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

Regional Haze Reasonable Progress Analysis - Nixon Page 1 

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

For 

Colorado Springs Utilities – Ray D. Nixon Power Plant 

I. Source Description

Owner/Operator: Colorado Springs Utilities 

Source Types: Electric Utility Steam Generating Unit 

SCC (EGU): 10100222 

Boiler Type: Pulverized Coal, Dry-Bottom, Front-Fired, firing coal and natural 

gas 

 

The Nixon facility is located at 14020 Ray Nixon Road in Fountain, Colorado. This 

facility consists of one (1) steam driven turbine/generator unit, auxiliary boiler, the 

associated equipment needed for generating electricity, and two natural gas fired simple 

cycle combustion turbines driving electricity generators. The boiler fires low sulfur 

western coal as the primary fuel and can currently use No. 2 distillate oil or natural gas 

for an ignition fuel. The ignition fuels are used for startup of the boiler, flame 

stabilization, and the coal pulverizer startup. The facility also includes the various 

processes necessary to handle the coal, flyash and bottom ash. The coal and flyash 

handling systems are provided with baghouses for air pollution emission control at 

appropriate point sources. 

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

information regarding the Nixon power plant, 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. 

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 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 

 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

Regional Haze Reasonable Progress Analysis - Nixon Page 2 

• SO2 – 40 tons per year 

• PM10 – 15 tons per year 

Nixon Power Plant is considered a single source with six (6) other facilities, depicted in 

Table 1. 

Table 1: Facilities Co-Located or Considered to be a Single Source with Nixon Power Plant 

Emission Sources Colorado 

Construction/Operating 

Permit #

Permit Holder

Coal Screen 98PO149 Western Resources

2 Anaerobic Digestors, 4 

Biogas Boilers and 2 Flares 96OPEP152 CSU – Clear Spring Ranch Solids & Handling 

2 Natural Gas Turbines 99EP0851 Front Range Power Company, LLC

1 Coal-fired Boiler, 2 

Natural Gas Turbines, 

Cooling Tower, Ash 

Handling, Coal Handling, 

Auxiliary Boiler

95OPEP106 CSU – Nixon Power Plant

Wastewater Treatment and 

3 Internal Combustion 

Engines 

95EP1097 CSU – Las Vegas Street Municipal 

Treatment Plant

Custom Anaerobic 

Wastewater Treatment 

System 

03EP0158 CSU – Northern Water Reclamation 

Facility

The two natural-gas fired combustion turbines at Front Range Power Plant (FRPP) are 

above the Prevention of Significant Deterioration significance level for NOx. The other 

single source facilities emit NOx, SO2, and/or PM10 below the Prevention of Significant 

Deterioration significance levels. 

The Front Range Power Plant (FRPP) is located at 6615 Generation Drive, Fountain, 

Colorado. The facility produces electrical power using two natural gas combustion 

turbines, with two Heat Recovery Steam Generators (HRSG), and duct burners. These 

two combustion turbines are evaluated within the source category “Combustion 

Turbines” in Section 8.2.3 of the Regional Haze SIP. 

Nixon Unit 1 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. CSU 

provided information in “NOx and SO2 Reduction Cost and Technology Updates for 

Colorado Springs Utilities Drake and Nixon Plants” Submittal provided on February 20, 

2009 and additional relevant information on February 21, March 21, May 10, and June 2, 

2010. Table 2 depicts technical information for Nixon Unit 1. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 3 

Table 2: Nixon/FRPP RP-eligible Emission Controls and Reduction (%) 

 Nixon Unit 1 

Placed in Service April 1980 

Boiler Rating, MMBtu/Hr for 

coal 2,049 

Electrical Power Rating, Gross 

Megawatts 227 

Description 

Babcock and Wilcox Pulverized 

Coal Front Fired Dry Bottom, 

firing coal. The coal burner 

ignitors fire No. 2 fuel or spec 

oil & NG 

Air Pollution Control 

Equipment 

Western Precipitation 

Thermoflex Fabric Filter 

(baghouse) 

Special Features Low NOx burners placed in 

service in 1989 

Emissions Reduction (%) 

NOx – 37% 

SO2 – None 

PM/PM10 – 99.9/99.7% 

Regulations that apply to the boiler are as follows: 

For Nixon Unit 1: 

• NSPS Subpart D regulates particulate matter emissions to 0.1 lb/MMBtu. 

• NSPS Subpart D regulates NOX emissions to 0.7 lb/MMBtu. 

• The Title V Operating Permit limits annual NOX emissions to 2853.3 tons per 

year. 

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

regulates NOX emissions to 0.50 lb/MMBtu of heat input on an annual average 

basis. 

• NSPS Subpart D regulates SO2 emissions to 1.2 lb/MMBtu. 

II. Source Emissions

Table 3 summarizes each unit at the facility and applicable NOx, SO2, and PM actual 

emissions averaged over the 2006 – 2008 timeframe with data from EPA’s CAMD 

database, Colorado’s Air Pollutant Emission Notices submitted by the facility, and 

Colorado inspection reports as applicable. Table 4 summarizes the NOx, SO2, and PM

actual emissions averaged over the 2006 – 2008 timeframe (baseline) for each RPeligible unit. 

Table 3. Summary of 2006 - 2008 Averaged Emissions by Unit - Nixon Facility 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

Boiler #1 SO2 (tons) 3877.6 4043.1 4442.3 4121.0 

 SO2 (lb/MMBtu) 0.46 0.52 0.53 0.50 

 NOx (tons) 2390.1 2137.0 2542.9 2356.7 

 NOx (lb/MMBtu) 0.26 0.26 0.26 0.26 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 4 

