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

Regional Haze Reasonable Progress Analysis - Nucla Page 1 

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

For 

Tri-State Generation & Transmission Association, Inc. – Nucla Station 

I. Source Description

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

Source Type: Electric Utility Steam Generating Unit 

SCC (EGU): 10100218 

Boiler Type: Atmospheric Circulating Fluidized Bed 

 

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

located in Montrose County approximately 3 miles southeast of the town of Nucla, 

Colorado. The Nucla Station consists of one coal fired steam driven electric generating 

unit (Unit 4), with a rated electric generating capacity of 110 MW (gross), which was 

placed into service in 1987. The boiler is equipped with a fabric filter (baghouse) system 

for controlling particulate matter (PM) emissions, and limestone injection into the 

fluidized bed for the removal of sulfur dioxide (SO2). The boiler is designed for the 

reduction of NOx formation and a small Selective Non-Catalytic Reduction (SNCR) 

system using anhydrous ammonia injection is used for NOx trim to ensure compliance 

with annual NOx limits. Additionally, the facility includes a number of fugitive dust 

sources. 

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

information regarding the Nucla facility, and information about similar facilities to 

determine RP for PM and SO2. 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 be considered in making BART and RP determinations are 

largely the same. 

 

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

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

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

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

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

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

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

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

.” 

 1

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

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

Regional Haze Reasonable Progress Analysis - Nucla Page 2 

These de minimis levels are as follows: 

• NOx – 40 tons per year 

• SO2 – 40 tons per year 

• PM10 – 15 tons per year 

The Nucla facility originally consisted of three coal fired stoker boilers that were shut 

down and replaced with an atmospheric circulating fluidized bed (CFB) boiler (Unit #4). 

Unit #4 was placed in service in June, 1987. CFBs without post-combustion controls are 

able to achieve emission rates of NOx and SO2 that are lower than Pulverized Coal (PC) 

fired boilers due to the nature of their design (lower combustion temperatures result in 

less NOx formation, while intimate mixing of a sorbent within the fluidized bed results in 

enhanced SO2 removal). SO2 emissions from CFBs without post-combustion controls are 

typically lower than similarly sized PC-fired boilers equipped with Flue Gas 

Desulfurization (FGD) systems.2 The original construction of Unit #4 included four 

baghouses for the control of PM10 emissions, limestone injection to the combustion 

chamber for SO2 removal, and inherent minimization of NOx emissions due to boiler 

design. 

In 2006, Tri-State permitted and installed a small-scale SNCR system that injects 

anhydrous ammonia to provide additional NOx reduction. Tri-State does not operate the 

SNCR system frequently; it is used on occasions when NOx emissions approach 0.4 

lb/MMBtu (operation above this level at high unit capacity factors results in levels that 

approach the annual NOx limit of 1,987.9 tons per year on a 12-month rolling basis). The 

system was designed with a 2,000 gallon tank and a flow rate during operation of around 

10 gallons per hour.3 

Nucla Unit 4 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, and July 30, 2010. Error! 

Reference source not found. depicts technical information for Unit 4 at Nucla Station. 

Table 1: Nucla Unit 4 Technical Information 

 Unit 4 

Placed in Service 1987 

Gross Boiler Rating, MMBtu/Hr for coal 1,112 

Electrical Power Rating, Net Megawatts 110 

Description Pyropower Circulating Fluidized Bed, Coal Fired Boiler 

Air Pollution Control Equipment PM/PM10 –Fabric Filter Baghouses (1987) 

 2

 Babcock & Wilcox Company, 2000. “Why Build a Circulating Fluidized Bed Boiler to Generate Steam and 

Electric Power” Presented to POWER-GEN Asia 2000. Page 2. 3

 Tri-State, May 14, 2010. “RE: Response to the Division’s January 25, 2010 Letter Regarding NOx Emissions 

Control Costs.” Page 6. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 3 

NOx – Voluntary SNCR (2006) 

SO2 – Limestone Injection (1987)

Emissions Reduction (%) NOx – NA4

SO2 – 77.4% 

PM/PM10 – 98% - 99.9+%5

II. Source Emissions

Table 2 summarizes the NOx and SO2 actual emissions averaged over the 2006 – 2008 

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 Air Pollutant Emission Notices (APENs) 

submitted by the facility (based on amount and heat content and amount of coal 

combusted, also as reported on the APENs). 

Table 2. Summary of 2006 - 2008 Averaged Emissions – Tri-State Nucla Station 

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

1,760 1,335 40 

Table 3. Summary of 2006 - 2008 Averaged Emissions by Unit – Tri-State Nucla Station 

Unit Pollutant 2006 2007 2008 

2006 - 2008 

average* 

Unit 4 Boiler 

SO2 (tons) 1509.4 1230.4 1265.7 1335.2 

SO2 

(lb/MMBtu) 0.34 0.30 0.30 0.31 

NOx (tons) 1716.0 1598.0 1711.4 1675.1 

NOx (lb/MMBtu) 0.39 0.38 0.40 0.39 

PM10 (tons) 41.6 39.4 40.24 40.4 

PM10 (lb/ MMBtu) 0.009 0.009 0.009 0.009 

Coal Handling & 

Processing PM10 (tons) 2.09 2.15 2.15 2.13 

Ash Handling & Processing PM10 (tons) 8.91 10.62 10.62 10.05 

P401 Cooling Tower PM10 (tons) 37.5 23.7 0.34 20.5 

P402 Cooling Tower PM10 (tons) 9.8 9.8 9.8 9.8 

Limestone Preparation PM10 (tons) 1.29 1.29 1.29 1.29 

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

average. 

