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

Reasonable Progress Analysis – CENC Page 1 

Reasonable Progress (RP) Four-Factor Analysis of Control Options 

For 

Colorado Energy Nations, Golden, Colorado 

I. Source Description

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

 Colorado Energy Corporation) 

Source Type: Steam Generating Unit 

Boiler Type(s): Boiler 1 – Natural Gas Front-Fired 

 (SCC: 10200601 for natural gas) 

 Boiler 2 – Natural Gas Front-Fired 

 (SCC: 10200601 for natural gas) 

 Boiler 3 – Pulverized Coal Spreader Stoker 

 (SCC: 10200224) 

 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 and US Highway 58 

borders the northern side of the CENC site. 

Figure 1: CENC facility Aerial Perspective 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 2 

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 operate 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 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. 

For this analysis, the Division also relied on the existing Title V permit, historical 

information regarding the CENC facility, and information about similar facilities 

to determine RP for NOx, SO2, and PM10. EPA’s BART guidelines recommend 

that states utilize a five step process for determining BART for EGU sources 

above 750 MW. Although this five step process is not required for making 

Reasonable Progress (RP) determinations, the Division has elected to largely 

follow it in RP. This is for ease of reference, and because the statutory factors 

that must considered in making BART and RP determinations are largely the 

same. 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. 

Therefore, these two boilers have been evaluated for BART, which the Division 

has determined meets the requirements of RP at this time. 

The Division has elected to set a de minimis threshold for actual baseline 

emissions for evaluating reasonable progress units at each facility equal to the 

federal Prevention of Significant Deterioration levels. The Division defines 

“unit” as an Air Pollutant Emission Notice (APEN) subject source, or a stationary 

source, defined as “any building, structure, facility, equipment, or installation, or 

any combination thereof belonging to the same industrial grouping that emit or 

may emit any air pollutant subject to regulation under the Federal Act that is 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 3 

located on one or more contiguous or adjacent properties and that is owned or 

operated by the same person or by persons under common control1 .” 

 These levels are as follows: 

• NOx – 40 tons per year 

• SO2 – 40 tons per year 

• PM10 – 15 tons per year 

Boiler 3 is considered by the Division to be eligible for the purposes of 

Reasonable Progress, being an industrial boiler with the potential to emit 40 tons 

or more of haze forming pollution (NOx, SO2, PM10) at a facility with a Q/d 

impact greater than 20. CENC submitted a “Reasonable Progress Control 

Evaluation” on May 7, 2010 as well as additional relevant information on 

February 8, 2010. Table 1 depicts technical information for Boiler 3 at the CENC 

facility. 

Table 1: CENC Boiler 3 RP-eligible Emission Controls and Reduction (%) 

 Unit B003 

Placed in Service 1962; updated to coal in 1981 

Boiler Rating, MMBtu/Hr for 

coal 225 

Electrical Power Rating, Gross 

Megawatts 24 

Description 

Combustion Engineering Model 

CE-VU40 225 MMBtu/hr (coal), 

traveling grate stoker, firing only 

coal for primary fuel and fuel 

oil/coal for a cold start 

Air Pollution Control Equipment Carter Day fabric filter baghouse 

with 4 compartments 

Emissions Reduction (%) 

NOx – None 

SO2 – None 

PM/PM10 – 93+% 

 

II. Source Emissions

CENC estimated that a realistic depiction of annual emissions for Boiler 3, or 

“Baseline Emissions” was the years 2006 – 2008. CENC determined that the 

maximum year within this scope was 2006, since it had the highest capacity factor 

and heat input. 

Table 2 summarizes the NOx, SO2, and PM actual emissions averaged over the 

2006 – 2008 timeframe for the facility. Table 3 summarizes each unit at the 

facility and applicable NOx, SO2, and PM10 actual emissions averaged over the 

2006 – 2008 timeframe with data from Colorado’s Air Pollutant Emission Notices 

 1

 Colorado Department of Public Health and Environment. Air Quality Control Commission Common 

Provisions Regulation 5 CCR 1001-2. Amended December 17, 2009. Effective January 30, 2010. Page 

19. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 4 

submitted by the facility and as applicable, EPA’s CAMD Database (Boilers 4 

and 5). 

Table 2: Summary of 2006 - 2008 Averaged Emissions – CENC Facility 

NOx (tons/year) SO2 (tons/year) PM10 (tons/year) 

1,512 2,433 38 

Table 3: Summary of 2006 - 2008 Averaged Emissions by Unit - CENC Facility 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

Boiler #1 

(288 MMBtu/hour – 

natural gas fired) 

SO2 (tons) 0.1 0.1 0.1 0.1 

SO2 (lb/ MMBtu) 0.00 0.00 0.00 0.00 

NOx (tons) 30.8 23.9 30.3 28.3 

NOx (lb/ MMBtu) 0.02 0.02 0.02 0.02 

PM10 (tons) 0.8 0.7 0.8 0.7 

PM10 (lb/ MMBtu) 0.00 0.00 0.00 0.00 

Boiler # 2 

(288 MMBtu/hour – 

natural gas fired) 

