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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 1 

Reasonable Progress Analysis of Control Options 

For 

Tri-State Generation & Transmission Association, Inc. – Craig Station Unit 3 

I. Source Description

Owner/Operator: Tri-State Generation & Transmission Association, Inc. 

Source Type: Electric Utility Steam Generating Unit 

SCC (EGU): 10100202 

Boiler Type: Three Dry-Bottom Pulverized Coal-Fired Boilers, two opposedwall-fired (Units 1 and 2) and one front-fired (Unit 3) 

The Tri-State Generation & Transmission Association, Inc. (Tri-State) Craig Station is 

located in Moffat County approximately 2.5 miles southwest of the town of Craig, 

Colorado. This facility is a coal-fired power plant with a total net electric generating 

capacity of 1264 MW, consisting of three units. Units 1 and 2, rated at 4,318 

mmBtu/hour each (net 428 MW), were placed in service in 1980, and 1979, respectively. 

Unit 3, rated at 4,600 MMBtu/hour (net 408 MW) was placed in service in 1984. 

Units 1 & 2: Construction of Units 1 and 2 began in 1974; Unit 1 began operation in 

1980 and Unit 2 began operation in 1979. These units are equipped with fabric filter 

(baghouse) systems for controlling particulate matter (PM) emissions, and wet limestone 

Fuel Gas Desulfurization (FGD) systems for the control of sulfur dioxide (SO2) 

emissions. The boilers are equipped with ultra-low nitrogen oxide (NOx) dual register 

burners with overfire air for minimization of NOx emissions. The FGD and ultra low 

NOx burner systems were required to be installed and fully operational by December 31, 

2004 as a result of a consent decree with the Sierra Club (signed January 10, 2001). 

Unit 3: Construction of Unit 3 began in 1981 and the unit commenced operation in 1984. 

This unit is equipped with a baghouse system for controlling PM emissions, a dry lime 

system for control of SO2 and low-NOx burners with overfire air. 

All three units can use natural gas, propane, or fuel oil for start-up, shutdown, and for 

flame stabilization. All three units are subject to the requirements of Title IV, the Acid 

Rain Program, and were approved for Early Election for NOx limits, effective January 1, 

1997. Associated activities include two cooling towers, coal handling systems, ash 

handling systems, limestone handling system, and the staging/landfilling area. 

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

information regarding Craig Station, 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. Units 1 and 2 are considered BART-eligible, being industrial boilers 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 2 

with the potential to emit 250 tons or more of haze forming pollution (NOx, SO2, PM10), 

and commenced operation in the 15-year period prior to August 7, 1977. Therefore, 

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

meets the requirements of RP at this time. 

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

evaluating reasonable progress units at each facility equal to the federal Prevention of 

Significant Deterioration levels. The Division defines “unit” as an Air Pollutant 

Emission Notice (APEN) subject source, or a stationary source, defined as “any building, 

structure, facility, equipment, or installation, or any combination thereof belonging to the 

same industrial grouping that emit or may emit any air pollutant subject to regulation 

under the Federal Act that is located on one or more contiguous or adjacent properties 

and that is owned or operated by the same person or by persons under common control1

.” 

 These levels are as follows: 

• NOx – 40 tons per year 

• SO2 – 40 tons per year 

• PM10 – 15 tons per year 

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

Progress, being an industrial boiler with the potential to emit 40 tons or more of haze 

forming pollution (NOx, SO2, PM10) at a facility with a Q/d impact greater than 20. TriState Generation and Transmission Association (Tri-State) provided information relevant 

to RP to the Division on December 31, 2009, May 14, 2010, June 4, 2010 and July 30, 

2010. Error! Reference source not found. depicts technical information for Unit 3 at 

Craig Station. 

Table 1: Craig Unit 3 Technical Information 

 Unit 3 

Placed in Service 1984 

Gross Boiler Rating, 

MMBtu/Hr for coal 

4,600 

Electrical Power Rating, Net 

Megawatts 

408 

Description Babcock & Wilcox coal, dry bottom boiler - Natural gas, propane, or fuel oil used at 

startup and shutdown, and for flame stabilization 

Air Pollution Control 

Equipment 

PM/PM10 – Pulse Jet Fabric Filter Baghouse (1984 – upgraded between 2007 and 

2009) 

NOx – Low NOx Burners with Over-Fire Air (upgraded between 2007 and 2009) 

SO2 – Dry Limestone FGD (1984 – upgraded between 2007 and 2009) 

Existing turbine generator replaced with larger unit completed in May 2009. 

Emissions Reduction (%)* NOx – 19.0%/38.8%* 

SO2 – 80.9% 

 

1

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

Regulation 5 CCR 1001-2. Amended December 17, 2009. Effective January 30, 2010. Page 19. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 3 

PM – 99.8% 

PM10 – 99.6% 

*Emissions Reduction estimated by comparing pre-control upgrade 2006-2008 CAMD data to AP-42 emission 

factor data. The first NOx number compares the additional reduction achieved by the ultra-low NOx burners vs. the 

original low-NOx burners and the second NOx number compares uncontrolled AP-42 factor to actual average 

emission factor (June 2009 – June 2010). For PM/PM10., uncontrolled AP-42 factor were compared to actual 

average emission factors (2006 – 2008). See “Craig APCD Technical Analysis” for further details. Not based on 

actual testing.

II. Source Emissions

Table 2 summarizes the NOx, SO2, and PM10 actual emissions averaged over the 2006 – 

2008 baseline timeframe from EPA’s CAMD Database for the facility. Table 3 

summarizes each unit at the facility and applicable NOx, SO2, and PM10 actual emissions 

averaged over the 2006 – 2008 timeframe with data from Colorado’s APEN’s submitted 

by the facility and as applicable, EPA’s CAMD Database (primarily for the Unit 101 

boiler and the turbines). 

