1 

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

For Colstrip Energy Limited Partnership, Rosebud Power Plant, in Colstrip, Montana 

U.S. EPA Region 8 Air Program 

March 20, 2012 

Executive Summary

This four-factor analysis documents the basis for determination of Reasonable Progress (RP) 

control options for control of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions at 

Colstrip Energy Limited Partnership (CELP), Rosebud Power Plant, an electric utility power 

plant in Colstrip, Montana, operated by Rosebud Operating Services. The four-factor analysis 

consists of the following steps: 

Step 1 – Identify All Available Technologies 

Step 2 – Eliminate Technically Infeasible Options 

Step 3 – Evaluate Control Effectiveness of Remaining Control Technology 

Step 4 – Evaluate Impacts and Document Results: 

Factor 1: Cost of compliance 

Factor 2: Time necessary for compliance 

Factor 3: Energy and non-air quality environmental impacts of compliance 

Factor 4: Remaining useful life

Step 5 – Select Reasonable Progress Controls 

This analysis is based on the following submittals from CELP: 

→ Response to Request for Information for the Colstrip Energy Limited Partnership Facility 

Pursuant to Section 114(a) of the Clean Air Act (42 U.S.C. Section 7414(A) (“CELP 

Initial Response”), Rosebud Energy Corp. (Mar. 11, 2009) 

→ Response to Additional Reasonable Progress Information for the Colstrip Energy Limited 

Partnership Facility Pursuant to Section 114(a) of the Clean Air Act (42 U.S.C. Section 

7414(A)) (“CELP Additional Response”), Rosebud Energy Corp., Prepared by Bison 

Engineering Inc (Feb. 24, 2011) 

The Rosebud Power Plant is rated at 43 megawatts gross output (30 megawatts net). The 

primary source of emissions consists of a single circulating fluidized bed (CFB) boiler, fired on 

waste coal, with average heating value of 8,073 Btu/lb, sulfur content of 1.5% to 1.7% by 

weight, and ash content of 14% to 15.6% by weight. This Reasonable Progress analysis focuses 

on the CFB boiler. 

The boiler and emission controls were installed in 1989-90. Expected life of the boiler and its 

emission control equipment is 40 years from date of installation. The boiler was manufactured 

by Tampela-Keeler and utilizes a twin-cyclone design. Heat input capacity is 516 MMBtu per 

hour. Emission controls consist of a fabric filter baghouse for particulate control and limestone 

injection into the boiler for sulfur dioxide (SO2) control. There are no nitrogen oxide (NOx) add-
2 

on controls. The limestone injection system is rated at no less than 79% control efficiency. 

Limestone injection rate is 5.5 tons/hr, or about 91 tons/day. The limestone is injected with the 

waste coal prior to combustion in the boiler.1

 

CELP states that average hourly controlled emissions during 2007, as determined from CEMS 

data, were 310 lbs/hr for SO2 and 250 lbs/hr for NOx. This is equivalent to about 1,358 tons/yr 

for SO2 and 1,095 tons/yr for NOx, assuming the boiler operates at capacity for 8,760 hrs/yr. 

Actual annual tonnages would be somewhat less; none were listed by CELP in its March 13, 

2009 submittal.2

 Emissions during 2002, listed in EPA’s National Emissions Inventory, were 

705 tons/yr for SO2 and 537 tons/yr for NOx. In its cost analyses, CELP used 1,141 tons/yr for 

SO2 and 768 tons/yr for NOx.

3

Particulate matter (PM) emissions are controlled by a fabric filter baghouse that is designed to 

achieve greater than 99% control of particulates.4 As discussed in Section V.D.6.b. of EPA’s 

Federal Register notice on the proposed Montana regional haze Federal Implementation Plan, the 

contribution from point sources to primary organic aerosols, elemental carbon, and PM2.5 at 

Montana Class I areas is very small, and modeling tends to confirm that PM emissions from 

point sources do not have a very large impact. Therefore, EPA is proposing that additional 

controls for PM are not necessary for this planning period. 

Reasonable Progress Evaluation of SO2 Emissions

As stated above, current SO2 control consists of a limestone injection system rated at no less than 

79% control efficiency. Limestone injection rate is 5.5 tons/hr, or about 91 tons/day. The 

limestone is injected with the waste coal prior to combustion in the boiler.

