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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 1 

Best Available Retrofit Technology (BART) Analysis of Control Options 

For 

Public Service Company – Hayden Station 

I. Source Description

Owner/Operator: Public Service Company 

Source Type: Electric Utility Steam Generating Unit 

SCC (EGU): Unit 1: 10100222 Unit 2: 10100226 

Boiler Type: Pulverized Coal, Dry-Bottom, Front-Fired, firing coal (Unit 1 a) 

 Pulverized Coal, Dry Bottom, Tangentially-Fired, firing coal (unit 

2) 

The facility is located four miles east of Hayden, Colorado at 13125 U.S. Highway 40 in 

Routt County. This facility consists of two (2) steam driven turbine/generator units 

(Units 1 and 2) and the associated equipment needed for generating electricity. The Unit 

1 ignitors utilize either natural gas or No. 2 fuel oil and the Unit 2 ignitors utilize No. 2 

fuel oil for startup, shutdown and/or flame stabilization. In addition to the coal fired 

boilers, other significant sources of emissions at this facility include fugitive emissions 

from coal handling, ash handling and disposal and vehicle traffic on paved and unpaved 

roads. Point source emissions of particulate matter include coal crushing and conveying, 

an ash storage silo, two (2) ash recycle silos (recycle ash used with lime in the spray 

dryer), two (2) lime storage silos, two (2) ball mill slakers (prepares lime slurry for spray 

dryer) and two (2) recycle mixers (prepares recycle as slurry for spray dryer). Additional 

emission units at this facility include two (2) cooling towers. Only Units 1 and 2 are 

BART-eligible. Table 1 below lists the units at Public Service Company Hayden Station 

that the Division examined for control to meet BART-eligible requirements. Controlled 

and uncontrolled emission factors and CAMD data were used to evaluate the control 

effectiveness of the current emission controls. 

Table 1: Hayden Boilers Technical Information 

 Unit 1 Unit 2 

Placed in Service July 1965 1976 

Boiler Rating, 

MMBtu/Hr for coal 

1,963 2,712 

Electrical Power 

Rating, Gross 

Megawatts 

190 275 

Description Riley-Stoker Pulverized Coal Front Fired Dry 

Bottom, firing coal with natural gas and No. 2 

fuel oil used for startup, shutdown and/or flame 

stabilization. 

Combustion Engineering Pulverized Coal 

Tangentially Fired Dry Bottom, firing coal with 

No. 2 fuel oil used for startup, shutdown, and/or 

flame stabilization.

Air Pollution 

Control Equipment 

PM/PM10 - Reverse-Air Fabric Filter 

Baghouse 

NOx – Low NOx Burners with Over-Fire Air 

SO2 – Lime Spray Dryer 

PM/PM10 – Reverse-Air Fabric Filter 

Baghouse 

NOx – Low NOx Burners with Over-Fire Air 

SO2 – Lime Spray Dryer 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 2 

All equipment commenced operation in 

December 1998 

All equipment commenced operation in 

October – December 1999 

Emissions 

Reduction (%)* 

NOx – 54.1% 

SO2 – 82.0% 

PM – 99.7% 

PM10 – 98.8% 

NOx – 33.3% 

SO2 – 79.6% 

PM – 99.7% 

PM10 – 98.9% 

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

PM/PM10. For NOx and SO2 estimates, CAMD data was used to calculate reductions. See “Hayden APCD 

Technical Analysis” for further details. Not based on actual testing.

Units 1 and 2 are considered BART-eligible, being fossil-fuel steam electric plants of 

more than 250 MMBtu/hr heat input 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. These boilers also cause or contribute to visibility impairment at 

a federal Class I area at or above a 0.5 deciview change; consequently, both boilers are 

subject-to-BART. Public Service Company (PSCo) submitted a BART analysis to the 

Division on September 14, 2006 with revisions submitted on November 1, 2006 and 

January 8, 2007. In response to Division requests, PSCo submitted additional 

information on May 25 and July 14, 2010. The submittals are included as “PSCo BART 

Submittals”. 

II. Emissions for Units 1 & 2

PSCo estimated that a realistic depiction of anticipated annual emissions for Units 1 and 

2, or “Baseline Emissions”, to be conservative, was the average of two previous years 

(2004, 2005) of emissions data in the September 14, 2006 analysis. Several years have 

passed since the original BART submittal, in which the Division has updated modeling 

and technical analyses. Therefore, the Division used years 2006 – 2008 (annual averages 

and 30-day rolling) for baseline emissions for reduction and cost calculations. 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 2. 

Table 2: PSCo Hayden Units 1 & 2 Emissions 

Pollutant 

Unit 1 Unit 2 

Annual Emissions* 

(tpy) 

Annual emissions** 

(lb/MMBtu) 

Annual Emissions* 

(tpy) 

Annual emissions** 

(lb/MMBtu) 

NOx 3,750 0.415 3,743 0.320 

SO2 1,172 0.131 1,469 0.127 

PM10 88.0 0.006*** 109.3 0.004*** 

*Using daily CEMs data from 2006 – 2008 calendar years (CAMD data).

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

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

***The PM10 emission rate is determined from the latest Title V permit compliance stack test (June 2009). 

These values are as follows: Hayden Unit 1: 0.006 lb/MMBtu Hayden Unit 2: 0.004 lb/MMBtu
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 3 

III. Units Evaluated for Control

PSCo notes that the Hayden boilers burn Colorado coal that primarily comes from two 

different mines in northwestern Colorado, the Twenty Mile Mine and the ColoWyo Mine. 

Coal characteristics are very similar from both of these mines. However, the ColoWyo 

coal is ranked as sub-bituminous while the Twenty Mile coal is ranked as bituminous 

(ASTM Method 388). However, PSCo performed an analysis using the Electric Power 

Research Institute (“EPRI”) NOx/LOI Predictor software program (Version 2.1) to 

demonstrate that the more appropriate rating for ColoWyo coal is bituminous. The 

specifications for these coals are listed below in Table 3. Note that with the exception of 

moisture content, the coal characteristics are reasonably close for the two coals. 