Table 2. Summary of 2006 - 2008 Averaged Emissions – Craig Station 

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

16,942 3,769 363 

Table 3. Summary of 2006 - 2008 Averaged Emissions by Unit – Craig Station 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

Unit 1 

SO2 (tons) 865.1 1053.0 990.5 969.5 

SO2 

(lb/ MMBtu) 0.06 0.06 0.06 0.06 

NOx (tons) 4665.7 5817.3 5056.9 5180.0 

NOx (lb/ MMBtu) 0.34 0.32 0.30 0.32 

PM (tons) 92.9 107.3 101.1 100.4 

PM (lb/ MMBtu) 0.007 0.006 0.006 0.006 

Unit 2 

SO2 (tons) 999.6 797.1 1149.1 981.9 

SO2 

(lb/ MMBtu) 0.05 0.05 0.06 0.06 

NOx (tons) 5548.7 4965.7 5566.4 5360.3 

NOx (lb/ MMBtu) 0.30 0.32 0.30 0.31 

PM (tons) 90.7 81.9 87.5 86.7 

PM (lb/ MMBtu) 0.005 0.005 0.005 0.005 

Unit 3 

SO2 (tons) 1721.3 1948.5 1782.6 1817.5 

SO2 

(lb/ MMBtu) 0.10 0.11 0.11 0.10 

NOx (tons) 6592.1 6670.1 5943.9 6402.0 

NOx (lb/ MMBtu) 0.38 0.36 0.35 0.37 

PM (tons) 70.4 71.8 67.7 70.0 

PM (lb/ MMBtu) 0.004 0.004 0.004 0.004 

Auxiliary Boiler (130 

MMBtu/hr) Fuel Oil Boiler 

SO2 (tons) 0 0 0 0 

SO2 

(lb/ MMBtu) 0 0 0 0 

NOx (tons) 0 0 0 0 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 4 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

NOx (lb/ MMBtu) 0 0 0 0 

PM (tons) 0 0 0 0 

PM (lb/ MMBtu) 0 0 0 0 

F101a – Coal Hauling – 

Units 1 & 2 PM (tons) 8.15 8.15 11.39 9.23 

F101b – Coal Unloading to 

Grizzly – Units 1 & 2 PM (tons) 0.04 0.04 0.05 0.04 

F101c – Coal Surge Pile PM (tons) 0.05 0.05 0.05 0.05 

S101d – Primary Coal 

Crushing – Units 1 & 2 PM (tons) 0.18 0.18 0.23 0.20 

S101e – Secondary Coal 

Crushing Bldg – Units 1 & 

2 PM (tons) 0.46 0.46 0.56 0.49 

S101f – Common Coal 

Transfer Bldg Belt A PM (tons) 0.001 0.001 0.0013 0.0011 

S101g – Common Coal 

Transfer Bldg Belt B PM (tons) 0.001 0.001 0.0013 0.0011 

S101h – Coal Stackout 

Building – Units 1 & 2 PM (tons) 0.002 0.002 0.0025 0.0022 

S101i - Coal Stackout – 

Units 1 & 2 PM (tons) 0.051 0.051 0.063 0.055 

F101 j -Coal Storage Piles 

– Units 1 & 2 PM (tons) 0.63 0.63 0.63 0.63 

S101k – Coal Reclaim A – 

Units 1 & 2 PM (tons) 0.0018 0.0018 0.0019 0.0018 

S101l – Coal Reclaim B – 

Units 1 & 2 PM (tons) 0.0018 0.0018 0.0019 0.0018 

S101m – coal Tripper Deck 

& Silos – Units 1 & 2 PM (tons) 0.0036 0.0036 0.0038 0.0037 

S101n – Common Coal 

Drive House PM (tons) 0.0036 0.0036 0.0038 0.0037 

S203a – Fly Ash Storage 

Silo A – Units 1 & 2 PM (tons) 0.0047 0.0047 0.002 0.0038 

S203b – Fly Ash Storage 

Silo B – Units 1 & 2 PM (tons) 0.0047 0.0047 0.002 0.0038 

F203c – Fly Ash Truck 

Loading – Units 1 & 2 PM (tons) 0.0079 0.0079 0.0034 0.0064 

P204 – Ash Hauling & 

Storage – Unit 3 PM (tons) 62.2 62.2 62.2 62.2 

P201 – Limestone Hauling PM (tons) 14.7 14.7 17.5 15.6 

F102a – Coal Train 

Unloading – Unit 3 PM (tons) 0.0607 0.0607 0.0676 0.063 

S102b/c – Coal Conveyor 

Portal Building – Unit 3 PM (tons) 0.003 0.003 0.0034 0.0031 

S102d – Secondary Coal 

Crushing (2 crushers0 – 

Unit 3 PM (tons) 0.68 0.68 0.76 0.71 

S102e – Coal Stackout 

Building – Unit 3 PM (tons) 0.003 0.003 0.0034 0.0031 

F102f – Coal Stackout – 

Unit 3 PM (tons) 0.076 0.076 0.085 0.078 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 5 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

F102g – Coal Storage Pile 

– Unit 3 PM (tons) 0.24 0.24 0.24 0.24 

S102h – Coal Reclaim 

System – Unit 3 PM (tons) 0.003 0.003 0.0034 0.0031 

S102k – Common Coal 

Transfer Building Extension PM (tons) 0.003 0.003 0.0034 0.0031 

S102n – Common Coal 

Drive House PM (tons) 0.003 0.003 0.0034 0.0031 

S102i – Coal Tripper Deck 

and Silos – Unit 3 PM (tons) 0.0018 0.0018 0.0018 0.0018 

S102j – Loadout Coal to 

Railcars – Unit 3 PM (tons) 0 0 0 0 

F205a – Ash Hauling to 

“Landfill” (Outage Waste 

to Trapper) PM (tons) 0.114 0.114 0.114 0.114 

F205b – Ash and Wet Waste 

Hauling to/from Decant 

Basin PM (tons) 0.676 0.676 0.676 0.676 

F205c – Ash Unloading at 

“Landfill” (Outage Waste) 

& Ash Unloading at Decant 

Basin PM (tons) 0.0024 0.0024 0.0024 0.0024 

F205d – Wet Waste 

Unloading at Decant Basin PM (tons) 0 0 0 0 

F202a – Lime Hauling 

(trucks) PM (tons) 0 0 0 0 

S202b – Lime Unloading – 

Unit 3 PM (tons) 0.0011 0.0011 0.0012 0.0011 

S202c – Lime Conveying & 

Silo – Unit 3 PM (tons) 0.0011 0.0011 0.0012 0.0011 

S202d – Lime Day Bin PM (tons) 0.0011 0.0011 0.0012 0.0011 

S401/2 – Cooling Towers – 

Units 1 & 2 PM (tons) 10.3 10.3 10.3 10.3 

Auxiliary Boiler PM (tons) 0 0 0 0 

S403 - Cooling Tower – 

Unit 3 PM (tons) 5.8 5.2 5.2 5.4 

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

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

average emission rate. 

