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

Regional Haze Reasonable Progress Analysis - Rawhide Page 1 

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

For 

Platte River Power Authority – Rawhide Energy Station

I. Source Description

Owner/Operator: Platte River Power Authority 

Source Type: Electric Utility Steam Generating Unit 

SCC (EGU): 1010026 

Boiler Type: Pulverized Coal Dry-Bottom Tangentially-Fired 

 

The Platte River Power Authority (PRPA) Rawhide Energy Station is located in Larimer County 

approximately 10 miles north of the town of Wellington, Colorado. The Rawhide Energy Station 

consists of one coal fired steam driven electric generating unit (Unit 101), with a rated electric 

generating capacity of 305 MW (gross), and was placed into service in 1984. The boiler is 

equipped with a fabric filter (baghouse) system for controlling particulate matter (PM) emissions, 

and a lime spray dry absorber controls sulfur dioxide (SO2). The boiler is equipped with low 

nitrogen oxide (NOx) concentric firing system (LNCFS) burners with separated overfire air 

(SOFA) configuration for minimization of NOx emissions, installed in 2005. 

The Rawhide Station also has five natural-gas fired combustion turbines, designed to operate in a 

simple cycle mode, four rated at a heat input of 831.1 MMBtu/hour (approximately 82 MW) and 

one rated at a heat input of 1,400 MMBtu/hour (about 150 MW). Each turbine is equipped with 

integral dry low NOx combustion systems and inlet air fog cooling systems and startup and 

shutdown duration average NOx and CO emission limits determined to be Best Available Control 

Technology (BACT)1 since each turbine is subject to Prevention of Significant Deterioration 

(PSD) provisions. These turbines were placed into service starting in May 2002, with the last 

turbine (150 MW) started up in June 2008. The primary use of these units is to meet Platte River’s 

energy reliability and peak load requirements. The turbines operate on limited, intermittent, and 

unpredictable schedules as peak loading units. Additionally, the facility includes a number of 

fugitive dust sources. PRPA has prepared a Reasonable Progress (RP) analysis as well as 

supplemental information which can be found in “PRPA RP Submittals”. 

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

regarding the Rawhide facility, and information about similar facilities to determine RP for PM10

and SO2 (available in the TSD). 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. 

For the purposes of evaluating RP, the Division has elected to set de minimis thresholds for any 

emission unit at a subject-to-RP source with actual baseline emissions of SO2, NOx, or PM10 equal 

 1

 Colorado Air Pollution Control Division, 2004. Colorado Operating Permit 03OPLR261: Rawhide Energy Station. 

Section II: Condition 1.7, pages 10 – 13. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 2 

to or exceeding the federal Prevention of Significant Deterioration (PSD) significance levels. The 

Division has established de minimis thresholds for SO2, NOx and PM10 to focus the technical 

emission control analysis on significant emission sources where potential controls could provide a 

meaningful improvement in visibility if emission controls are determined to be cost effective. 

The de minimis levels are applicable to individual emission units at a stationary source. The 

Division defines “emissions unit” as “any part or activity of a stationary source that emits or has 

the potential to emit any air pollutant regulated under the state or Federal Acts. This term is not 

meant to alter or affect the definition of the term “unit” for purposes of Title IV (acid deposition 

control) of the federal act, or of the term “source” for purposes of the Air Pollutant Emission 

Notice requirements of Regulation Number 3, Part A, Section II.B.3. 2

 .” These de minimis levels 

are as follows: 

• NOx – 40 tons per year 

• SO2 – 40 tons per year 

• PM10 – 15 tons per year 

Emissions Unit P301 serves as a detailed example of evaluating one “unit” in Table 1. As the 

PM10 emissions from emissions unit P301 are below the de minimis level of 15 tons per year, it is 

exempted from any further analysis under RP. 

 

Table 1: Unit Detail Example for de minimis Threshold 

Unit P301 Breakdown

2006 – 2008 Average PM10 Emissions 

(Baseline Actual Emissions)

Solid Wastes Silo Rotary Unloader 

Discharge 0.41 

Solid Wastes Hauling to Landfill 1.64

Solid Wastes Haul Truck Unloading 0.02

Active/Exposed Landfill Area 0.21

Waste Landfilling/Reclamation 0.39

Bottom Ash Excavation and Loading 0.02

Solid Wastes Silo Filling 0.00

Solids Vacuum Conveying System and 

Silo Filling 0.17

Fly Ash and Solid Waste Silo Dry 

Unloading and Haul Truck Loading 0.02

Unit P301 Baseline PM10 Emissions 3.01 << 15 (PSD threshold)

 

Rawhide Unit 101 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. PRPA submitted a 

“Rawhide NOx Reduction Study” on January 22, 2009 as well as additional relevant information 

on May 5 and 6, 2010. Table 2 depicts technical information for Rawhide Unit 101. 

 2

 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 - Rawhide Page 3 

Table 2: Rawhide Unit 101 RP-eligible Emission Controls and Reduction (%) 

 Rawhide Unit 101 

Placed in Service 1984 

Boiler Rating, MMBtu/Hr for 

coal 3,000 

Electrical Power Rating, Gross 

Megawatts 305 

Description 

Combustion Engineering 

tangentially fired, dry bottom 

steam generator/boiler firing 

pulverized coal. 

Air Pollution Control 

Equipment 

Fabric Filter (baghouse) for 

PM/PM10 control 

Spray Dryer Removal System 

for SO2 control 

Special Features 

Low NOx Concentric Firing 

System (LNCFS) with separated 

overfire air (SOFA) installed in 

2005 

Emissions Reduction (%)1 

NOx – 49.6% 

SO2 – 83.1% 

PM/PM10 – 99.2/96.7% 1

Emissions Reduction estimated by comparing uncontrolled AP-42 factor to actual average 

emission factor for PM/PM10. For SO2 estimates, CAMD data (average of 2006 – 2008) was used 

to calculate reduction %. The NOx reduction is based on actual data from pre-2005 actual 

emissions. See “Rawhide APCD Technical Analysis” for further details. Not based on actual 

testing. 

For the boiler, the Voluntary Emissions Reduction Agreement (VERA) permit limit for NOx is 

0.180 lbs/MMBtu on an annual average effective July 15, 2006. The Acid Rain permit limit for 

NOx is currently 0.40 lbs/MMBtu on an annual average and the PSD/NSPS limit is 0.50 

lbs/MMBtu on a 30-day rolling average. 

In October of 2005, PRPA installed a low NOx Concentric Firing System (LNCFS) with separated 

overfire air (SOFA) on Unit 101 that resulted in an approximate 50% reduction of NOx emissions 

(from pre-2005 actual emissions) in accordance with the Voluntary Emissions Reduction 

Agreement entered into with the State of Colorado in 20023

. 

Rawhide Unit 101 was initially installed in 1984 with a baghouse for particulate emission 

(PM/PM10) control, with control efficiency exceeding 99.9%. This system was BACT at the time 

of initial startup and is still considered BACT currently. 