Step 1: Identify All Available Technologies 

EPA has identified the following technologies as being available for SO2 emission reductions, 

beyond those achieved by the current control configuration at Rosebud Power Plant: 

1. Limestone injection process upgrade 

2. Dry scrubbing 

(a) Spray dry absorber 

(b) Dry sorbent injection 

(c) Circulating dry scrubber 

(d) Hydrated ash reinjection 

3. Wet scrubbing 

(a) Wet lime scrubber 

(b) Wet limestone scrubber 

(c) Dual alkali scrubber 

 

1

 CELP Initial Response, p. 3; CELP Additional Response, p. 2-2. 

2

 CELP Initial Response, p. 3. 

3

 CELP Additional Response, pp. 7-2, 7-3 and Appendix A. 

4

 CELP Additional Response, p. 2-1. 
3 

Below is a description of each available control technology. 

Limestone Injection Process Upgrade 

CELP currently controls SO2 emissions using limestone injection. Crushed limestone is injected 

with the waste coal prior to its combustion in the boiler, becoming the solid medium in which 

coal combustion takes place. When limestone is heated to 1550o F, it releases carbon dioxide 

(CO2) and forms lime (CaO), which subsequently reacts with acid gases released from the 

burning coal, to form calcium sulfates and calcium sulfites. The calcium compounds are 

removed as PM by the baghouse. Depending on the fuel fired in the boiler and the total heat 

input, this process currently removes 70% to 90% of SO2 emissions, on average about 80%. 

Increasing the limestone injection rate beyond current levels could theoretically result in a 

modest increase in SO2 control.5 

Spray Dry Absorber (SDA)

SDAs use lime slurry and water injected into a tower to remove SO2 from the combustion gases. 

The towers must be designed to provide adequate contact and residence time between the 

exhaust gas and the slurry in order to product a relatively dry by-product. The process 

equipment associated with an SDA typically includes an alkaline storage tank, mixing and feed 

tanks, atomizer, spray chamber, particulate control device, and recycle system. The recycle 

system collects solid reaction product and recycles it back to the spray dryer feed system to 

reduce alkaline sorbent use. SDAs are the commonly used dry scrubbing method in large 

industrial and utility boiler applications. SDAs have demonstrated the ability to achieve 90% to 

94% SO2 reduction.6

Dry Sorbent Injection (DSI)

Dry sorbent injection (DSI) involves the injection of powdered or hydrated sorbent (typically 

alkaline) directly into the flue gas exhaust stream. Dry sorbent injection systems are simple 

systems, and generally require a sorbent storage tank, feeding mechanism, transfer line and 

blower, and injection device. The dry sorbent is typically injected countercurrent to the gas flow 

through a venturi orifice. An expansion chamber is often located downstream of the injection 

point to increase residence time and contact efficiency. Particulates generated in the reaction are 

controlled in the system’s particulate control device. 

SO2 control efficiencies for dry sorbent injection systems by themselves (not downstream of 

limestone injection systems) are approximately 50%, but if the sorbent is hydrated lime, then 

80% or greater removal can be achieved. These systems are commonly called lime spray dryers. 

 

5

 CELP Additional Response, p. 2-2. 

6

 US EPA Region 8, Final Statement of Basis, PSD Permit to Construct, Deseret Power Elec. Coop., Bonanza Power 

Plant (“Deseret Bonanza SOB”), p. 92 (Aug. 30, 2007), available at 

http://www.epa.gov/region8/air/pdf/FinalStatementOfBasis.pdf
4 

Circulating Dry Scrubber (CDS)

A CDS uses a fluidized bed of dry hydrated lime reagent to remove SO2. Flue gas passes 

through a venturi at the base of a vertical reactor tower and is humidified by a water mist. The 

humidified flue gas then enters a fluidized bed of powdered hydrated lime where SO2 is 

removed. The dry by-product produced by this system is routed with the flue gas to the 

particulate removal system. A CDS can achieve removal efficiency similar to that achieved by 

SDA on CFB boilers.7 

 

Hydrated Ash Reinjection (HAR)

The HAR process is a modified dry FGD process developed to increase the use of unreacted lime 

in the CFB ash and any free lime left from the furnace burning process. HAR will further reduce 

the SO2 concentration in the flue gas. The actual design of an HAR system is vendor-specific, 

but in general, a portion of the collected ash and lime is hydrated and re-introduced into a 

reaction vessel located ahead of the fabric filter inlet. In conventional boiler applications, 

additional lime may be added to the ash to increase the mixture’s alkalinity. For CFB 

applications, sufficient residual lime is available in the ash and additional lime is not required. 