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

further for the purposes of reasonable progress. 

Tri-State estimated that a realistic depiction of anticipated annual emissions for Unit 3, or 

“Baseline” Emissions”, to be conservative, was the average of 30-day averages from 

2009, or 0.33 lb/MMBtu for NOx. Tri-State noted that this baseline reflects the recent 

PSD permit limit of 6,752 tons associated with a 2009 turbine upgrade. This baseline 

reflects the low-NOx burners and overfire air installed at Craig 3 in 2009. The Division 

notes that the 2006 – 2008 baseline period used for other RP and BART sources is not 

reasonable for Craig Unit 3 due to the recent upgrades. The Division also used the recent 

PSD permit limit of 6,752 tons for NOx and 2,125 tons for SO2 to determine a baseline. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 6 

The notable difference is that the Division used the average capacity factor (based on heat 

input) from 2006 – 2008 to determine the baseline emissions, resulting in 0.28 lb/MMBtu 

for NOx and 0.09 lb/MMBtu for SO2. Craig Unit 3 ran at an average of 86.4% capacity 

(based on heat input) from 2006 – 2008, thus this factor is assumed to be a reasonable 

baseline for this planning period. The highest 24-hour peak emission rate during this 

timeframe was used for modeling visibility results. The Division verified these emissions 

using Colorado’s Air Pollutant Emission Notices and EPA’s CAMD database. These 

emissions are summarized in Table 4. 

Table 4: Tri-State Craig Unit 3 Baseline Emissions 

Pollutant Unit 3 

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

NOx 5,693 0.283 

SO2 1,792 0.089 

PM10 148** 0.007** 

 *The Division calculated annual (tpy and lb/MMBtu) NOx and SO2 emissions using 2006 – 2008 capacity 

factor and current PSD permit limits. 

**The PM10 emissions and emissions factor are from August 2009 stack test data; PM10 current 

construction permit annual emission limit is 403 tons/year and 0.012 lb/MMBtu. 

III. Units Evaluated for Control

Tri-State notes that the Craig boilers burn Colorado coal that primarily comes from the 

Trapper mine, supplemented by ColoWyo coal, which are both high-ranking subbituminous coal. Limited amounts of coal from the Twentymile mine, ranked as 

bituminous, are also burned. All of these mines are located in northwestern Colorado. 

The Trapper contract expires in 2014. Future nearby coal supplies could come from 

sources such as Trapper, ColoWyo, or Twentymile. Accordingly, the trend of future coal 

supplies is such that in the context of NOx-forming characteristics, Craig 3 will continue 

to burn “bituminous-like” coal, plus, it is likely that additional quantities of bituminous 

coals will be burned at Craig 3 in the future. Similar to PSCo, Tri-State notes that these 

coals are ranked as sub-bituminous, but are closer in characteristics to bituminous coal in 

many of the parameters influencing NOx formation. The specifications for these coals are 

listed below in Table 6. Note that with the exception of moisture content, the coal 

characteristics are reasonably close for the two coals. The actual APEN coal 

specifications (2006 – 2008) 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) 

Craig Unit 3 10,224 0.39 6.47 

Table 6: Craig Station Coal Specifications (2008) 

Coal Mine/Region Colowyo Trapper Twentymile 

Coal Rank Classification Sub-bituminous, Class A Sub-bituminous, Class A Bituminous 

H2O (Moisture %) 17.42 16.7 9.62 

Ash (%) 5.71 6.5 11.93 

Sulfur (%) 0.37 0.44 0.52 

Nitrogen (%) 1.35 ~1.5 1.57 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 7 

Heating Value (HHV Btu/lb) 10,392 9,800 11,084 

Uncontrolled emission factors are outlined in Table 7. The factors are based on firing 

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

conservative estimates. 

Table 7: Uncontrolled emission factors for Craig BART-eligible sources2

 Pollutant (lb/ton)* 

Emission Unit NOx SO2 PM 

(filterable) 

PM10

(filterable) 

Unit 3 12 14.7 64.7 14.9 

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

% of sulfur and ash present in the coal supply, respectively, averaged from APEN data (2006 – 2008). 

Please refer to “Craig APCD Technical Analysis” for more details. 

IV. Reasonable Progress Evaluation of Unit 3

A. Sulfur Dioxide (SO2)

Step 1: Identify All Available Technologies 

The Division requested that Tri-State evaluate the option below, and received relevant 

information for this request on June 4, 2010: 

Dry FGD upgrades 

As discussed in EPA’s BART Guidelines3

, 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. 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 

The current PSD permit SO2 limits are depicted in Table 8. 

Table 8: Craig Unit 3 SO2 PSD Permit Limits 

SO2 limits (lb/MMBtu) Reduction (%) Required

30-day rolling

Annual Emission Limit (tons/year)

Calendar day average

Unit 3 0.20* 80 2,125

*May be exceeded once during any calendar month. 

 

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 3

 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 8 

Step 2: Eliminate Technically Infeasible Options 

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 

plants4

. 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 slaked lime 

slurry that is sprayed into the flue gas, subsequently dried by the heat of the flue gas, and then 

collected in a particulate control device. 

Craig Unit 3 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. Tri-State has since upgraded this system (between 2007 and 2009) and currently achieves 

greater than 80% SO2 removal, with an actual annual average of approximately 0.09 lb/MMBtu. 

This system exceeds EPA’s presumptive limits stated in 40 CFR part 51 Appendix Y of 0.15 

lb/MMBtu5. 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 “Division RBLC Analysis” 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 median design efficiency of 90%6

 . 

The BART Guidelines note potential upgrades for dry scrubbing systems7

. 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 

Tri-State 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. Tri-State and 

 the Division are not aware of SO2 scrubber performance additives applicable or 

 commercially available for the Unit 3 SDA system. 

 

4

 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. 5

 Colorado Operating Permit 96OPLR142 pg. 5 – SO2 30-day rolling average limit is 0.13 lb/MMBtu. 6

 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. 