Table 3: Hayden Station Coal Specifications (2004 – 2005) 

Coal Mine/Region Colowyo Twentymile 

Coal Rank Classification Sub-bituminous, Class A Bituminous 

As Received Analysis 

H2O (Moisture %) 16.8 9.8 

Ash (%) 5.82 9.5 

Sulfur (%) 0.36 0.49 

Nitrogen (%) 1.33 1.65 

Heating Value (HHV Btu/lb) 10,450 11,350 

EPRI Model NOx Prediction (lb/MMBtu) 0.46 0.39 

 Uncontrolled emission factors are outlined in Table 4. 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 4: Uncontrolled emission factors for PSCo Hayden BART-eligible sources1

 Pollutant (lb/ton)* 

Emission Unit NOx SO2 PM 

(filterable) 

PM10

(filterable) 

Hayden Unit 1 22** 18.6 95 21.9 

Hayden Unit 2 15** 18.6 95 21.9 

*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, determined from Table 3. 

 **Assumed no low-NOx burners. 

IV. BART Evaluation of Units 1 and 2

A. Sulfur Dioxide (SO2)

Step 1: Identify All Available Technologies

Semi-Dry FGD Upgrades – As discussed in EPA’s BART Guidelines2

, electric generating units 

(EGUs) with existing controls achieving removal efficiencies of greater than 50 percent are not 

 

1

 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 2

 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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 4 

required to remove these controls and replace them with new controls. The Division interprets 

this to include fuel switching to natural gas, which would require significant boiler 

modifications, including removing the semi-dry FGD. 

However, based on Appendix Y [70 FR 39171], the following dry scrubber upgrades should be 

considered for Hayden Units 1 and 2 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 

-Additional equipment and maintenance: In the May 25, 2010 response to the Division, PSCo 

noted that Hayden Units 1 and 2 could potentially achieve a new reduced 30-day average 

emission rate limit of 0.13 lbs/MMBtu by conducting changes to the dry scrubber systems, so 

this option will be evaluated as part of possible semi-dry FGD upgrades. 

The current Operating Permit limits are depicted in Table 5. 

Table 5: Hayden Units 1 & 2 SO2 Operating Permit Limits 

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

3-hr rolling 30-day rolling 90-day rolling 30-day rolling

Units 1 & 2 1.2 0.160 0.130 82 (rounded)

Step 2: Eliminate Technically Infeasible Options

At the Division’s request, PSCo submitted an SO2 upgrade analysis to the Division on May 25, 

2010 regarding potential upgrades for the LSDs installed on Hayden Units 1 and 2. The 

following summarizes PSCo’s submittal and the Division’s analysis of the information provided. 

FGD: Flue gas desulfurization removes SO2 from flue gases by a variety of methods. The most 

common dry FGD system is a lime spray dry absorber uses that slaked lime slurry sprayed into 

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

particulate control device. Generally, FGD control systems need to be located in close proximity 

to the boiler exhaust gas stream to prevent condensation (e.g. cooling of the exhaust gases) that 

result in acidic precipitation in the duct which results in corrosion issues. 

Dry FGD Upgrades: Dry FGD systems are commonly known as spray dry absorbers (SDA) or 

lime spray dryers (LSD), and currently make up about 12% of FGD systems at U.S. power 

plants3. SDA systems are typically utilized at units that burn lower-sulfur coal in the western 

U.S., where water resources are limited. A SDA system must be located before the boiler flue 

gases enter the baghouse. Each reactor vessel requires a “foot print” area comprising about 

2,000 to 4,000 square feet (depending on volume of flue gas treated) along with additional space 

for support equipment access, slurry preparation, mixing and associated tanks. 

 

3

 Electric Power Research Institute: A Review of Literature Related to the Use of Spray Dryer Absorber Material – 

Production, Characterization, Utilization Applications, Barriers, and Recommendations, Technical Report, 

September 2007. University of North Dakota: Energy & Environmental Research Center – Coal Ash Resources 

Research Consortium. 15 North 23rd Street, Stop 9018. Grand Forks, ND, 58202. Pg. v. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 5 

PSCo installed lime spray dryers (LSDs) in connection with baghouses on Hayden Units 1 and 2 

1998 and 1999, respectively. PSCo notes that both of these dryers currently achieve greater than 

80% removal, with actual annual averages of 0.13 lbs SO2/MMBtu (each unit) in comparison 

with the permit limits4

 depicted in Table 5. This system exceeds EPA’s presumptive limits 

stated in 40 CFR Part 51 Appendix Y of 0.15 lb/MMBtu, although the current permit limit is 

higher than the presumptive limits. 

At the Division’s request, PSCo submitted a SO2 upgrade analysis to the Division on May 25, 

2010 regarding potential upgrades for the lime spray dryer systems at Hayden Station. Hayden’s 

Babcock and Wilcox (B&W) lime spray dryers that use a single atomizer per scrubber module 

design that sprays a mixture of lime and recycled ash into the flue gas. This atomized mist then 

dries, reacts with SO2 in the flue gas and is collected in the baghouse. 

PSCo examined potential upgrades to the Hayden dry scrubbers, with the following results: 

-Use of performance additives: The supplier (Babcock & Wilcox) of PSCo’s Colorado dry 

scrubbing equipment does not recommend the use of any performance additive. PSCo is aware 

of some additive trials, using a chlorine-based chemical, which have been used on dry scrubbers. 

Chlorides are used to slow the drying time of the fly ash/lime mixture used to capture the 

gaseous SO2. The chemistry of the calcium sulfate/sulfite reaction is much more effective when 

liquid water droplets exist. By slowing the drying time the theory is that the lime sorbent will be 

more efficient and the lime use could be decreased to obtain the same SO2 reduction capability of 

the equipment unless the unit is limited on the total amount of lime slurry injection. There are 

cases on units that use high sulfur coal (significantly greater than 1.2 lbs/MMBtu) where the total 

amount of lime slurry injection is limited by the solids content of the slurry. When the total limit 

injection for a unit is limited, additives may allow some increase in SO2 removal. However, 

because the Hayden boilers burn low sulfur western coals, PSCo is not limited on lime slurry 

injection and the use of performance additives on the scrubbers would not be expected to 

increase the SO2 removal. Based on the information provided by PSCo, the Division agrees that 

the use performance additives are not likely to increase SO2 removal and therefore warrants no 

further consideration. 