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

further for the purposes of reasonable progress. 

Note also that Tri-State installed improved drift eliminators on the P401 Cooling Tower 

in 2007. The Operating Permit6 for the facility includes a limit of 0.55 tons PM10 per 

 4

 NOx emission reductions from the existing SNCR system have not been characterized because the system is 

operated only infrequently – total reported emissions are therefore assumed to be uncontrolled. 

5

 The low range is calculated assuming uncontrolled emissions based on AP-42 factors. The high range is stated in 

the U.S. Department of Energy: Project Fact Sheet – Nucla CFB Demonstration Project. 

http://www.netl.doe.gov/technologies/coalpower/cctc/cctdp/project_briefs/nucla/documents/nucla.pdf. Page 5. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 4 

year effective beginning October 1, 2007 (actual emissions for 2008 were reported to be 

0.34 tons per year); therefore this unit will also not be considered further in this analysis.

The Title V permit includes the following limits for the Unit 4 Boiler: 

• NOx: 0.50 lbs/MMBtu on a rolling 30-day average (PSD limit), 0.5 lb/MMBtu on 

a rolling 30-day average (NSPS Subpart Da) and 1987.9 tons per year on a 

rolling 12-month total 

• SO2: 1.2 lb/MMBtu on a rolling 30-day average (NSPS Subpart Da), 1.2 

lb/MMBtu on a 3-hr average (Colorado Regulation No. 1), 0.4 lb/MMBtu on a 

30-day average (Colorado Regulation No. 6) and 1598.9 tons per year on a rolling 

12-month total; 70% reduction at less than 0.6 lb/MMBtu (30-day rolling average) 

• PM10: 131 tons per year on a rolling 12-month total 

• PM: 0.03 lb/MMBtu (PSD limit), 0.03 lb/MMBtu (NSPS Subpart Da) 0.1 

lb/MMBtu (Colorado Regulation No. 1) and 135.9 tons per year on a rolling 12-

month total 

III. Units Evaluated for Control

The Nucla boiler burns Colorado bituminous coal. Nucla Station is a mine-mouth 

facility; therefore the Division assumes that this facility burns New Horizon Coal, since 

that facility is the closest coal mine identifiable in Division records. The actual APEN 

coal specifications (2006 – 2008) are listed below in Table 4. Uncontrolled emission 

factors are outlined in Table 5. 

Table 4: Coal Specifications (2006 - 2008 Averaged APEN data) 

 Specifications 

Emission Unit Fuel Heating Value 

(Btu/lb) 

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

Nucla Unit 4 10,545 0.83 19.95 

Table 5: Uncontrolled emission factors for Nucla RP-eligible sources7

 Pollutant 

Emission Unit NOx SO2 PM 

(filterable) 

PM10

(filterable) 

Unit 4 (lb/ton) 5.0 25.8 17.0 12.4 

Unit 4 (lb/MMBtu) 0.24 1.22 0.81 0.59 

 6

 Colorado Air Pollution Control Division, September 25, 2007. Colorado Operating Permit 96OPMO168: Nucla 

Station. Section II: Condition 8.2, Page 38. 

7

 PM and PM10 emission factors are from 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 (for spreader stokers with multiple cyclones and 

reinjection). Uncontrolled SO2 emission factors are based on the AP-42, Fifth Edition, Volume I, Chapter 1, Section 

1.1 emission factor for underfeed stoker boilers (Table 1.1-3). Uncontrolled NOx emission factors are based on 

actual emissions from 2006 – 2008. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 5 

IV. Reasonable Progress Evaluation of Unit 4

a. Sulfur Dioxide 

Step 1: Identify All Available Technologies 

The Division identified all of the available CFB control technologies listed below. 

Fuel Switching – Natural Gas or Alternate Coal Source 

Fuel Washing 

Limestone Injection Process Upgrades 

Post-Combustion Controls: Dry Scrubbing (Spray Dry Absorber, Circulating Dry 

Scrubber, Hydrated Ash Reinjection and Dry Sorbent Injection) 

Post-Combustion Controls: Wet Scrubbing 

As discussed in EPA’s BART Guidelines8, 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 existing limestone injection process if technically feasible. 

The current PSD permit SO2 limits are depicted in Table 6. 

Table 6: Nucla Unit 4 SO2 PSD Permit Limits 

SO2 limits (lb/MMBtu) Rolling 12-month 

Emission Limit 

(tons/year)

3-hour avg. 

(Colo. Reg. No. 1)

Rolling 30-day avg.

(NSPS Subpart Da)

30-day avg. 

(Colo. Reg. No. 6)

Unit 4 1.2 1.2 0.4 1,599

Step 2: Eliminate Technically Infeasible Options 

Fuel Switching – Natural Gas or Alternative Coal Sources: CFB boilers are designed to 

create a circulating bed of solid fuels; the nature and locations of the solids and air 

injection points as well as the combustion zone itself are inherently different from 

traditional PC and natural gas-fired boilers. The recent conversion from a natural gasfired boiler to a CFB-boiler at the Lamar Light and Power facility in Lamar, Colorado 

required the construction of an entirely new and separate unit. Therefore, the Division 

determines that the conversion to natural gas is technically infeasible for Nucla’s CFB 

boiler. 

Nucla Unit #4 is currently burning coal from the New Horizon Mine located five miles 

south of the plant, with an average sulfur content of 0.83%. The facility is located 

approximately 4.5 miles southeast of Nucla, Colorado and does not have rail service. 