7

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

Retrofit Technology (BART) Determinations; Final Rule. Pgs. 39171. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 9 

-Use of more reactive sorbent/Increase the pulverization level of sorbent: The purchase 

and installation of two new vertical ball mill slakers improved the ability to supply high 

quality slaked (hydrated) lime. A higher quality slaked lime slurry means a more reactive 

sorbent. Typically, slakers are not designed for particle size reduction as part of the 

slaking process. However, the new vertical ball mill slakers are particularly suited for 

slaking lime that is a mixture of commercial peblle lime and lime fines. Fines are 

generated at the Craig facility in the pneumatic lime handling system. Therefore, the 

Division concurs that Tri-State cannot use a more reactive sorbent or increase the 

pulverization level of sorbent. 

-Engineering redesign of atomizer or slurry injection system: Both the slaked lime slurry 

and recycled ash slurry preparation and delivery systems were redesigned to improve 

overall performance and reliability. The improved system allows for slurry pressure 

control at both the individual reactor level and for each slurry injection header level on 

each reactor. Tri-State notes that consistent control of slurry parameters (pressure, flow, 

composition) promotes consistent and reliable SO2 removal performance. The Division 

concurs that with the recent redesign of the slurry injection system and expansion to two 

trains of recycled ash slurry preparation, no further redesigns are possible at this time.

Therefore, Tri-State and the Division concur that there are not any technically feasible upgrade 

options for Craig Station Unit 3. However, the Division has evaluated the option of tightening 

the SO2 emission limit for Craig Unit 3. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology 

The control effectiveness of tightening the 30-day rolling emission limit on Craig Unit 3 has 

been evaluated by the Division. The Division analyzed the period after Tri-State upgraded the 

turbine (post-control: June 2009 – June 2010) against baseline emissions (2006 – 2008) to 

determine the maximum and average 30-day rolling emission rates, shown in Table 9, to 

determine potential control effectiveness, if any. Additionally, the Division evaluated the 

baseline heat input, capacity factor, and hours of operation pre-upgrade (2006 – 2008) and postupgrade (June 2009 – June 2010) to evaluate whether the data was consistent with baseline 

information, and whether there was enough information to determine if a tighter emission limit is 

warranted, in Table 10. This information allows the Division to set a more relevant emission 

limit for Craig Unit 3 using representative actual emissions. 

Table 9: Craig Unit 3 30-day rolling emission rates (baseline 2006 - 2008) 

Unit and Timeline Maximum 30-day rolling emission rate 

(lb/MMBtu) 

Average 30-day rolling emission rate postcontrol (lb/MMBtu) 

Craig Unit 3 – post 

control 

(June 2009 – June 

2010) 

0.1350 0.1081 

Craig Unit 3 – precontrol 

(2006 – 2008) 

0.1412 0.1088 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 10 

Table 10: Craig Unit 3 30-day rolling emission rates (baseline 2006 - 2008) 

Unit and Timeline Capacity Factor 

(Heat Input %) 

Hours of Operation 

(% of total possible operating hours) 

Craig Unit 3 – June – December 2009 98.1% 95.5% 

Craig Unit 3 – January – June 2010 89.7% 96.1% 

Craig Unit 3 – June 2009 – June 2010 Average 93.9% 95.8% 

Craig Unit 3 – pre-control 

(2006 – 2008) 

86.4% 96.3% 

The Division notes that there are not significant differences between the maximum or average 

30-day rolling emissions before and after the turbine and control upgrades. Similarly, the 

capacity factor and hours of operation do not change discernibly. Therefore, the Division 

concludes that post-upgrade operations may be used in determining a tighter SO2 emission limit 

in this reasonable progress. 

Table 11 summarizes each available technology options and technical feasibility for SO2 control 

on Craig Unit 3. 

Table 11: Craig Unit 3 SO2 Technology Options and Technical Feasibility 

Technology Emission Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

Wet FGD 52-98%, median 90%8 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

 

8

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

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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 11 

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance

A more stringent emission limit is not anticipated to result in any increased costs. Thus, this 

factor does not influence the selection of controls. 

Factor 2: Time Necessary for Compliance

A more stringent emission limit is not anticipated to result in any system upgrades or changes 

and can be implemented as soon as the SIP is approved. Thus, this factor does not influence the 

selection of controls. 

Factor 3: Energy and Non-Air Quality Impacts

There is not any negative energy or non-air quality impacts related to a more stringent emission 

limit. Thus, this factor does not influence the selection of controls. 

Factor 4: Remaining Useful Life

Tri-State asserts that there are no near-term limitations on the useful of this boiler, so it can be 

assumed that they will remain in service for the 20-year amortization period. Thus, this factor 

does not influence the selection of controls. 

Step 5 (optional): Evaluate Visibility Results

CALPUFF modeling was used to determine the projected visibility improvement associated with 

emission limit tightening. 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 12 shows the number of days pre- and 

post-control. Table 13 depicts the visibility results (98th percentile impact and improvements). 

Cost effectiveness in $/deciview was not determined since there will minimal, if any, costs 

associated with emission limit tightening. 

Table 12: Visibility Results – Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

SO2 

Control 

Scenario 

Boiler(s) 

SO2 

Emission 

Rate 

(lb/MMBtu) 

Class I 

Area 

Affected 

3-year totals 3-year totals 

PreControl 

Days 

>0.5 dv 

PostControl 

Days 

>0.5 dv 

∆days

PreControl 

Days 

>1.0 dv 

PostControl 

Days 

>1.0 dv 

∆days

Max 24-

hour SO2 

rates 

3 0.326 

Mt. Zirkel 

Wilderness 

239 --- --- 173 --- --- 

Dry FGD 3 0.150 239 233 6 173 170 3 

Dry FGD 3 0.070 239 230 9 173 168 5 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 12 

Table 13: Visibility Results – SO2 Control Options 

SO2 Control 

Scenario Boiler(s) SO2 Emission 

Rate (lb/MMBtu) 

Output (@ 98th

Percentile 

Impact)* 

98th Percentile 

Impact 

Improvement 

98th Percentile 

Improvement from 

Maximum 

(dv) (∆ dv) (%) 

Max 24-hour 

SO2 rates 3 0.326 5.20 --- --- 

Dry FGD 3 0.150 4.94 0.26 5% 

Dry FGD 3 0.070 4.82 0.38 7% 

Step 6: Select RP Control

Therefore, there are no technically feasible upgrade options for Craig Station Unit 3. However, 

the state evaluated the option of tightening the emission limit for Craig Unit 3 and determined 

that a more stringent 30-day rolling SO2 limit of 0.15 lbs/MMBtu represents an appropriate and 

reasonable level of emissions control for this dry FGD control technology. Upon review of 2009 

emissions data from EPA’s Clean Air Markets Division website, the state has determined that 

this emissions rate is achievable without additional capital investment. 