 PM10 (tons) 89.24 82.29 88.78 86.8 

 PM10 (lb/MMBtu) 0.011 0.011 0.011 0.011 

Auxiliary Boiler SO2 (tons) 0 0 0 0.0 

 SO2 (lb/MMBtu) 0.00 0.00 0.00 0.00 

 NOx (tons) 0.02 0.02 0.05 0.0 

 NOx (lb/MMBtu) 1.50 1.50 1.52 1.51 

 PM10 (tons) 0 0 0 0.0 

 PM10 (lb/MMBtu) 0.000 0.000 0.000 0.000 

Nixon Combustion 

Turbine 1 SO2 (tons) 0.01 0.01 0.01 0.0 

 SO2 (lb/MMBtu) 0.00 0.00 0.00 0.00 

 NOx (tons) 0.81 0.61 0.76 0.7 

 NOx (lb/MMBtu) 0.04 0.04 0.04 0.04 

 PM10 (tons) 0.23 0.19 0.25 0.2 

 PM10 (lb/MMBtu) 0.011 0.012 0.012 0.012 

Nixon Combustion 

Turbine 2 SO2 (tons) 0.01 0.02 0.01 0.0 

 SO2 (lb/MMBtu) 0.00 0.00 0.00 0.00 

 NOx (tons) 0.97 1.67 0.85 1.2 

 NOx (lb/MMBtu) 0.04 0.05 0.05 0.05 

 PM10 (tons) 0.27 0.36 0.23 0.3 

 PM10 (lb/MMBtu) 0.012 0.012 0.014 0.012 

Coal Reclaim 

Conveyor (003) PM10 (tons) 25.97 25.97 21.85 24.60 

Ash Handling/Disposal 

(006) PM10 (tons) 1.41 1.41 1.41 1.41 

Coal Handling (008) PM10 (tons) 23.2 23.2 1.47 15.96 

Ash Haul Roads & 

Disposal (009) PM10 (tons) 1.85 1.85 1.87 1.86 

Unit #1 Cooling Tower PM10 (tons) 0.8 0.8 0.75 0.78 

Four Digester Gas 

Boilers SO2 (tons) 10.15 9.03 9.03 9.40 

 NOx (tons) 4.95 3.84 3.84 4.21 

 PM10 (tons) 0.50 0.35 0.35 0.40 

2 Digester Gas Flares SO2 (tons) 11.0 11.19 11.19 11.13 

 NOx (tons) 2.61 2.65 2.65 2.64 

 PM10 (tons) 0.54 0.40 0.40 0.45 

Sludge Injection & 

Unpaved Roads PM10 (tons) 8.90 8.90 8.90 8.90 

*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 0.58 lbs/MMBtu for Boiler 1). 

Units italicized in Table 2 are less than de minimis thresholds and will not be evaluated 

further for the purposes of reasonable progress. 

Table 4. Nixon Unit 1 Baseline Emissions 

Pollutant Nixon Unit 1 

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

NOx 2,357 0.258 

SO2 4,121 0.453 

PM10 87 0.002*** 

*Using daily CEMs data from 2006 – 2008 calendar years (CAMD data).
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 5 

**The Division calculated average emission rate (lb/MMBtu) from the 2006 - 2008 calendar years (CAMD 

data) based on average daily reported data for each unit for NOx and SO2 emissions and for PM10 emissions 

for the turbines. 

***The PM10 emission rate is determined from the Title V permit compliance stack test. These values are 

as follows: Nixon Unit 1 – 0.0021 lb/MMBtu (4/15/2008) 

 

III. Units Evaluated for Control

As documented by CSU, Nixon Unit 1 fires low sulfur, high heating value Power River 

Basin sub-bituminous coal. The specifications for the coal are listed below in Table 5. 

Table 5: Coal Specifications (2006 - 2007 Averaged APEN data) 

 Specifications 

Emission Unit Fuel Heating Value 

(Btu/lb) 

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

Nixon Unit 1 8,752 0.22 4.99 

Table 1 lists the units at Nixon 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 Nixon Unit 1 

Emission Unit Pollutant 

Fuel 

Coal (sub-bituminous) (lb/ton) 

Nixon Unit 12

NOx 7.2 

SO2 35 x %S = 7.7* 

PM/PM10 PM – 49.90** 

PM10 – 11.48 

*%S = % of sulfur present in coal supply. For example, 35 x 0.22 = 7.7 

**%A = % of ash present in coal supply. For example, 10 x 4.99 = 49.90 

IV. Reasonable Progress Evaluation of Nixon Unit 1

a. Sulfur Dioxide 

Step 1: Identify All Available Technologies 

CSU identified one SO2 control option: 

Flue gas desulfurization (FGD): 

Lime spray dry absorber (SDA or dry FGD) 

The Division identified two additional SO2 control options: 

Flue gas desulfurization (FGD): 

 Lime or limestone-based (wet FGD) 

 Dry sorbent injection – Trona (DSI) 

 2

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

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

Regional Haze Reasonable Progress Analysis - Nixon Page 6 

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. 

CSU’s 2009 submittal states that a dry FGD (SDA) system is technically feasible. The 

Division concurs with this conclusion. 

 

The Division notes that traditional wet FGD controls are possible at Nixon Unit 1 

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 at Nixon Unit 1. 

It is worth noting that CSU is currently testing a new, innovative non-traditional wet 

scrubber control system at another facility that appears to be as effective, if not more 

effective, at controlling SO2 emissions with much less pressure drop (less parasitic load 

from increased fan demands) and requires a much smaller operational foot print area in 

comparison to traditional wet scrubbing.. The pilot-scale wet scrubber control system, 

 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

Regional Haze Reasonable Progress Analysis - Nixon Page 7 

called the NeuStream-S FGD process, is presently being tested on a 20 MW flue gas 

stream. CSU anticipates scaling the non-traditional wet scrubber control to full scale 

pending successful outcome of the current testing. This new wet scrubber technology 

uses a unique contacting vessel that makes it different from traditional wet scrubbers. It 

affords a higher liquid to gas contact ratio and so uses much less water / has lower 

pressure drop. It also uses a dual alkali system that is somewhat unique when compared 

to most traditional wet scrubbers. In comparison to traditional wet and LSD scrubbers, 

this new technology will have smaller water and energy requirements. There are several 

non-air quality aspects of the NeuStream-S process that compare favorably to traditional 

scrubbers, described in Step 4. 

Although the technology being tested by CSU does not technically meet the definition of 

“available” as set forth in the BART (Regional Haze) rules, the Division is willing to 

allow CSU the opportunity to prove the technology and if successful, the opportunity to 

install the NeuStream-S FGD scrubber at Nixon Unit 1 if desired and applicable. This 

process will be required to meet the emission limits established for the LSD technology 

established in this RP determination. Regardless of the technology utilized, Nixon has to 

meet the LSD-based RP limits within 5 years of EPA approval of the Regional Haze SIP. 

CSU will test the NeuStream system at this facility until December 2011, and at that 

time, determine the control technology that will be used to comply with the specified SO2

RP limit for Nixon Unit 1. 

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 as in the case of the 

Drake boilers. CSU asserts that the flue gas temperatures present downstream of the 

airheater 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. CSU’s preliminary review indicates that even with the added loading of DSI 

reagent, the Drake baghouses would be operating within the design specification for 

particulate loading. 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. 