HAR downstream of a CFB boiler that utilizes limestone injection can reduce the remaining SO2

by about 80%.8

Wet Lime Scrubber

The wet lime scrubbing process uses alkaline slurry made by adding lime to water. The alkaline 

slurry is sprayed into the exhaust stream and reacts with the SO2 in the flue gas. Insoluble 

calcium sulfite (CaSO3) and calcium sulfate (CaSO4) salts are formed in the chemical reaction 

that occurs in the scrubber. The salts are removed as a solid waste by-product. The waste byproduct is mainly CaSO3, which is difficult to dewater. Solid waste by-products from wet lime 

scrubbing are typically managed in dewatering ponds and landfills. 

Wet Limestone Scrubber

Wet limestone scrubbers are very similar to wet lime scrubbers. Again, alkaline slurry is sprayed 

into the exhaust stream and reacts with the SO2 in the flue gas. The use of limestone (CaCO3) 

instead of lime requires different feed preparation equipment and a higher liquid-to-gas ratio. 

The higher liquid-to-gas ratio typically requires a larger absorbing unit. The limestone slurry 

process also requires a ball mill to crush the limestone feed. Similar to wet lime scrubbers, wet 

limestone scrubbers generate sludge that can create material handling and disposal issues. 

Wet lime and limestone scrubbers have been demonstrated to achieve greater than 99% control 

efficiency.9

 

7

 Id. 

8

 Id., p. 93. 

9

 Id., p. 94 (for proposed CFB boiler, indicating that a wet FGD scrubber plus limestone injection can achieve 

99.1% control efficiency). 
5 

Dual Alkali Wet Scrubber

Dual-alkali scrubbers use a sodium-based alkali solution to remove SO2 from the combustion 

exhaust gas. The process uses both sodium-based and calcium-based compounds. The sodiumbased reagents absorb SO2 from the exhaust gas, and the calcium–based solution (lime or 

limestone) regenerates the spent liquor. Calcium sulfites and sulfates are precipitated and 

discarded as sludge, and the regenerated sodium solution is returned to the absorber loop. 

The dual-alkali process requires lower liquid-to-gas ratios than scrubbing with lime or limestone. 

The reduced liquid-to-gas ratios generally mean smaller reaction units; however, additional 

regeneration and sludge processing equipment is necessary. 

A sodium-based scrubbing solution, typically consisting of a mixture of sodium hydroxide, 

sodium carbonates, and sodium sulfite, is an efficient SO2 control reagent. However, the process 

generates a sludge that can create material handling and disposal issues. The control efficiency 

is similar to the wet lime/limestone scrubbers at approximately 95% or greater. 

Step 2: Eliminate Technically Infeasible Options

Limestone Injection Process Upgrade 

The current limestone injection system is operating at or near its maximum capacity. The boiler 

feed rates are approximately 770 tons/day of waste coal and 91 tons/day of limestone. Increasing 

limestone injection beyond the current levels would result in plugging of the injection lines, 

increased bed ash production, which can reduce combustion efficiency, and increased particulate 

loading to the baghouses. Therefore, increasing limestone injection beyond its current level 

would require major upgrades to the limestone feeding system and the baghouses.10 Only 

modest increases in SO2 removal efficiency, if any, would be expected with this scenario, 

compared to add-on SO2 control systems discussed below. Therefore, a limestone injection 

process upgrade is eliminated from further consideration. 

Circulating Dry Scrubber

CDS systems result in high particulate loading to the unit’s particulate control device. Because 

of the high particulate loading, the pressure drop across a fabric filter would be unacceptable; 

therefore, electrostatic precipitators are generally used for particulate control. CELP has a high 

efficiency fabric filter (baghouse) in place. Based on limited technical data from noncomparable applications and engineering judgment, EPA is determining that CDS is not 

technically feasible for this baghouse-equipped facility.11 Therefore, CDS is eliminated from 

further consideration. 