-Use of more reactive sorbent: All PSCo dry scrubbers were designed to use a highly reactive 

lime with 92% calcium oxide content. The scrubbers were also designed to inject fly ash to 

maximize available surface area and allow efficient lime reagent use. Some dry scrubbers used 

by other companies were designed to use a lower quality lime, a dry hydrated lime product, or 

operate on lime without fly ash. On these scrubbers, the option of using a higher quality lime or 

injecting fly ash possibly could improve SO2 removal. The only other common reagent option 

for a dry scrubber is sodium-based products which are more reactive than freshly hydrated lime. 

Sodium has a major side effect of converting some of the NOx in the flue gas into NO2. Since 

NO2 is a visible gas, large coal-fired units can generate a visible brown/orange plume at high 

SO2 removal rates, such as those experienced at Hayden. 

 

4

 Colorado Operating Permit Number 96OPROB132 Last Revised 5/14/10. Pgs. 6, 9. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 6 

Lime is the reagent of choice in modern spray dryer systems on utility scale units. PSCo is 

aware of only one exception that was designed to use sodium carbonate to remove SO2. The 

Coyote Station, a 420MW unit located near Beulah, North Dakota and operated by Otter Tail 

Power Company, was placed in service in 1981. The spray dryer was supplied by Rockwell and 

used rotary atomizers. The unit was designed to obtain 70% SO2 removal. This unit was 

reported to have a visible plume at times likely due to the conversion from NO to NO2 due to the 

sodium reagent. This unit was converted from sodium carbonate to lime after a number of years 

in service. PSCo verified with the two major suppliers of utility sized spray dryers, B&W and 

Alstom, and confirmed that there are no other operating utility spray dryers in the United States. 

B&W also states that in theory the sodium based reagents are more reactive as they have a 

slower drying time than lime reagents. However, because of their slower drying time, the spray 

dryer absorber would need to be larger to ensure the product was dry when leaving the scrubber. 

Thus, the use of sodium reagent in a unit designed for lime would not allow higher SO2 removal 

and it may not even be possible to convert to a sodium reagent with the existing equipment. 

PSCo is using a highly reactive reagent that maximizes SO2 removal; there are no known 

acceptable reagents without side effects that would allow additional SO2 removal in the dry 

scrubbing systems present at Hayden Station. The Division agrees with PSCo’s assessment and 

considers that use of a more reactive sorbent does not warrant further consideration. 

-Increase the pulverization level of sorbent: The Hayden dry scrubbers are designed with either 

horizontal or vertical ball mills to obtain optimum particulate size and reduce lime grit 

generation. There have been some technical papers presented by pulverizer suppliers, that state 

vertical ball mills may provide a smaller particulate size and reduce lime use. PSCO’s 

experience is that there is no SO2 removal benefit in using vertical ball mills versus horizontal 

ball mills and there is also no measurable reduction in lime use. Since PSCo already uses the 

best available grinding technologies, the Division would agree that changes to the design of the 

atomizers are unlikely to result in a higher SO2 removal. 

-Engineering redesign of atomizer or slurry injection system: The Hayden dry scrubber systems 

are from B&W and use the same size and general design atomizer, a Model F800. While there 

are differences in the motor size and exact atomizer wheel construction that relate to the total 

slurry injection rate, the atomizer design is based on the vendor’s experience to maximize both 

SO2 removal and lime use efficiency. B&W offers no upgrade in atomizer design to improve 

SO2 removal. There are certain third-party suppliers who offer different atomizer nozzle designs 

that they claim can reduce lime use or provide longer maintenance life. To PSCo’s knowledge, 

no vendors claim an improved SO2 removal. PSCo has tried some of these different nozzle 

designs and doesn’t believe any of the designs improve the SO2 removal level, although some 

have improved wear life and reduced maintenance costs. 

However, PSCo provided to the Division upon additional request (July 14, 2010) additional 

information stating that an additional scrubber module (i.e. atomizer) would be required for each 

unit as well as additional spare parts and maintenance personnel in order to meet a lower 

emission limit. Therefore, this option is technically feasible. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 7 

-Additional equipment and maintenance: PSCo reviewed actual operating experience on Hayden 

along with possible changes to the systems necessary to achieve lower emission rates on a 30-

day average basis. The primary factors that affect SO2 control efficiency for short-term averages 

are start-ups, equipment malfunctions, and low load operation. In order to begin injecting 

lime/recycle ash slurry into the scrubber, a minimum inlet scrubber temperature must be 

achieved so the lime/recycle ash slurry dries when it hits the hot flue gas. When the scrubber 

inlet temperature is below this minimum level, the lime slurry drops out in the scrubber and 

forms concrete-like deposits that eventually plug the scrubber vessel. This situation actually 

occurred while operating PSCo’s Comanche Unit 2 and Valmont Unit 5 scrubbers and resulted in 

extended maintenance outages to clean the scrubbers. During unit start-ups, it can take anywhere 

from 12-24 hours to get the inlet scrubber temperatures up to the level necessary for safe lime 

slurry injection. 

During these start-up periods, SO2 emissions rates are at uncontrolled levels based on the sulfur 

content in the coal. Typically, if the unit only starts once during a 30-day period, operators can 

over-control SO2 by running the scrubber below the 30-day average emission rate to "make-up" 

for higher emission rates during start-up. If the unit has more than one start-up in a 30-day 

period, which certainly happens with older units, it becomes nearly impossible to scrub hard 

enough to achieve the 30-day rolling emission rate limits. The same situation occurs under low 

load operation, especially during winter months. Inlet temperature to the baghouse due to air 

heater in-leakage can approach minimum acceptable levels, thus lowering overall SO2 control 

efficiency during low load operation. PSCo coal-fired units will be required to cycle (under 60% 

load) more in the future to accommodate the intermittent nature of ever increasing wind 

generation on the electric grid and thus requiring the boilers to operate more frequently at low 

loads. 

Based on a review of actual operating data and the factors noted above that affect short-term 

average SO2 emission rates, PSCo believes Hayden Units 1 and 2 can achieve a lower 30-day 

average emission rate limit of 0.13 lbs/MMBtu as BART. This is currently the 90-day average 

emission limit for these units. In order to meet this lower limit on a 30-day average basis, the 

plant needs to purchase additional spare atomizer parts and increase annual operating and 

maintenance due to increased labor and reagent requirements. 