There are no other coal mines located 100 miles of the facility. Because the current coal 

source is already lower than 1% sulfur and no other sources within a reasonable distance 

 8

 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 - Nucla Page 6 

of the facility have been identified, fuel switching to other coal types will not be 

considered further in this analysis. 

Fuel Washing: Fuel washing has been used historically to reduce the sulfur content of 

some high sulfur coals prior to combustion. There are no identified fuel-washing 

processes for low sulfur coal. 

Existing Process Upgrades and Post-Combustion Controls: In the absence of any 

specific feasibility or cost information related to SO2 controls for the Nucla Station, the 

Division relied on control evaluations performed for other CFB boilers, with a focus on 

CFB boilers in the western part of the country. Coal supplies for CFB boilers in the 

eastern part of the country are significantly different from western coals in terms of sulfur 

and heat content; therefore the Division believes that the specifics of control devices for 

eastern CFB boilers may not be wholly applicable to Nucla Unit 4. The majority of recent 

BACT determinations identify limestone injection, with or without additional postcombustion controls as the chosen SO2 control device. Refer to “Division RBLC 

Analysis” for more details. The Division reviewed two of the most recent BACT 

analysis reports in detail: the lignite-fired Spiritwood Station in North Dakota9 and the 

waste coal-fired Bonanza Station in Utah10. The Spiritwood Station was intended to fire 

beneficiated lignite but is designed with the capability for firing dried lignite and 

subbituminous coal as well, and the BACT analysis specifically identified the findings to 

be applicable to subbituminous coal. The estimated control efficiencies and costs from 

these reports were used as a basis to evaluate potential SO2 emission control options at 

Nucla. 

Limestone Injection Process Upgrades: The average reduction in SO2 emissions due to 

limestone injection into the CFB boiler for the baseline period is estimated to be 77.4% as 

shown in Table 1, above. The unit participated in a U.S. Department of Energy Clean 

Coal Technology Demonstration Program (CCTDP) from 1988 – 1991 in order to 

examine the energy and environmental impacts from the unit, which was the first utilityscale atmospheric CFB boiler at the time. The project demonstrated a 70% SO2 removal 

rate at a calcium to sulfur ratio (Ca/S) of 1.5 and a 95% removal rate at a calcium to 

sulfur ratio of 4.011. The demonstration project tested a range of western bituminous 

coals, including Salt Creek (0.5% sulfur), Peabody (0.7% sulfur) and Dorchester (1.5% 

Sulfur), with the Salt Creek coal serving as the baseline coal (used in 62 of the 72 tests). 

Limestone injection process upgrades are feasible for Nucla Unit 4. 

Post-Combustion Controls – Dry Scrubbing: Additional treatment of the boiler exhaust 

gases can potentially be accomplished with several dry scrubbing techniques. 

 9

 Barr, July 2007. “Application for a Permit to Construct a Combined Heat and Power (CHP) Plant.” Prepared for 

Great River Energy – Spiritwood Station, Spiritwood, ND. 

10 EPA, August 30, 2007. “Deseret Power Electric Cooperative, Bonanza Power Plant, Waste Coal Fired Unit: 

Prevention of Significant Deterioration Permit to Construct – Final Statement of Basis for Permit No. PSD-00-

0002.01.00. ” 

11 U.S. Department of Energy: Project Fact Sheet – Nucla CFB Demonstration Project. 

http://www.netl.doe.gov/technologies/coalpower/cctc/cctdp/project_briefs/nucla/documents/nucla.pdf 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 7 

Spray Dryer Absorption (SDA) is the most commonly used follow-on controls for CFB 

boilers with limestone injection. SDAs currently make up about 12% of Flue Gas 

Desulfurization (FGD) systems at U.S. power plants12. SDA systems are typically 

utilized at smaller units that burn lower-sulfur coal 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 the collected 

in a particulate control device. A SDA system is technically feasible for Nucla Unit 4. 

Circulating Dry Scrubber (CDS) Systems use a circulating fluidized bed of dry hydrated 

lime in a separate reactor tower. The flue gas must first be humidified with a water mist. 

EPA noted in the Bonanza BACT analysis that CDS systems have limited application on 

large PC-fired boilers or CFB boilers, and can result in particulate loading rates that are 

high enough to create unacceptable pressure drops across fabric filters and therefore 

require electrostatic precipitators for particulate control.13 The potential need to replace 

the existing baghouse (99.9% particulate control) with an electrostatic precipitator 

renders a CDS system inappropriate as an option for the Nucla station. 

Hydrated Ash Reinjection (HAR) increases utilization of uncreated calcium oxide in the 

CFB boiler ash by collecting, hydrating and re-introducing a portion of the unit’s ash in a 

separate vessel prior to the baghouse. HAR is technically feasible for Nucla Unit 4. 

Dry Sorbent Injection (DSI) systems require injection of powdered absorbent directly into 

the flue gas stream. EPA identified this option as impractical for use in a CFB boiler 

burning low sulfur coals due to an expected SO2 reduction of less than 50%.14 DSI is a 

technically feasible option for Nucla. 