SO2 (tons) 0.1 0.0 0.1 0.1 

SO2 (lb/ MMBtu) 0.00 0.00 0.00 0.00 

NOx (tons) 32.4 10.4 27.6 23.5 

NOx (lb/ MMBtu) 0.03 0.01 0.02 0.02 

PM10 (tons) 0.9 0.3 0.7 0.6 

PM10 (lb/ MMBtu) 0.00 0.00 0.00 0.00 

Boiler #3 

(225 MMBtu/hour – 

coal fired) 

SO2 (tons) 264 205 267 245 

SO2 (lb/ MMBtu) 0.27 0.21 0.27 0.25 

NOx (tons) 185 150 170 168 

NOx (lb/ MMBtu) 0.19 0.15 0.17 0.17 

PM10 (tons) 2.3 1.9 2.1 2.1 

PM10 (lb/ MMBtu) 0.00 0.00 0.00 0.00 

Boiler #4 – 

(360 MMBtu/hour – 

coal fired) 

SO2 (tons) 764 815 763 781 

SO2 (lb/ MMBtu) 0.48 0.52 0.48 0.49 

NOx (tons) 637 589 575 600 

NOx (lb/ MMBtu) 0.40 0.37 0.37 0.38 

PM10 (tons) 10.9 10.0 10.4 10.4 

PM10 (lb/ MMBtu) 0.01 0.01 0.01 0.01 

Boiler #5 – 

(650 MMBtu/hour – 

coal fired) 

SO2 (tons) 1,598 1,333 1,289 1,407 

SO2 (lb/ MMBtu) 0.56 0.47 0.45 0.49 

NOx (tons) 900 614 559 691 

NOx (lb/ MMBtu) 0.32 0.22 0.20 0.25 

PM10 (tons) 21 17 16 18 

PM10 (lb/ MMBtu) 0.01 0.01 0.01 0.01 

P005 – Coal Unloading 

and Conveying PM10 (tons) 0.03 0.03 0.03 0.03 

P007 – Boiler #5 Silos – 

coal conveyor to Unit 5 

silos PM10 (tons) 0.00 0.00 0.00 0.00 

P008 – Ash Handling – 

11, 12, 13 – general ash 

silo PM10 (tons) 5.57 5.57 5.38 5.51 

P009 – Boiler #3 Silos – 

coal conveyor to Unit 5 

silos PM10 (tons) 0.00 0.00 0.00 0.00 

P010 – Ash Handling – 

Boiler #4 & #5 fly ash PM10 (tons) 0.02 0.02 0.02 0.02 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 5 

collection 

P011 – Ash Handling –

Fly ash silo loadout PM10 (tons) 0.00 0.00 0.00 0.00 

P012 – Ash Handling – 

Fly ash silo bin vent PM10 (tons) 0.00 0.00 0.00 0.00 

P013 – Diesel Air 

Compressors – GM diesel 

engine for backup 

operation of air 

compressor 

SO2 (tons) 0.00 0.00 0.00 0.00 

NOx (tons) 0.00 0.00 0.00 0.00 

PM10 (tons) 0.00 0.00 0.00 0.00 

*The above emissions are for the most recent three years (2006 – 2008). These emissions are an 

annual average. 30-day rolling averages are estimated to be 5-15% higher than the annual average 

emission rate (i.e. the 30-day NOx rolling average is likely about 0.44 lbs/MMBtu for Boiler 4 and 0.29 

lbs/MMBtu for Boiler 5). 

Units italicized in Table 3 are less than de minimis thresholds and will not be 

evaluated further for the purposes of reasonable progress. 

Boiler 3 currently has grandfathered status for State construction permits. This boiler 

is included in the current Title V permit, but does not currently have fuel usage or 

emission limitations for NOx, PM, or SO2. This boiler is subject to opacity 

requirements under Colorado Regulation No. 1, Section II.A.1 and a sulfur dioxide 

limit of 1.8 lbs/MMBtu when burning coal. Boiler 3 has a PM emission rate limit of 

0.122 lbs/MMBtu and is controlled with a baghouse that was installed in the early 

1980s. In addition to not utilizing a CEMS, a sophisticated automatic Data 

Acquisition System for control parameters, such as fuel usage, is not installed. The 

actual NOx emissions is based on AP-42 factors applicable to the coal type 

(bituminous, sub-bituminous, etc.) and coal usage based on rail car / truck unloading 

records. This AP-42 factor has a B-rating and may be subject to change in the future. 

Unit 3 is a base-loaded boiler. It’s load range varies from the low end (plant 

reliability—ready to respond in the event of a malfunction in Unit 4 or Unit 5), 

medium loads (increased customer steam loads) to high loads (i.e., during Unit 4 or 

Unit 5 overhauls). The load range varies within the month, and has patterns 

throughout the year. Therefore, the Division believes that a baseline period of 2000 

– 2008 is warranted for CENC Boiler 3 due to the factors listed above. The baseline 

emissions for Boiler 3 are further detailed in Table 4 

Table 4: CENC Unit 3 Detailed Baseline Emissions 

Pollutant Unit 3 (2000 – 2008) 

Annual Emissions* (tpy) Annual Emissions** (lb/MMBtu) 

NOx 205 0.21 

SO2 257 0.26 

PM10 2 0.037*** 

*Using most recent three calendar years (Division APEN data). 