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

SO2 RP is dry FGD controls at the following SO2 emission rates: 

 Craig Unit 3: 0.15 lb/MMBtu (30-day rolling average) 

An SO2 limit lower than 0.15 lbs/MMBtu would not result in significant visibility improvement 

(less than 0.2 delta deciview) and would likely result in frequent non-compliance events and, 

thus, is not reasonable. 

B. Filterable Particulate Matter (PM10) 

Craig Unit 3 is equipped with pulse jet fabric filter (PJFF) baghouses to control PM/PM10

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

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

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

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

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

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

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

Table 14 shows the most recent stack test data (2009). Real-time data demonstrates that these 

baghouses are meeting >95% control. The current Colorado construction permit limit is 0.013 

lb/MMBtu for filterable PM emissions and 0.012 lb/MMBtu for filterable PM10 emissions and 

also limits total PM and PM10 (filterable and condensable) emissions to 0.022 and 0.020 

lb/MMBtu respectively (Condition 4). The most recent stack test data is used to determine 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 13 

compliance with the permit limit, which at a minimum, occurs every five years, and more 

frequently depending on the results. 

Table 14: Craig Unit 3 Stack Test Results (August 2009) 

Pollutant Unit 3 (lb/MMBtu) 

Total PM 0.013 

Filterable PM 0.0091 

Condensable PM 0.0035 

Total PM10 0.007 

Filterable PM10 0.0035 

Condensable PM10 0.0035 

PM Control efficiency 99.5% 

PM10 Control efficiency 98.8% 

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

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

netting, EGU type and age, coal type, and adjacent controls (i.e. wet and dry FGD systems). The 

above stack test results are well below the range of recent BACT determinations. Refer to 

“Division RBLC Analysis” for more details regarding BACT determinations. 

The State has determined that the existing Unit 3 fabric filter baghouse and regulatory emissions 

limit of 0.013 (filterable PM) and 0.012 lb/MMBtu (PM10) represents the most stringent control 

option. The unit is exceeding a PM control efficiency of 95%, and the control technology and 

emission limit is RP for PM/PM10. 

C. Nitrogen Oxide (NOx) 

Step 1: Identify All Available Technologies

Tri-State identified five options for NOx control: 

New/modified Low NOx Burners (LNBs) with Overfire Air (OFA) system (next generation) 

Advanced OFA system or Rotating overfire Air (ROFA) 

Neural network system combustion controls 

Selective Non-Catalytic Reduction (SNCR) 

Selective Catalytic Reduction (SCR) 

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

units: 

Electro-Catalytic Oxidation (ECO)® 

Rich Reagent Injection (RRI) 

Coal reburn +SNCR 

Step 2: Eliminate Technically Infeasible Options

LNBs with OFA Upgrades: TriState contracted with ACT to modify the existing Craig 3 burners 

and upgrade the OFA system. ACT determined that burners and OFA system could be 

upgraded. However, ACT has not modified ultra low-NOx Babcock & Wilcox 4Z burners such 

as those in use at Craig Unit 3. In addition ACT stated that a complete plant inspection, data 

review, baseline testing, and computational fluid dynamics (CFD) modeling would be required 

for them to guarantee performance predictions. An amended proposal was submitted by ACT 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 14 

upon receipt of updated coal analyses that more closely represent the quality of coal being 

burned at Craig 1&2. In their amended proposal, ACT again reiterated that “to give a guaranteed 

NOx reduction, a lot more information is required.” LNBs modifications with OFA upgrades 

appear to be technically feasible for Craig Unit 3. 

Advanced OFA system – rotating overfire air system (ROFA): ROFA® injects air into the 

furnace first to break up the fireball and then to create a cyclonic gas flow to improve 

combustion. ROFA® differs from OFA in that ROFA® utilizes a booster fan to increase the 

velocity of air to promote mixing and to increase the retention time in the furnace. To date, 

ROFA® has only been installed as a retrofit technology on units firing eastern bituminous coals. 

TriState contacted Motobec, the manufacturer of ROFA® technology, to determine if ROFA is 

feasible for Craig Unit 3. Mobotec could not give TriState a definitive guarantee for reductions 

due to the variability in the quality of coals. 

Based on data published by the manufacturer, ROFA® technology has been reported as 

achieving NOx emission reductions from 45 to 65 % based on fuel load9. While ROFA is 

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

expected to increase emissions reductions for Craig Units 1 and 2. The Division asserts that 

ROFA® technology would not be expected to provide better emissions performance than the 

LNB+OFA baseline for these units, ROFA® technology is not considered further in this 

analysis. 

Neural network system combustion controls: TriState received a neural network proposal from 

NeuCo in April 2006. The proposal offers to enhance the existing Craig 3 control system by 

providing combustion optimization technology. For a given set of objectives, a neural network 

directs the unit’s distributive control system (DCS) or other control systems to optimize the 

boiler performance. 

Based on review of the Craig 3 current operations, NeuCo stated that Craig 1&2 appear to be 

good candidates for the optimization system. Key aspects to neural network success are the 

training support provided by the supplier, as well as achieving buy-in from plant operators. 

TriState states that it is important to note that the condition of the unit(s) and the manner in 

which the unit(s) is operated prior to the installation of the combustion optimization system also 

play an important role in determining potential NOx reductions. Neural network system 

combustion controls appear to be technically feasible for Craig Unit 3. 

SNCR: Selective non-catalytic reduction is generally utilized to achieve modest NOx reductions 

on smaller units. With SNCR, an amine-based reagent such as ammonia or urea is injected into 

the furnace within a temperature range of 1,600°F to 2,100°F, where it reduces NOx to nitrogen 

and water. NOx reductions of up to 60% have been achieved, although 20-40% is more realistic 

for most applications. Reagent utilization, a measure of the efficiency with which the reagent 

reduces NOx, can have a significant impact on economics, with higher levels of NOx reduction 

generally resulting in lower reagent utilization and higher operating cost. SCNR is considered a 

technically feasible alternative for Craig Unit 3. Tri-State conducted a site-specific SNCR study 

 

9

 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 15 

in October and November 2010. The Division received a summary of results on November 23, 

2010 and the raw data on December 8, 2010. 

