% control for 

Boiler 4 and 80% control for Boiler 5. These control efficiencies are consistent with EPA’s AP42 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.20,21

Table 16 summarizes each available technology and technical feasibility for NOx control. 

Table 16: CENC Boilers 4 and 5 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

Low NOx Burners (LNB) 35 – 55% Y

LNB + OFA 40 – 60% Y 

Overfire air (OFA) 10 – 25% (alone) Y

Selective non-catalytic reduction 

(SNCR)

~30 - 50% Y

SNCR+LNB+SOFA ~50 – 80% Y

Selective catalytic reduction (SCR) ~75 – 90% Y

ECO® n/a N

RRI n/a N

Coal reburn +SNCR n/a N

Step 4: Evaluate Impacts and Document Results

 

18 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 19 Srivastava et. al, 2005. Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers. Journal 

of Air & Waste Management Association 55:1367 – 1388. 

20 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 21 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 – Colorado Energy Nations Company Page 21 

Cost of Compliance

LNB/LNB+SOFA: CENC contracted Alstom Power to determine total installed costs for lowNOx burners and separated overfire air. Factors from EPA’s Cost Control Manual were used to 

develop the total annual cost estimate. EPA’s regulations recommend using the EPA’s Office of 

Air Quality Planning and Standards’ Air Pollution Cost Control Manual (Sixth Edition, January 

2002) for estimating costs of compliance. This Manual provides guidance and methodologies for 

developing accurate and consistent estimates of cost for air pollution control devices. The costs 

that may be estimated include capital costs, operation and maintenance (O&M) expenses, and 

other annual costs. 

In reviewing CENC’s estimates, the Division found that the ratio of annual costs to the total 

capital costs for LNB/LNB+SOFA projected by CENC to be slightly higher than those projected 

by other facilities that were amortized over the same 20 year time frame. For example, the 

annualized costs for LNB for Boilers 4 and 5 are 16.1% and 15.5%, respectively, of the total 

capital investment. The EPA found that other facilities in Arizona, New Mexico, and Oregon 

presented annual costs that ranged from 12 – 15% of total capital investments22. However, the 

Division and CENC note that the boilers are much smaller than those examined by the EPA. 

Therefore, the Division concurs with CENC’s cost estimates for LNBs. Further, the Division 

compared recent NESCAUM studies estimating LNB+SOFA for tangentially-fired boilers as 

between $420 - $1,600 per ton NOx reduced.23 Both the original and revised CENC cost 

effectiveness estimates are within the NESCAUM ranges, providing further verification that cost 

estimates are reasonable. The NESCAUM study did not provide cost estimate ranges for LNB 

on tangentially-fired boilers. 

SNCR/SNCR+LNB+SOFA: The difficulty of SNCR retrofit on smaller boilers significantly 

increases, with the primary concern being that there is adequate wall space within the boiler for 

installation of injectors. Movement and/or removal of existing watertubes and asbestos from the 

boiler housing may be required, as in the case of the CENC boilers. 

A typical breakdown of annual for industrial boilers will be 15 – 35% for capital recovery and 65 

– 85% for operating expense.24 The CENC-estimated SNCR costs for operating expenses are 

81% and 86% for Boiler 4 and Boiler 5, respectively. Since SNCR is an operating expensedriven 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 

site-specific 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.25 

 

22 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. 

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

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

24 ICAC, 2000. Institute of Clean Air Companies, Inc. “White Paper: Selective Non-Catalytic Reduction (SNCR) 

for Controlling NOx Emissions.” Washington, D.C. 2000. 25 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 – Colorado Energy Nations Company Page 22 

The cost effectiveness for SNCR on Boilers 4 and 5 is about $2,900 and $3,350 per ton, 

respectively. Recent NESCAUM studies estimate SNCR retrofits on tangentially fired boilers 

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.26,27 EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NOx

reduced. 28 Although CENC’s estimates are greater than these ranges, the small size of the 

boilers as well as the difficulty of the retrofit leads the Division to the conclusion that CENC’s 

cost estimates for SNCR are reasonable. 

SCR: CENC contracted Lutz, Daily, & Brain (LDB) to develop a capital cost estimate. On both 

boilers, it was determined that the economizers must be moved because there is very little space 

between the air heater outlet and the current economizer configuration, adding to the capital cost. 