The “Spray Dryer Removal System” for Unit 101 was considered a new control technology at the 

time of installation in 1984 and started up at the same time as Rawhide Unit 101. This system 

originally reduced SO2 emissions by approximately 80% and 0.13 lbs/MMBtu (30-day rolling 

average) (from AP-42 emission calculations) according to Federal PSD emission standards at that 

time (0.2 lbs/MMBtu annually). In 2003, PRPA entered into a Voluntary Emissions Reduction 

Agreement with the State of Colorado to reduce SO2 emissions to 0.09 lbs/MMBtu (annual 

 3

 Colorado Air Pollution Control Division, 1992. Exhibit A: Division Evaluation of Nitrogen Oxides Emission 

Limitation and Regulatory Assurance Periods. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 4 

average) by upgrading the lime spray dryer system4. This upgraded system resulted in an 

approximate 30% emission rate reduction of SO2 emissions from pre-VERA emission rates. 

II. Source Emissions

Table 3 summarizes the NOx, SO2, and PM10 actual emissions averaged over the 2006 – 2008 

baseline timeframe from EPA’s CAMD Database for the facility. Table 4 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 APEN’s submitted by the facility and as applicable, EPA’s 

CAMD Database (primarily for the Unit 101 boiler and the turbines). 

Table 3. Summary of 2006 - 2008 Averaged Emissions - PRPA Rawhide Facility 

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

1,885 914 125 

Table 4. Summary of 2006 - 2008 Averaged Emissions by Unit - PRPA Rawhide Facility 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

Unit 101 Boiler 

SO2 (tons) 943 928 869 913 

SO2 

(lb/ MMBtu) 0.078 0.081 0.078 0.081 

NOx (tons) 1,990 1,863 1,745 1,866 

NOx (lb/ MMBtu) 0.163 0.162 0.173 0.166 

PM10 (tons) 109 113 101 108 

PM10 (lb/ MMBtu) 0.018 0.017 0.018 0.018 

Turbine Unit A (82 MW) SO2 (tons) 0.10 0.12 0.12 0.11 

 NOx (tons) 1.17 5.45 0.75 2.46 

 PM10 (tons) 0.20 1.12 0.13 0.48 

Turbine Unit B (82 MW) SO2 (tons) 0.09 0.06 0.11 0.09 

 NOx (tons) 3.87 3.17 5.07 4.04 

 PM10 (tons) 0.77 0.58 0.99 0.78 

Turbine Unit C (82 MW) SO2 (tons) 0.04 0.09 0.03 0.05 

 NOx (tons) 2.03 4.45 1.65 2.71 

 PM10 (tons) 0.33 0.80 0.30 0.48 

Turbine Unit D (82 MW) SO2 (tons) 0.05 0.10 0.03 0.06 

 NOx (tons) 2.53 4.95 1.50 2.99 

 PM10 (tons) 0.45 0.85 0.26 0.52 

Turbine Unit F (150 MW)** SO2 (tons) 0.38 0.38 

 NOx (tons) 20.45 20.45 

 PM10 (tons) 3.75 3.75 

P201 Train Unloading 

Facility PM10 (tons) 0.60 0.01 0.01 0.20 

P201 Active Coal Pile 

Reclaim PM10 (tons) 0.03 0.02 0.00 0.02 

P201 Coal Silo Filling and 

Conveyor Belt Transfer PM10 (tons) 0.30 0.00 0.00 0.10 

P201 Coal Silo Discharge to 

Conveyor Belt PM10 (tons) 0.28 0.00 0.00 0.10 

P201 Coal Crushing and PM10 (tons) 0.33 0.02 0.02 0.12 

 4

 Colorado Air Pollution Control Division, 1992. Exhibit B: Division Evaluation of Sulfur Dioxides Emission 

Limitation and Regulatory Assurance Periods. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 5 

Conveying 

P201 Coal Conveyor Belt 

Transfer PM10 (tons) 0.30 0.00 0.00 0.10 

P201 In-Plant Silo Filling 

Conveyor Belt Transfer PM10 (tons) 0.30 0.00 0.00 0.10 

P201 Coal Pile Stockout PM10 (tons) 1.18 0.01 0.02 0.40 

P201 Active Coal Storage 

Area PM10 (tons) 0.93 1.91 1.96 1.60 

P201 Active Coal Pile 

Storage Area PM10 (tons) 0.95 2.56 2.56 2.02 

P201 Coal Crusher Stockout PM10 (tons) 0 0 0 0.00 

P201 Coal Conveying PM10 (tons) 1.81 1.23 1.09 1.38 

P301 Solid Wastes Silo 

Rotary Unloader Discharge PM10 (tons) 0.70 0.28 0.25 0.41 

P301 Solid Wastes Hauling 

to Landfill PM10 (tons) 1.82 1.67 1.44 1.64 

P301 Solid Wastes Haul 

Truck Unloading PM10 (tons) 0.04 0.02 0.01 0.02 

P301 Active/Exposed 

Landfill Area PM10 (tons) 0.19 0.24 0.19 0.21 

P301 Waste 

Landfilling/Reclamation PM10 (tons) 0.13 0.57 0.46 0.39 

P301 Bottom Ash 

Excavation and Loading PM10 (tons) 0.03 0.02 0.02 0.02 

P301 Solid Wastes Silo 

Filling PM10 (tons) 0.02 0.20 0.17 0.13 

P301 Solids Vacuum 

Conveying System and Silo 

Filling PM10 (tons) 0.17 0.18 0.16 0.17 

P301 Fly Ash and Solid 

Waste Silo Dry Unloading 

and Haul Truck Loading PM10 (tons) 0.02 0.02 0.01 0.02 

P401 Scrubber Lime 

Storage Silo Filling PM10 (tons) 0 0.01 0.01 0.00 

P401 Recycle Ash Storage 

Silo Filling PM10 (tons) 0.11 0.89 0.81 0.60 

P501 Unpaved Site 

Roadways and Parking Lots PM10 (tons) 3.14 3.92 4.23 3.76 

P501 PRS Soda Ash Storage 

Silo Filling PM10 (tons) 0 0 0 0.00 

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

30-day rolling averages for the Unit 101 Boiler are estimated to be 5-15% higher than the annual average emission 

rate (i.e. the maximum 30-day NOx rolling average is likely about 0.190 lbs/MMBtu). 

**Note that Unit F did not start up until June of 2008; therefore it was not operated in 2006 or 2007 and for only 

half of 2008. 

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

for the purposes of reasonable progress. 

Each of the five turbines at Rawhide Station was installed with an advanced dry low-NOx

combustion system that controls NOx emissions to less than 9 ppm @ 15% O2 as well as a gas 

turbine inlet air fog cooling system designed for optimal power augmentation during hot weather 

operations. . Each turbine is subject to BACT under the PSD provisions. The turbines are also 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 6 

required to use pipeline quality natural gas as defined by the Acid Rain Provisions 40 CFR Part 

72. The Title V permit enforces a compliance SO2 emission factor of 0.0006 lb/MMBtu for each 

turbine. These combustion turbines are further evaluated within the source category 

“Combustion Turbines” in Section 8.2.3 of the Regional Haze SIP. 