Dry Sorbent Injection (DSI)

A DSI system is not practical for use in a CFB boiler such as CELP, where limestone injection is 

already being used upstream in the boiler for SO2 control. With limestone injection, the CFB 

 

10 CELP Additional Response, p. 2-2. 

11 Deseret Bonanza SOB, p. 92 (indicating that CDS systems have thus far not been used on CFB boilers). 
6 

boiler flue gas already contains excess unreacted lime. Fly ash containing this unreacted lime is 

reinjected back into the CFB boiler combustion bed, as part of the boiler operating design. A 

DSI system would simply add additional unreacted lime to the flue gas and would probably 

achieve little, if any, additional SO2 control.12 If used instead of limestone injection, rather than 

in addition to limestone injection (the only practical way it might be used), DSI would achieve 

less control efficiency (50%) than the limestone injection system already being used (70% to 

90%). Therefore, DSI is eliminated from further consideration. 

Note: CELP did not eliminate DSI as technically infeasible at Step 2, but calculated the cost of 

installing and using DSI at Step 4. CELP calculated the average cost effectiveness using a 

control efficiency of 50%.13 For reasons explained above, EPA believes this control efficiency 

figure is too high, where DSI is used downstream of limestone injection. Actual control 

efficiency for DSI in such a scenario would probably be very low, such that average cost 

effectiveness would be very high, eliminating DSI as too expensive, even if it was to be 

considered technically feasible. 

Wet Scrubbing

There is limited area at Rosebud Power Plant to install additional SO2 controls. A wet scrubber 

would require high quantities of water and dewatering ponds. The wet FGD scrubber systems 

with the higher water requirements (wet lime scrubber, wet limestone scrubber, dual alkali wet 

scrubber) would require an on-site dewatering pond or an additional landfill to dispose of 

scrubber sludge. Due to the limited available space, its proximity to the East Armels Creek to 

the east of the plant, an unnamed creek to the south of the plant, and limited water availability for 

these controls,14 EPA considers these technologies technically infeasible and does not evaluate 

them further. 

The remaining technically feasible SO2 control options for CELP are SDA and HAR. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

Baseline SO2 emissions from CELP are 1,141 tons per year. A summary of emissions 

projections for the various control options is provided in Table 1 below. Since limestone 

injection is already in use at the CELP facility, the control efficiencies and emissions reductions 

show below are those that might be achieved beyond the control already being achieved by the 

existing limestone injection system. 

 

12 Id., p. 93. 

13 CELP Additional Response, Appendix A, DSI control cost spreadsheet. 

14 CELP Additional Response, p. 2-5. 
7 

Table 1 

Summary of CELP SO2 Reasonable Progress Analysis Control Technologies 

Control 

Option 

Control 

Effectiveness 

(%) 

Emissions 

Reduction 

(tpy) 

Remaining 

Emissions 

(tpy) 

SDA 80 913 228

HAR 50 571 570

Step 4: Evaluate Impacts and Document Results 

Factor 1: Cost of Compliance

Table 2 provides a summary of estimated annual costs for the various control options. 

EPA has relied on the control costs provided by CELP,15 with two exceptions. First, EPA 

calculated the annual cost of capital using a 7% annual interest rate and a 20-year equipment life 

(which yields a capital CRF of 0.0944), as specified in the Office of Management and Budget’s 

Circular A-4, Regulatory Analysis.16 Second, EPA calculated the cost of SDA and HAR in two 

ways: (1) with baghouse replacement, and (2) without baghouse replacement. The calculated 

costs by CELP for both SDA and HAR included replacement of the existing baghouse. CELP 

cited one equipment vendor as saying that the baghouse design must be matched with the add-on 

control system and its particulate loading; however, CELP did not explain why the baghouse 

would need to be replaced to accommodate either SDA or HAR.17 

Table 2 

Summary of CELP SO2 Reasonable Progress Cost Analysis 

Control 

Option

Control

Effectiveness 

(%)

Tons 

SO2 

Reduced

from 

Baseline

Capital Cost

($)

Annual Cost

of Capital ($)

(CRF=.0944)

Annual

O&M

Cost ($)

Total

Annual

Cost ($)

Average Cost

 Effectiveness

($/ton reduced)

SDA w/o 

replacing

baghouse 

80 913 18,760,005 1,770,944 1,367,506 3,138,450 3,437 

HAR w/o 

replacing 

baghouse 

50 571 13,362,115 1,261,383 842,160 2,103,543 3,684

SDA with 

baghouse 

replaced 

80 913 18,760,005 + 

5,768,033 = 

24,528,038 

2,315,446 1,367,506 + 

736,520 = 

2,104,206 

4,419,472 4,840 

HAR with 

baghouse 

replaced 

50 571 13,362,115 + 

5,768,033 = 

19,130,148 

1,805,885 842,160 + 

736,520 = 

1,578,680 

3,384,565 5,927 

 