Post-Combustion Controls – Wet Scrubbing: Wet Flue Gas Desulfurization (FGD) 

systems were identified as potentially feasible for CFB boilers in both the Bonanza and 

Spiritwood BACT analyses. The process involves an alkaline slurry (lime or limestone) 

scrubbing liquid in an absorber tower. The process produces a wet byproduct that 

requires dewatering. Wet scrubbing is a technically feasible option for Nucla Unit 4. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology 

Limestone Injection Process Upgrades: The Spiritwood BACT analysis states that the 

control efficiency from the limestone injection process is expected to be 75%15 (further 

reductions occur in a Spray Dry Absorber). EPA acknowledges in the Bonanza BACT 

analysis report that a control efficiency of 80 – 85% should be expected for the limestone 

injection process alone16. The Division believes that an expectation of 95% reduction for 

the Nucla station from the limestone injection process, although it may have been 

 12 Recommendations, Technical Report, September 2007. University of North Dakota: Energy & Environment 

Research Center – Coal Ash Resources Research Consortium. 15 North 23rd Street, Stop 9018. Grand Forks, ND, 

58202. Pg V. 

13 Ibid., Page 92. 

14 EPA, Deseret Power Electric Cooperative...Page 93. 

15 Barr, Appendix E, Page 50 

16 EPA, Deseret Power Electric Cooperative...Page 99. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 8 

demonstrated during the CCTDP test project, is not appropriate as a long term operation 

scenario. The fluidized bed is currently optimized carefully to balance efficiency, 

operational and emission characteristics. Increasing the Ca/S to 4.0 in order to achieve 

95% SO2 reduction is expected to cause significant operational issues; the Division has 

not found any evidence of current CFB boilers in operation with Ca/S ratios near 4.0. 

Higher limestone injections will also result in an increase in NOx emissions, although the 

quantitative relationship is not well understood.17 For these reasons, the Division 

believes that an increase in SO2 control efficiency to 85% by increasing limestone 

injection is a feasible option. This correlates to an approximate 39.4% decrease in 

comparison to current SO2 emissions. 

Spray Dry Absorber: Based on experience with other Colorado EGUs, the Division 

believes that a realistic achievable control efficiency for a SDA at Nucla is approximately 

87%, or an approximate 0.04 lb/MMBtu (30-day rolling average). This is approximately 

97% from uncontrolled SO2 emissions. A review of the EPA’s RBLC database showed 

two retrofit Western facilities from about 0.04 – 0.05 lb/MMBtu (30-day rolling average) 

with SDAs as the SO2 control option. Please refer to the document “RBLC for CFBs – 

July 2010” for more information.

Limestone Injection Improvements + Spray Dry Absorber: Limestone injection 

improvements (85%) combined with a spray dry absorber (90%) could achieve up to 

approximately 94% control from current SO2 emissions, or 98.4% from uncontrolled SO2

emissions. 

Hydrated Ash Reinjection: EPA references vendor information showing that hydrated 

ash reinjection could reduce the post-combustion SO2 emissions by about 80%.18 This 

results in about 95% reduction from uncontrolled SO2 emissions.

Hydrated Ash Reinjection + Limestone Injection Improvements: It may be possible to 

combine HAR (80% reduction) with improvements to the limestone injection system 

(85% reduction). This results in a potential 87.9% decrease from current SO2 emissions 

or 96.9% reduction from uncontrolled SO2 emissions. 

Post-Combustion Controls – Wet Scrubbing: EPA noted a potential SO2 removal 

efficiency of 94% for the post-combustion gas in the Bonanza BACT analysis19. 

Combined with the current limestone injection system, the overall potential control 

efficiency is 98.4% from uncontrolled SO2 emissions. 

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

for Nucla Unit 4. 

 17 Ibid., Page 100. 

18 Barr, Appendix E, Page 93. 

19 Ibid., Page 94. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 9 

Table 7: Nucla Unit 4 SO2 Technology Options and Technical Feasibility 

Technology Emission Reduction Potential 

(%)

Technically Feasible? 

(Y = yes, N = no)

Fuel switching – 

Natural gas or alternate coal 

source

Natural gas: 99%

Alternate coal: minimal

Natural gas – N

Alternate coal – Y – will not provide 

further SO2 control

Fuel washing Minimal N

Limestone Injection Process 

Upgrades

~85% overall control 

efficiency

~40% increase from current 

control efficiency

Y

Dry Scrubbing (SDA) ~97% overall control 

efficiency

~87% increase from current 

control efficiency

Y 

Limestone Injection 

Improvements + SDA

~98% overall control 

efficiency

~94% increase from current 

control efficiency

Y 

Circulating Dry Scrubber Unknown N

Hydrated Ash Reinjection 

(HAR)

~95% overall control 

efficiency

~80% increase from current 

control efficiency

Y

HAR + Limestone Injection 

Improvments

~97% overall control 

efficiency

~88% increase from current 

control efficiency

Y

Dry Sorbent Injection (DSI) <50% overall control 

efficiency

Y – will not provide further SO2 

control

Wet Scrubbing ~98% overall control 

efficiency

~94% increase from current 

control efficiency

Y

Step 4: Evaluate Factors and Present Determination

Factor 1: Cost of Compliance

 

Costs for SO2 control options were evaluated based on analyses for similar systems 

proposed at other western CFB boiler units (Spiritwood and Bonanza). Refer to “Nucla 

APCD Cost Analysis” for more details. Depending on the control option, the Division 

also relied on additional submittals regarding Nucla feasibility and costs submitted on 

Limestone Injection Process Upgrades: The Division relied on the U.S. Department of 

Energy Clean Coal Technology Demonstration Program (CCTDP) study to determine 

control efficiency for limestone injection upgrades. The Spiritwood BACT analysis used 

the cost of limestone in 2006 to determine limestone injection costs. The Division 

adjusted this cost using the Consumer Price Index (CPI), increasing limestone cost from 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 10 

$80 per ton to $87 per ton. The Division also calculated the additional amount of 

limestone (in tons per year) that will be needed to achieve an 85% control efficiency (or 

40% increase from current control efficiency). These calculations result in an annualized 

cost of $914,920 per year. Refer to “Nucla APCD Cost Analysis” for more details. 