 

III. Units Evaluated for Control

As documented by PRPA, Rawhide Unit 101 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 - 2008 Averaged APEN data) 

 Specifications 

Emission Unit Fuel Heating Value 

(Btu/lb) 

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

Rawhide Unit 101 8,853 0.24 5.42 

Table 4 lists the units at Rawhide 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 Rawhide Unit 101 

Emission Unit Pollutant 

Fuel 

Coal (sub-bituminous) (lb/ton) 

Rawhide Unit 1015

NOx 7.2 

SO2 35 x %S = 8.5* 

PM/PM10 PM – 54.2** 

PM10 – 12.5 

*%S = % of sulfur present in coal supply. For example, 35 x 0.24 = 8.5 

**%A = % of ash present in coal supply. For example, 10 x 5.42 = 54.2 

IV. Reasonable Progress Evaluation of Unit 101

a. Sulfur Dioxide 

Step 1: Identify All Available Technologies 

PRPA identified one SO2 control option: 

Fuel Switching – Natural Gas or Colorado Coal 

The Division requested that PRPA evaluate the option below, and received relevant information 

for this request on May 5, 2010: 

Dry FGD upgrades 

As discussed in EPA’s BART Guidelines6, electric generating units (EGUs) with existing 

controls achieving removal efficiencies of greater than 50 percent are not required to remove 

these controls and replace them with new controls. 

 5

 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 6

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

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

Regional Haze Reasonable Progress Analysis - Rawhide Page 7 

However, upgrades need to be considered for the scrubber if technically feasible. These 

upgrades include: 

 -Use of performance additives 

 -Use of more reactive sorbent 

 -Increase the pulverization level of sorbent 

 -Engineering redesign of atomizer or slurry injection system 

Step 2: Eliminate Technically Infeasible Options 

Fuel Switching – Natural Gas or Colorado Coal: The Division and PRPA both assert that the 

Unit 101 boiler at Rawhide could convert fuels from coal to natural gas with boiler modifications 

and natural gas pipeline construction. Conversion from coal to natural gas would reduce SO2

emissions by about 906 tons per year, or approximately 99% (using 2006 - 2008 CAMD data 

average)7. SO2 emissions from coal combustion are affected by the chemical and physical 

properties of the feed coal. Feed coal characteristics significantly affect the design and operation 

of combustion controls, such as the existing LNB+SOFA system. With the dry FGD – lime 

spray dryer system in place, Unit 101 currently achieves an emission rate of 0.07 lb/MMBtu 

(annual average). 

PRPA notes that Unit 101 is designed to burn PRB coal and the boiler is additionally optimized 

through a technologically complex process to burn this coal at very tightly controlled rate. 

PRPA has indicated that it is infeasible as well as economically impractical to change coal 

supplies. The sulfur content of the Rawhide Unit 101 PRB coal supply is between 0.8 – 1.4 

lb/MMBtu with most of the supply containing less than 1.2 lbs/MMBtu (based on northern 

Wyoming PRB coal mine reports). The average sulfur content in the coal is 0.29%. PRPA 

obtains coal for Rawhide Unit 101 from the Antelope Mine in Converse County, Wyoming, 

which has one of the lowest sulfur content of any mine in the county. PRPA additionally pays a 

premium to ensure higher Btu/lower sulfur coal. A review by the Colorado Geological Survey 

found that on average, Wyoming coal had similar sulfur content to Colorado coal8

. Virtually all 

Colorado coal contains less than 1 percent sulfur and most of it contains less than half of that 

amount (0.5% or less)9

. Therefore, the sulfur content of the Antelope Mine coal is similar, if not 

lower, than Colorado coal. 

The Division has determined that fuel switching to natural gas is technically feasible for 

Rawhide Unit 101. However, fuel switching to Colorado coal will not further reduce SO2

emissions from Unit 101 and will not be considered further in this analysis. 

Dry Flue Gas Desulfurization (FGD) Upgrades: Dry FGD systems are commonly known as 

spray dry absorbers (SDA), and currently make up about 12% of FGD systems at U.S. power 

 7

 Colorado Air Pollution Control Division Technical Analysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 

2010. See Appendix D of the SIP for detailed calculations. 

8

 Colorado Geological Survey: RockTalk. Volume One, Number Three. July 1998. 

http://geosurvey.state.co.us/pubs/rocktalk/rtv1n3.pdf

9

 Colorado Geological Survey: RockTalk. Volume One, Number Three. July 1998. 

http://geosurvey.state.co.us/pubs/rocktalk/rtv1n3.pdf
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 8 

plants10. SDA systems are typically utilized at smaller units that burn lower-sulfur in the western 

U.S., where water resources are limited. A SDA system captures SO2 by using a slaked lime 

containing slurry that is sprayed into the flue gas and reacts with the SO2 to form calcium sulfate, 

and then is subsequently dried by the heat of the flue gas, and collected in a particulate control 

device. 

Rawhide Unit 101 was installed in 1984 with a “Spray Dryer Removal System” in connection 

with the aforementioned baghouse for control of the resultant SDA materials. At the time, the 

system was a new control technology for SO2 removal from the gaseous emission stream of a 

utility boiler. PRPA has since upgraded this system (in 2002) and currently achieves greater than 

80% SO2 removal, with an actual annual average of 0.07 lb/MMBtu and a permit limit of 0.09 

lb/MMBtu on an annual average basis, 0.13 lb/MMBtu on a 30-day average, and 0.19 

lbs/MMBtu on a 3-hour rolling average. This system exceeds EPA’s presumptive limits stated in 

40 CFR part 51 Appendix Y of 0.15 lb/MMBtu11. Lime spray dryers have been determined to be 

Best Available Control Technology (BACT) for new Electric Generating Unit (EGU) sources 

proposed in the West according to EPA’s RBLC (RACT/BACT/LAER Clearinghouse) database. 

The RBLC database lists recent BACT determinations ranging from 0.06 – 0.167 lb/MMBtu, 

with an average of 0.11 lb/MMBtu on a 30-day rolling average. Refer to Appendix D for more 

details regarding recent RBLC BACT determinations. Additionally, an EPA Report regarding 

the control of SO2 emissions found that lime spray drying processes have a range of design 

efficiencies from 70 – 96% and a median design efficiency of 90%; however, application 

conditions may differ (e.g. coal sulfur percent)12 . 

PRPA submitted a SO2 upgrade analysis to the Division on May 6, 2010 upon request regarding 

potential upgrades for the dry FGD scrubber system. PRPA asserts that operating the SO2 

scrubber at the 0.09 lbs/MMBtu VERA limit pushes many of the scrubber’s material handling 

and slurry preparation sub-systems to the limits of their design capacity. As part of the VERA 

scrubber improvements, the recycle ash pressure feeders were upgraded and the recycle ash 

conveying line was replaced with larger diameter piping to increase the recycle ash conveying 

capacity between the solids waste silo and recycle ash storage bin/silo. Moving beyond current 

levels of scrubber operation would require additional equipment upgrades and would reduce the 

existing redundancy in some critical scrubber sub-systems. Specifically, the recycle ash blowers, 

bin vent filter on recycle ash silo, feed slurry preparation pumps, and feed slurry tanks are all 

operating at maximum throughput levels or at the margin and would need to be replaced with 

larger capacity equipment. While there is usually available redundancy within the lime slaking 

sub-system, a lower SO2 limit would diminish this available capacity and likely also require an 

upgrade to ensure adequate margin. 