One major challenge of DSI systems is the possibility of converting the NOx present in 

the flue gas from NO which is colorless to NO2 which has a reddish-brown color. This 

conversion of NO to NO2 can create a brown plume from the stack which could create 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 8 

opacity compliance issues. 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, CSU estimated the maximum SO2

removal rate that can be achieved while minimizing the creation of the brown plume 

condition to be 60% SO2 removal at another facility. 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. Therefore, since CSU notes that DSI is technically 

feasible for a similar facility, the Division assumes this same technology is also then 

technically feasible for Nixon Unit 1. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology 

CSU 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 Unit 1 to determine control efficiencies 

and annual reductions. 

The Division has reviewed the data supplied by CSU 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. 

Dry FGD (LSD): Controlling SO2 Emissions: A Review of Technologies5

 indicates that 

the median control efficiency for dry FGD processes, such as LSD, is 90%. Typically dry 

FGD technology is applied to units that fire coal with a sulfur content below 1.0% to 

1.5%. However, when concentrations of pollutants are low, as is the case with low-sulfur 

western coal, the achievable control efficiency will drop. Due to the very low sulfur 

content of the coal burned at the Nixon Power Plant, typically <0.5% as detailed in Table 

5, a 90% removal rate is at the upper end of what may reasonably be expected in practice. 

Therefore, dry FGD is evaluated at two control efficiencies level – 78% (0.010 

lb/MMBtu annual average) and 82.3% (0.08 lb/MMBtu annual average) for comparison 

purposes. 

DSI: Based on literature review, CSU estimated the maximum SO2 removal rate that can 

be achieved to be 60% SO2 removal. The Division concurs that this control efficiency is 

reasonable for retrofit on these units. 

 5 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

Regional Haze Reasonable Progress Analysis - Nixon Page 9 

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

Table 7: Nixon Unit 1 SO2 Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

Wet FGD 95% Y 

Dry FGD (LSD) 75 – 85% Y

DSI 60% (CSU) Y

Step 4: Evaluate Factors and Present Determination 

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. 

LSD/DSI: CSU submitted cost estimates for a LSD system on Unit 1 on February 20, 

2009. CSU provided cost estimates for the DSI system evaluated on another similar 

Colorado unit (CSU Drake Unit 5) on May 10, 2010. 

CSU states that the direct energy cost of the LSD systems due to additional auxiliary 

loads on the plant, as well as increased headloss through the scrubber, is the primary 

energy impact. These loads reduce the net output of each unit; therefore, both the lost 

energy production, as well as the reduced capacity, must be replaced. CSU estimates 

energy costs for replacement capacity and differential cost between existing MW-h of 

output and a replacement MW-h in Table 8. This is the incremental cost of a unit of 

replacement energy, and does not double count the direct energy cost already included in 

the operating cost. The reduced unit output will consequently reduce unit efficiency, 

thereby increasing emissions of CO2 when measured on a per MW-h basis. These 

estimates are for another facility, Drake Units 6 and 7, but are assumed to be directly 

applicable to Nixon Unit 1 as well. 

Table 8: LSD Energy Replacement Costs 

Unit Replacement capacity 

cost ($/kW-yr)

Differential energy 

cost ($/MW-h)

Drake 6/7 44 35

This information, including detailed capital and annual cost data, are provided as “CSU 

Drake BART Submittals” and “CSU Nixon RP Submittals”. CSU originally generated 

costs using EPRI’s FGD Cost model for Drake.6

 This model uses specific unit data to 

 6

 EPA’s BART Guidelines recommend that the OAQPS Control Cost Manual be used to develop cost estimates, 

where possible. Unfortunately, the Control Cost Manual does not contain a section for SO2 removal equipment as of 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 10 

calculate the cost of controlling emissions, and is considered to be accurate within ± 30%. 

When preparing cost estimates for Nixon, cost estimates were developed using the 

IECCOST program. 

The application of LSD or DSI would remove nearly all of the halogens in the flue gas, 

thus improving the acid gas removal of the baghouse. However, it is anticipated that 

LSD or DSI would also lower the inherent mercury removal in the baghouses. Recent 

mercury tests at the Drake Plant have shown that the amount of mercury leaving the stack 

is approximately 60 – 90% less than what would have been expected based on coal 

analysis. It is believed that the halogens present in the flue gas are oxidizing the mercury, 

which is subsequently removed in the baghouse. The application of LSD or DSI would 

remove the halogens in the flue gas, which may lead to reduced mercury control. Due to 

this possibility, the provision of adding mercury control via activated carbon injection as 

part of a LSD or DSI system has been included in the estimated cost of LSD/DSI 

application. 

The Division compared CSU’s updated cost information to the study that EPA conducted 

in developing presumptive BART limits,7

 shown in Table 9. 

Table 9: CSU-Drake SO2 LSD Control Cost Comparison 

Unit Capacity 

(MW) 

EPA’s Calculated Cost 

Effectiveness for MW Group ($/ton 

SO2 Removed) 

CSU Refined Cost Estimate 

($/ton SO2 Removed (Control 

System)) 

Cost Differential 

Drake Unit 6 

– 85 MW 

$2,399 $2,579 - $2,981 + 8% – 24% 

Drake Unit 7 

– 142 MW 

$1,796 $2,140 - $2,694 + 19% - 50% 

Nixon Unit 1 

– 225 MW 

$1,282 $3,744 - $3,950 + 192% - 208% 

EPA’s study was published in 2005 whereas CSU sent the Division updated cost 

analyses for LSD systems on Unit 1 using various cost updates from the 2008 

timeframe. Nixon has reflected the costs of retrofitting a facility that is moderately 

congested with limited room and access for major retrofits of new capital equipment 

in the retrofit multiplier that is applied to the cost of new equipment. The Division 

does not necessarily concur with these estimates, but will accept them for purposes of 

this RP analysis. 

CSU only submitted DSI cost information for another facility, Drake Unit 5. The 

Division scaled this cost information for Units 1 in Table 10. Please see “Drake 

APCD Technical Analysis” and “Nixon APCD Technical Analysis” for more details. 

 the date of this report. The Fifth edition (EPA 453/B-96-001) of the Control Cost Manual is referenced in the BART 

guideline; however, the Sixth edition (EPA 452/B-02-001, 7-22-2002) is now available.