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

PSCo provided the Division 30-day rolling average control estimates. In the Division’s 

experience, 30-day SO2 rolling average emission rates are expected to be approximately 5% 

higher than the annual average emission rate. The Division projected an annual average 

emission rate at 5% for Hayden to determine control efficiencies and annual reductions. 

The Division has reviewed the data supplied by PSCo as well as other control techniques applied 

to pulverized coal boilers. A Division review of the EPA’s RBLC revealed recent BACT SO2

determinations range from 0.06 – 0.167 lbs/MMBtu. The Division narrowed down this range 

depending on the averaging time, permit type, facility size, and fuel type. This narrowed range is 

0.095 – 0.161 lbs/MMBtu, with an average of 0.119 lbs/MMBtu rounded to 0.12 lbs/MMBtu. 

While determinations made by other states do not dictate the emissions rate choice made by the 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 8 

Division, they do provide information on the range to validate the emissions rate chosen by the 

Division. Refer to “Division RBLC Analysis” for more details. 

Engineering redesign of atomizer or slurry injection system: At the Division’s request, PSCo 

sent cost information regarding the requirements for an additional scrubber module on July 14, 

2010 in order to meet a SO2 30-day rolling emission limit of 0.08 lb/MMBtu, or 90% control 

efficiency (pre-control). This upgrade/redesign will result in control efficiencies of 41.7% and 

40.1% beyond the current reductions shown in Table 1 on Units 1 and 2, respectively. Using this 

information, the Division calculated the resultant control effectiveness using the baseline and 

annual emissions for each unit. See “Hayden APCD Technical Analysis” for more information. 

Dry FGD Upgrade – Additional equipment and maintenance: To evaluate the control 

effectiveness of tightening the 30-day rolling emission limits on Hayden Units 1 and 2, the 

Division used the annual baseline emissions, the average annual operating hours (2006 – 2008), 

and the daily heat input (MMBtu/day) to determine the emission rates at 0.13 lb/MMBtu and 

calculated the resultant control effectiveness and annual emissions for each unit. 

Table 6 summarizes each available technology and technical feasibility for SO2 control. 

Table 6: Hayden Units 1 and 2 SO2 Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%) 

Technically 

Feasible? (Y = yes, 

N = no) 

Dry FGD Upgrades 

 Use of performance additives n/a N 

 Use of more reactive sorbent n/a N 

 Increase pulverization level of sorbent n/a N 

 Engineering redesign of atomizer or 

slurry injection system 

~40 – 42% Y 

 Additional equipment and maintenance ~3 - 5% Y 

Step 4: Evaluate Impacts and Document Results

Cost of Compliance

Engineering redesign of atomizer or slurry injection system: The Division calculated cost 

estimates for an additional scrubber module – based on total capital and operating and 

maintenance costs provided in PSCo’s July 14, 2010 letter. PSCo stated that Hayden Station will 

need for an additional module on each unit as well as estimated spare parts and additional 

maintenance personnel (i.e. O&M costs). PSCo estimated capital costs for Unit 1 at $37,000,000 

and Unit 2 at $43,000,000 and operating & maintenance costs at $650,000 and $750,000 for 

Units 1 and 2, respectively. These costs are determined based on meeting a more stringent 30-

day rolling limit of 0.08 lb/MMBtu for each unit. 

Dry FGD Upgrade – Additional equipment and maintenance: The Division calculated cost 

estimates for dry FGD upgrade – additional equipment and maintenance – based on total capital 

and operating and maintenance costs provided in PSCO’s May 25, 2010 letter. PSCo stated that 

Hayden Station will need spare atomizer parts at a cost of $330,000 along with increased annual 

operating and maintenance costs of $220,000 per year for reagent and labor to meet the more 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 9 

stringent 30-day rolling SO2 emission limit of 0.13 lbs/MMBtu. This cost analysis was 

conducted to demonstrate the impact of meeting the more stringent limit only. Table 7, Table 8, 

Table 9, and Table 10 show the SO2 control cost per unit. 

Table 7: Hayden Unit 1 Control Resultant SO2 Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual 

Emissions

(tons/year)

Annual 

Average

(lb/MMBtu)

30-day Rolling 

Average

(lb/MMBtu)

Baseline --- 1,172 0.131

Dry FGD Upgrade –

Additional Equipment and 

Maintenance

5.2% 1,111 0.124 0.130

Additional Scrubber 

Module 41.7% 684 0.076 0.080

Table 8: Hayden Unit 2 Control Resultant SO2 Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual 

Emissions

(tons/year)

Annual 

Average

(lb/MMBtu)

30-day Rolling 

Average

(lb/MMBtu)

Baseline --- 1,469 0.127 

Dry FGD Upgrade – 

Additional Equipment and 

Maintenance 

2.7% 1,430 0.124 0.130 

Additional Scrubber Module 40.1% 880 0.076 0.080 

Table 9: Hayden Unit 1 SO2 Cost Effectiveness 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

Dry FGD Upgrade – 

Additional Equipment 

and Maintenance

61 $141,150 $2,317 $2,317

Additional Scrubber 

Module 488 $4,142,538 $8,490 $9,370
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 10 

Table 10: Hayden Unit 2 SO2 Cost Effectiveness 

Alternative Emissions 

Reduction (tpy)

Annualized 

Cost ($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

Dry FGD Upgrade – 

Additional Equipment 

and Maintenance

39 $141,150 $3,626 $3,626

Additional Scrubber 

Module 589 $4,808,896 $8,164 $8,485

Energy and Non-Air Quality Impacts

There are no energy and non-air quality impacts related to tightening the emission limit for SO2 

beyond the acquisition of additional reagent. Thus, this factor does not influence the selection of 

controls. 

Remaining Useful Life

PSCo asserts that the remaining useful life of Hayden Units 1 and 2 are each in excess of 20 

year, which is the maximum amortization period allowed in the BART analysis. Thus, this 

factor does not influence the selection of controls. 