**The Division calculated annual average rate (lb/MMBtu) from the most recent three calendar 

years, the maximum heat input and annual operating hours. 

***The PM10 emission rate is determined from the last Title V permit compliance stack test 

(August 24, 2007). 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 6 

III. Units Evaluated for Control

 

As documented by CENC, this boiler fires low sulfur, high heating value 

bituminous coal from western Colorado. The specifications for the coal are listed 

in Table 5. 

Table 5: Coal Specifications (2006 – 2008 Averaged APEN data) 

 Specifications 

Emission Unit Fuel Heating Value 

(Btu/lb) 

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

B003 12,541 0.42 8.38 

Table 1 lists the units at Colorado Energy Nations Golden Facility that the 

Division examined for control to meet reasonable progress requirements. 

Controlled and uncontrolled emission factors and APEN data were used to 

evaluate the control effectiveness of the current emission controls. Uncontrolled 

emission factors are outlined in Table 6. 

Table 6: Uncontrolled emission factors for CENC Boilers 

Emission Unit Pollutant 

Fuel 

Coal (bituminous) (lb/ton) 

Boiler 32

NOx 11 

SO2 38 x %S = 16.0* 

PM/PM10 PM – 66 

PM10 – 13.2 

*%S = % of sulfur present in coal supply. For example, 38 x 0.42 = 16.0 

**%A = % of ash present in coal supply. For example, 10 x 8.39 = 83.9 

It is worth noting that although Boiler 3 was on-line the majority of the time, it 

ran at reduced capacity due to production requirements, demonstrated in Table 7. 

Table 7: Boiler 3 Baseline Capacity Factor 

Heat Input (HI) (MMBtu/year) 

Potential HI 1,971,000 B3 % Potential-HI 

2006 874,569 44.37% 

2007 711,157 36.08% 

2008 805,320 40.86% 

Average 797,015 40.44% 

IV. Reasonable Progress Evaluation of Boiler 3

a. Sulfur Dioxide 

Step 1: Identify All Available Technologies 

CENC identified five SO2 control options: 

Flue gas desulfurization (FGD): 

 Lime or limestone-based (wet FGD) 

 2

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

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 7 

 Lime spray dry absorber (SDA or dry FGD) 

Dry sorbent injection – Trona (DSI) 

Fuel switching – different coal type 

Fuel switching – natural gas 

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 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 plants3. 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 Technologies4 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 

 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. 

4 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

Reasonable Progress Analysis – CENC Page 8 

 bound the facility to the north and east. Table 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 Boiler 3, a SDA vessel for each boiler, not including other 

 associated equipment, would be approximately 27 feet in diameter by 47 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 Boiler 

 3. 

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

 feasibility of potential SO2 controls on Units 4 and 5. It can be reasonably 

 assumed that this visit also applies to Unit 3. The Division noted: 

• 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 Boiler 3. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 9 

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

Reasonable Progress Analysis – CENC Page 10 

 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, DSI-Trona is technically feasible 

 for the CENC facility Boiler 3. 

Fuel Switching – Different Coal Type: CENC asserts that the facility already 

utilizes low sulfur, high heating value bituminous coal from western Colorado. 

Typically, the coal contains only about 0.43 percent sulfur with a heating value of 

12,100 Btu/lb and potential SO2 emissions of 0.73 lb/MMBtu. The sulfur content 

of CENC’s Colorado coal rivals the low sulfur properties of Powder River Basin 

(PRB) coal from Wyoming, and therefore, it represents the lowest sulfur coal 

available. Any shift from the purchase of local Colorado coal would have an 

adverse effect on Colorado mining and transportation industries. 

Additionally, CENC notes that PRB coal is extremely dusty to handle, being 

much more friable than the Colorado coal presently used) and it generates dust 

through weathering much more quickly than bituminous coal. PRB coal also is 

subject to spontaneous combustion in and around material handling systems and 

silos. The generation of fugitive dust and periodic spontaneous combustion is a 

tremendous issue at a site such as a Coors Brewery, which precludes conversion 

to PRB coal. Therefore, a change in coal supply is not a feasible RP control 

option. 

Fuel Switching – Natural gas: Natural gas offers some operating and maintenance 

advantages. The use of natural gas would eliminate coal handling and baghouse 

operating and maintenance labor as well as ash handling and disposal. Natural 

gas fuel switching is a feasible option for CENC Boiler 3. 

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 

 Boiler 3 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. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 11 

 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 submittals5

 and to be conservative since this technology is relatively 

 novel. 

Fuel Switching – Natural Gas: Conversion from coal to natural gas would reduce 

SO2 emissions by almost 100% from each unit using EPA’s AP-42 emission 

factors6

 and concurs with CENC’s submittal.