15 CELP Additional Response, Appendix A, pp. 17-24. 

16 Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

17 CELP Additional Response, p. 3-1. 
8 

Factor 2: Time necessary for compliance

EPA has relied on CELP’s estimates that the time necessary to complete the modifications to the 

boiler to accommodate SDA or HAR, without baghouse replacement, would be approximately 

four to six months and that a boiler outage of approximate two to three months would be 

necessary to perform the installation of either system. As noted previously, CELP states that 

complete replacement or major modifications to the existing baghouse would be necessary; 

however, the company does not explain why the existing baghouse would need to be replaced or 

modified to accommodate SDA or HAR. 18 

Factor 3: Energy and non-air quality environmental impacts of compliance

Wet FGD systems are estimated to consume 1% to 2.5% of the total electric generation of the 

plant and can consume approximately 40% more than dry FGD systems (SDA). Electricity 

requirements for a HAR system are less than FGD systems. DSI systems are estimated to 

consume 0.1% to 0.5% of the total plant generation.19 For reasons explained above, wet FGD 

systems and DSI systems have already been eliminated as technically infeasible. 

SO2 controls would result in increased ash production at the CELP facility. Boiler ash is 

currently either sent to a landfill or sold for beneficial use, such as oil well reclamation. Changes

in ash properties due to increased calcium sulfates and calcium sulfites could result in the ash 

being no longer suitable to be sold for beneficial uses. If the ash properties were to change such 

that the ash could no longer be sold for beneficial use, the loss of this market would cost 

approximately $1,020,000 per year at the current ash value and production rates (approximately 

100,000 tons of ash per year). The loss of this market could also result in the company having to 

dispose of the ash at its current landfill, which is adjacent to the plant. The cost to dispose of the 

ash would be approximately $62,000 per year. The total cost from the loss of the beneficial use 

market and the increase in ash disposal costs would be a total of $1,082,000 per year.20 This 

potential cost has not been included in the cost described above, as it is only speculative, being 

based on an undetermined potential future change in ash properties. 

As described above, wet FGD scrubber systems with the higher water requirements (wet lime 

scrubber, wet limestone scrubber, dual alkali wet scrubber) would require an on-site dewatering 

pond or an additional landfill to dispose of scrubber sludge. 

Factor 4: Remaining useful life 

EPA has determined that the default 20-year amortization period is most appropriate to use as the 

remaining useful life of the facility. Without commitments for an early shut down, EPA cannot 

consider a shorter amortization period in its analysis. 

 

18 Id. 

19 Id., p. 4-1. 

20 Id. 
9 

Step 5: Select Reasonable Progress Controls 

EPA has considered the following four factors: the cost of compliance; the time necessary for 

compliance; the energy and non-air quality environmental impacts of compliance; and the 

remaining useful life of the source. EPA is also taking into account the size of the facility, the 

baseline Q/D of the facility, and the potential reduction in Q/D from the controls. Given the cost 

of $3,437 per ton of SO2 (at a minimum) for the most cost-effective option (SDA), the relatively 

small size of CELP, and the small baseline Q/D of 11, EPA finds it reasonable to not impose any 

of the SO2 control options. EPA therefore proposes to not require additional SO2 controls for 

this planning period.21

Reasonable Progress Evaluation of NOx Emissions

Currently there are no NOx controls at the CELP facility. 

Step 1: Identify All Available Technologies 

EPA has identified the following technologies as being available for NOx emission reductions at 

the Rosebud Power Plant: 

1. Selective Catalytic Reduction (SCR) 

2. Selective Non-Catalytic Reduction (SNCR) 

3. Low Excess Air (LEA) 

4. Flue Gas Recirculation (FGR) 

5. Overfire Air (OFA) 

6. Low NOx Burners (LNB) 

7. Non-thermal Plasma Reactor 

8. Carbon Injection into Combustion Chamber 

Selective Catalytic Reduction (SCR)

SCR is a post-combustion gas treatment technique that uses either ammonia (NH3) or urea in the 

presence of a metal-based catalyst to selectively reduce NO and NO2 to molecular nitrogen, 

water, and oxygen. The catalyst lowers the temperature required for the chemical reaction 

between NOx and the reducing agent. Technical factors that impact the effectiveness of this 

technology include the catalyst reactor design, operating temperature, type of fuel fired, sulfur 

content of the fuel, design of the ammonia injection system, and the potential for catalyst 

poisoning. 