Step 5: Evaluate Visibility Results

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

various control technologies. The modeling guideline requires that modeled baseline emission 

rate is the 24-hour peak emission rate. The modeling guideline also requires that, at a minimum, 

the presumptive emission rate scenario be modeled. Table 11 shows the number of days pre- and 

post-control. Table 12 depicts the visibility results (98th percentile impact and improvements) as 

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

Division. 

Per the April 2010 modeling protocol5

, to isolate the effects of a given unit for controls on a 

given pollutant, the Division has judiciously constructed each emissions scenario to isolate the 

impact of a given BART control on a given unit. For example, to determine the effect of a SO2

BART control technology on a given unit, emission rates for the other pollutants (NOx and 

PM/PM10) and other BART-eligible units are held constant at pre-control levels. For BART 

sources with more than one BART unit, modeling the units individually would ignore important 

atmospheric chemical reactions that occur when units operate simultaneously. The combination 

scenario assumed Units 1 and 2 with NOx emissions at 0.07 lb/MMBtu and SO2 emissions at 

0.12 lb/MMBtu. 

In situations where the BART-eligible units at a given BART-eligible source operate 

simultaneously, the sulfate and nitrate estimates from the modeling system will be more realistic, 

in general, if all BART units and all pollutants at a BART-eligible source are modeled together. 

 

5

 Colorado Air Pollution Control Division, Technical Services Program, 2010. “Supplemental BART Analysis 

CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling Analysis.” 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 11 

The combined unit approach has the added benefit of allowing Colorado to estimate the net 

degree of visibility improvement from the simultaneous operation of BART controls on multiple 

units for multiple pollutants at a given BART-eligible source. 

Table 11: 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-hr 

SO2 rates 

1 0.339 

Rocky 

Mountain 

National 

Park 

236 --- --- 155 --- --- 

2 0.402 

Dry FGD 

Upgrade 

1 0.160* n/a 

2 0.160* n/a 

Dry FGD 

Upgrade 

1 0.130 236 228 8 155 147 8 

2 0.130 236 224 12 155 143 12 

Additional 

Scrubber 

Module 

1 0.100 236 228 8 155 146 9 

2 0.100 236 223 13 155 143 12 

Additional 

Scrubber 

Module 

1 0.070 236 228 8 155 146 9 

2 0.070 236 223 13 155 142 13 

Combo 

1 0.070 

2 0.070 236 57 179 155 6 149 

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

Modeling Summary” for more details. 

Table 12: 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 

Cost 

Effectiveness 

(dv) (∆ dv) (%) ($/dv) 

Max 24-hr 

SO2 rates 

1 0.339 

3.627 --- --- --- 

2 0.402 

Dry FGD 

Upgrade 

1 0.160* 3.540 0.09 2% n/a 

2 0.160* 3.445 0.18 5% n/a 

Dry FGD 

Upgrade 

1 0.130 3.525 0.10 3% $1,383,820 

2 0.130 3.422 0.21 6% $688,535 

Additional 

Scrubber 

Module 

1 0.100 3.505 0.12 3% $33,955,232 

2 0.100 3.395 0.23 6% $20,727,999 

Additional 

Scrubber 

Module 

1 0.070 3.485 0.14 4% n/a 

2 0.070 3.367 0.26 7% n/a 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 12 

Combo 

1 0.120 

0.91 2.72 75% n/a 

2 0.120 

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

Modeling Summary” for more details. 

Step 6: Select BART Control

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

SO2 BART the following SO2 emission rates: 

 Hayden Unit 1: 0.13 lb/MMBtu (30-day rolling average) 

 Hayden Unit 2: 0.13 lb/MMBtu (30-day rolling average) 

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

existing lime spray dryers (LSDs). The state evaluated the option of tightening the emission 

limit for Hayden Units 1 and 2 and determined that a more stringent 30-day rolling SO2 limit of 

0.13 lbs/MMBtu represents an appropriate level of emissions control for semi-dry FGD control 

technology. The tighter emission rate for both units is achievable with a negligible investment 

and the facility operator has offered to undertake these actions to allow for refinement of the 

emissions rate appropriate for this technology at this source despite the lack of appreciable 

modeled visibility improvement, and the state accepts this. 

B. Filterable Particulate Matter (PM10) 

Hayden Units 1 and 2 are each equipped with reverse-air fabric filter baghouses to control 

PM/PM10 emissions. Baghouses, or fabric filters, operate on the same principle as a vacuum 

cleaner. Air carrying dust particles is forced through a cloth bag. As the air passes through the 

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

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

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

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

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

Table 13 shows the most recent stack test data (2009). Real-time data demonstrates that these 

baghouses are meeting >99% control. The Title V permit limit is 0.03 lb/MMBtu. 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 13: Hayden Units 1 and 2 Stack Test Results (2009) 

Pollutant Unit 1 (lb/MMBtu) Unit 2 (lb/MMBtu) 

Filterable PM10 0.006 0.004 

PM10 Control efficiency 99.85% 99.91% 

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. While 

determinations made by other states do not dictate the emissions rate choice made by the 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 13 

Division, they do provide information on the range to validate the emissions rate chosen by the 

Division. Refer to “Division RBLC Analysis” for more details. 

Both boilers must meet the PM emission standard of 0.03 lb/MMBtu in accordance with the 

Long-Term Strategy Review and Revision of Colorado’s SIP for Class I Visibility Protection 

Part I: Hayden Station Requirements (8/15/96), as approved by EPA at 62 FR 2305 (1/16/97), 

Section VI.C.V.8.c.ii(2). 

The state has determined that the emission limit of 0.03 lb/MMBtu (PM/PM10) represents the 

most stringent level of available control for PM/PM10. The units are exceeding a PM control 

efficiency of 95%, and the state has selected this control technology and emission limit for 

PM/PM10 as BART. The state assumes that the BART emission limit can be achieved through 

the operation of the existing fabric filter baghouses. Thus, as described in EPA’s BART 

Guidelines, a full five-factor analysis for PM/PM10 is not needed for Hayden Units 1 and 2. 