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. 

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

applications in new coal units, for Craig, a retrofit SCR system, the 0.07 lb/MMBtu controlled 

NOx value is more expected, although Tri-State asserts that the unit cannot achieve below 0.08 

lb/MMBtu. See “Tri-State BART Submittals” for more details. The SCR reaction occurs within 

the temperature range of 550°F to 850°F where the extremes are highly dependent on the fuel 

quality. SCR is a technically feasible alternative for Craig Unit 3. 

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

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

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

been demonstrated on a full-size pulverized coal-fired boiler10 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 boilers11 and has not been demonstrated for other types of 

units. Therefore, RRI is considered technically infeasible for Units 1 and 2. 

LNB/SOFA/LNB+SOFA: Craig Unit 3 is equipped with low-NOx burners with over-fire air (LNB+OFA) as 

part of a construction permit modification. 

Table 1 illustrates that this system achieves about 39% NOx reductions (based on actual 

emissions) on Unit 3. 

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

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

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

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

or well below 0.1 lb/MMBtu12. However, this procedure has not been performed on a full-size 

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

 

10 Powerspan ECO®: Overview and Advantages, 2000 – 2010. http://www.powerspan.com/ECO_overview.aspx 11 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. http://www.ftek.com/apcRRI.php 12 Coal Tech. Corp, 2002. “Tests on Combined Staged Combustion, SNCR & Reburning for NOx Control and 

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

http://www.netl.doe.gov/publications/proceedings/04/NOx/summary/h11.50zauderer-summary.pdf 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 16 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

Tri-State provided the Division annual average control estimates. In the Division’s experience 

and other state BART proposals,13 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 Craig Unit 3 to determine control 

efficiencies and annual reductions. 

LNBs with OFA Upgrades: TriState noted in the original BART submittal (July 31, 2006) that 

ACT proposed that a modified LNB with upgraded OFA system could achieve 10 – 15% NOx

reduction above current levels. Tri-State submitted additional information regarding combustion 

control refinement, which the Division assumes is upgrades of the existing ULNBs, on 

December 8, 2010. These control refinements consist mostly of more precise control of fuel and 

air for combustion. This study conducted by Black & Veatch (B&V) notes that these 

refinements could achieve approximately 0- 2 % control. B&V explains that the reduction in 

control efficiency is due to the difference between “design criteria” versus permit limit. The 

Division notes that the Craig units already have ultra-low NOx burners (ULNBs) installed, and as 

there is very little to no information on improvements to ULNBs, the Division accepts the 

amended B&V study for combustion control refinements from December 8, 2010. 

 

Neural network system combustion controls: TriState noted in the original BART submittal (July 

31, 2006) that NeuCo provided a neural network proposal projecting that an optimization system 

could achieve 5 – 15% NOx reductions. Tri-State submitted additional information regarding 

neural network (NN) system combustion controls on December 8, 2010. This study, conducted 

by Black & Veatch (B&V), notes that the NN equipment will be minimal, consisting of a few 

computer servers that will interface with existing systems in the same location(s). NN system 

combustion controls could achieve approximately 0 – 5% control. B&V explains that the 

reduction in control efficiency is due to the difference between “design criteria” versus permit 

limit. The Division notes that although limited information is available regarding NN systems, 

this information is very specific to individual units and is still considered emerging by industry 

standards. Therefore, the Division accepts the amended B&V study control efficiency for NN 

system controls submitted on December 8, 2010. 

SNCR: Tri-State stated in the May 14, 2010 submittal that based on the boiler configuration, TriState could expect a continuous NOx reduction performance with SNCR technology in the range 

of 10 – 15%. This is based on Tri-State’s extensive research into the application of SNCR 

technology at Craig Station. The vast majority of the research was focused on system 

performance and impacts on plant performance. Tri-State staff conducted a visit to First 

Energy’s Eastlake and Sammis power plants in Ohio; this visit was specifically design to 

evaluate boiler designs due to the similarity in boiler/burner configurations similar to the Craig 

Station boilers. These estimates are lower than EPA’s SNCR Air Pollution Control Technology 

Fact Sheet, which estimates SNCR between 30 – 50% control. Other Colorado facilities 

estimated SNCR as achieving between 17 – 40% NOx control. Control effectiveness has been 

historically noted to be lower for wall fired boilers similar to the Craig boilers; therefore the 

Divisions considers 15% to be a reasonable control effectiveness for SNCR. 

 

13 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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 17 

SCR: Tri-State stated in the May 14, 2010 submittal the expected emission rate for Craig Unit 3 

when applying SCR are 0.08 lb/MMBtu. Tri-State did not specify if this estimate was a 30-day 

rolling averages, although, as stated in the December 31, 2009 submittal, the baselines are 

averages of 30-day averages. The Division notes that several other Colorado facilities have 

noted SCR expectations of 0.070 lb/MMBtu14or even lower. Additionally, a recent AWMA 

study found similar-sized EGUs achieve NOx reduction efficiencies greater than 85% with 

emission rates between 0.04 and 0.07 lb/MMBtu (during the ozone season).15 EPA’s AP-42 

emission factor tables estimate SCR as achieving 75 – 85% NOx emission reductions. Table 15 

depicts a comparison of SCR control efficiencies. The Division adjusted Tri-State’s estimate to 

0.07 lb/MMBtu based on the reasoning above. 