Table 8 summarizes each available technology options and technical feasibility 

for SO2 control on CENC Boiler 3. 

Table 8: CENC Boiler 3 SO2 Technology Options and Technical Feasibility 

Technology Emission Reduction Potential (%) Technically Feasible? 

(Y = yes, N = no) 

Wet FGD 52-98%, median 90%7 Y 

Dry FGD 70 – 90% (CENC) N 

DSI (Trona) ≤65% (CENC) Y 

Fuel switching – 

different coal type 

minimal (CENC) N 

Fuel switching – 

natural gas 

99% (EPA AP-42) Y 

Step 4: Evaluate Factors and Present Determination 

Factor 1: Cost of Compliance

CENC submitted cost estimates for DSI and natural gas fuel switching for Boiler 

3 on May 7, 2010. 

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 Boiler 3. 

 5

 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. 

6

 AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.4, Table 1.4-2. 

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf 7

 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

Reasonable Progress Analysis – CENC Page 12 

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 RP 

APCD Technical Analysis”. 

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

in size that analyzed DSI. 

Table 9: DSI Cost Comparisons 

Facility & Unit Size 

(MW) 

Annualized Costs 

($/year) 

Cost Effectiveness 

($/ton) 

Ratio 

($/kW) 

Colorado Energy Nations – 

Boiler 3 

24 $1,340,661 $9,114 $55.86 

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 

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.8

 CENC Boiler 3 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. 

Fuel Switching – Natural Gas: The Division used EPA’s Cost Control Manual9 to 

estimate annual operating costs, of approximately $25,000 per ton of SO2

 8

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

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

9

 EPA, 2002. EPA Air Pollution Control Cost Manual, Sixth Edition. Office of Air Quality Planning and 

Standards, Research Triangle Park, North Carolina, 27711. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 13 

removed annually for Boiler 3 at the CENC facility.10 However, it should be 

noted that natural gas prices vary significantly; the Division used 2008 

commercial natural gas prices reported by the U.S. Energy Information 

Administration11 to determine natural gas costs. Therefore, the Division concurs 

that the natural gas estimates submitted by CENC on May 7, 2010 to be 

reasonable. 

In the February 8, 2010 submittal, CENC notes that the fuel is the largest steam 

production cost incurred by CENC, and stresses the variability in natural gas 

prices. CENC also emphasized the added negative Colorado economic impact in 

that CENC coal is purchased from Colorado mines, which may be offset by the 

natural gas purchases also from Colorado-based corporations. The use of natural 

gas would eliminate pulverizer and baghouse operating and maintenance costs as 

well as ash handling and disposal costs. Other boiler maintenance costs would be 

reduced if coal was not burned. 

Table 10: CENC Unit 3 Resultant SO2 Emissions 

Alternative 

Control 

Efficiency 

(%) 

Resultant Emissions 

Annual 

Emissions 

(tons/year) 

Annual Average 

(lb/MMBtu) 

30-day Rolling 

Average 

(lb/MMBtu) 

Baseline --- 257 0.260 0.273 

DSI - Trona 60 103 0.104 0.109 

Fuel Switching - 

Natural Gas 100 0 0.000 0.000 

Table 11: CENC Unit 3 SO2 Cost Comparison 

Alternative Emissions 

Reduction (tpy) 

Annualized 

Cost ($) 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

Baseline 0 $0 $0 --- 

DSI - Trona 154 $1,340,661 $8,709 $57 

Fuel Switching - 

Natural Gas 257 $1,428,911 $5,569 -$31 

Factor 2: Time Necessary for Compliance

In the May 7, 2010 submittal, CENC notes that due to the gross estimate of this 

 evaluation, compliance time must include a more extensive study of the control 

 10 Colorado Air Pollution Control Division Technical Analysis – CENC RP APCD Technical Analysis, 

2010. 

11 U.S. Energy Information Administration, 2010. 

http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 14 

 options and their technical feasibility. It is anticipated that if controls were 

 required, at least five years after SIP approval would be needed to perform this 

 study, work with the Division regarding the final options, incorporate the 

 decision, and finally initiate and complete the construction process. 

Factor 3: 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 domestic, agricultural and industrial demands. 

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 Regional Haze 

 program. The Division largely focused its RP 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 the negative environmental impacts of a traditional wet FGD 

 control system far outweigh minimal incremental SO2 emission reduction benefits 

 (tons of SO2 reduced annually) and visibility improvement (deciview 

 improvement at nearest Class I area) when applied to this small boiler at the 

 CENC facility (Boiler 3). 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 15 

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,12 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. 

 Fuel Switching – Natural Gas: Fuel switching to natural gas does not have any 

 significant energy or non-air quality related impacts. Thus, this factor does not 

 influence the selection of this control. 

Factor 4: Remaining Useful Life

 CENC asserts that there are no near-term limitations on the useful of this boiler, 

 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. 