C. Nitrogen Oxide (NOx) 

Step 1: Identify All Available Technologies

PSCo identified three options for NOx control: 

Low NOx burners (next generation) 

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) 

Rotating overfire Air (ROFA) 

Separated overfire Air (SOFA) 

Low NOx Burners (LNB) 

LNB + SOFA 

Coal reburn +SNCR 

Step 2: Eliminate Technically Infeasible Options

Low NOx burners (PSCo – LNB): PSCo evaluated low NOx burner upgrades for Hayden Units 1 

and 2, completing studies in July 2006. Units 1 and 2 currently have first-generation low NOx

burners and over-fire air systems. The combustion modifications include upgrades to these 

existing low NOx burners rather than complete burner replacements. In addition, changes to the 

over-fire air systems were also needed to achieve further NOx reductions on these units. LNB 

upgrades are technically feasible for Hayden Units 1 and 2. 

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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 14 

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 Hayden Units 1 and 2. 

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 Hayden, two retrofit SCR systems, the 0.07 lb/MMBtu 

controlled NOx value is more expected. The SCR reaction occurs within the temperature range 

of 550°F to 850°F where the extremes are highly dependent on the fuel quality. There are three 

different types of SCR arrangements – high-dust, low-dust, and tail-end. The pre-dominant 

arrangement applied in the United States has been high-dust. In most circumstances, a high-dust 

SCR system is the most economical arrangement alternative. PSCo economically evaluated a 

high-dust SCR arrangement. SCR is a technically feasible alternative for Hayden Units 1 and 2. 

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 boiler6

 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 boilers7

 and has not been demonstrated for other types of 

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

LNB/ROFA®/SOFA/LNB+SOFA: Hayden Units 1 and 2 are already equipped with low NOx

burners with over-fire air (LNB+OFA)as part of a consent decree entered by the District Court 

on August 19,1996, Civil Action 93-B-1749 and adopted into revisions to Colorado’s Visibility 

SIP, specified in a document entitled “Long-Term Strategy Review and Revision of Colorado’s 

State Implementation Plan for Class I Visibility Protection Part I: Hayden Station 

Requirements,” dated August 15, 1996. Table 1 illustrates that these systems achieve 49.5% and 

43.3% NOx reductions (based on actual emissions) on Units 1 and 2, respectively. 

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 

 

6

 Powerspan ECO®: Overview and Advantages, 2000 – 2010. http://www.powerspan.com/ECO_overview.aspx 7

 Fuel Tech: Air Pollution Control – Rich Reagent Injection (RRI), 1998 – 2009. http://www.ftek.com/apcRRI.php 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 15 

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. 

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

achieving NOx emission reductions from 45 to 65 % based on fuel load8

. While ROFA is 

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

expected to increase emissions reductions for Hayden Units 1 and 2. Since ROFA® technology 

would not be expected to provide better emissions performance than the LNB+SOFA baseline 

for these units, ROFA® technology is not considered further in this analysis. 

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

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

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

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

or well below 0.1 lb/MMBtu9

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

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

Step 3: Evaluate Control Effectiveness of Each Remaining Technology

PSCo provided the Division 30-day rolling average control estimates. The Division, from 

experience and other state BART proposals10, determined that 30-day NOx rolling average 

emission rates are expected to be about 5 -15% higher than the annual average emission rate. 

The Division projected an annual average emission rate at 15% for Hayden to determine control 

efficiencies and annual reductions. 

Low NOx burners (PSCo – LNB): PSCo stated in their April 20, 2010 submittal that Hayden 

Units 1 and 2 can meet a 30-day rolling limit of 0.30 lb/MMBtu and 0.24 lb/MMBtu respectively 

with upgraded low NOx burner systems. The baselines from Table 2 show that Hayden Unit 1 

baseline NOx emissions are 0.415 lb/MMBtu and Unit 2 baseline NOx is 0.320 lb/MMBtu. 

Therefore, the control effectiveness for upgraded low NOx systems for Unit 1 is 37.1% and Unit 

2 is 34.8%. As shown in Table 1, the current low-NOx burners with overfire air systems achieve 

54.1% and 31.3% control respectively. These upgrade control estimates are greater than EPA’s 

AP-42 emission factor table, which estimate LNB with OFA as achieving 40 – 60% reduction.11

In a recent AWMA study, wall-fired boilers burning sub-bituminous coal fitted with LNB+OFA 

system achieved NOx reductions from 40 – 80.9% (similar to Hayden Unit 1). Tangential-fired 

boilers achieved NOx reductions ranging from 11.3 – 74.4%.12 With such wide control 

 

8

 Nalco-Mobotec, ROFA Technology, 1992-2009, http://www.nalcomobotec.com/technology/rofa-technology.html 9

 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 10 State of North Dakota BART Determination for Leland Olds Station Units 1 and 2. Page 16. 11 EPA AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.1, Table 1.1-2. 

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf 12 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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 16 

efficiency ranges, the Division concludes that the 88.9% and 66.1% (pre-control) reductions 

estimated by PSCo are reasonable. 

SNCR: PSCo stated in their April 20, 2010 submittal that Hayden Units 1 and 2 can meet a 30-

day rolling limit of 0.30 lb/MMBtu and 0.21 lb/MMBtu respectively by installing SNCR on each 

boiler. Therefore, the control effectiveness for SNCR on Unit 1 is 37.1% and Unit 2 is 43.0%. 

These control effectiveness estimate is consistent with EPA’s SNCR Air Pollution Control 

Technology Fact Sheet between 30 – 50% control efficiency for tangentially fired boilers. 

Control effectiveness has been historically noted to be lower for wall fired boilers similar to Unit 

1. Therefore, the Division concludes that the reductions estimated by PSCo are reasonable. 

SCR: PSCo stated in their April 20, 2010 submittal that Hayden Units 1 and 2 can meet a 30-day 

rolling limit of 0.08 lb/MMBtu and 0.07 lb/MMBtu respectively by installing SCR on each 

boiler. Therefore, the control effectiveness for SCR on Unit 1 is 83.2% and Unit 2 is 81.0%. 

These control efficiencies are consistent with EPA’s AP-42 emission factor tables, which 

estimate SCR as achieving 75 – 85% NOx emission reductions and also with a recent AWMA 

study citing SCR as achieving 80 – 90% reduction.13,14 

Table 14 summarizes each available technology and technical feasibility for NOx control. 

Table 14: Hayden Units 1 and 2 NOx Technology Options and Technical Feasibility 

Technology Emission 

Reduction 

Potential (%)

Technically Feasible? 