Dry Scrubbing (Spray Dry Absorber)/ Limestone Injection Process Upgrades + SDA: 

The Division again relied on the Spiritwood BACT Analysis to determine the cost of a 

spray dry absorber (SDA) system. The annualized cost (2006) for the Spiritwood CFB 

was $2,644,412. The Division used the CPI to adjust this cost to $2,814,108 and then 

scaled this cost up by the ratio of potential tons SO2 removed at the Nucla CFB compared 

to tons removed at the Spiritwood CFB, and then added in a retrofit factor of 50% to 

consider the difficulty of the retrofit at Nucla as compared to a new CFB (Spiritwood). 

This results in an annualized cost of $4,304,807. For limestone injection improvements 

combined with a SDA system, the Division combined annualized costs from both 

controls to result in an annualized cost of $5,219,097. Refer to “Nucla APCD Cost 

Analysis” for more details.

Wet Scrubbing: Although Wet FGD systems provide higher levels of SO2 removal over 

dry scrubbers, their incremental cost is likely the reason that they are not identified as 

BACT controls on any CFB boilers. The incremental cost of using a wet scrubber versus 

the spray dry absorber is identified as $12,902/ton in the Spiritwood BACT analysis20, 

and $10,540 per ton in the Bonanza BACT analysis.21 A wet scrubber at the Nucla 

Station should be expected to have even higher costs than these examples due to the 

retrofit factor. Therefore, a Wet FGD option will not be considered further in this 

analysis. 

HAR/HAR+Limestone Injection Improvements: Study-level information for potential 

HAR systems at Nucla or any other EGU in the western part of the country were not 

available for use in evaluating costs. Therefore, the Division does not consider this 

option to commercially available at this time, and HAR will not be considered further in 

this analysis. However, HAR is technically feasible and will be considered in future 

analyses if more information becomes available. 

Table 8 illustrates resultant SO2 emissions for each technically feasible control option. 

Table 9 shows the SO2 control cost comparisons for each unit based on the detailed cost 

analyses. The Division used baseline emissions from Table 3. The Division analyzed 

both annual and 30-day rolling average limits. The Department’s experience with power 

plants suggests that the maximum 30-day rolling average SO2 emission rate is 

approximately 5% higher than the annual average emission rate. 

Table 8: Nucla Unit 4 Control Resultant SO2 Emissions 

Alternative Control Resultant Emissions

 20 Barr, Appendix E, Page 95. 

21 EPA, Deseret Power Electric Cooperative...Page 95. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 11 

Efficiency (%) Unit 4

(tons/year) Annual Average 

(lb/MMBtu)

30-day Rolling 

Average (lb/MMBtu)

Baseline --- 1,335 0.299 0.314

Limestone Injection 

Improvements (LII) 39.4 809 0.182 0.191

Hydrated Ash 

Reinjection (HAR) 80.0 267 0.060 0.063

Spray Dry Absorber 

(SDA) 87.0 174 0.039 0.041 

HAR + LII 87.9 162 0.036 0.038

 

LII+SDA 93.9 81 0.018 0.019

Wet Scrubbing 94.0 80 0.018 0.019

Table 9: Nucla Unit 4 SO2 Cost Comparison 

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

LII 526 $2,188,595 $4,161 $4,161

HAR 1,068 Not determined

HAR+LII 1,173 Not determined

SDA 1,162 $7,604,627 $6,547 $8,520

LII+SDA 1,254 $9,793,222 $7,808 $23,619

Wet 

Scrubbing

1,255 Not determined

Factor 2: Time Necessary for Compliance

It is assumed that the Limestone Injection Improvements will not require any 

construction or capital improvements since the Unit has already been demonstrated at 

the higher Ca/S ratios during the CCTDP test project. 

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 the SDA or LII+SDA 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
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 12 

There are no identified energy or non-air quality impacts associated with 

improvements to the Limestone Injection System. Thus, this factor does not 

influence the selection of this control. 

Wet Scrubbing: Based upon its experience, and as discussed in detail below, the 

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

quality environmental impacts, including massive water usage. This is a significant 

issue in Colorado, where water is a costly, precious and scarce resource. In the arid 

West, securing sufficient water supplies to support a wet FGD control system is a 

difficult undertaking that precludes other beneficial uses for such water. In Colorado, 

water law is based upon the doctrine of prior appropriation or “first in time - first in 

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

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

water appropriation and whether such appropriation is adequate to supply the 

demand, there may be insufficient water appropriations available in some areas of the 

state, particularly in the Front Range, to accommodate the added demands of wet 

FGD controls. At a minimum, the water demands of wet FGDs will compete for what 

is already a scarce resource needed for Colorado’s domestic, agricultural and 

industrial demands. 

There are other environmental impacts that the Division also considers undesirable 

with respect to wet scrubbers. Potential on-site storage of wet ash is an increasing 

regulatory concern, as evidenced by the recent Tennessee Valley Authority spill. The 

Division has received complaints regarding the more visible plumes associated with 

wet scrubbing; a potential irony in light of the visibility issues at the heart of the 

Regional Haze program. The Division largely focused its RP SO2 control technology 

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

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

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

level of SO2 control on a percent capture basis that exceeds the capabilities of LSDs 

but, as noted above, there are a number of non-air quality and other environmental 

impacts including increased water usage, sludge disposal and wet plume issues that 

often overshadow any incremental improvement in SO2 emission reductions. Recent 

PSD applications in Colorado have demonstrated lime spray dryer systems to be 

BACT. 