Table 15: SCR Control Efficiency Comparison 

Unit Baseline 

(lb/MMBtu)

Control Efficiency (%) Resultant Emissions (lb/MMBtu)

Tri-State 

Estimate

Division 

Estimate

Tri-State Estimate 

(annual average)

Division Estimate 

(annual average)

Craig 

Unit 3

0.283 71.8 75.2 0.080 0.070

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

Table 16: Craig Unit 3 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

LNB + OFA 25-45% Y – installed

Air Staging – overfire air 

(OFA)

5-40% Y – installed

Ultra-Low NOx Burner 

(ULNB) 

Upgrade/Refinements

0 – 2% 

(TriState)

Y

Neural network system 0 – 5% 

(TriState)

Y 

SNCR 10 – 40% Y

Rotating overfire air (ROFA) 45 – 65% N

SCR 75 – 90% Y

Electro-Catalytic Oxidation 

(ECO)®

n/a N

Rich Reagent Injection (RRI) n/a N

Coal reburn+SNCR n/a N

 

14 Public Service Company of Colorado (April 20, 2010), Colorado Energy Nations Company (November 12, 2009), 

Colorado Springs Utilities (February 20, 2009), and Platte River Power Authority (January 22, 2009) all note that 

their individual EGUs can achieve 0.070 lb/MMBtu or even lower on a 30-day rolling average basis. 15 Srivastava et. al, 2005. Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers. Journal 

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

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 18 

Step 4: Evaluate Impacts and Document Results

Factor 1: Cost of Compliance

Low NOx burner upgrades: Tri-State submitted additional information regarding combustion 

control refinement, which the Division assumes is upgrades of the existing ULNBs, on 

December 8, 2010. Through a literature review, the Division could not find any examples or 

support for upgrades on ultra-low NOx burners with overfire air. Ultra-low NOx burners are 

fairly new within the industry, so additional upgrades have not yet been researched. The first 

commercial application for these burners was documented in May 2000.16 Tri-State estimates 

that the initial cost of combustion control refinement at about $2,200,000 with an annualized 20-

year cost of $122,000. The Division notes that the Craig units already have ultra-low NOx

burners (ULNBs) installed, and as there is very little to no information on improvements to 

ULNBs, the Division accepts the amended B&V study for combustion control refinement cost 

estimates from December 8, 2010. 

Neural network system: TriState did not provide a quantitative evaluation of the application of a 

neural network system to the Division. There are three other facilities in Colorado alone using 

neural network systems from the same provider that TriState contacted.17 It is unknown why 

TriState will provide further analysis of this system. Costs for these systems are very specific to 

individual units, so the Division cannot estimate costs for this option. Tri-State submitted 

additional information regarding neural network (NN) system combustion controls on December 

8, 2010. Tri-State estimates that the initial cost of neural network systems (per unit) at about 

$800,000 with an annualized 20-year cost of $280,000. The Division notes that although 

limited information is available regarding NN systems, this information is very specific to 

individual units and is still considered emerging by industry standards. Therefore, the Division 

accepts the amended B&V study cost estimates for NN system controls submitted on December 

8, 2010. 

SNCR: A typical breakdown of annualized costs for SNCR on industrial boilers will be 15 – 25% 

for capital recovery and 65 – 85% for operating expenses.18 The Tri-State-estimated SNCR costs 

for operating expenses are 70% for Craig Unit 3. Since SNCR is an operating expense-driven 

technology, its cost varies directly with NOx reduction requirements and reagent usage. There is 

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

uncontrolled NOx level, required emission reductions, unit size and thermal efficiency, economic 

life of the unit, and degree of retrofit difficulty.19 

 

 

16 Bryk and Kleisley, 2000. “First Commercial Application of DRB-4ZTM Ultra-Low NOx Coal-Fired Burner.” 

Presented to POWER-GEN International 2000. November 14-16, 2000. Orlando, Florida. 

17 NeuCo White Papers and Case Studies. http://www.neuco.net/library/case-studies/default.cfm and Platte River 

Power Authority January 22, 2009 submittal: “Rawhide Unit 101 NOx Emission Control Cost and Technical 

Feasibility Information.” 

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

for Controlling NOx Emissions.” Washington, D.C. 2000. 19 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 19 

The cost effectiveness for SNCR on Unit 3 (at 15% control efficiency) is approximately $4,887 

per ton. Recent NESCAUM studies estimate SNCR retrofits on wall fired boilers (comparable to 

Unit 3) achieving 0.50 – 0.65 lb/MMBtu and emission reductions of 30 – 50% as costing $590 - 

$1,100 per ton of NOx reduced, depending on initial capital costs and capacity factor. 20,21 It 

should be noted that Tri-State is estimating resultant emission rates lower than 0.30 lb/MMBtu 

for both boilers, therefore costs will be higher. EPA’s SNCR Fact Sheet cites SNCR as costing 

from $400 - $2,500 per ton of NOx reduced.22 On a linear scale, based on the NESCAUM 

estimates and assuming an achieved rate of 0.23 lb/MMBtu, the costs should be approximately 

$2,500 per ton. Tri-State and the Division’s revised estimates are above this range; the Division 

inquired about the reagent and auxiliary power costs; Tri-State responded on July 30, 2010 

adjusted the auxiliary power and lost generation costs for all of the Craig Units for both SNCR 

and SCR. Tri-State also provided further information regarding the cost of potential reagent 

options. The costs for these two items remain higher than other Colorado facility estimates; 

however, Tri-State has provided adequate information detailing the reasoning for power and 

reagent costs. The Division and Tri-State still do not completely concur on other cost items, 

including an annual 3% escalation rate for capital material, capital labor, capital indirect, and 

operation and maintenance. Additionally, similar Colorado facility cost estimates fall within the 

EPA SNCR Fact Sheet range. The Division will use Tri-State’s capital and 

operation/maintenance costs for this analysis in the absence of additional information at this 

time. 

SCR: Recent NESCAUM studies estimate SCR retrofits on wall fired boilers achieving NOx

emission rates of 0.15 – 0.25 lb/MMBtu and emission reductions of 75 – 85% as costing $1,700 - 

$3,200 per ton of NOx reduced, depending on initial capital costs and capacity factor.23,24 25,26 It 

should be noted that Tri-State is estimating resultant emission rates lower than 0.15 lb/MMBtu 

for both boilers, therefore costs will be higher. Tri-State’s estimates are above this range; on a 

linear scale (achieving 0.07 lb/MMBtu); the costs should be approximately $7,000 per ton. The 

Division’s revised cost estimates are close to this estimate; therefore, the Division concludes that 

these cost estimates are reasonable. 

Table 17 and Table 18 depict controlled NOx emissions and control cost comparisons. 

 

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

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

21 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. 

22 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 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. 