Factor 5 (optional): Evaluate Visibility Results

The Division conducted CALPUFF modeling to determine the projected visibility 

improvement associated with various control technologies for Boilers 4 and 5 at 

the CENC facility. The projected visibility improvements attributed to DSI are 

outlined in Table 12. CALPUFF modeling indicates a 0.08 Δdv for DSI applied 

to Boiler 4 (360 MMBtu/hr). DSI controls for Boiler 4 would reduce SO2

emissions by approximately 268 tons per year. DSI controls for Boiler 3 would 

reduce SO2 emissions by about 147 tons per year. Fuel switching to natural gas 

would reduce SO2 emissions by an estimated 245 tons annually. Consequently, it 

is reasonable to infer, based on scaling, that either control applied to Boiler 3, a 

smaller boiler at the same site (225 MMBtu/hr), would yield model results much 

less than 0.10 Δdv. 

 12 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

Reasonable Progress Analysis – CENC Page 16 

Table 12: CENC Boiler 4 SO2 Modeling Results 

SO2 Control 

Method 

CENC - Boiler 4 

Emission 

Reduction 

(tpy) 

SO2 Annual Emission Rate 

(lb/MMBtu) 

98th Percentile Impact 

(Δdv) 

Daily Maximum 

(3-yr) --- 0.90 --- 

DSI - Trona 268 0.26 0.08 

Determination

Table 13 illustrates fuel analysis from 2000 – 2010. The Division believes a 20% 

contingency factor is warranted for CENC Boiler 3 due to the factors listed on 

page 5. Based on Table 13, the maximum SO2 emissions from the past decade 

(2000 – 2010) is 0.99 lb/MMBtu. With the uncertainty factor, the Division 

believes that a 1.2 lb/MMBtu is appropriate for RP. 

Table 13: CENC Boiler 3 Coal Supply SO2 Limit Support 

2000-

2006 

2006-

2008 

2009-

2010 

Minimum Btu/lb 11,068 11,221 11,444 

Maximum % Sulfur 0.55 0.55 0.57 

Theoretical lb/MMBtu... 

Maximum B3 Conversion Sulfur to SO2 (using fuel 

analysis) 

0.99 0.98 0.99 

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

 determined that SO2 RP is the following SO2 emission rate: 

CENC Boiler 3: 1.2 lb/MMBtu 

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 (<< 0.10 dv) afforded. 

b. Filterable Particulate Matter (PM and PM10) 

 CENC Boiler 3 is 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 Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 17 

 Colorado Operating Permit 96OPJE143 Condition 2.2 requires Boiler 3 to comply 

 with State Regulation No. 1 where the PM/PM10 emission limit is calculated from 

 the equation PE = 0.5(FI)-.0.26, where PE= Particulate Emissions in lbs/MMBtu 

 and FI = Fuel input in million Btu per hour. Additionally, Condition 18.1 

 mandates that each baghouse be equipped with an operating pressure drop 

 measuring device and outlines the Continuous Opacity Monitor requirements. 

 Table 14 shows the most recent stack test data (August 24, 2007). 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 >90% control. 

Table 14: CENC 2007 Stack Test Results 

Pollutant Boiler 3 (lb/MMBtu) 

Filterable PM10 0.037 

PM10 Control efficiency 93.0% 

 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. Refer to “Division RBLC Analysis” for more 

 details regarding BACT determinations. 

 This boiler is 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, 2010.13 As currently proposed, the boiler will be subject to a 

 PM limit of 0.02 lb/MMBtu (monthly average).14

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 non-compliance is assumed backward in-time until the last 

performance test indicating compliance. Thus a tighter PM limit has the effect of 

 13 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. 

14 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

Reasonable Progress Analysis – CENC Page 18 

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 (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 state has determined that an emissions limits of 0.07 lb/MMBtu 

(PM/PM10 represents the most stringent control option. The unit is exceeding 

a PM control efficiency of 90%, and the control technology and emission 

limit is RP for PM/PM10. The state assumes that the RP emission limit can be 

achieved through the operation of the existing fabric filter baghouse. 

c. Nitrogen Oxides (NOx) 

Step 1: Identify All Available Technologies 

 CENC, using a similar unit’s NOx analysis15, identified eight potential NOx

 control options: 

 Flue Gas Recirculation (FGR) 

 Low-temperature Oxidation System (LoTOx) 

 Selective Non-Catalytic reduction (SNCR) 

 Rotating Over-Fire Air w/ Rotamix (ROFA) 

 Fuel switching – different fuel type (natural gas) 

 Regenerative Selective Catalytic Reduction (RSCR) 

 High Temperature Selective Catalytic Reduction (HT SCR) 

 Low Temperature Selective Catalytic Reduction (LT SCR) 

 The Division also identified and examined the following additional control option 

 for this unit: 

 Electro-Catalytic Oxidation (ECO)® 

 Rich Reagent Injection (RRI) 

 Coal reburn +SNCR 

Step 2: Eliminate Technically Infeasible Options 

Flue Gas Recirculation (FGR): FGR technology extracts up to 20 to 30% of the 

flue gas from downstream of the economizer, air heater, or particulate control 

equipment, and is mixed into the combustion inlet air duct. The amount of FGR 

 15 “Black Hills Clark Station NOx Reduction Feasibility Study” BH Clark Station Unit 1. Prepared by 

CH2MHill. December 2009. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 19 

that is achievable is determined by a boiler’s operating characteristics and the 

ability to mix with primary air to allow for good fuel bed combustion stability. 