The Division finds the negative environmental impacts of a traditional wet FGD 

control system far outweigh minimal incremental SO2 emission reduction benefits 

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

nearest Class I area) when compared to a SDA system when applied to the Nucla Unit 

4 CFB boiler. 

Spray dry absorber (SDA): Other Colorado facility have noted that there are a 

number of non-air quality environmental impacts with regard to lime spray dryer 

systems. Application of a dry scrubber will tend to remove halogens from the flue 

gas (primarily chlorine) that are important to the removal of mercury from the flue 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 13 

gas. Several sources of speciated mercury stack test data, including EPA’s own ICR 

stack test data, show that an unscrubbed plant with a baghouse burning western coal 

will remove more mercury from the flue gas when compared to a similar plant with a 

scrubber. There will be a greater volume of material being landfilled. A LSD 

scrubber consumes a tremendous amount of water. Wet scrubbers consume 

approximately 23% more water than LSD scrubbers, depending on boiler size.22

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

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

elimination of this control option. 

DSI: Other Colorado facility have documented additional collateral impacts of 

applying DSI include enhanced removal of halogenated acid gases, and reduced 

mercury capture in the baghouse. DSI ahead of the baghouse would contaminate the 

flyash with sodium sulfate, rendering the ash unsalable as a replacement for concrete 

and render it landfill material only. Application of DSI would be effective in further 

enhancing the removal of halogenated acid gases in the baghouse. Currently, there is 

moderate removal of acid gases in the baghouse due to the alkaline nature of the 

flyash. 

The dry sorbent injection system does result in an ash by-product. This by-product 

does not require additional treatment before being deposited in a landfill. However, a 

study conducted by the Department of Energy found arsenic and methylene chloride 

in the ash at some plants,23 which could become a problem if more stringent 

regulations are imposed in the future. However, it is not known yet if these levels are 

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

requires future research. Otherwise, the DSI does not have any negative energy or 

non-air quality related impacts. Thus, this factor (regarding DSI) does not influence 

the selection of controls 

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. 

Factor 5 (optional): Evaluate Visibility Results

Due to time and domain constraints, projected visibility improvements were not 

modeled by the state for this analysis. Nucla already has a system in place to inject 

limestone into the boiler as required by current state and federal air permits. This 

system achieves an approximate 70% SO2 emissions reduction capture efficiency at a 

 22 2008. “Revised BART Analysis for Unit 1 & 2 Gerald Gentleman Station Sutherland, Nebraska: Nebraska Public 

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

technology costs provided by: Sargent & Lundy. 

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

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

Ferry Road Morgantown, WV 26507-0880. 

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

Regional Haze Reasonable Progress Analysis - Nucla Page 14 

permitted emission rate of 0.4 lbs/MMBtu limit. Increased SO2 capture efficiency 

(85%) with the existing limestone injection as an effective system upgrade, by use of 

more limestone (termed “limestone injection improvements”) was evaluated and 

determined to not be feasible under certain operating conditions. The system cannot 

be ‘run harder’ with more limestone to achieve a more stringent SO2 emission limit; 

the system would have to be reconstructed or redesigned with attendant issues, or 

possibly require a new or different SO2 system, to meet an 85% capture efficiency. 

Step 6: Select RP Determination 

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

determined that the existing permitted SO2 emission rate for Unit 4 satisfies RP: 

Nucla Unit 4: 0.4 lb/MMBtu (30-day rolling average) 

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

existing limestone injection system. 

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

Nucla Unit 4 is currently equipped with a four baghouse system 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. 

The baghouses performed over the 2006 – 2008 baseline period with PM and PM10

emissions of 0.013 lb/MMBtu and 0.009 lb/MMBtu, respectively. During the 

CCTDP test project, the unit demonstrated particulate emissions ranging between 

0.0072 to 0.0125 lb/MMBtu, corresponding to a removal efficiency of 99.9%24. 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. 

 Table 10 shows the most recent verified stack test data (2002). Another stack test 

was conducted in August 2010, but is not yet available for release due to ongoing 

analysis by the Division and Tri-State. Real-time data demonstrates that these 

 24 U.S. Department of Energy, Page 5. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 15 

baghouses are meeting >95% control. The Operating Permit (96OPMO168) limit is 

0.03 lb/MMBtu for PM/PM10 emissions (Conditions 1.1.1, 1.1.2). The most recent 

stack test data is used to determine compliance with the permit limit, which at a 

minimum, occurs every five years, and more frequently depending on the results. 

Table 10: Nucla Unit 4 Stack Test Results (August 2002) 

Pollutant Unit 4 (lb/MMBtu) 

Filterable PM10 0.014 

PM10 Control efficiency 98.3% 

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 in the range of recent 

BACT determinations. Please refer to “Division RBLC Analysis” for more details 

about recent BACT determinations. 