7

 EPA, 2005. Technical Support Document for the Best Available Retrofit Technology (BART) Notice of Final 

Rulemaking: Setting BART SO2 Limits for Electric Generating Units: Control Technology and Cost-Effectiveness. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 11 

For dry FGD, CSU estimated a removal rate of 80% based on 2008 average data and 

a resulting emission rate at the BART presumptive limits of 0.10 lb/MMBtu. The 

Division adjusted this removal rate using the baseline SO2 emissions from Table 4 

(lb/MMBtu and tons/year) for each unit and using a realistic removal rate of 78 - 

82%that meets the BART presumptive limit for Nixon Unit 1. This range allows the 

Division to determine the most reasonable RP limit for this control option, if 

applicable. The Division scaled costs linearly for the LSD systems for higher control 

efficiencies as applicable. See “Nixon APCD Technical Analysis” for more details. 

Table 10 illustrates resultant SO2 emissions for each technically feasible control 

option. Table 11 shows the SO2 control cost comparisons for each unit based on the 

detailed cost analyses. The Division used baseline emissions from Table 4. The 

Division analyzed both annual and 30-day rolling average limits. The Department’s 

experience with power plants suggests that the maximum 30-day rolling average SO2

emission rate is approximately 5% higher than the annual average emission rate. 

Table 10: Nixon Unit 1 Control Resultant SO2 Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Unit 1

(tons/year) Annual Average 

(lb/MMBtu)

30-day Rolling 

Average (lb/MMBtu)

Baseline --- 4,121 0.453

DSI 60 1,649 0.181 0.190

Dry FGD (LSD) @ 

78% control 78 907 0.100 0.105

Dry FGD (LSD) @ 

82.3% control 82.3 729 0.080 0.084

Table 11: Nixon Unit 1 SO2 Cost Comparison 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

DSI 2,473 $4,938,692 $1,997 $1,997

Dry FGD (LSD) @ 

78% control

3,215 $12,036,604 $3,744 $9,568

Dry FGD (LSD) @ 

82.3% control

3,392 $13,399,590 $3,950 $7,691

Factor 2: Time Necessary for Compliance
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 12 

Based on other Colorado facility submittals8, the Division anticipates that the time 

necessary for completing design, permitting, procurement, pipeline installation, and 

system startup and shutdown, after SIP approval, it would take CSU approximately 3 – 5 

years to implement any of the above control options. This timeframe may vary 

somewhat due to regional demand for natural gas and to schedule the necessary major 

maintenance outage with other regionally affected utilities. 

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. Potential 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 river valley will 

produce a noticeable cloud that will hang over a densely populated area (City of Colorado 

Springs). 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 

 8

Prepared for Black Hills Colorado Electric by CH2M Hill, December 2009. “Black Hills Clark Station NOx 

Reduction Feasibility Study.” Pgs. 3-13 and 3-14. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 13 

area) when compared to LSD or the pilot NeuStream-S FGD scrubber when applied to 

the Nixon Unit 1 boiler. 

Semi-dry FGD (LSD): CSU notes that there are a number of non-air quality 

environmental impacts with regard to lime spray dryer systems. Application of a dry 

scrubber will tend to remove halogens from the flue gas (primarily chlorine) that are 

important to the removal of mercury from the flue gas. Several sources of speciated 

mercury stack test data, including EPA’s own ICR stack test data, show that an 

unscrubbed plant with a baghouse burning western coal will remove more mercury from 

the flue gas when compared to a similar plant with a scrubber. There will be a greater 

volume of material being landfilled. A LSD scrubber consumes a tremendous amount of 

water, as detailed in Table 12. Wet scrubbers consume approximately 23% more water 

than LSD scrubbers, depending on boiler size.9

Table 12: LSD Water Requirements 

Unit Water required for LSD (gpm) Water required for LSD (Mg/year) 

Drake 6 68 35.7 

Drake 7 100 53.0 

Nixon 1 

(scaled) ~160 ~84.0 

Although these non-air quality/energy impacts have been identified, the State has 

determined that these impacts are not significant or unusual enough to warrant 

elimination of this control option. 

DSI: CSU 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. 

Application of DSI would be effective in further enhancing the removal of halogenated 

acid gases in the baghouse. 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 

at some plants,10 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 

 9

 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. 

10 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

Regional Haze Reasonable Progress Analysis - Nixon Page 14 

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

controls. 

Factor 4: Remaining Useful Life

CSU asserts that the remaining useful life of Nixon Unit 1 in excess of 20 years, which is 

the maximum amortization period allowed in the RP analysis. Thus, this factor does not 

influence the selection of controls. 

Factor 5 (optional): 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. 

The state performed modeling using the maximum 24-hour rate during the baseline 

period, and compared resultant annual average control estimates. In the state’s 

experience, 30-day SO2 rolling average emission rates are expected to be approximately 

5% higher than the annual average emission rate. The state projected a 30-day rolling 

average emission rate increased by 5% for all SO2 emission rates to determine control 

efficiencies and annual reductions. 

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) Class I 

Area 

Affected 

3-year totals 3-year totals 

Pre-Control 

Days >0.5 

dv 

PostControl 

Days >0.5 

dv 

∆days Pre-Control 

Days >1.0 

dv 

PostControl 

Days >1.0 

dv 

∆days

Max 24-hr 

SO2 rates 

1 

RMNP 

17 --- --- 6 --- --- 

DSI @ 0.18 

lb/MMBtu 

1 

17 6 11 6 1 5 

LSD @ 0.10 

lb/MMBtu 

1 

17 6 11 6 1 5 

LSD @ 0.08 

lb/MMBtu 

1 

17 6 11 6 1 5 

Table 14: Visibility Results – SO2 Control Scenarios 

SO2 Control 

Scenario 

Unit(s) Output (@ 98th

Percentile Impact)* 

98th Percentile 

Impact Improvement 

98th Percentile 

Improvement from 

Maximum 

Cost 

Effectiveness 

(deciviews) (deciviews) (%) ($/deciview) 

Max 24-hr SO2

rates 

1 0.914 --- 

DSI @ 0.18 

lb/MMBtu 

1 0.48 0.44 48% $11,249,869 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 15 

LSD @ 0.10 

lb/MMBtu 

1 0.46* 0.46 50% $26,454,076 

LSD @ 0.070 

lb/MMBtu 

1 0.42 0.50 55% $28,307,522 

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

Summary” for more details. 

Determination

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

determined that SO2 RP the following SO2 emission rate: 

Nixon Unit 1: 0.11 lb/MMBtu (30-day rolling average) 

The state assumes that the emission limit can be achieved with semi-dry FGD (LSD). A 

lower emissions rate for Unit 1 was deemed to not be reasonable as increased control 

costs to achieve such an emissions rate do not provide appreciable improvements in 

visibility (0.04 delta deciview). Also, stringent retrofit emission limits below 0.10 

lb/MMBtu have not been demonstrated in Colorado, and the state determines that a lower 

emission limit is not reasonable in this planning period. 