 

21 As explained in Section V.D.6.b of EPA’s Federal Register notice on the proposed Montana regional haze Federal 

Implementation Plan, Q/D means the quantity of a source’s combined SO2 and NOx emissions, in tons per year, 

divided by the distance in kilometers from the source to the nearest Federal Class I area. 
10 

SCR has been demonstrated to achieve high levels of NOx reduction in the range of 80% to 90% 

control, for a wide range of industrial combustion sources, including PC and stoker coal-fired 

boilers and natural gas-fired boilers and turbines. EPA used 80% for its analysis. 

 Typically, installation of the SCR is upstream of the particulate control device (e.g., baghouse). 

However, calcium oxide (from a dry scrubber) in the exhaust stream can cause the SCR catalyst 

to plug and foul, which would lead to an ineffective catalyst. 

SCRs are classified as a low dust SCR (LDSCR) or high dust SCR (HDSCR). LDSCR is usually 

applied to natural gas combustion units or after a particulate control device. HDSCR units can 

be installed on solid fuel combustion units before the particulate control device, but they have 

their limitations. Installation of SCR in a low dust flue gas stream is often not practical, 

especially on an existing boiler. The reason is that the low dust portion of a flue gas stream is 

located after a baghouse or precipitator. The temperature of the flue gas stream is too low in 

these areas for proper operation of an SCR. The temperature range for proper operation of an 

SCR is between 480o

F and 800oF. Many of the CFBs in the United States have baghouses for 

particulate control. The normal maximum allowable temperature for a baghouse is 400o

F. 

Therefore, on some installations, regenerative SCR (RSCR) is installed. RSCRs are expensive to 

install and expensive to operate, because an RSCR requires the use of burners to heat up the flue 

gas stream in order for the NOx capture to occur. This is often an efficiency decrease for the 

boiler, significant increase in operating cost, and often not a practical solution. For this reason, 

RSCR was not evaluated as a control option for CELP. Instead, HDSCR was evaluated. 

Selective Non-Catalytic Reduction (SNCR)

SNCR involves the non-catalytic decomposition of NOx to nitrogen and water. An NOx reducing 

agent, typically ammonia or urea, is injected into the upper reaches of the furnace, through 

injection nozzles at the cyclone inlets. Because catalyst is not used to drive the reaction, 

temperatures of 1600oF to 2100oF are required. 

Typical NOx control efficiencies range from 40% to 60%, depending on inlet NOx

concentrations, fluctuating flue gas temperatures, residence time, amount and type of nitrogenous 

reducing agent, mixing effectiveness, acceptable levels of ammonia slip, and presence of 

interfering chemical substances in the gas stream. Guaranteed NOx reduction rates are in the 

50% range to limit ammonia slip to 10 ppm. EPA used 50% for its analysis. 

Low Excess Air (LEA)

LEA operation involves lowering the amount of combustion air to the minimum level compatible 

with efficient and complete combustion. Limiting the amount of air fed to the furnace reduces 

the availability of oxygen for the formation of fuel NOx and lowers the peak flame temperature, 

which inhibits thermal NOx formation. 

Emissions reductions achieved by LEA are limited by the need to have sufficient oxygen present 

for flame stability and to ensure complete combustion. As excess air levels decrease, emissions 
11 

of carbon monoxide (CO), hydrocarbons (HC) and unburned carbon increase, resulting in lower 

boiler efficiency. Other impediments to LEA operation are the possibility of increased corrosion 

and slagging in the upper boiler because of the reducing atmosphere created at low oxygen 

levels. 

Flue Gas Recirculation (FGR)

FGR is a flame-quenching technique that involves recirculating a portion of the flue gas from the 

economizers or the air heater outlet and returning it to the furnace through the burner or 

windbox. The primary effect of FGR is to reduce the peak flame temperature through absorption 

of the combustion heat by relatively cooler flue gas. FGR also serves to reduce the oxygen 

concentration in the combustion zone. 