PRPA notes that the SO2 scrubber has three atomizer reaction compartments that provide critical 

operating flexibility. The scrubber generally operates with all three compartments in-service, 

 10 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. 11 Colorado Operating Permit 96OPLR142 pg. 5 – SO2 30-day rolling average limit is 0.13 lb/MMBtu. 12 EPA, 2000. “Controlling SO2 Emissions: A Review of Technologies.” Prepared by Ravi K. Srivastava for Office 

of Research and Development, Washington, D.C. 20460. Pg. 33. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 9 

which provides maximum reaction/residence time, eases SO2 removal equipment demands, and 

minimize pressure drop. Though not a desirable operating mode, the scrubber is currently 

capable of operating at full load with only two atomizer compartments in-service. In addition to 

the improved scrubber performance, the current atomizer compartment redundancy provides 

critical atomizer operational and maintenance flexibility, ensuring environmental compliance, 

and providing for high SO2 scrubber and unit availability. Achieving a lower SO2 limit may 

compromise atomizer compartment redundancy, which will significantly diminish scrubber 

operational and maintenance flexibility. This loss of redundancy and flexibility will likely result 

in increase malfunctions and could also affect unit availability if load reduction is triggered. 

Even with the potential scrubber equipment upgrades, additional SO2 reductions will still present 

unacceptable operational challenges. SO2 scrubbing is limited by scrubber outlet temperatures 

which must remain above the fluegas dew point with an adequate margin to prevent 

condensation and catastrophic damage to the baghouse. Over-spraying below minimum SDA 

outlet temperatures also results in higher moisture ash in the baghouse that is difficult to convey 

from the collection hoppers. 

Given existing spray-down temperature constraints, reducing SO2 emissions below 0.09 

lbs/MMBtu requires additional lime to increase feed slurry reactivity. At higher SO2 removal 

rates, the lime/SO2 stoichiometry increases and more unreacted lime is carried-over with the 

flyash and scrubber waste to the baghouse. The higher lime content in the flyash and scrubber 

waste affects the fluidity of the material making it harder to pneumatically convey out of and 

between the baghouse hoppers, solid waste silo, and recycle ash storage bin/silo. Hopper 

bridging and conveying piping pluggage are significant operational and maintenance issues 

impacting SO2 scrubber reliability. Lowering the SO2 emissions below the VERA limit will 

increase the potential for scrubber and baghouse malfunctions. 

PRPA examined BART-guideline dry scrubbing potential upgrades, with the following results: 

-Use of performance additives: Performance additives are typically used with dry-sorbent 

injection systems, not semi-dry SDA scrubbers that spray slurry products. PRPA and the 

Division are not aware of SO2 scrubber performance additives applicable to the Unit 101 SDA 

system. Therefore, this upgrade is not technically feasible for the dry scrubbing system. 

-Use of more reactive sorbent: Lime quality is critical to achieving the VERA emission limit. 

PRPA utilizes premium lime at higher cost to ensure compliance with the VERA limit. The lime 

contract requires >92% reactivity (available calcium oxide) lime to ensure adequate scrubber 

performance. Therefore, this upgrade is not technically feasible for the dry scrubbing system. 

-Increase the pulverization level of sorbent: The fineness of sorbents used in dry-sorbent 

injection systems is a consideration and may improve performance for these types of scrubbers. 

Again, the Unit 101 SO2 scrubber is a semi-dry SDA type scrubber that utilizes feed slurry that is 

primarily recycle-ash slurry with added lime slurry. PRPA recently completed SDA lime slaking 

sub-system improvements are designed to improve the reactivity of the slaked lime-milk slurry. 

Therefore, this upgrade is not technically feasible for the dry scrubbing system. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 10 

-Engineering redesign of atomizer or slurry injection system: The Unit 101 SDA scrubber 

utilizes atomizers for slurry injection. The scrubber utilizes three reactor compartments, each 

with a single atomizer. PRPA maintains a spare atomizer to ensure high scrubber availability. 

The atomizers utilize the most current wheel-nozzle design. Therefore, this upgrade is not 

technically feasible for the dry scrubbing system. 

The Division concludes that upgrades are not technically feasible for the Unit 101 Boiler. 

Fuel switching to Colorado coal will not provide further SO2 emission reductions. Rawhide Unit 

101 has a SDA system for which the State has determined that no upgrades are feasible. 

Therefore, the Division has conducted a four-factor analysis for reasonable progress for fuel 

switching to natural gas regarding SO2 reductions. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology 

Fuel Switching – Natural Gas: Conversion from coal to natural gas would reduce SO2 emissions 

by almost 100% from the boiler using EPA’s AP-42 emission factors13 and concurs with PRPA’s 

submittal.

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

on Rawhide Unit 101. 

Table 7: Rawhide Unit 101 SO2 Technology Options and Technical Feasibility 

Technology Emission Reduction 

Potential (%) 

Technically Feasible? 

(Y = yes, N = no) 

Wet FGD 52-98%, median 90%14 Y – not evaluated 

Dry FGD 70 – 90% Y - installed 

DSI (Trona) 60-65% Y – not evaluated, will not provide 

further SO2 control 

Fuel switching – 

different coal type 

None Y – will not provide further SO2 control 

Use of performance additives None N 

Use of more reactive sorbent None N 

Increase the pulverization level of sorbent None N 

Engineering redesign of atomizer or slurry 

injection system 

None N 

Fuel switching – 

natural gas 

99% (EPA AP-42) Y 

Step 4: Evaluate Factors and Present Determination 

 13 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 14 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 - Rawhide Page 11 

Factor 1: Cost of Compliance

 

In 2008, Platte River performed a Unit 101 Natural Gas Conversion Study. The primary 

objective of the study was to determine required unit modifications and associated capital costs 

to co-fire the unit up to 100% using natural gas. The direct capital cost of converting to 100% 

natural gas was estimated to be about $50 million by PRPA15. This results in an initial control 

cost, using EPA’s Cost Control Manual16 to estimate annual operating costs, of about $262,000 

per ton of SO2 removed annually17. Changing to natural gas would dramatically raise fuel costs 

given that natural gas prices are approximately nine (9) times the cost of PRB coal and are 

subject to significant cost variability, which was not taken into account in the 2008 study18. 

To determine annualized costs of switching to natural gas, the annual electricity cost differentials 

between coal and natural gas were analyzed. PRPA notes that when using natural gas, fuel use 

will increase 17% annually due to anticipated efficiency drops, increased heat input 

requirements, and drop in generation. The annual electricity cost of coal is $25.5 million 

compared to natural gas at about $240 million when using 2008 commercial natural gas prices 

reported by the U.S. Energy Information Administration19. Therefore, this results in a 

significant annualized cost increase of $233 million. Refer to Appendix D for details. 