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

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

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

Internal Combustion Engines: Technologies & Cost Effectiveness.” Northeast States for Coordinated Air Use 

Management, 129 Portland Street, Boston, MA 02114. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 20 

Table 17: Craig Unit 3 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual Emissions 

(tons/year)

Annual Average 

(lb/MMBtu)

30-day 

Rolling Average 

(lb/MMBtu)

Baseline --- 5,693 0.283

Combustion control 

refinements 2 5,579 0.277 0.32 

Neural network 

system 5 5,408 0.268 0.31 

SNCR 15 4,839 0.240 0.28

SCR 75 1,412 0.070 0.08

Table 18: Craig Unit 3 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

Combustion control 

refinements 114 $122,000 $1,071 $1,071 

Neural network 

system 285 $280,000 $984 $925 

SNCR 854 $4,173,000 $4,887 $4,887

SCR 4,281 $239,762,387 $6,952 $7,466

Factor 2: Time Necessary for Compliance

Based on other Colorado facility submittals, 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 Tri-State 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

LNB Upgrades/Neural network system(s): There are no known non-air quality impacts 

associated with upgrades on low-NOx burner systems or neural network systems. Energy 

impacts are not significant. 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. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 21 

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

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

overcome additional pressure drops caused by the control equipment, and provide steam in some 

cases. In particular, SCR systems require additional auxiliary power or power from the existing 

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

mixing with the ammonia, and to pump ammonia into the vaporizer. 

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

ammonia rates are not adequately controlled. Other environmental factors include ammonia 

storage and transportation, particularly for anhydrous ammonia. Anhydrous ammonia is clear in 

the liquid state and boils at a temperature of -28°F. With its low boiling point, liquid anhydrous 

ammonia must be stored under pressure at ambient temperatures to remain a liquid. With 

anhydrous ammonia, an invisible vapor or gas is formed as the liquid evaporates during 

depressurization. Accidental atmospheric release of anhydrous ammonia vapor can be 

hazardous; therefore, stringent requirements for safety are enforced, and obtaining the permits to 

allow the storage of large quantities of anhydrous ammonia may prove difficult in densely 

populated areas. 

Factor 4: Remaining Useful Life

Tri-State asserts that there are no near-term limitations on the useful of this boiler, so it can be 

assumed that they will remain in service for the 20-year amortization period. Thus, this factor 

does not influence the selection of controls. 

Step 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 20 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 19: Visibility Results – Change in Days >0.5 dv and >1.0 dv at highest affected Class I Area 

NOx 

Control 

Scenario 

Boiler(s) 

NOx 

Emission 

Rate 

(lb/MMBtu) 

Class I 

Area 

Affected 

3-year totals 3-year totals 

PreControl 

Days 

>0.5 dv 

PostControl 

Days 

>0.5 dv 

∆days

PreControl 

Days 

>1.0 dv 

PostControl 

Days 

>1.0 dv 

∆days

Max 24-

hour 2nd 3 0.365 Mt. Zirkel Wilderness 239 --- --- 173 --- --- 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 22 

half 2009 

NOx rate 

2009 New 

LNBs 3 0.283 239 234 5 173 170 3 

SNCR 3 0.240 239 233 6 173 166 7 

SCR 3 0.070 239 224 15 173 149 24 

Table 20: Visibility Results – NOx Control Options 

NOx Control Scenario Boiler(s) NOx Emission Rate 

(lb/MMBtu) 

Output (@ 

98th

Percentile 

Impact) 

98th Percentile 

Impact 

Improvement 

98th

Percentile 

Improvement 

from 

Maximum 

(dv) (∆ dv) (%) 

Max 24-hour 2nd half 2009 NOx 

rate 3 0.365 5.20 --- --- 

2009 New LNBs 3 0.283 4.99 0.21 4% 

SNCR 3 0.240 4.88 0.32 6% 

SCR 3 0.070 4.41 0.79 15% 

 Step 6: Select RP Control

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

NOx RP for Craig Unit 3 is SNCR control at the following NOx emission rates: 

 Craig Unit 3: 0.28 lb/MMBtu (30-day rolling average) 

 

For SNCR at Unit 3, the cost per ton of emissions removed, coupled with the estimated visibility 

improvements gained, falls with guidance cost criteria discussed in section 8.4 above. 

• Unit 3: $4,887 per ton NOx removed; 0.32 deciview of improvement 

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

this determination. To the extent practicable, any technological application Tri-State utilizes to 

achieve this RP emission limit shall be installed, maintained, and operated in a manner consistent 

with good air pollution control practice for minimizing emissions. 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 of the Regional Haze State Implementation Plan. 

V. Reasonable Progress Evaluation of Ash Hauling & Storage (P204) and Limestone 

Hauling (P201)

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

96OPMF155. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Reasonable Progress (RP) Analysis – Tri-State Craig Station Page 23 

Ash hauling (P204) is controlled with two methods to minimize fugitive emissions: 

• Ash deposited in trucks for transport to disposal areas shall be sufficiently moist 

(Condition 8.2). 

• The scrubber sludge/ash haul road servings Units 1, 2, and 3 shall be treated with 

magnesium chloride or equivalent as a dust suppressant. The magnesium chloride 

shall be applied according to manufacturer’s specifications. The frequency of 

application shall be according to manufacturer’s recommendations (Condition 8.3). 

Limestone hauling (P201) activities are controlled several ways to minimize fugitive 

emissions: 

• Opacity limitations of 20% except under certain operational conditions (U.S. EPA 

Reference Method 9) (Conditions 6.2, 11.2, and 11.3) 

• Unloading facilities are vented to a baghouse (Condition 6.3) 

• All process equipment shall be maintained and operated so as to minimize leakage of 

air contaminants to the atmosphere prior to their in the pollution control system 

(Condition 6.4) 

These existing controls and corresponding emission limits in Section II, Conditions 6 and 

8 of Operating Permit 96OPMF155 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. 

VI. Reasonable Progress Evaluation of Units 1 & 2

Units 1 and 2 have been evaluated under Best Available Retrofit Technology (BART) 

provisions. BART for Units 1 and 2 can be found in Chapter 6 of the Regional Haze 

State Implementation Plan. The Division determines that BART represents the most 

stringent available NOx, SO2, and PM/PM10 control technologies and represents 

reasonable progress. Therefore, a full 4-factor analysis is not needed to evaluate 

reasonable progress for NOx, SO2, or PM/PM10 for Units 1 and 2 at Craig Station.