Overfire Air (OFA)

OFA allows staged combustion by supplying less than the stoichiometric amount of air 

theoretically required for complete combustion through the burners. The remaining necessary 

combustion air is injected into the furnace through overfire air ports. Having an oxygendeficient primary combustion zone in the furnace lowers the formation of fuel NOx. In this 

atmosphere, most of the fuel nitrogen compounds are driven into the gas phase. Having 

combustion occur over a larger portion of the furnace lowers peak flame temperatures. Use of a 

cooler, less intense flame limits thermal NOx formation. 

Poorly controlled OFA may result in increased CO and HC emissions, as well as unburned 

carbon in the fly ash. These products of incomplete combustion result from a decrease in boiler 

efficiency. OFA may also lead to reducing conditions in the lower furnace that in turn may lead 

to corrosion of the boiler. 

Low NOx Burners (LNB)

LNBs integrate staged combustion into the burner, creating a fuel-rich primary combustion zone. 

Fuel NOx formation is decreased by the reducing conditions in the primary combustion zone. 

Thermal NOx is limited due to the lower flame temperature caused by the lower oxygen 

concentration. The secondary combustion zone is a fuel-lean zone where combustion is 

completed. LNB may result in increased CO and HC emissions, decreased boiler efficiency, and 

increased fuel costs. 

Non-thermal Plasma Reactor

This control technique involves using methane and hexane as reducing agents. Non-thermal 

plasma has been shown to remove NOx in a laboratory setting with a reactor duct only two feet 

long. The reducing agents were ionized by a transient high voltage that created a non-thermal 

plasma. The ionized reducing agents reacted with NOx and achieved a 94% destruction 

efficiency. There are indications that even higher destruction efficiency can be achieved. A 

successful commercial vendor uses ammonia as a reducing agent to react with NOx in an electron 

beam generated plasma. Such a short reactor can meet available space requirements for virtually 
12 

any plant. The non-thermal plasma reactor could also be used without a reducing agent to 

generate ozone and use that ozone to raise the valence of nitrogen for subsequent absorption as 

nitric acid. This control technology may have practical potential for application to coal-fired 

CFB boilers as a technology transfer option.22 

Carbon Injection into Combustion Chamber

A version of sorbent injection uses carbon injected into the air flow to finish the capture of NOx. 

The carbon is captured in either the baghouse or the ESP just like other sorbents.23

Step 2: Eliminate Technically Infeasible Options

LEA, FGR, and OFA are typically used on Pulverized Coal (PC) units and cannot be used on 

CFB boilers due to air needed to fluidize the bed.24 While LEA may have substantial effect on 

NOx emissions at PC boilers, it has much less effect on NOx emissions at combustion sources 

such as CFBs that operate at low combustion temperatures. FGR reduces NOx formation by 

reducing peak flame temperature and is ineffective on combustion sources such as CFBs that 

already operate at low combustion temperatures. For these reasons, LEA, FGR and OFA are 

eliminated from further consideration. 

LNBs are typically used on PC units and cannot be used on CFB boilers because the combustion 

occurs within the fluidized bed.25 CFB boilers do not use burners during normal operation. 

Therefore, LNBs are eliminated from further consideration. 

While a non-thermal plasma reactor may have practical potential for application to coal-fired 

CFB boilers as a technology transfer option at Step 1 of the analysis, it is not known to be 

commercially available for CFB boilers.26 Therefore, a non-thermal plasma reactor is eliminated 

from further consideration. 

Although carbon injection is an emerging technology used to reduce mercury emissions, it has 

not been used anywhere to control NOx. Therefore, it is eliminated from further consideration. 

The remaining technically feasible NOx control options for CELP are HDSCR and SNCR. 

Step 3: Evaluate Control Effectiveness of Remaining Control Technology

Baseline NOx emissions from CELP are 768 tpy. A summary of emissions projections for the 

various control options is provided in Table 3. 

 

22 Deseret Bonanza SOB, p. 46. 

23 US EPA, Office of Air Quality Planning and Standards, Technical Bulletin: Nitrogen Oxides (NOx), Why and 

How They are Controlled, EPA-456/F-99-006R, p. 19 (Nov. 1999), available at 

http://www.epa.gov/ttn/catc/dir1/fnoxdoc.pdf . 