The LSD control for Unit 1 provides 78% SO2 emission reduction at a modest cost per 

ton of emissions removed and result in a meaningful contribution to visibility 

improvement. 

• Unit 1: $3,744 per ton SO2 removed; 0.46 deciview of improvement 

An alternate control technology that achieves the emissions limits of 0.11 lb/MMBtu, 30-

day rolling average, may also be employed. 

b. Filterable Particulate Matter (PM) & Particulate Matter (PM10) 

Nixon Unit 1 is equipped with a reverse-air fabric filter baghouse 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 95OPEP106 Condition 1.5.5 requires Unit 1 to conduct 

performance testing for PM10 annually. While the emission limit in Condition 1.5.1 is set 

at 0.1 lb/MMBtu, the annual performance test must be used as an emission factor in 

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

Regional Haze Reasonable Progress Analysis - Nixon Page 16 

Table 15 shows the most recent stack test data (April 14, 2008). It is important to note 

that the most recent stack test, which at a minimum, occurs every five years, and more 

frequently depending on the results, demonstrates that these baghouses are meeting >95% 

control. 

Table 15: Nixon Unit 1 2008 Stack Test Results 

Pollutant Unit 1 (lb/MMBtu) 

Filterable PM10 0.0021 

PM10 Control efficiency 99.5% 

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

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

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

dry FGD systems). The 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. 

The state determines that the existing Unit 1 regulatory emissions limit of 0.03 lb/MMBtu 

(PM/PM10) represents the most stringent control options. The unit is exceeding a PM control 

efficiency of 95%, and the control technology and emission limits are RP for PM/PM10. The 

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

filter baghouse. Thus, as described in EPA’s BART Guidelines, a full four-factor analysis for 

PM/PM10 is not needed for Nixon Unit 1. 

c. Nitrogen Oxides (NOx) 

Step 1: Identify All Available Technologies 

CSU identified four NOx control options: 

 Overfire air (OFA) 

 Ultra-low NOx burners (ULNBs) 

 Selective Catalytic Reduction (SCR) 

 Ultra-low NOx burners and SCR (ULNBs + SCR) 

 

The Division also identified and examined the following additional control options 

for these units: 

 Electro-Catalytic Oxidation (ECO)® 

 Rich Reagent Injection (RRI) 

 Ultra-low NOx burners and Over-fire air (ULNBs+OFA) 

 Selective Non-Catalytic Reduction (SNCR) 

 Coal reburn +SNCR 

 

Rotating overfire air (ROFA) was not considered in this analysis because ROFA® 

technology has been reported as achieving NOx emission reductions from 45 to 65 % 

based on fuel load11. While ROFA is considered superior to SOFA alone, ROFA 

alone is not superior to LNB+OFA and cannot achieve the predicted 70% or greater 

NOx reduction for Unit 1. Since ROFA® technology would not be expected to 

 11 Nalco-Mobotec, ROFA Technology, 1992-2009, http://www.nalcomobotec.com/technology/rofa-technology.html
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 17 

provide better emissions performance than the LNB+OFA baseline for this unit, 

ROFA® technology is not considered further in this analysis. 

Step 2: Eliminate Technically Infeasible Options 

OFA: Air staging or two-stage combustion, is generally described as the introduction 

of overfire air into the boiler or furnace. Staging the air in the burner (internal air 

staging) is generally one of the design features of low NOx burners, such as those 

already present on Unit 1. Furnace overfire air (OFA) technology requires the 

introduction of combustion air to be separated into primary and secondary flow 

sections to achieve complete burnout and to encourage the formation of N2 rather 

than NOx. Primary air (70-90%) is mixed with the fuel producing a relatively low 

temperature; oxygen deficient, fuel-rich zone and therefore moderate amounts of fuel 

NOx are formed12. The secondary (10-30%) of the combustion air is injected above 

the combustion zone through a special wind-box with air introducing ports and/or 

nozzles, mounted above the burners. Combustion is completed at this increased flame 

volume. Hence, the relatively low-temperature secondary-stage limits the production 

of thermal NOx. The location of the injection ports and mixing of overfire air are 

critical to maintain efficient combustion. Retrofitting overfire air on an existing boiler 

involves waterwall tube modifications to create the ports for the secondary air nozzles 

and the addition of ducts, dampers and the wind-box. OFA is a technically feasible 

option for Unit 1. 

ULNBs: Unit 1 has low NOx burners installed, shown in Table 2. These LNBs can be 

replaced with ULNBs. Burner designs have improved in recent years to improve 

flame stability and combustion control schemes for increased NOx emission 

reductions with these ultra-low NOx burners. ULNBs are a technically feasible 

option for Unit 1. 

ULNBs+OFA: Since ULNBs and OFA are each technically feasible options and 

would be installed separately for Unit 1, it stands to reason that ULNBs+OFA is a 

technically feasible options for Unit 1. 

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, achieving NOx emission reductions as low as 

0.07 lb/MMBtu when passed over an appropriate amount of catalyst as demonstrated 

by recent determinations found in the EPA’s RBLC database. 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. 

 12 IEA Clean Coal Centre: Clean Coal Technologies – Air Stating for NOx control (overfire air and two-stage 

combustion), 2010. http://www.iea-coal.org/site/ieacoal_old/clean-coal-technologies-pages/air-staging-for-noxcontrol-overfire-air-ofa-or-two-stage-combustion? 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 18 

While lower controlled NOx emission values have been demonstrated by SCR system 

applications in new coal units, for CSU Nixon, a retrofit SCR, the 0.07 lb/MMBtu 

controlled NOx value is more expected. 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, lowdust, 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 Unit 1 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, 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 at the 

Drake Plant. Therefore, high-dust SCR is a technically feasible alternative for Nixon 

Unit 1. 

ULNBs/SCR layered: A layered approach of installing ULNBs pre-combustion and 

SCR post-combustion is technically feasible for Nixon Unit 1.This scenario considers 

that less NOx would enter the SCR system and reduce aqueous ammonia storage, 

handling, and injection. CSU considered this scenario to determine if this option 

would be more economically and technically feasible for Nixon Unit 1.

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 

boiler13 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 boilers14 and 

has not been demonstrated for other types of units. Therefore, RRI is considered 

technically infeasible for Nixon Unit 1.