Table 8 and Table 9 illustrate the resultant emissions and costs of switching fuel to natural gas, 

based on the difference between costs of coal and natural gas in 2008 and AP-42 emission 

factors.20 

Table 8: Unit 101 Control Resultant SO2 Emissions 

Alternative Control 

Efficiency (%)*

Resultant Emissions**

(tons/year) (lb/MMBtu)

Baseline --- 913 0.08

Fuel Switching - NG 99% 7.7 0.0006

* Control efficiency calculated by the Division based on PRPA submittal of projected natural 

gas NOx lb/MMBtu estimate. 

** Division calculated from average baseline years (2006 – 2008). This is an annual average. 

Table 9: Unit 101 SO2 Cost Comparison 

Alternative Emissions 

Reduction 

(tpy)

Annualized 

Cost ($)*

Cost 

Effectiveness 

($/ton)*

Incremental 

Cost ($/ton)

Baseline 0 $0 $0 n/a

 15 PRPA, February 18, 2010. “Re: Rawhide Unit 101 NOx Emissions Control Cost and Technical Feasibility 

Information Request – Additional Details and Explanation.” Contained in Appendix D. 

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

Standards, Research Triangle Park, North Carolina, 27711. 17 Colorado Air Pollution Control Division Technical Analysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 

2010. See Appendix D for detailed calculations. 

18 PRPA, February 18, 2010. “Re: Rawhide Unit 101 NOx Emissions Control Cost and Technical Feasibility 

Information Request – Additional Details and Explanation.” Contained in Appendix D. 

19 U.S. Energy Information Administration, 2010. http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_a.htm 20 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 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 12 

Fuel 

Switching - 

NG

906 $237,424,331 $262,169 $262,169

* Division estimate based on PRPA submittal estimating direct capital cost at $50,000,000, 

current delivered coal costs at ~$20/ton, EPA Cost Control Manual, and EPA AP-42 emission 

factors for natural gas. 

Platte River noted that the Division natural gas cost analysis does not account for replacement 

power for the lost generation. The Rawhide Natural Gas Conversion Study performed by B&V 

estimated that a 100% fuel switch would result in a loss of approximately 30 MW, in addition to 

the increased heat rate which was considered. 

Platte River asserts that replacement power cost and associated emissions would depend on the 

specific source. Replacement with coal-fired sources would run in the $20 - $25/MWh range 

($5.3 - $6.6 million/year), while natural gas-fired sources would run in the $60 - $125/MWh 

range ($15.8 – 32.8 million/year). Unaccounted NOx emissions from the replacement power 

sources would likely be around 1.5 lbs/MWh (197 tons/year) for well combustion controlled 

coal-fired sources, and 0.36 lbs/MWh (47 tons/year) for natural gas-fired sources. The 

replacement power prices reflect current conditions and will need to be escalated over the 20-

year 4-factor evaluation period. SO2 emissions would likely be in the 0.7 lbs/MWh (92 

tons/year) for well controlled coal-fired sources and 0.007 lbs/MWH (1 ton/year) for natural gasfired sources. Table 7 below summarizes these costs and emissions. 

Table 10: Unaccounted for Replacement Power Cost & Emissions Estimates (30 MW) 

Power 

Source

Lower Cost 

($/MWh)

Lower Cost ($ 

million/year)

Higher 

Cost 

($/MWh)

Higher Cost ($ 

million/year)

Coal $20 $5.26 $25 $6.57

Natural 

Gas

$60 $15.77 $125 $32.85

Power 

Source

NOx

(lbs/MWh)

NOx

(ton/year)

SO2

(lb/MWh)

SO2

(ton/year)

Coal 1.5 197 0.7 92

Natural 

Gas

0.36 47 0.007 1

Factor 2: Time Necessary for Compliance

Based on other Colorado facility submittals21, the Division anticipates that, taking into account 

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

system startup and shutdown, after SIP approval it would take PRPA approximately 2 – 3 years 

to convert the boiler from coal to natural gas. 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. 

 21Prepared 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 - Rawhide Page 13 

Factor 3: Energy and Non-Air Quality Impacts

The Division has determined that there are not any negative energy or non-air quality related 

impacts related to fuel switching to natural gas for the Unit 101 boiler. Thus, this factor does not 

influence the selection of controls. 

Factor 4: Remaining Useful Life

PRPA asserts that since Rawhide Unit 101 is one of the newest units in Colorado, it 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

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 11 shows the number of days pre- and 

post-control. Error! Reference source not found. depicts the visibility results (98th percentile 

impact and improvements) as well as cost effectiveness in $/deciview and the calculation 

methodology utilized by the Division. 

Table 11: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

SO2

Control 

Scenario 

Unit(s) SO2 

Emission 

Rate 

(lb/MMBtu) 

Class I 

Area 

Affected

3-year totals 3-year totals 

PreControl 

Days 

>0.5 

dv 

PostControl 

Days 

>0.5 

dv 

∆days PreControl 

Days 

>1.0 

dv 

PostControl 

Days 

>1.0 

dv 

∆days

Max 24-

hr SO2

rates 

101 0.11 

RMNP 

20 --- --- 6 --- --- 

dry FGD 101 0.09 n/a 

dry FGD 101 0.07 20 19 1 6 4 2 

Fuel 

Switching 

- NG 

101 0.001 

n/a

Table 12: Visibility Results - SO2 Control Scenarios 

SO2 Control Scenario Unit(s) SO2 Emission Rate Output (@ 

98th

Percentile 

Impact) 

98th

Percentile 

Impact 

Improvement 

98th

Percentile 

Improvement 

from 

Maximum 

(lb/MMBtu) (deciviews) (deciviews) (%) 

Max 24-hr SO2 rates 101 0.11 0.871 

dry FGD 101 0.09* 0.87 0.01 1% 

dry FGD 101 0.07 0.84 0.03 3% 

Fuel Switching - NG 101 0.001 0.00 0.87 100% 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 14 

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

Modeling Summary” for more details. 

Determination

The Division evaluated emission limit tightening based on current operations through the fourfactor analysis. PRPA’s average 30-day rolling emission rate during the baseline period (2006 – 

2008) was 0.09 lb/MMBtu. The maximum 30-day rolling emission rate during this period was 

0.13 lb/MMBtu. Please refer to “Rawhide Cost Analysis” for more detail. The Division and 

PRPA agree that Rawhide can meet an emission limit of 0.11 lb/MMBtu (30-day rolling 

average). 

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

SO2 RP is the following SO2 emission rate: 

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

The state has determined that these emissions rates are achievable without additional capital 

investment. Upgrades to the existing SO2 control system were evaluated, and the state 

determines that meaningful upgrades to the system are not available. Lower SO2 limits would 

not result in significant visibility improvement (less than 0.02 delta deciview) and would likely 

result in frequent non-compliance events and, thus, are not reasonable. 

b. Filterable Particulate Matter (PM10) 

PRPA Unit 101 is currently equipped with two twelve-compartment fabric filter baghouses to 

control PM/PM10 emissions from the boiler. 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 micron in diameter. 