24 CELP Additional Response, pp. 2-7, 2-8. 

25 CELP Additional Response, p. 2-8. 

26 Deseret Bonanza SOB, pp. 46, 48. 
13 

Table 3 

Summary of CELP NOx Reasonable Progress Analysis Control Technologies 

Control 

Option 

Control 

Effectiveness

(%) 

Emissions 

Reduction 

(tpy) 

Remaining 

Emissions 

(tpy) 

HDSCR 80 614 154

SNCR 50 384 384

Step 4: Evaluate Impacts and Document Results 

Factor 1: Cost of Compliance

Table 4 provides a summary of the estimated costs for the various NOx control options. 

Table 4 

Summary of CELP NOx Reasonable Progress Cost Analysis 

Control 

Option

Control

Effectiveness 

(%)

Tons 

NOx

Reduced

from 

Baseline

Capital

Cost ($)

Annual Cost

of Capital ($) 

(CRF=.0944)

Annual

O&M

Cost ($)

Total

Annual

Cost ($)

Average Cost

 Effectiveness

($/ton reduced)

SCR 80 614 13,500,000 $1,274,400 827,789 2,102,189 3,423 

SNCR 

 

50 384 800,000 $75,520 509,197 584,717 1,523 

EPA has relied on all the NOx control costs provided by CELP27, with one exception. EPA 

calculated the annual cost of capital using a 7% annual interest rate and 20-year equipment life 

(which yields a capital CRF of 0.0944), as specified in the Office of Management and Budget’s 

Circular A-4, Regulatory Analysis.28 (CELP used 10% interest rate and 10-year equipment 

life.29) 

 

Factor 2: Time necessary for compliance

EPA has relied on CELP’s estimates that SCR would take approximately 26 months to install 

and that SNCR would take 16 to 24 weeks to install.30

 

 

27 CELP Additional Response. 

28 Available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/. 

29 CELP Additional Response.

30 CELP Additional Response, p. 3-1. 
14 

Factor 3: Energy and non-air quality environmental impacts of compliance

The energy impacts from SNCR are expected to be minimal. SNCR is not expected to cause a 

loss of power output from the facility. SCR, however, could cause significant backpressure on 

the boiler, leading to lost boiler efficiency and, thus, a loss of power production. If LDSCR was 

to be installed instead of HDSCR, CELP would be subject to the additional cost of reheating the 

exhaust gas. 

Regarding other non-air quality environmental impacts of compliance, SCRs can contribute to 

airheater fouling from the formation of ammonium sulfate. Airheater fouling could reduce unit 

efficiency, increase flue gas velocities in the airheater, cause corrosion, and erosion. Catalyst 

replacement can lengthen boiler outages, especially in retrofit installations, where space and 

access is limited. This is a retrofit installation in a high dust environment, thus fouling is likely, 

which could lead to unplanned outages or less time between planned outages. On some 

installations, catalyst life is short and SCRs have fouled in high dust environments. For both 

SCR and SNCR, the storage of on-site NH3 could pose a risk from potential releases to the 

environment. An additional concern is the loss of NH3, or “slip” into the emissions stream from 

the facility. This “slip” contributes another pollutant to the environment, which has been 

implicated as a precursor to PM2.5 formation. 

Factor 4: Remaining useful life

 

EPA has determined that the default 20-year amortization period is most appropriate to use as the 

remaining useful life of the facility. Without commitments for an early shut down, EPA cannot 

consider a shorter amortization period in its analysis. 

Step 5: Select Reasonable Progress Controls 

EPA has considered the following four factors: the cost of compliance; the time necessary for 

compliance; the energy and non-air quality environmental impacts of compliance; and the 

remaining useful life of the sources. EPA is also taking into account the size of the facility, the 

baseline Q/D of the facility, and the potential reduction in Q/D from the controls. Based on costs 

of compliance, the relatively small size of CELP, and the relatively small baseline Q/D, EPA 

proposes to eliminate the more expensive control option (SCR). The more cost-effective control 

option (SNCR) would result in a fairly small total reduction in emissions (384 tpy). This would 

constitute an approximately 20% reduction in overall emissions of SO2 + NOx for the facility and 

a reduction of the facility’s Q/D from 11 to 9. Based on the cost of compliance, the relatively 

small size of CELP, and the reduction in Q/D for SNCR, EPA finds it reasonable to not require 

SNCR. EPA therefore proposes to not require additional NOx controls for this planning period.