Flue gas recirculation is considered technically feasible for CENC Boiler 3. 

LoTOx System: The LoTox system has the potential of significant NOx reduction; 

however, the process requires operation in conjunction with a wet scrubber. 

CENC does not currently have a wet scrubber in service, has a limited footprint in 

which to locate a wet scrubber, and the Division has determined that wet 

scrubbers are not being considered for this facility due to non-air and energy 

impacts. Therefore, the LoTOx alternative is not considered due to the 

determination regarding wet scrubbers. 

SNCR: 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 

Boiler 3. 

ROFA: Nalco Mobotec markets ROFA as an improved second generation OFA 

system. ROFA® injects air into the furnace first to break up the fireball and then 

to create a cyclonic gas flow to improve combustion. ROFA® differs from OFA 

in that ROFA® utilizes a booster fan to increase the velocity of air to promote 

mixing and to increase the retention time in the furnace. Nalco Mobotec offers 

the ROFA system as a stand-alone installation, or with the Rotamix feature. 

Rotamix is Nalco Mobotec’s version of SNCR technology, and ammonia is 

injected into the ROFA airstream. ROFA is considered technically feasible for 

CENC Boiler 3. 

Fuel switching – different fuel type (natural gas): Natural gas reburning 

technology is a staged fuel approach using an expanded volume of the furnace to 

control NOx production, rather than only within the flame envelope, also referred 

to as Methane de-NOx. The primary solid fuel combustion delivery and boiler 

location remains the same, and for the case of CENC Boiler 3 this is currently 

assumed to occur on the traveling fuel grate. The secondary fuel introduction 

point is after the primary fuel burn zone, in a fuel-rich reaction zone (the reburn 

zone). While other fuels may be used in the reburning zone, natural gas is most 

common and NOx reductions of 30-70% may be feasible. Higher removals are 

associated with longer boiler residence times. Therefore, 50% was used for the 

analysis due to the relatively short boiler at CENC (similar to Black Hills Clark 

Station Unit 1). Natural gas fuel switching is considered a technically feasible 

alternative for CENC Boiler 3. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 20 

RSCR/HT SCR/LT 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 a retrofit SCR system on Boiler 3 could achieve 0.024 

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. CENC 

evaluated three types of SCR for this analysis – regenerative SCR, hightemperature SCR, and low-temperature SCR. These three different options were 

evaluated because of the potential variable inlet temperature on a spreader stoker 

boiler such as Unit 3. Regenerative SCR notably may not achieve the same 

reductions as the other two SCR options, but regardless was evaluated. All three 

SCR options – RSCR, HTSCR, and LTSCR – are considered technically feasible 

for CENC Boiler 3. 

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 fullsize pulverized coal-fired boiler16 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 boilers17 and has not been demonstrated for other types of units. 

Therefore, RRI is considered technically infeasible for CENC Boiler 3. 

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/MMBtu18. However, this procedure has not been performed on a full-size 

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

 16 Powerspan ECO®: Overview and Advantages, 2000 – 2010. 

http://www.powerspan.com/ECO_overview.aspx 17 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. 

http://www.ftek.com/apcRRI.php 18 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 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 21 

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,19 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 Boiler 3 to determine control efficiencies and 

annual reductions. 

Flue Gas Recirculation (FGR): CENC estimated a 20% NOx reduction. Flue gas 

recirculation is considered an operational modification, since fuel is rearranged in 

the main combustion zone. EPA’s AP-42 emission factor tables estimate 

operational modifications to reduce NOx 10 –20%.20 It should be noted the 

baseline NOx emission rate (0.17 lb/MMBtu) is much lower than other spreader 

stoker boilers examined in many control case studies.21 The Division considers 

this level of control optimistic and concurs with CENC’s control efficiency 

estimates for FGR. 

SNCR: CENC noted in the May 6, 2010 submittal that the similar unit was 

assumed to achieve 40% control for SNCR. However, CENC determined that 

30% control was a more realistic estimate. EPA’s SNCR Air Pollution Control 

Technology Fact Sheet states that SNCR achieves 30 – 50% control, which 

concurs with the Division’s experience. The Division determined in CENC’s 

BART analysis that an appropriate NOx reduction estimate is 30%; therefore, the 

Division concurs with CENC’s control efficiency estimate. 

ROFA: A recent AWMA study noted that ROFA achieves from 45 – 60% NOx

reduction depending on temperature and distribution of combustion products. 22 

CENC estimated a reduction of 57.1% based on a vendor guarantee for a similar 

unit. This results in a resultant NOx emission rate of 0.07 lb/MMBtu. In the 

Division’s experience, this emission rate may not be realistically achievable and 

will require more study if applicable. 

