BART FIVE FACTOR ANALYSIS – NOX ANALYSIS

ARKANSAS ELECTRIC COOPERATIVE CORPORATION 

BAILEY AND MCCLELLAN GENERATING STATIONS 

Prepared By:

TRINITY CONSULTANTS, INC.

120 East Sheridan, Suite 205

Oklahoma City, Oklahoma 73104

(405) 228-3292

TRINITY CONSULTANTS, INC.

977 Ridge Drive, Suite 380

Lenexa, Kansas 66219

(913) 894-4500

In conjunction with:

ARKANSAS ELECTRIC COOPERATIVE CORPORATION

PO Box 194208

Little Rock, Arkansas

(501) 570-2420

Trinity Project No. 123701.0036

September 2012

Version 1
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NOx BART Analysis – Bailey and McClellan

TABLE OF CONTENTS

1. NOX BART EVALUATION................................................................................... 1-3

1.1 CROSS-STATE AIR POLLUTION RULE AND BART................................................. 1-3

1.2 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL TECHNOLOGIES FOR 

BAILEY UNIT 1 AND MCCLELLAN UNIT 1......................................................................... 1-3

1.3 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES ............... 1-4

1.3.1 COMBUSTION CONTROLS....................................................................................1-4

1.3.1.1 Flue Gas Recirculation (FGR) .............................................................1-4

1.3.1.2 Overfire Air (OFA)..............................................................................1-4

1.3.1.3 Low NOX Burners................................................................................1-5

1.3.2 POST COMBUSTION CONTROLS...........................................................................1-5

1.3.2.1 Selective Catalytic Reduction..............................................................1-5

1.3.2.2 Selective Non-Catalytic Reduction......................................................1-6

1.4 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS.. 1-6

1.5 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 1-7

1.5.1 COST OF COMPLIANCE ........................................................................................1-8

1.5.2 ENERGY IMPACTS & NON-AIR IMPACTS ..........................................................1-11

1.5.3 REMAINING USEFUL LIFE .................................................................................1-11

1.6 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ................... 1-11

1.7 PROPOSED BART FOR NOX FOR BAILEY UNIT 1 AND MCCLELLAN UNIT 1 ......... 1-19

APPENDIX A.................................................................................................................................
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LIST OF TABLES

TABLE 1-1. AVAILABLE NOX CONTROL TECHNOLOGIES FOR BAILEY UNIT 1 AND MCCLELLAN UNIT 

1..............................................................................................................................................1-4

TABLE 1-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL TECHNOLOGIES1-7

TABLE 1-3. SUMMARY OF COST EFFECTIVENESS FOR BAILEY UNIT 1 NOX CONTROLS ...................1-10

TABLE 1-4. SUMMARY OF COST EFFECTIVENESS FOR MCCLELLAN UNIT 1 NOX CONTROLS...........1-10

TABLE 1-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA FOR NOX CONTROL1-13

TABLE 1-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL.......1-13

TABLE 1-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA + SNCR FOR NOX

CONTROL..............................................................................................................................1-13

TABLE 1-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON 

BAILEY UNIT 1 (2001-2003) – FUEL OIL..............................................................................1-15

TABLE 1-9. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON 

BAILEY UNIT 1 (2001-2003) – NATURAL GAS .....................................................................1-16

TABLE 1-10. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON 

MCCLELLAN UNIT 1 (2001-2003) – FUEL OIL .....................................................................1-17

TABLE 1-11. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON 

MCCLELLAN UNIT 1 (2001-2003) – NATURAL GAS.............................................................1-18
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NOx BART Analysis – Bailey and McClellan

1. NOX BART EVALUATION

1.1 CROSS-STATE AIR POLLUTION RULE AND BART

On June 7, 2012 EPA published a final rule allowing states participating in the Cross-State Air 

Pollution Rule (CSAPR) trading program to use CSAPR to satisfy BART. On August 21, 2012 the 

DC Circuit Court in a 2-1 decision vacated CSAPR.1 The vacatur will have direct implications on 

many regional haze State Implementation Plans (SIPs) and Federal Implementation Plans (FIPs), 

including several FIPs that EPA recently finalized that rely on CSAPR as an alternative to BART 

(i.e., FIPs for Georgia, Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio, Pennsylvania, 

South Carolina, Tennessee, Virginia, and West Virginia). It is anticipated that the vacatur of 

CSAPR will now require source-specific BART determinations. 