The State has determined that the existing regulatory emissions limit of 0.03 

lb/MMBtu 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. The state assumes that the emission limit can be achieved through the 

operation of the existing fabric filter baghouse. Therefore, a full 4-factor analysis is 

not needed to evaluate PM/PM10 for the Unit 4 boiler.

c. Nitrogen Oxides (NOx) 

Step 1: Identify All Available Technologies 

Fuel Switching – Natural Gas or Alternate Coal Source 

Selective Non-Catalytic Reduction (SNCR) system upgrades 

Selective Catalytic Reduction (SCR) with flue gas reheat 

Step 2: Eliminate Technically Infeasible Options 

Tri-State provided an analysis of the requirements and costs associated with 

increasing the size of the existing SNCR system to allow for more frequent operation, 

and the Division has relied on this information (with some exceptions) in order to 

evaluate a full-time SNCR option. Due to lack of any specific feasibility or cost 

information related to SCR controls at Nucla Station, the Division relied on recent 

control evaluations performed for other CFB boilers in the western part of the country 

(the Spiritwood and Bonanza evaluations, noted in Section III.a above). Every BACT 

determination listed in the RACT/BACT/LAER Clearinghouse for CFB Boilers 

specifies SNCR; no SCR determinations or installations have been identified. This is 

likely due to the significantly high incremental costs of SCR systems, as discussed 

below. 

As described above for SO2 controls, fuel switching to natural gas or an alternative 

coal source is not considered technically feasible. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 16 

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. SNCR is considered a 

technically feasible alternative is Nucla Unit 4. 

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

technology for PC-fired boilers. SCR control involves injecting ammonia into the 

flue gas stream in the presence of a catalyst, and requires a temperature range of 

500°F – 800°F. SCR systems are not considered feasible for CFB boilers because the 

particles present in the boiler exhaust act as catalyst poisons. However, the recent 

BACT analyses for the Spiritwood and Bonanza Units have considered the 

application of SCR technology following the particulate control device on CFB 

boilers in order to achieve 90% NOx reduction. Since baghouse exhaust temperatures 

are too low to satisfy SCR requirements, reheating of the flue gas is required. NOx

control efficiencies of 90% are expected. The Division considers SCR a technically 

feasible alternative for Nucla Unit 4. Please see the cost section for more details 

regarding SCR. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology 

SNCR: The current SNCR system associated with Unit 4 is a small system using 

anhydrous ammonia injection for NOx trim during period when emissions approach 

0.4 lb/MMBtu (the permit limit is 0.5 lb/MMBtu). NOx trim is required to ensure that 

the facility is able to meet the 1,987.9 ton per year permit limit on a rolling 12-month 

total. Tri-State notes that the unit is not in service the majority of the time. The 

system was designed with a 2,000 gallon tank and a flow rate during operation of 

around 10 gallons per hour, allowing only 8 days of continuous service. Tri-State 

also notes that there is such a wide variability in the effectiveness of SNCR for 

controlling NOx emissions that only 10% control should be assumed, but provided no 

data to support this value. Note that 10% control over a baseline of 0.39 lb/MMBtu is 

0.35 lb/MMBtu. 

On August 17, 2006, Tri-State performed a stack test in order to ensure that ammonia 

slip emissions resulting from the newly installed SNCR system would not result in a 

significant emission increase (for PM10) and trigger PSD review for the project. The 

test was completed at maximum and minimum boiler loads, and maximum ammonia 

injection rate (15.4 – 15.5 gallons per hour)25. The test runs occurred during the 

following timeframes: 

 25 Colorado Department of Public Health & Environment, November 2, 2006. “Stack Testing Report, Nucla 

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

Regional Haze Reasonable Progress Analysis - Nucla Page 17 

 Low Load (80.4 MW) High Load (109.2 MW)

Run 1: 7:28 – 8:28 Run 1: 13:51 – 14:51 

 Run 2: 9:14 – 10:14 Run 2: 15:25 – 16:25 

 Run 3: 10:44 – 11:44 Run 3: 16:52 – 17:52 

The NOx CEMS data from CAMD for August 17, 2006 in Figure 1 shows an hourly 

NOx rate during the low load test of 0.22 lb/MMBtu (corresponding to 43.6% control 

over the baseline), and an hourly NOx rate during the high load test of 0.35 lb/MMBtu 

(corresponding to 10.3% control). 

Figure 1: NOx CEMs Data (August 17, 2006) for Nucla Unit 4 

0

0.1

0.2

0.3

0.4

0.5

0.6

0 5 10 15 20 25

l

b

/

M

M

B

t

u

Hour

NOx Emissions on 8/17/2006 (CAMD)

CEMS Data

LowLoad Test

High Load Test

The low load rate of control is more in line with estimates for the SNCR systems in 

the Spiritwood and Bonanza BACT analyses (58%26 and 47%27, respectively). 

The Division conducted an analysis to determine the typical load for Nucla Unit 4 

using baseline data (2006 – 2008). From 2006 – 2008, Nucla ran at 97.6% load. This 

high load data indicates that 10.3% control is more reasonable. However, the 

Division and Tri-State both note that the existing small scale SNCR system is not 

designed for full-scale operation and would last about 8 days in continuous service 

and has never operated for an extended period of time. Tri-State further notes that 

given the design purpose of the existing system for injection to trim emissions as 

 26 Barr, Appendix E, Page 56. 

27 EPA, Deseret Power Electric Cooperative...Page 49. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 18 

needed, the system is not engineered to achieve a specific percent reduction. The 

Division concludes that there is a significant amount of uncertainty surrounding the 

application of SNCR on CFB boilers due to lack of information at this time. 

Table 11 summarizes each available technology and technical feasibility for NOx

control. 

Table 11: Nucla Unit 4 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

Fuel switching – 

Natural gas or alternate coal source

Natural gas: 20 – 

70%

Alternate coal: 

minimal

Natural gas – N

Alternate coal – Y – 

will not provide further 

NOx control

Low NOx Burners (LNB) ~10% N – CFB boiler

Overfire air (OFA) 10 – 25% (alone) N – CFB boiler

Selective non-catalytic reduction 

(SNCR)

20 – 40% Y – small scale system 

already installed

Selective catalytic reduction (SCR) 70 – 90% Y

Step 4: Evaluate Factors and Present Determination

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

experience and other state BART proposals,28 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 Nucla Unit 4 to determine control efficiencies and annual 

reductions. 