Additionally, fabric filters are the best PM control for western coals, due to the higher electrical 

resistivity. 

PRPA states that the baghouses are able to control PM/PM10 emissions to 0.03 lb/MMBtu and 

further notes that that the baghouses meet a 99.9+% control efficiency. The source was tested on 

November 18, 2009 and ran at 0.0023 lb/MMBtu, 92% lower than the permit limit (Method 5 –

filterable portion). This boiler is subject to 40 CFR Part 60, Subpart Da, which requires 99% 

reduction (for facilities commencing construction after September 18, 1978) of the potential 

combustion concentration when burning solid fuel. A Division review of the PM/PM10 emission 

limits in the current Title V permit revealed that these limits are for filterable PM/PM10

emissions only. 

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

0.010 – 0.10 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 

limit of 0.03 lb/MMBtu is well within the range of recent BACT determinations. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 15 

The State has determined that the existing Unit 101 regulatory emissions limits of 0.03 

lb/MMBtu (PM/PM10) represents the most stringent control option. The state assumes that the 

emission limit can be achieved through the operation of the existing fabric filter baghouses. The 

unit is exceeding a PM control efficiency of 95%, and the control technology and emission limit 

is RP for PM/PM10. Thus, as described in EPA’s BART Guidelines, a full four-factor analysis for 

PM/PM10 is not needed for Rawhide Unit 101. 

c. Nitrogen Oxides (NOx) 

Step 1: Identify All Available Technologies 

PRPA identified eight NOx control options: 

Fuel Switching – Natural Gas 

Selective non-catalytic reduction (SCNR)

Selective catalytic reduction (SCR)

Separated overfire Air (SOFA)

Low NOx Burners (LNB)

LNB + SOFA

ECC – Enhanced Combustion Control 

The Division also identified and examined the following additional control options: 

Electro-Catalytic Oxidation (ECO)®

Rich Reagent Injection (RRI) 

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 load22. 

While ROFA is considered superior to SOFA alone, ROFA alone is not superior to LNB+OFA 

and cannot achieve the greater than 70% NOx reduction already being achieved at Unit 101. 

Since ROFA® technology would not be expected to 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 

Fuel Switching – Natural Gas: The Unit 101 boiler at Rawhide could convert fuels from coal to 

natural gas with boiler modifications. NOx emissions from coal combustion are affected by the 

chemical and physical properties of the feed coal. Feed coal characteristics significantly affect 

the design and operation of combustion controls, such as the existing LNB+SOFA system. With 

the LNB+SOFA system in place, Unit 101 currently achieves an emission rate of 0.17 lb/MMBtu 

(annual average). 

PRPA notes that Unit 101 is designed to burn PRB coal and the boiler is additionally optimized 

through a technologically complex process to burn this coal at very tightly controlled rate. 

PRPA has indicated that it is infeasible and economically impractical to change coal supplies. 

With fuel switching to natural gas, NOx emissions were projected to drop from the current 0.17 

 22 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 - Rawhide Page 16 

lbs/MMBtu to a rate of 0.1 lbs/MMBtu23. However, this reduction would be diminished by the 

accompanying loss in boiler efficiency, increased boiler heat input requirement, and significant 

loss of generation resulting from natural gas firing. 

The Division has determined that fuel switching to natural gas is technically feasible for 

Rawhide Unit 101. 

LNB/ROFA®/SOFA/LNB+SOFA: The boiler is already equipped with a tangentially-fired 

LNB+SOFA system that was installed in 2005. This system achieves an approximate 50% NOx

reduction (based on actual emissions). 

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. 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. The optimum temperature 

window for Rawhide Unit 101 will most likely occur somewhere at the top of the furnace and in 

the backpass of the boiler if SNCR is applied. SCNR is considered a technically feasible 

alternative for Unit 101. 

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. 

The SCR reaction occurs within the temperature range of 550°F to 850°F where the extremes are 

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

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

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

arrangement alternative and would likely be the arrangement for Unit 101 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 Rawhide Station. Therefore, high-dust SCR is a technically feasible alternative for Rawhide 

Unit 101. 

 23 PRPA, February 18, 2010. “Re: Rawhide Unit 101 NOx Emissions Control Cost and Technical Feasibility 

Information Request – Additional Details and Explanation.” Contained in Appendix D. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 17 

ECC: The enhanced combustion control system option for Rawhide Unit 101, submitted by 

PRPA, consists of a neural-net based combustion optimization subsystem (software and 

hardware) and companion real-time boiler combustion constituents and temperature 

measurement system. These system components are interfaced with the boiler’s standard 

coordinated combustion control system (CCS). The ECC system continuously measures and 

monitors the dynamic boiler combustion constituents, temperatures and other process 

parameters. The ECC system then commands the CCS to manipulate variables such as 

combustion air damper positions, burner tilts, coal feeder speeds, and other process parameters to 

optimize fuel combustion and boiler efficiency, while controlling NOx and CO emissions within 

targeted ranges. Optimizing the ECC requires periodic combustion testing and CCS tuning. 

ECC is a technically feasible option for Rawhide Unit 101. 

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 boiler24 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 boilers25 and has not been demonstrated for other types of 

units. Therefore, RRI is considered technically infeasible for Unit 101.

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/MMBtu26. 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 

Fuel Switching – Natural Gas: The Unit 101 boiler at Rawhide could convert fuels from coal to 

natural gas with boiler modifications. Conversion from coal to natural gas would reduce NOx

emissions by about 545 tons per year, or approximately 29% (using 2006 - 2008 CAMD data 

average)27. 

 24 Powerspan ECO®: Overview and Advantages, 2000 – 2010. http://www.powerspan.com/ECO_overview.aspx 25 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. http://www.ftek.com/apcRRI.php 26 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 27 Colorado Air Pollution Control Division Technical Analysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 

2010. See Appendix D for detailed calculations. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 18 

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 study28 to conservatively approximate that 

Rawhide Unit 101 can achieve up to 30% control when SNCR is applied. PRPA asserts that 

NOx reductions of up to 60% have been achieved, although 20-40% is more realistic for most 

applications. However, if ammonia slip is controlled closer to 2 ppm then achievable NOx

reduction efficiencies will be closer to 20 percent. 

SCR:PRPA approximates that SCR can achieve an approximate 64% NOx reduction from the 

current low 0.17 lb/MMBtu baseline emission rate. PRPA asserts that while a lower controlled 

NOx emission values have been demonstrated by SCR system applications in new coal units, for 

PRPA, a retrofit SCR, the 0.07 lb/MMBtu controlled NOx value is more expected. This control 

efficiency is slightly lower than EPA’s AP-42 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 – 90% reduction from an assumed baseline emission rate of 0.5 lb/MMBtu.29,30 

However, in the Division’s experience and national CAMD emissions data (2009) reflect that an 

emission limit of no lower than 0.07 lb/MMBtu is realistically achievable for a retrofit SCR. 

Table 13 summarizes each available technology and technical feasibility for NOx control. 