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.29,30

CENC’s cost estimates are higher than this range, but the small size of the boilers as well as the 

difficulty of the retrofit leads the Division to the conclusion that CENC’s cost estimates for SCR 

are reasonable. 

Table 17, Table 18, Table 19, and Table 20 depict controlled NOx emissions and control cost 

comparisons.

Table 17: CENC Boiler 4 Control Resultant NOx Emissions 

Alternative Control 

Efficiency 

(%)

Resultant Emissions

Annual 

Emissions 

(tons/year)

Annual 

Average 

(lb/MMBtu)

30-day 

Rolling 

Average 

(lb/MMBtu)

Annual 

Average 

(lb/hour)

30-day 

Rolling 

Average 

(lb/hour)

Baseline --- 599 0.50 179

LNB 10 539 0.45 0.515 161 185

SNCR 30 420 0.35 0.400 125 144

LNB+SOFA 35 390 0.32 0.372 116 134

SNCR+LNB+SOFA 61 231 0.192 0.221 69 79

SCR 86 84 0.070 0.080 25 29

 

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

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

27 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. 

28 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 29 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

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

30 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. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 23 

Table 18: CENC Boiler 5 Control Resultant NOx Emissions 

Alternative Control 

Efficiency 

(%)

Resultant Emissions

Annual 

Emissions 

(tons/year)

Annual 

Average 

(lb/MMBtu)

30-day 

Rolling 

Average 

(lb/MMBtu)

Annual 

Average 

(lb/hour)

30-day 

Rolling 

Average 

(lb/hour)

Baseline --- 691 0.34 165

LNB 7 643 0.32 0.368 153 176

LNB+SOFA 18.5 563 0.28 0.322 134 155 

SNCR 30 484 0.24 0.277 115 133

SNCR+LNB+SOFA 51 337 0.17 0.193 80 93

SCR 79.6 141 0.07 0.081 34 39

Table 19: CENC Boiler 4 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

LNB 59.9 $193,433 $3,227 $54

SNCR 179.8 $694,046 $3,860 $5

LNB+SOFA 209.8 $678,305 $3,234 -$21

SNCR+LNB+SOFA 368.0 $1,372,351 $3,729 $3

SCR 515.4 $4,201,038 $8,150 $30

Table 20: CENC Boiler 5 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

LNB 48.4 $249,858 $5,166 $107

LNB+SOFA 127.3 $815,829 $6,383 $15 

SNCR 207.3 $923,996 $4,458 ($24)

SNCR+LNB+SOFA 353.7 $1,739,825.3 $4,918 $3

SCR 550.0 $6,469,610 $11,764 $35

Energy and Non-Air Quality Impacts

LNB/LNB+SOFA: Installing LNB with separated OFA may increase unburned carbon in the ash, 

commonly referred to as loss on ignition (LOI). Otherwise, there are no known non-air quality 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 24 

impacts associated with low-NOx burners and separated overfire air systems. Energy impacts are 

not significant. Thus, this factor does not influence the selection of this control. 

SNCR/SNCR+LNB+SOFA/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 such as SNCR do increase power needs, in the case 

of the CENC boilers, 90 kW per hour, or enough energy to power about 9 homes for a year, 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 in some cases. 

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. For CENC Boilers 4 and 5, the estimated 

pressure drop across the catalyst is 7 to 8 inches water column and the total energy consumption 

is approximately 1,000 kW per hour, or enough energy to power about 100 homes for a year. 

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. CENC has indicated to the Division that they would prefer to use urea instead if 

applicable to ensure personnel and surrounding community safety, and based the capital and 

operating costs of a SCR system on a urea reagent versus an ammonia reagent. Refer to “CENC 

BART Submittals” for more information. 

Remaining Useful Life

CENC asserts that there are no near-term limitations on the useful of these boilers, so it can be 

assumed that they will remain in service for the 20-year amortization period. 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 21 shows the number of days pre- and 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 25 

post-control. Table 22 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 protocol31, 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 and other 

BART-eligible units are held constant at pre-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 both 

boilers with NOx emissions at 0.07 lb/MMBtu (SCR control) and SO2 emissions at 0.258 

lb/MMBtu for Boiler 4 and 0.286 lb/MMBtu for Boiler 5. 

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 BART-eligible source. 