Factor 1: Cost of Compliance

SCR: Although SCR systems provide significantly higher levels of NOx removal over 

SNCR systems, their incremental cost is likely the reason that they are not identified 

as BACT controls on any CFB boilers. The incremental cost of using SCR versus 

SNCR on a CFB Boiler is identified as $25,315/ton in the Spiritwood BACT 

analysis29, and $40,297 per ton in the Bonanza BACT analysis30. A SCR system at 

the Nucla Station should be expected to have even higher costs than these examples 

due to a retrofit factor and small size. Therefore, the Division considers that costs for 

SCR will be excessive. Additionally, site-specific costs for SCR on Nucla are not 

available at this time. 

 28 State of North Dakota BART Determination for Leland Olds Station Units 1 and 2. Page 16. 

29 Barr, Appendix E, Page 57. 

30 EPA, Deseret Power Electric Cooperative...Page 51. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 19 

SNCR: The cost associated with installation of an upgraded SNCR system is shown 

below. Costs are based on values submitted by Tri-State on May 14, 2010.31 Refer to 

“Nucla APCD Cost Analysis” for more details. The Division used two discrete 

control efficiencies to demonstrate the significant uncertainty of the application of 

SNCR and the variation in resultant cost effectiveness. 

Table 12 and Table 13 depict controlled NOx emissions and control cost comparisons. 

Table 12: Nucla Unit 4 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual Emissions 

(tons/year)

Annual Average 

(lb/MMBtu)

30-day 

Rolling Average 

(lb/MMBtu)

Baseline --- 1,675 0.387

SNCR 10.3 1,503 0.347 0.399

SNCR 43.6 945 0.218 0.251

Table 13: Nucla Unit 4 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

SNCR 173 $2,238,592 $12,974 $12,974

SNCR 730 $2,238,592 $3,065 ---

Factor 2: Time Necessary for Compliance

Tri-State states that the SNCR project could be implemented in a two to three year 

time frame, but also notes that32: 

“Projects of this size entailing a significant outage lasting eight weeks or more 

must be integrated into the long term schedule in order to coordinate with the 

management of the grid and for power replacement commitments. The date on 

which EPA SIP approval occurs is necessarily the starting point for any schedule 

including significant investments for engineering and design, procurement of 

equipment and contract commitments. In addition, the schedule would have to be 

integrated into the electric supply planning process.” 

Tri-State has also described significant constructability challenges and balance-ofplant changes that will likely affect the timeframe for reconstruction of the SNCR 

project33. Nucla station is located approximately 70 miles from the nearest interstate 

highway. The facility does not have rail service and is located 40 miles from the 

nearest commercial air terminal. Below freezing temperatures are expected seven 

 31 Tri-State, Page 3. 

32 Ibid., Page 24. 

33 Ibid., Page 10. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 20 

months of the year, which affects soil excavation, structure foundations and concrete 

placement. 

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

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

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

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

reagents, overcome additional pressure drops caused by the control equipment, and 

provide steam in some cases. The cost associated with increased power needs was 

addressed in the cost effectiveness study provided by Tri-State and is reflected in the 

costs shown in the tables above. 

Installing SNCR 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; Tri-State has indicated that 

the larger quantity of on-site anhydrous ammonia storage required by the scale-up of 

the SNCR system will require the review and approval of new Risk Management 

Plans and Process Safety Management Plans. The larger tank may also trigger other 

state and local ordinances and requirements. 

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. 

Factor 5 (optional): Evaluate Visibility Results

Due to time and domain constraints, projected visibility improvements were not 

modeled by the state for this analysis. Nucla has a limited, small-scale SNCR system 

for emissions trimming purposes already installed. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Regional Haze Reasonable Progress Analysis - Nucla Page 21 

Step 6: Select RP Determination 

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

determined that NOx RP for Nucla Unit 4 is the following NOx emission rate: 

Nucla Unit 4: 0.5 lb/MMBtu (30-day rolling average) 

 

Additional Analyses of SO2 and NOx Controls for Nucla 

As state-only requirements of this Reasonable Progress determination, the Commission 

requires, and Tri-State agrees, that Tri-State conduct a comprehensive four factor analysis 

of all SO2 control options for Nucla using site-specific studies and cost information and 

provide to the state a draft analysis by July 1, 2012. A protocol for the four-factor 

analysis and studies will be approved by the Division in advance. The analysis will 

include enhancements or upgrades to the existing limestone injection system for 

increased SO2 reduction performance, and other relevant technologies such as lime spray 

dryers and flue gas desulfurization. A final analysis that addresses the state’s comments 

shall be submitted to the state by January 1, 2013. By January 1, 2013, Tri-State shall 

also conduct appropriate cost analyses, study and testing, as approved by the Division, to 

inform what performance would be achieved by a full-scale SNCR system at Nucla to 

determine potential circulating fluidized bed (CFB) boiler-specific NOx control 

efficiencies. By January 1, 2013, Tri-State shall conduct CALPUFF modeling in 

compliance with the Division’s approved BART-modeling protocol to determine 

potential visibility impacts the different SO2 and NOx control scenarios for Nucla. 

Finally, Tri-State shall propose to the state any preferred SO2 and NOx emission control 

strategies for Nucla by January 1, 2013.