Table 13: Rawhide Unit 101 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

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

LNB + OFA 25-45% Y – installed

Air Staging – overfire air 

(OFA)

5-40% Y – installed

Rotating overfire air (ROFA) 45-65% Y – will not increase 

current NOx

reductions

SCNR 20 – 40% Y

SCR – HTSCR Up to 90% Y-high-dust 

SCR – LTSCR arrangement

SCR – RSCR

Fuel switching – Natural gas 20-70% Y

Electro-Catalytic Oxidation 

(ECO)®

n/a N

Rich Reagent Injection (RRI) n/a N

Coal reburn+SNCR n/a N

ECC 15-25% Y

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

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

29 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 30 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 - Rawhide Page 19 

Step 4: Evaluate Factors and Present Determination

Factor 1: Cost of Compliance

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

and 65 – 85% for operating expense.31 The PRPA-estimated SNCR costs for operating expenses 

is 44% for Unit 1. Since SNCR is an operating expense-driven technology, its cost varies 

directly with NOx reduction requirements and reagent usage. The cost effectiveness for SNCR 

on Unit 1 is $3,168 per ton NOx reduced. Recent NESCAUM studies estimate SNCR retrofits 

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.32,33 EPA’s SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NOx

reduced. 34 

Platte River relies on Black and Veatch’s (B&V) expertise and cost estimates on major projects. 

Platte River contracted with B&V to perform a detailed study to provide capital costs for NOx 

emissions reduction alternatives for the Rawhide Unit 101. The Rawhide NOx Reduction Study, 

January 2009 noted that the SNCR costs were based on actual B&V engineering, procurement, 

and contracting projects. Rawhide specific SNCR project cost considerations were: 

• 

• Rawhide’s geographic location, economies of scale and small size of Rawhide 

Unit 101 

• Three levels of automatic injection lances with retract system to accommodate 

SNCR reaction temperature and boiler turndown requirements. 

• Computer flow/temperature modeling to establish optimum ammonia injection 

locations and flow patterns, 

• Boiler waterwall modifications for injector lances and steam piping modifications 

for performance optimization, 

• Electrical Motor Control Center switch gear upgrades and modifications to 

support urea system and ammonia delivery system, 

• Reagent storage tank, 

• Digital Control System (DCS) computer system hardware and control logic 

upgrades, 

• Fluegas temperature and NOx and ammonia continuous emission monitoring, data 

acquisition, alarming and reporting system, 

• Interest costs during construction, and 

• Use of a more expensive urea reagent system rather than anhydrous ammonia due 

to safety and transport concerns. 

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

for Controlling NOx Emissions.” Washington, D.C. 2000. 32 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

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

33 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. 

34 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 - Rawhide Page 20 

Platte River notes that the SNCR cost effectiveness ($/ton removed) remains comparatively high 

due to Rawhide’s low baseline NOx emission rates for the above reasons. 

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.35 Although PRPA’s estimates are greater than 

these ranges, the reasons above lead the Division to the conclusion that PRPA’s cost estimates 

for SNCR are reasonable. 

SCR: SCR reagent materials, such as urea and/or ammonia, primarily use a limited resource, 

natural gas. Therefore, future costs for these materials may fluctuate widely. These costs are not 

included in the overall $/ton projections. 

EPA’s regulations recommend using the EPA’s Office of Air Quality Planning and Standards’ 

Air Pollution Cost Control Manual (Sixth Edition, January 2002) for estimating costs of 

compliance. This Manual provides guidance and methodologies for developing accurate and 

consistent estimates of cost for air pollution control devices. The costs that may be estimated 

include capital costs, operation and maintenance (O&M) expenses, and other annual costs. 

In reviewing PRPA’s estimate, the Division found that the ratio of annual costs to the total 

capital costs for all control technologies projected by PRPA to be slightly lower than those 

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

the annualized costs for SCR for Unit 101 are 10.5% of the total capital investment. The EPA 

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

ranged from 12 – 15% of total capital investments36. Therefore, the Division concurs that 

PRPA’s estimate is consistent with annual costs estimated by other facilities. 

Platte River relies on Black and Veatch’s (B&V) expertise and cost estimates on major projects. 

Platte River contracted with B&V to perform a detailed study to provide capital costs for NOx 

emissions reduction alternatives for the Rawhide Unit 101. The Rawhide NOx Reduction Study, 

January 2009 noted that the SCR costs were based on actual B&V engineering, procurement, 

and contracting projects. Rawhide specific SCR project cost considerations were: 

• Vertical oriented high-dust SCR reactor configuration, 

• Construction crane access constraints due to north-side coal conveyor and ACI 

silo, and south-side underground 84 inch circulating water line, 

• Preliminary design and layout analyses including foundations, structural columns, 

cantilevered support steel, and main trusses support structures, 

• Modification to existing structures including demolition of ductwork between the 

economizer and the air heater inlet, 

• Rawhide’s geographic location, economies of scale and small size of Rawhide 

Unit 101, 

 35 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 36 Environmental Protection Agency, 2009. 40 CFR Part 49: Assessment of Anticipated Visibility Improvements at 

Surrounding Class I Areas and Cost Effectiveness of Best Available Retrofit Technology for Four Corners Power 

Plant and Navajo Generating Station: Advance Notice of Proposed Rulemaking. Pg. 44318. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 21 

• Induced draft (ID) fan higher hp motor replacement and retrofit issues, 

• Auxiliary power and switch gear upgrades and modifications to support two new 

ID fan motors, 

• Digital Control System (DCS) computer system hardware and control logic 

upgrades including new electrical and controls building located adjacent to SCR, 

• NOx and ammonia continuous emission monitoring, data acquisition, alarming 

and reporting system, 

• Three layer (two catalyst and one initial spare) reactor sizing for maximizing 

catalyst utilization, 

• Reactor design to accommodate both ceramic honeycomb and plate type catalyst 

products to insure future procurement flexibility, 

• Rerouted underground utilities (bottom-ash sluice trench and drain piping) due to 

SCR foundation requirements, 

• Added superstructure costs due to fully enclosed plant, including boiler and air 

heater areas for cold-weather concerns requiring roof and wall penetrations and 

modifications, 

• Higher structural costs due to high wind loading , 

• High gas temperature design issues (>800°F economizer gas temperature results 

in higher grade catalyst and steel issues), and 

• Use of a more expensive urea reagent system rather than anhydrous ammonia due 

to safety and transport concerns, 

• Interest costs during construction, and 

• Lost generation revenue costs during outage. 

Platte River notes that the SCR cost effectiveness ($/ton removed) remains comparatively high 

due to Rawhide’s low baseline NOx emission rates for the above reasons. The Division asserts 

that $/KW is not an appropriate metric when a detailed cost estimate has be developed. $/KW is 

rough estimate of controls for back of the envelope discussions and should not serve as cost 

estimate in light of more refined estimates. Therefore, the Division did not adjust PRPA’s 

estimates for capital costs. 

Fuel Switching – Natural Gas: In 2008, Platte River performed a Unit 101 Natural Gas 

Conversion Study. The primary objective of the study was to determine required unit 

modifications and associated capital costs to co-fire the unit up to 100% using natural gas. The 

direct capital cost of converting to 100% natural gas was estimated to be about $50 million. 