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 

 13 Powerspan ECO®: Overview and Advantages, 2000 – 2010. http://www.powerspan.com/ECO_overview.aspx 14 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

Regional Haze Reasonable Progress Analysis - Nixon Page 19 

a significant impact on economics, with higher levels of NOx reduction generally 

resulting in lower reagent utilization and higher operating cost. 

It should be noted that selective non-catalytic reduction (SNCR) was not considered 

in CSU’s RP analysis because CSU asserts that SNCR achieves full-load NOx

removal in the same range as ULNB at a higher levelized cost ($/ton NOx removed), 

and therefore should be ruled out due to a “least-cost envelope” analysis as detailed in 

the BART rule, and therefore should be ruled out for RP as well. The higher cost is 

primarily due to much higher operating costs, with most of the operating costs being 

for the reagent. Additionally, the chemical reaction required for SNCR to work is 

temperature sensitive. The CSU Drake boilers often operate below full load, when 

the temperature is no longer conducive to optimal NOx removal, resulting in NOx

removal declines. The weighted average NOx removal over an annual load range can 

be less than ULNB depending on the portion of time the units operate at partial load. 

Therefore, SNCR was eliminated from consideration by CSU because of higher costs 

and efficiency losses at partial loads. However, the Division considers SNCR a 

technically feasible alternative for Nixon Unit 1. Similar Colorado facilities 

evaluated SNCR as an option and it is recognized nationally as a NOx control option 

for EGUs, so the Division included SNCR in the full four-factor analysis. 

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/MMBtu15. 

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 

CSU provided the Division annual average control estimates. In the Division’s 

experience and other state BART proposals,16 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 Nixon Unit 1 to determine control efficiencies and annual 

reductions. 

OFA: CSU estimated that overfire air, in conjunction with the existing low-NOx

burners, is capable of reducing NOx emissions approximately an additional 25% from 

existing conditions in the original BART submittal (August 1, 2006). EPA’s AP-42 

emission factor tables estimate low-NOx burners controlling 35 – 55% and LNB with 

 15 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 16 State of North Dakota BART Determination for Leland Olds Station Units 1 and 2. Page 16. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 20 

OFA controlling 40 – 60% of NOx emissions.17 The low NOx burners currently 

achieve about 10% control. However, in a more recent AWMA study, it is noted that 

OFA achieves an additional 10 – 25% control with the installed low NOx burners.18 

Therefore, the Division concurs with CSU’s additional 25% NOx control estimate. 

ULNBs: CSU asserts that additional NOx reductions of 20% are possible with 

implementation of some or all of the modifications that will be needed to retrofit 

ULNBs at Nixon Unit 1. These additional NOx reductions could be achieved while 

meeting acceptable CO levels. The ULNBs are estimated to control approximately 

75% of uncontrolled NOx emissions, which is consistent with a U.S. Department of 

Energy Study which estimated NOx emissions reductions between 75 – 85%.19 

Therefore, the Division concurs with CSU NOx reduction estimates for ULNBs. 

ULNBs+OFA: The Division used information from CSU regarding ULNBs and OFA 

control efficiencies as described above. ULNBs alone can achieve 20% control; OFA 

alone can achieve 25% control. When determining the appropriate control efficiency 

regarding the combination of ULNBs and OFA, the most important consideration to 

note is that Nixon burns only Power River Basin (PRB) coal which is low in nitrogen 

content initially, so the margin to reduce NOx is lower than other facilities (i.e. 

Drake). The Division and CSU concur that a realistic control efficiency assumption 

is 30% for Nixon Unit 1. 

SNCR: Other Colorado facilities have noted a variety of control ranges for SNCR. 

The Division used a variety of information, including a similar Colorado facility 

estimates, EPA’s SNCR Air Pollution Control Fact Sheet and a recent AWMA 

study20 to conservatively approximate that Nixon Unit 1 can achieve 30% control 

when SNCR is applied. 

SCR:CSU approximates that SCR can achieve an approximate 80% NOx reduction 

using 2008 baseline emissions (or 0.05 lb/MMBtu), determined by URS WD using a 

survey of a large collection of photographs, and experience in developing retrofit 

factors for many types of units and configurations at numerous facilities. The 

Division adjusted the control efficiency percent reduction to reflect the 2006 – 2008 

baseline emissions and adjusted the resultant SCR percent removal to 73% (or 0.07 

lb/MMBtu), which the Division considers more realistic and consistent with other 

Colorado facility submittals. This control efficiency is slightly lower than EPA’s AP42 emission factor discussion, which estimates SCR as achieving 75 – 85% NOx

emission reductions and also with a recent AWMA study citing SCR as achieving 80 

 17 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 18 Srivastava et. al, 2005. Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers. Journal 

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

19 U.S. Department of Energy, 2004. Office of Fossil Energy, National Energy Technology Laboratory. 

http://www.netl.doe.gov/publications/factsheets/project/Proj294.pdf 20 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

Regional Haze Reasonable Progress Analysis - Nixon Page 21 

– 90% reduction.21,22 However, in the Division’s experience a emission limit of no 

lower than 0.07 lb/MMBtu is realistically achievable for a retrofit SCR. 

ULNBs/SCR layered approach: CSU evaluated a layered approach of installing 

ULNBs upstream of the combustion process to reduce NOx entering the boiler and 

thus reducing subsequent SCR reduction requirements. This approach will achieve 

the same NOx emission reductions as SCR alone and is deemed to be appropriate by 

the Division. 

Table 16 summarizes each available technology and technical feasibility for NOx

control. 

Table 16: Nixon Unit 1 7 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

Low NOx Burners (LNB) ~10% Y – installed

LNB + OFA 60 – 81% Y (partially installed)

Overfire air (OFA) 10 – 25% (alone) Y

Ultra-low NOx burners (ULNBs) 20% Y

ULNBs+OFA 30% Y 

Selective non-catalytic reduction 

(SNCR)

20 – 40% Y

Selective catalytic reduction (SCR) 70 – 90% Y

ULNB/SCR layered approach 70 – 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

OFA: Washington Group International Inc. estimated the cost of overfire air during 

the course of a pollution control study for the Drake and Nixon boilers in 2004. The 

cost estimates were generated using EPRI’s IECCOst model. This model uses 

specific unit data to calculate the cost of controlling emissions and is typically 

considered to be accurate within ±30%. Overfire air will not require large pieces of 

new equipment, but instead the costs consist primarily of labor and materials related 

to modifying the boiler waterwall tubes to allow for new air injection ports and the 

necessary ductwork, dampers, and instrumentation and control to supply the air from 

the existing secondary air duct. In a technical support document issued by the 

Northeast States for Coordinated Air Use Management (NESCAUM) entitled “NOx

 21 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 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

Regional Haze Reasonable Progress Analysis - Nixon Page 22 

Controls for Existing Utility Boilers,”23 OFA alone ranges from $410 - $1,100 per ton 

NOx reduced annually for units estimating 15 – 30% NOx control, which is within the 

range of Nixon’s estimated OFA NOx reductions (25%). The estimates in Table 17 

and Table 18 are within this range. Therefore, the Division concurs with the OFA 

cost estimates. 