(Y = yes, N = no)

Low NOx Burner (LNB) 

Upgrade

~35 - 37% Y

SNCR 20 – 50% Y

SCR 75 – 90% Y

Electro-Catalytic Oxidation 

(ECO)®

n/a N

Rich Reagent Injection (RRI) n/a N

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

LNB + OFA 25-45% Y – installed

Air Staging – overfire air 

(OFA)

5-40% Y – installed

Rotating overfire air (ROFA) 45 – 65% N

Coal reburn+SNCR n/a N

 

13 EPA AP-42, Fifth Edition, Volume I, Chapter 1, Section 1.1, Table 1.1-2. 

http://www.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf 14 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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 17 

Step 4: Evaluate Impacts and Document Results

Cost of Compliance

Low NOx burners (PSCo – LNB)/SNCR/SCR: PSCo completed engineering studies in July 2006 

to evaluate the cost of combustion controls on Hayden Units 1 and 2. These cost estimates, in 

2006 dollars, were based on vendor data and not on actual bids with performance guarantees. 

PSCo used the Coal Utility Environmental Cost Workbook (CUECost) to develop cost estimates 

for capital and annual costs ,an EPA-approved methodology to estimate rough order-ofmagnitude (ROM) cost estimates for air pollution control systems installed on coal-fired power 

plants (± 30%).15 PSCo provided CUECost input files at the Division’s request on April 20, 

2010. PSCo used this program for LNB, SNCR, and SCR system estimates. The Division 

concurs that CUECost is an appropriate methodology for determining cost effectiveness 

regarding these control technologies. 

LNB: In reviewing PSCo’s estimates, the Division found that the ratio of annual costs to the total 

costs for LNBs, which at 11.7% is consistent with an EPA assessment that concluded that 

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

from 12 – 15% of total capital investments. 16 Therefore, the Division concludes that 

PSCo’s estimates for LNBs are reasonable. 

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.17 The PSCo-estimated 

SNCR costs for operating expenses are 74% and 77% for Hayden Units 1 and 2 

respectively. Since SNCR is an operating expense-driven technology, its cost varies 

directly with NOx reduction requirements and reagent usage. There is a wide range of 

cost effectiveness for SNCR due to different boiler configurations and site-specific 

conditions, even with a given industry. Cost effectiveness is impacted primarily by 

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

economic life of the unit, and degree of retrofit difficulty.18 

 

The cost effectiveness for SNCR on Units 1 and 2 is about $1,000 and $1,200 per ton, 

respectively. Recent NESCAUM studies estimate SNCR retrofits on tangentially fired 

boilers (similar to Unit 2) achieving NOx emission rates of 0.30 – 0.40 lb/MMBtu and 

emission reductions of 30 – 50% as costing $630 - $1,300 per ton of NOx reduced, 

 

15 2009, Yelverton, William H. “Coal Utility Environmental Cost (CUECost) Workbook Development 

Documentation Version 5.0. Prepared by: ARCADIS, 4915 Prospectus Drive, Suite F, Durham, NC 27713. 

Prepared for: U.S. Environmental Protection Agency, Office of Research and Development, Air Pollution 

Prevention and Control Division, Research Triangle Park, NC 27711. 

16 Environmental Protection Agency, 2009. 40 CFR Part 49: Assessment of Anticipated Visibility Improvements at 

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

Plant and Navajo Generating Station: Advance Notice of Proposed Rulemaking. Pg. 44318. 

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

for Controlling NOx Emissions.” Washington, D.C. 2000. 18 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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 18 

depending on initial capital costs and capacity factor.19,20 This same study estimate 

SNCR retrofits on wall fired boilers (similar to Unit 1) 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. It should be noted that PSCo is 

estimating resultant emission rates lower than 0.30 lb/MMBtu for both boilers. EPA’s 

SNCR Fact Sheet cites SNCR as costing from $400 - $2,500 per ton of NOx reduced. 21

PSCo’s estimates are within this range. Therefore, the Division concludes that PSCo’s 

cost estimates for SNCR are reasonable. 

SCR: Recent NESCAUM studies estimate SCR retrofits on tangentially fired boilers achieving 

NOx emission rates of 0.10 – 0.15 lb/MMBtu and emission reductions of 75 – 85% as 

costing $2,600 - $5,000 per ton of NOx reduced, depending on initial capital costs and 

capacity factor.22,23 In reviewing PSCo’s estimates, the Division found that the ratio of 

annual costs to the total costs for LNBs, which at 17% is higher than an EPA assessment 

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

costs that ranged from 12 – 15% of total capital investments.24 However, PSCo’s cost 

estimates are within the NESCAUM study ranges, so the Division concludes that PSCo’s 

cost estimates for SCR are reasonable. 

Table 15, Table 16, Table 17, and Table 18 depict controlled NOx emissions and control cost 

comparisons.

Table 15: Hayden Unit 1 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual Emissions 

(tons/year)

Annual Average 

(lb/MMBtu)

30-day 

Rolling Average 

(lb/MMBtu)

Baseline --- 3,750 0.415

LNB* 37.1 2,359 0.261 0.300

SNCR* 37.1 2,359 0.261 0.300

SCR** 83.2 630 0.070 0.080

 *Determined based on difference between baseline (2006 – 2008) and PSCo’s expected emission rates 

 

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

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

20 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. 

21 EPA, 2003. “SNCR Air Pollution Control Technology Fact Sheet.” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf 22 Neuffer, Bill – ESD/OAQPS, 2003. “NOx Controls for Existing Utility Boilers.” 

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

23 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. 

24 Environmental Protection Agency, 2009. 40 CFR Part 49: Assessment of Anticipated Visibility Improvements at 

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

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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 19 

 **The Division calculated SCR reductions using a consistent baseline whereas PSCo uses an adjusted 

baseline depending on the control technology which results in different control costs. 