Fuel switching – different fuel type (natural gas): CENC estimates 50% NOx

reduction by converting fuel to natural gas. This is equal to about 0.09 

lb/MMBtu, which is consistent with EPA’s AP-42 emission factor tables for a 

 19 State of North Dakota BART Determination for Leland Olds Station Units 1 and 2. Page 16. 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 EPA, Office of Air and Radiation. “Alternative Control Technique Document – NOx Emissions from 

Industrial/Commercial/Institutional (ICI) Boilers.” Emission Standards Division. 

http://www.epa.gov/ttncatc1/dir1/icboiler.pdf 22 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

Reasonable Progress Analysis – CENC Page 22 

large wall-fired boiler controlled with flue gas recirculation (0.098 lb/MMBtu).23

Therefore, the Division concurs with CENC’s control efficiency estimate. 

RSCR/HT SCR/LT SCR: CENC estimates 74.5% NOx control for RSCR and 

85.7% for HTSCR and LTSCR. These control efficiencies are consistent with 

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.24,25 RSCR will not achieve the same control 

efficiencies as HTSCR and/or LTSCR due to the heat input being required 

through burner arrangement located between two canisters and can be applied to 

relatively cold flue gas temperatures seen after particulate control equipment. The 

Division notes that these control efficiencies, due to the low baseline NOx

emission rate, result in extreme emission rates (0.02 – 0.04 lb/MMBtu) and may 

not be realistically achievable, but concurs with CENC’s current estimate for 

purposes of this RP evaluation.

Table 15: CENC Boiler 3 NOx Technology Options and Technical Feasibility 

Technology 

Emission 

Reduction 

Potential (%) 

Technically Feasible? 

(Y = yes, N = no) 

Low NOx Burners (LNB) n/a N – coal stoker boiler 

Flue Gas Recirculation 

(FGR) ~20% Y 

Selective non-catalytic 

reduction (SNCR) ~30 - 50% Y 

Rotating Overfire Air 

(ROFA) 45-60% Y 

Fuel switching – natural gas ~50% Y 

Selective catalytic 

reduction options (RSCR, 

HTSCR, LTSCR) 

~75 – 90% Y 

ECO® n/a N 

RRI n/a N 

Coal reburn +SNCR n/a N 

Step 4: Evaluate Factors and Present Determination 

Factor 1: Cost of Compliance

FGR: The costs of flue gas recirculation for stoker boilers are not well 

documented. This type of modification is considered a pre-combustion boiler 

modification. This modification should be more cost-effective than other options, 

 23 EPA AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.4, Table 1.4-2. 

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf 24 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 25 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

Reasonable Progress Analysis – CENC Page 23 

considering that either a new FGR fan will have to be installed or that the existing 

forced draft (FD) fan may be used to inject the flue gas into the combustion air. 

The Division considers the annualized cost of approximately $280,000 for FGR to 

be reasonable for this small boiler. 

SNCR: 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 CENC Boiler 

3. 

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

recovery and 65 – 85% for operating expense.26 The CENC-estimated SNCR 

costs for operating expenses is about 77% for Boiler 3. 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 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.27 

The Division calculates cost effectiveness (using CENC cost estimates) for SNCR 

on Boiler 3 to be about $10,150 per ton. 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.28,29 

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

NOx reduced. 30 CENC’s estimates are greater than these ranges due to the small 

size of the boiler, the difficulty of the retrofit, and the different boiler 

configuration. There is a lack of information regarding the application of SNCR 

to spreader stoker boiler. Therefore, the Division concludes that CENC’s cost 

estimates for SNCR are reasonable. 

ROFA: The Division notes lack of information regarding ROFA cost estimates, 

especially applied to spreader stoker boilers. Therefore, the Division notes that 

CENC’s estimated ROFA annualized costs are similar to SNCR, which is a 

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

(SNCR) for Controlling NOx Emissions.” Washington, D.C. 2000. 27 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 28 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

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

29 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. 

30 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

Reasonable Progress Analysis – CENC Page 24 

comparable control technology in terms of achievable reductions and concludes 

that CENC’s cost estimates for ROFA are reasonable. 

RSCR/HTSCR/LTSCR: Using CENC estimates, the Division calculates that the 

three SCR options range from $15,650 - $22,300 per ton. 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.31,32 CENC’s cost estimates are much higher than this range, 

but the small size of the boiler, the difficulty of the retrofit, and the boiler 

configuration, the Division concludes that CENC’s cost estimates for SCR are 

reasonable. 