ULNBs: CSU’s cost estimate includes the burners, oil or gas lighter systems and 

controls at burner front, automatic air register adjustment and control drives, flame 

scanners and controls, all wind box controls including control drawings, all control 

and burner logic drawings. The estimates do not include burner wind box extensions 

or stove pipe, ducts installed on top of existing wind boxes, furnace water wall 

openings, structural steel support for ULNBs beyond supplemental support steel, cost 

for engineering, supply and construction of wind box extensions, physical modeling, 

math modeling, or wind box baffling, pulverizer upgrades, burner piping or classifiers 

for improved coal fineness and required size distribution. CSU notes that some or all 

of the items must be determined by boiler modeling and pulverizer testing. If all of 

these are needed, the capital costs could increase by 40 – 70% compared to the base 

scope listed in Table 18. The Division considers CSU’s estimated costs more than 

reasonable, with ULNBs at about $1,200/ton which is comparable or lower than LNB 

costs presented in recent NESCAUM papers.24, 25

ULNB+OFA: The Division based cost estimates for this control option assuming that 

OFA and ULNBs will be installed separately; therefore, the cost for this layering 

option is a summation of individual annualized costs for OFA and ULNBs for each 

unit. The Division checked this assumption with CSU on November 8, 2010. 

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

capital recovery and 65 – 85% for operating expense.26 A similar Colorado facility 

estimated operating expenses at approximately 81 – 86%.27 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.28 

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

http://www.epa.gov/ttn/nsr/gen/u3-26.pdf 24 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. www.nescaum.org/documents/nox-2000.pdf 25 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

http://www.epa.gov/ttn/nsr/gen/u3-26.pdf 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 CENC, 2009. “NOx Technical Feasibility and Emission Control Costs for Colorado Energy Nations, Golden, 

Colorado.” Prepared by AECOM. 28 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

Regional Haze Reasonable Progress Analysis - Nixon Page 23 

The Division used information from a similar facility submittal to determine 

approximate SNCR costs scaled for the Nixon boiler since CSU did not have SNCR 

information.29 The Division consulted with CSU on this decision to ensure that these 

boilers are roughly equivalent to the Nixon boiler in scope and retrofit difficulty. 

The resultant cost effectiveness for SNCR on Units 1 is approximately $4,500 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.30,31 EPA’s SNCR Fact Sheet cites SNCR as costing from 

$400 - $2,500 per ton of NOx reduced. 32 Although the resulting cost estimates for the 

Nixon boiler greater than these ranges, the smaller size of the boiler as well as the 

difficulty of the retrofit leads the Division to the conclusion that the estimated cost 

estimates for SNCR are reasonable. 

SCR: CSU estimated the cost for the SCR system(s) using the IECCOST program. 

This estimate includes the cost of a new ID booster fan, since CSU/URS noted that 

the current ID fan does not have sufficient capacity to accommodate the additional 

pressure drop of the SCR retrofit. Recent NESCAUM studies estimate SCR retrofits 

achieving NOx emission rates of 0.05 – 0.15 lb/MMBtu and emission reductions of 65 

– 85% as costing $2,600 - $7,400 per ton of NOx reduced, depending on initial capital 

costs and capacity factor.33,34 The SCR system estimates for the CSU Nixon boiler is 

approximately $6,400, which is within the NESCAUM estimates. The Division 

concurs that CSU cost estimates for SCR controls are reasonable. 

ULNBs/SCR layered approach: CSU chose to examine the ULNB/SCR layered 

approach because the cost of the SCR would be reduced somewhat in this scenario. 

The reduced costs would be noted in the reactor housing, amount of catalyst required, 

and the aqueous ammonia storage, handling, and injection. Therefore, this option was 

examined to determine the significance of the potential cost differential. The 

Division concurs that this is an appropriate option and may possibly reduce costs. 

Table 17 illustrates resultant NOx emissions for each technically feasible control 

option. Table 18 shows the NOx control costs for each unit based on detailed cost 

analyses. The Division estimated resultant NOx using annual average reductions for 

 29 CENC, 2009. “NOx Technical Feasibility and Emission Control Costs for Colorado Energy Nations, Golden, 

Colorado.” Prepared by AECOM. 

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

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

31 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. 

32 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 33 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

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

34 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

Regional Haze Reasonable Progress Analysis - Nixon Page 24 

tons of NOx reduced per year. The Division’s experience with power plants suggest 

that the maximum 30-day rolling average NOx emission rate is 5-15% higher than the 

annual average emission rate. 

Table 17: Unit 1 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Unit 1

Annual 

Emissions 

(tons/year)

Annual Average 

(lb/MMBtu)

30-day rolling 

(lb/MMBtu)

Baseline --- 2,357 0.258

Ultra-low NOx burners 

(ULNBs)

20 1,885 0.206 0.24

Overfire air (OFA) 25 1,768 0.194 0.22

ULNBs+OFA 30 1,650 0.181 0.21 

Selective Non-Catalytic 

Reduction (SNCR)

30 1,650 0.181 0.21

ULNB+SCR 73 636 0.070 0.080

Selective Catalytic 

Reduction (SCR)

73 636 0.070 0.080

Table 18: Unit 1 NOx Cost Comparison 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost 

Effectiveness 

($/ton)

Incremental 

Cost ($/ton)

Baseline 0 $0 $0 ---

Ultra-low NOx burners 

(ULNBs)

471 $567,000 $1,203 $1,203 

Overfire air (OFA) 589 $403,000 $684 ($1,392)

ULNBs+OFA 707 $907,000 $1,372 $4,812 

Selective Non-Catalytic 

Reduction (SNCR)

707

$3,226,877

$4,564 --- 

ULNB+SCR 1,720.4 $11,007,000 $6,398 $7,677 

Selective Catalytic 

Reduction (SCR)

1,720 $11,010,000 $6,400 ---

Factor 2: Time Necessary for Compliance

Based on other Colorado facility submittals35, the Division anticipates that the time necessary for 

completing design, permitting, procurement, pipeline installation, and system startup and 

 35 Prepared for Black Hills Colorado Electric by CH2M Hill, December 2009. “Black Hills Clark Station NOx 

Reduction Feasibility Study.” Pgs. 3-13 and 3-14. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 25 

shutdown, after SIP approval, it would take CSU be approximately 2-3 years for SNCR and 3-4 

years for SCR. This timeframe may vary somewhat due to regional demand for natural gas and 

to schedule the necessary major maintenance outage with other regionally affected utilities. 