Table 16: Hayden Unit 2 Control Resultant NOx Emissions 

Alternative Control 

Efficiency (%)

Resultant Emissions

Annual Emissions 

(tons/year)

Annual Average 

(lb/MMBtu)

30-day 

Rolling Average 

(lb/MMBtu)

Baseline --- 3,743 0.320

LNB* 34.8 2,441 0.209 0.240

SNCR* 43.0 2,134 0.183 0.210

SCR** 81.0 711 0.061 0.070

 *Determined based on difference between baseline (2006 – 2008) and PSCo’s expected emission rates 

 **The Division calculated SCR reductions using a consistent baseline whereas PSCo uses an adjusted 

baseline depending on the control technology which results in different control costs. 

Table 17: Hayden Unit 1 NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

LNB 1,391 $572,010 $411 $411

SNCR 1,391 $1,353,500 $973 ---

SCR 3,120 $10,560,612 $3,385 $5,326

Table 18: Hayden Unit 2NOx Cost Comparisons 

Alternative Emissions 

Reduction (tpy)

Annualized Cost 

($)

Cost Effectiveness 

($/ton)

Incremental Cost 

($/ton)

Baseline 0 $0 $0 ---

LNB 1,303 $992,729 $762 $762

SNCR 1,610 $1,893,258 $1,176 $2,934

SCR 3,032 $12,321,491 $4,064 $7,331

Energy and Non-Air Quality Impacts

LNB: There are no known non-air quality impacts associated with upgrades on low-NOx burner 

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. SCR reagent injection systems have 

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

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 20 

Post-combustion add-on control technologies such as SNCR do increase power needs, in the 

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

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

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

kW is less enough energy to power about 10 homes for a year. These energy requirements are 

minimal. 

SCR systems require additional auxiliary power or power from the existing flue gas fan systems 

to overcome the pressure loss across the catalyst, to supply dilution air for mixing with the 

ammonia, and to pump ammonia into the vaporizer. These energy requirements are moderate. 

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. 

Remaining Useful Life

PSCo asserts that there are no near-term limitations on the useful of these boilers, 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: 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. 

Per the April 2010 modeling protocol25, to isolate the effects of a given unit for controls on a 

given pollutant, the Division has judiciously constructed each emissions scenario to isolate the 

impact of a given BART control on a given unit. For example, to determine the effect of a NOx

BART control technology on a given unit, emission rates for the other pollutants (SO2 and 

PM/PM10) and other BART-eligible units are held constant at pre-control levels. For BART 

 

25 Colorado Air Pollution Control Division, Technical Services Program, 2010. “Supplemental BART Analysis 

CALPUFF Protocol for Class I Federal Area Visibility Improvement Modeling Analysis.” 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 21 

sources with more than one BART unit, modeling the units individually would ignore important 

atmospheric chemical reactions that occur when units operate simultaneously. The combination 

scenario assumed Units 1 and 2 with NOx emissions at 0.07 lb/MMBtu and SO2 emissions at 

0.12 lb/MMBtu. 

In situations where the BART-eligible units at a given BART-eligible source operate 

simultaneously, the sulfate and nitrate estimates from the modeling system will be more realistic, 

in general, if all BART units and all pollutants at a BART-eligible source are modeled together. 

The combined unit approach has the added benefit of allowing Colorado to estimate the net 

degree of visibility improvement from the simultaneous operation of BART controls on multiple 

units for multiple pollutants at a given BART-eligible source. 

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-

hr NOx 

rates 

1 0.610 

Mt. Zirkel 

Wilderness 

Area 

236 --- --- 155 --- --- 

2 0.367 

NOx 

Scenario 

1 0.390 236 227 9 155 131 24 

2 0.280 236 230 6 155 144 11 

NOx 

Scenario 

1 0.300 236 218 18 155 125 30 

2 0.210 236 226 10 155 137 18 

LNB 

1 0.261* n/a 

2 0.209* n/a 

SNCR 

1 0.261* n/a 

2 0.183* n/a 

SCR 

1 0.070 236 188 48 155 91 64 

2 0.070 236 213 23 155 116 39 

Combo 

1 0.070 

236 57 179 155 6 149 

2 0.070 

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

Modeling Summary” for more details. 

Table 20: Visibility Results – NOx Control Options 

NOx 

Control 

Scenario 

Boiler(s) 

NOx Emission 

Rate 

(lb/MMBtu)* 

Proposed Limit 

(@ 98th

Percentile 

Impact) 

98th Percentile 

Impact 

Improvement 

98th Percentile 

Improvement 

from Maximum 

Cost 

Effectiveness 

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

Max 24-hr 1 0.610 3.63 --- --- --- 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Best Available Retrofit Technology (BART) Analysis – PSCo Hayden Station Page 22 

NOx rates 2 0.367 

NOx 

Scenario 

1 0.390 3.13 0.50 14% n/a 

2 0.280 3.42 0.20 6% n/a 

NOx 

Scenario 

1 0.300 3.02 0.60 17% n/a 

2 0.210 3.23 0.40 11% n/a 

LNB 

1 0.261* 2.94 0.69 19% $832,621 

2 0.209* 3.23 0.40 11% $2,500,576 

SNCR 1 0.261* 2.94 0.69 19% $1,970,161 

2 0.183* 3.15 0.48 13% $3,969,094 

SCR 1 0.070 2.51 1.12 31% $9,462,914 

2 0.070 2.77 0.85 24% $14,427,975 

Combo 

1 0.070 

0.91 2.72 75% n/a 

2 0.070 

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

Modeling Summary” for more details. 

Step 6: Select BART Control

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

NOx BART is the following NOx emission rates: 

 Hayden Unit 1: 0.08 lb/MMBtu (30-day rolling average) 

 Hayden Unit 2: 0.07 lb/MMBtu (30-day rolling average) 

The state assumes that the BART emission limits can be achieved through the installation and 

operation of selective catalytic reduction (SCR). For these emission limits, the cost per ton of 

emissions removed, coupled with the estimated visibility improvements gained, falls within the 

guidance criteria presented in Chapter 6 of the Regional Haze State Implementation Plan: 

• Unit 1: $3,385 per ton NOx removed; 1.12 deciview of improvement 

• Unit 2: $4,064 per ton NOx removed; 0.85 deciview of improvement 

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

this determination. The NOx emission limits of 0.08 lb/MMBtu (30-day rolling average) for Unit 

1; and 0.07 lb/MMBtu (30-day rolling average) for Unit 2; are technically feasible and have been 

determined to be BART for Hayden Units 1 and 2.