Table 21: 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-hr 

4 0.67 

Rocky 

Mountain 

National 

Park 

33 --- --- 10 --- --- 

5 0.66 

LNB 

4 0.45* n/a 

5 0.30* n/a 

SNCR 

4 0.35* n/a 

5 0.24* n/a 

LNB+SOFA 4 0.32 33 27 6 10 7 3 

NOx Modeled Rate 5 0.28 33 25 8 10 6 4 

LNB+SOFA 5 0.24* n/a 

LNB+SOFA+SNCR 

4 0.19 33 27 6 10 7 3 

5 0.17 33 19 14 10 6 4 

SCR @ 0.07 

lb/MMBtu 4 0.07 33 25 8 10 6 4 

SCR @ 0.07 

lb/MMBtu 5 0.07 33 19 14 10 6 4 

 

31 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 – Colorado Energy Nations Company Page 26 

Combo 

4 0.07 

33 3 30 10 0 10 

5 0.07 

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

Modeling Summary” for more details. 

Table 22: 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 

Improvement 

from 

Maximum 

Cost 

Effectiveness 

(dv) (∆ dv) (%) ($/dv) 

Max 24-hr 

4 0.67 

1.07 --- --- --- 

5 0.66 

LNB 

4 0.45* 1.02 0.05 5% $3,868,660 

5 0.30* 0.89 0.17 16% $1,435,965 

SNCR 4 0.35* 0.99 0.07 7% $9,507,477 

5 0.24* 0.86 0.21 20% $4,358,471 

LNB+SOFA 4 0.32 0.99 0.08 7% $8,478,816 

NOx Modeled Rate 5 0.28 0.88 0.18 17% n/a 

LNB+SOFA 5 0.24* 0.86 0.21 20% $3,848,252 

LNB+SOFA+SNCR 4 0.19 0.96 0.11 10% $12,475,919 

5 0.17 0.82 0.25 23% $7,101,328 

SCR @ 0.07 

lb/MMBtu 4 0.07 0.89 0.18 17% $23,734,677 

SCR @ 0.07 

lb/MMBtu 5 0.07 0.75 0.31 29% $20,669,680 

Combo 

4 0.07 

0.28 0.79 74% $18,393,225 5 0.07 

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

Modeling Summary” for more details. 

Step 6: Select BART Control

The Division and CENC worked together to determine a “flexible” BART option for Boilers 4 

and 5. CENC initially proposed this option in its’ prehearing statement on September 15, 2010. 

This option incorporates both an individual limit (lb/MMBtu) for each boiler or a combined 

average (lbs/hr) for both boilers for a 30-day rolling average period. CENC submitted 

supplemental information regarding a “flexible” BART plan on October 19, 2010 to the 

Division, citing the preamble to the BART regulations to ‘consider allowing sources to ‘average’ 

emissions across any set of BART-eligible emission units within a fencline, so long as the 

emission reductions from each pollutant being controlled for BART would be equal to those 

reductions that would be obtained by simply controlling each of the BART-eligible source.” 

This determination adheres to the language in the BART preamble. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – Colorado Energy Nations Company Page 27 

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

NOx BART for Boiler 4 is the following NOx emission rates: 

 CENC Boiler 4: 0.37 lb/MMBtu (30-day rolling average) 

or 

0.26 lb/MMBtu Boiler 4 and Boiler 5 combined average (30-day 

rolling average) 

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

operation of low NOx burners with separated over-fire air. Although the other alternatives 

achieve better emissions reductions, achieving lower limits through different controls was 

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

visibility improvement afforded. 

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

NOx BART for Boiler 5 is the following NOx emission rates: 

 CENC Boiler 5: 0.19 lb/MMBtu (30-day rolling average) 

 or 

 0.26 lb/MMBtu Boiler 4 and Boiler 5 combined average (30-day 

rolling average) 

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

operation of low NOx burners with separated over-fire air and selective non-catalytic reduction. 

For the emission limits above, the cost per ton of emissions removed, coupled with the estimated 

visibility improvements gained, falls within the guidance criteria discussed in section 6.4.3 of the 

Regional Haze State Implementation Plan. 

• Boiler 5: $4,918 per ton NOx removed; 0.26 deciview of improvement 

The dollars per ton control cost, coupled with notable visibility improvements, leads the state to 

this determination. Though SCR achieves better emissions reductions, achieving lower limits 

through SCR was determined to not fall into the guidance cost and visibility improvement 

criteria discussed in section 6.4.3 of the Regional Haze State Implementation Plan.