 

Table 16: CENC Boiler 3 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 --- 180 0.25 56 65

Flue Gas 

Recirculation 20.0 144 0.15 0.17 41 47 

SNCR 30.0 144 0.13 0.15 33 38 

Fuel 

Switching - 

NG 

34.8 118 0.12 0.14 29 33 

ROFA w/ 

Rotamix 57.1 77 0.08 0.09 18 20 

Regenerative 

SCR 74.5 46 0.05 0.05 11 12 

High 

Temperature 

SCR 

85.7 26 0.03 0.03 6 7 

Low 

Temperature 

SCR 

85.7 26 0.03 0.03 6 7 

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

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

32 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

Reasonable Progress Analysis – CENC Page 25 

Table 17: CENC Boiler 3 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy) 

Annualized 

Cost ($) 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost ($/ton) 

Baseline 0 $0 $0 --- 

Flue Gas 

Recirculation 33.7 $278,358 $7,716 $214 

SNCR 50.6 $513,197 $9,484 $98 

Fuel Switching - 

NG 58.7 $1,428,911 $22,763 $1,534 

ROFA w/ 

Rotamix 96.3 $978,065 $9,496 -$330 

Regenerative 

SCR 125.6 $1,965,929 $14,629 $164 

High 

Temperature 

SCR 

144.5 $2,772,286 $17,933 $164 

Low 

Temperature 

SCR 

144.5 $3,222,223 $20,844 --- 

Factor 2: Time Necessary for Compliance

In the May 7, 2010 submittal, CENC notes that due to the gross estimate of this 

 evaluation, compliance time must include a more extensive study of the control 

 options and their technical feasibility. It is anticipated that if controls were 

 required, at least five years after SIP approval would be needed to perform this 

 study, work with the Division regarding the final options, incorporate the 

 decision, and finally initiate and complete the construction process. 

Factor 3: Energy and Non-Air Quality Impacts

FGR: Installation of a FGR system is not expected to impact the boiler efficiency 

or forced draft fan power usage significantly. Thus, this factor does not influence 

the selection of this control. 

Fuel Switching – Natural Gas: Fuel switching to natural gas does not have any 

significant energy or non-air quality related impacts. Thus, this factor does not 

influence the selection of this control.

ROFA w/ Rotamix: The ROFA system requires installation and operation of the 

ROFA fans on this boiler, with a 125 hp fans being anticipated based on a similar 

boiler analysis. The Rota system alone will have a modest increase in power 

consumption. This system may result in higher levels of carbon in the fly ash due 

to incomplete combustion. Rotamix may impact any potential salability of fly ash 

due to ammonia levels. However, the Division is not currently aware of CENC 

selling fly ash. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 26 

SNCR /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. 

Post-combustion add-on control technologies such as SNCR do increase power 

needs 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. In particular, 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. 

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. 

Factor 4: Remaining Useful Life

CENC asserts that there are no near-term limitations on the useful of this boiler, 

 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. 

Factor 5 (optional): Evaluate Visibility Results

The Division conducted CALPUFF modeling to determine the projected visibility 

 improvement associated with various control technologies for Boilers 4 and 5 at 

 the CENC facility. The projected visibility improvements attributed to DSI are 

 outlined in Table 12. CALPUFF modeling indicates a 0.12 Δdv for 

 LNB+SOFA+SNCR applied to Boiler 4 (360 MMBtu/hr). LNB+SOFA+SNCR 

 controls for Boiler 4 would reduce NOx emissions by approximately 368 tons per 

 year. SCR controls for Boiler 3 would reduce NOx emissions by about 145 tons 

 per year. Consequently, it is reasonable to infer that either control applied to 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress Analysis – CENC Page 27 

 Boiler 3, a smaller boiler at the same site (225 MMBtu/hr), would yield model 

 results much less than 0.10 Δdv. 

Table 18: CENC Boiler 4 NOx Modeling Results 

NOx Control Method 

CENC - Boiler 4 

Emission 

Reduction (tpy) 

NOx Annual 

Emission Rate 

(lb/MMBtu) 

98th 

Percentile 

Impact (Δdv) 

Daily Maximum (3-yr) --- 0.67 

LNB 60 0.45 0.05 

SNCR 180 0.35 0.07 

LNB + SOFA 210 0.32 0.08 

LNB + SOFA + SNCR 368 0.19 0.12 

Determination

Based on review of historical actual load characteristics of this boiler, the 

Division proposes an annual NOx ton/year limit based on 50% annual capacity 

utilization based on the maximum capacity year in the last decade (2000). This 

annual capacity utilization will then have a 20% contingency factor (similar to 

SO2) due to the reasons listed on page 5. 

Based upon its consideration of the five factors summarized herein and detailed in 

Appendix D, the state has determined that NOx RP for Boiler 3 is following NOx 

emission rate 

CENC Boiler 3: 246 tons/year (12-month rolling total) 

Though other controls achieve better emissions reductions, the expense of these 

options coupled with minimal visibility improvement (<< 0.10 dv) were 

determined to be excessive and above the guidance cost criteria discussed in 

section 8.4 of the Regional Haze State Implementation Plan, and thus not 

reasonable. 

V. Reasonable Progress Evaluation of Boiler 4 and Boiler 5

Boiler 4 and Boiler 5 have been evaluated under Best Available Retrofit 

Technology (BART) provisions. BART for Boilers 4 and 5 can be found in 

Chapter 6 of the Regional Haze State Implementation Plan. The Division 

determines that BART represents the most stringent available NOx, SO2, and 

PM/PM10 control technologies and represents reasonable progress. Therefore, a 

full 4-factor analysis is not needed to evaluate reasonable progress for NOx, SO2, 

or PM/PM10 for Boiler 4 and Boiler 5 at the CENC facility.