Factor 3: Energy and Non-Air Quality Impacts

OFA: Overfire air does not have any significant energy or non-air quality related impacts. Thus, 

this factor does not influence the selection of this control. 

ULNBs: The additional energy required to further pulverize coal is relatively small and is 

accounted for in CSU’s February 2009 submittal. Therefore, ULNBs do not have any significant 

energy or non-air quality related impacts. Thus, this factor does not influence the selection of 

this control. 

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. SCR reagent injection systems have 

minimal power requirements. 

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

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

equipment, drive the pumps and fans necessary to supply reagents, overcome additional pressure 

drops caused by the control equipment, and provide steam in some cases. 100 – 300 kW is less 

than 1.0% of the power generated by the Drake Unit 7 boiler annually, or enough energy to 

power about 10 homes for a year. These energy requirements are minimal. 

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. CSU has indicated to the Division that they would prefer to use aqueous 

ammonia instead if applicable to ensure personnel and surrounding community safety, and based 

the capital and operating costs of a SCR system on a aqueous ammonia reagent versus an 

ammonia reagent. 

Factor 4: Remaining Useful Life
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 26 

CSU asserts that the remaining useful life of Nixon 1 is in excess of 20 years, which is the 

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

the selection of controls. 

Factor 5 (optional): 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 19 shows the number of days pre- and 

post-control. Table 20depicts the visibility results (98th percentile impact and improvements) as 

well as cost effectiveness in $/deciview and the calculation methodology utilized by the 

Division. 

The state performed modeling using the maximum 24-hour rate during the baseline period, and 

compared resultant annual average control estimates. In the state’s experience and other state 

BART proposals, 30-day NOx rolling average emission rates are expected to be approximately 

5-15% higher than the annual average emission rate. The state projected a 30-day rolling 

average emission rate increased by 15% for all NOx emission rates to determine control 

efficiencies and annual reductions. 

Table 19: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

NOx Control 

Scenario 

Unit(s) Class I 

Area 

Affected 

3-year 

totals 

 3-year 

totals 

 

PreControl 

Days >0.5 

dv 

PostControl 

Days >0.5 

dv 

∆days PreControl 

Days >1.0 

dv 

PostControl 

Days >1.0 

dv 

∆days

Max 24-hour 

NOx rates 

1 

RMNP 

17 --- --- 6 --- --- 

ULNBs @ 0.21 

lb/MMBtu 

1 

17 15 2 6 4 2 

OFA @ 0.19 

lb/MMBtu 

1 

17 15 2 6 4 2 

ULNBs+OFA @ 

0.18 lb/MMBtu 

1 

17 15 2 6 4 2 

SNCR @ 0.18 

lb/MMBtu 

1 

17 15 2 6 4 2 

SCR @ 0.07 

lb/MMBtu 

1 

17 12 5 6 3 3 

Table 20: Visibility Results - NOx Control Scenarios 

NOx Control 

Scenario 

Unit(s) Output (@ 98th

Percentile 

Impact)* 

98th Percentile 

Impact 

Improvement 

98th Percentile 

Improvement from 

Maximum 

Cost 

Effectiveness 

(deciviews) (deciviews) (%) ($/deciview) 

Max 24-hour NOx 

rates 

1 0.91 --- --- --- 

ULNBs @ 0.21 

lb/MMBtu 

1 0.77 0.15 16% $3,831,081 

OFA @ 0.19 

lb/MMBtu 

1 0.76* 0.15 17% $2,616,883 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nixon Page 27 

ULNBs+OFA @ 

0.18 lb/MMBtu 

1 0.75* 0.16 18% $6,024,845 

SNCR @ 0.18 

lb/MMBtu 

1 0.75* 0.16 18% $20,042,714 

SCR @ 0.07 

lb/MMBtu 

1 0.68 0.24 26% $46,639,831 

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

Summary” for more details. 

Determination

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

NOx RP for Nixon Unit 1 the following NOx emission rate: 

Nixon Unit 1: 0.21 lb/MMBtu (30-day rolling average) 

The state assumes that the emission limit can be achieved with ultra-low NOx burners with over 

fire air control. The Division notes that ultra-low NOx burners with over-fire air is the 

appropriate RP determination for Nixon Unit 1 due to the low cost effectiveness. SNCR would 

achieve similar emissions reductions at an added expense. Therefore, SNCR was determined to 

not be reasonable considering the low visibility improvement afforded. 

V. RP Evaluation for Fugitive Dust Sources: Coal Reclaim Conveyor (003) and Coal 

Handling (008)

Both of these fugitive dust sources are permitted within Colorado Operating Permit 

95OPEP106. 

Coal handling is comprised of five (6) parts – reclaim tunnel bagfilter vent, coal crusher 

building bagfilter vent, coal gallery bagfilter vents, and coal train off-loading-conveyingstockpiling. It should be noted that while these two sources are reported individually in 

Colorado’s emission inventory, in the Operating Permit, these sources are combined 

together since coal handling is treated as one point. Colorado Regulation No.1.II.A.1 

limits opacity from these sources to 20%. This source is also subject to NSPS Subpart Y, 

New Source Performance Standards for Coal Preparation Plants. Additionally, the 

following measures to control fugitive dust via a fugitive particulate emissions control 

plan (Condition 3.4): 

• A wet dust suppression system shall be used for railroad car unloading. 

• Above ground conveyors to and from the transfer building must be covered. 

• Loadout to storage must by telescoping chute. 

• Emissions from coal storage piles shall be effectively controlled by application of 

chemical binders and by watering, if need be. 

These existing controls and corresponding emission limits in Section II, Condition 3 of 

Operating Permit 95OPEP106 represent the most stringent level of control available for 

these fugitive dust sources. 

Therefore, the Division proposes that RP for these sources is no additional control and 

the current emission limit for the above units is RP.