Conversion from coal to natural gas would reduce NOx emissions by about 545 tons per year 

(using 2006 - 2008 CAMD data average). This results in an initial control cost, using EPA’s 

Cost Control Manual to estimate annual operating costs, of about $436,000 per ton of NOx

removed annually37. Changing to natural gas would dramatically raise fuel costs given that 

natural gas prices are approximately nine (9) times the cost of PRB coal and are subject to 

significant cost variability. Tables 9 and 10 illustrate the resultant emissions and costs of 

switching fuel to natural gas, based on the difference between costs of coal and natural gas in 

2008 and AP-42 emission factors. The annual cost to control was determined using a capital 

 37 Colorado Air Pollution Control Division Technical Analysis – Rawhide Unit 101 Boiler – Natural Gas Switching, 

2010. See Appendix D SIP for detailed calculations. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 22 

recovery factor based on an approximate 8% interest rate. Refer to “Rawhide Cost Analysis” for 

more details. 

To determine annualized costs of switching to natural gas, the annual electricity cost differentials 

between coal and natural gas were analyzed. PRPA notes that when using natural gas, fuel use 

will increase 17% annually due to anticipated efficiency drops, increased heat input 

requirements, and drop in generation. The annual electricity cost of coal is $25.5 million 

compared to natural gas at about $240 million when using 2008 commercial natural gas prices 

reported by the U.S. Energy Information Administration38. Therefore, this results in a 

significant annualized cost increase of $233 million. Refer to Appendix D for details. 

ECC: PRPA worked with three different vendors on an enhanced combustion control pilot 

system. The cost estimates provided are from this pilot project. The annualized cost of 

approximately $288,500 is much lower than SNCR, which achieves about the same amount of 

control. This is little available cost information regarding this type of boiler modification. Since 

the costs are comparable or lower than other pre-combustion technologies, the Division concurs 

that PRPA’s cost estimate is reasonable. 

Table 14 and Table 15 depict controlled NOx emissions and control cost comparisons. 

Table 14: Unit 101 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual Emissions 

(tons/year)

Annual Average 

(lb/MMBtu)

30-day Rolling 

Average (lb/MMBtu)

Baseline --- 1,866 0.166

ECC 24.0 1,418 0.126 0.145

SNCR 27 1,362 0.121 0.140

Fuel Switching 

- NG

29.2** 1,321 0.118

0.135

SCR 63.5 681 0.061 0.070

* Control efficiency calculated by the Division based on PRPA submittal of projected natural gas NOx

lb/MMBtu estimate. 

** Control efficiency provided in PRPA’s analysis based on 0.17 lb/MMBtu NOx input, equivalent to 2006 – 

2008 baseline conditions. Refer to “Rawhide Cost Analysis” for more information. 

Table 15: Unit 101 NOx Cost Comparison 

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

 38 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

Regional Haze Reasonable Progress Analysis - Rawhide Page 23 

ECC 448 $ 288,450 $644 $644 

SNCR 504 $1,596,000 $3,168 $23,357 

Fuel Switching - 

NG

545 $237,424,331 $435,681 $5,735,260 

SCR 1,185 $12,103,000 $10,214 ($352,073)

Factor 2: Time Necessary for Compliance

Based on other Colorado facility submittals39, 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 PRPA approximately 2 – 3 years to convert the 

boiler from coal to natural gas. 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. 

PRPA anticipates that the time necessary for completing design, permitting, procurement, control 

equipment installation, and system startup and shakedown, after SIP approval, would be 

approximately 2-3 years for SNCR and 3-4 years for SCR. These timeframes may also vary 

somewhat to schedule the necessary major maintenance outage with other regionally affected 

utilities. The ECC option timeframe is much shorter due to the fact that PRPA has already been 

working with independent vendors on this system. Therefore, this system could be functional 

within 6 months of SIP approval. 

Factor 3: Energy and Non-Air Quality Impacts

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 and SNCR reagent injection system have 

minimal power requirements. 

Post-combustion add-on control technologies like SCR and 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. 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. 100 – 300 kW is less than 0.5% of the 

power generated by the Unit 101 boiler annually, or enough energy to power about 10 homes for 

a year. These energy requirements are minimal. 

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 

 39 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 - Rawhide Page 24 

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. PRPA 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 

Appendix D for more information. 

Factor 4: Remaining Useful Life

PRPA asserts that since Rawhide Unit 101 is one of the newest units in Colorado, it will remain 

in service for the 20-year amortization period. Thus, this factor doesn’t 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 16 shows the number of days pre- and 

post-control. Table 17 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 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 16: Visibility Results - Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

NOx 

Control 

Scenario 

Boiler 

NOx Emission 

Rate 

(lb/MMBtu)* 

Class I 

Area 

Affected 

3-year totals 3-year totals 

PreControl 

Days 

>0.5 dv 

PostControl 

Days 

>0.5 dv 

∆days

PreControl 

Days 

>1.0 dv 

PostControl 

Days 

>1.0 dv 

∆days

Max 24-hr 

NOx rate 101 0.302 

Rocky 

Mountain 

National 

Park 

20 --- --- 6 --- --- 

ECC 101 0.126 20 6 14 6 1 5 

SNCR 101 0.121* n/a 

Fuel 

Switching 

- NG 

101 0.118* n/a 

SCR 101 0.061 20 1 19 6 0 6 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Rawhide Page 25 

Table 17: Visibility Results - NOx Control Scenarios 

NOx 

Control 

Scenario 

Boiler 

NOx Emission 

Rate 

(lb/MMBtu)* 

Output (@ 

98th

Percentile 

Impact) 

98th Percentile 

Impact 

Improvement 

98th Percentile 

Improvement 

from Maximum 

Cost 

Effectiveness 

(dv) (∆ dv) (%) ($/dv) 

Max 24-hr 

NOx rate 101 0.302 0.87 --- --- --- 

ECC 101 0.126 0.42 0.45 52% $642,428 

SNCR 101 0.121* 0.41 0.46 53% $3,469,565 

Fuel 

Switching - 

NG 

101 0.118* 0.41 0.47 54% $509,494,272 

SCR 101 0.061 0.28 0.59 68% $20,548,387 

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

Summary” for more details. 

Determination

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

NOx RP for Rawhide Unit 101 is the following NOx emission rate: 

Rawhide Unit 1: 0.145 lb/MMBtu (30-day rolling average) 

The state assumes that the RP emission limits can be achieved through the operation of enhanced 

combustion control. The dollars per ton control cost, coupled with notable visibility 

improvements, leads the state to this determination. Although SCR achieves better emission 

reductions, the expense of SCR was determined to be excessive and above the guidance cost 

criteria discussed in section 8.4 above. SNCR would achieve similar emissions reductions to 

enhanced combustion controls and would afford a minimal additional visibility benefit (0.01 

delta deciview), but at a significantly higher dollar per ton control cost compared to the selected 

enhanced combustion controls, so SNCR was not determined to be reasonable by the state.