In the event that EPA appeals the DC Circuit Court’s decision and CSAPR is reinstated, AECC is 

proposing to satisfy BART for NOx at Bailey Unit 1 and McClellan Unit 1 by complying with 

CSAPR. In the event that EPA moves forward with new rulemaking in a timeline that satisfies 

Arkansas’s regional haze SIP obligations, AECC is proposing that Arkansas and AECC consider the 

rulemaking as an alternative to a source specific BART determination. Finally, in the event that 

Arkansas requires a source-specific BART determination, AECC has conducted a full five factor 

analysis to determine BART for NOx for Bailey Unit 1 and McClellan Unit 1. 

1.2 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL 

TECHNOLOGIES FOR BAILEY UNIT 1 AND MCCLELLAN UNIT 1

Nitrogen oxides, NOx, are produced during fuel combustion when nitrogen contained in both the fuel 

and the combustion air is exposed to high temperatures. The origin of the nitrogen (i.e. fuel vs. 

combustion air) has lead to the use of the terms “thermal” NOx and “fuel” NOx when describing NOx

emissions. Thermal NOx emissions are produced when elemental nitrogen in the combustion air is 

exposed to a high temperature zone and oxidized. Fuel NOx emissions are created during the rapid 

oxidation of nitrogen compounds contained in the fuel. 

Nitrogen oxide (NO) is typically the predominant form of NOx from fossil fuel combustion. Nitrogen 

dioxide (NO2) makes up the remainder of the NOx. The formation of NOx compounds in utility boilers 

is sensitive to the method of firing. In wall-fired boilers, such as Bailey Unit 1 and McClellan Unit 1, 

burners are mounted in the boiler walls, producing discrete flames in the furnace. In tangentiallyfired boilers, a single rotating flame is created in the center of the furnace, rather than the discrete 

flames produced by burners in the wall-fired boilers. Tangentially fired boilers typically have lower 

uncontrolled NOx emissions than wall-fired boilers. Therefore baseline NOx emission rates can vary 

significantly from plant to plant due to method of firing and also several other factors.

Step 1 of the BART determination is the identification of all available retrofit NOx control 

technologies. The available retrofit NOx control technologies are summarized in Table 1-1 for

Bailey Unit 1 and McClellan Unit 1. 

NOx emissions controls, as listed in Table 1-1, can be categorized as combustion or post-combustion 

controls. Combustion controls, including flue gas recirculation (FGR), overfire air (OFA), and Low 

 

1 EME Homer City Generation v. EPA, --F. 3d --, No. 11-1302 (DC Cir 2012)
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NOx Burners (LNB), reduce the peak flame temperature and excess air in the furnace which 

minimizes NOx formation. Post-combustion controls, such as selective catalytic reduction (SCR) and 

selective non-catalytic reduction (SNCR) convert NOx in the flue gas to molecular nitrogen and 

water. 

TABLE 1-1. AVAILABLE NOX CONTROL TECHNOLOGIES FOR BAILEY UNIT 1 AND MCCLELLAN 

UNIT 1

NOx Control Technologies

Combustion Controls

Flue Gas Recirculation (FGR)

Overfire Air (OFA)

Low NOx Burners (LNB) 

Post-Combustion Controls Selective Catalytic Reduction (SCR)

Selective Non-Catalytic Reduction (SNCR)

1.3 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NOx control technologies that 

were identified in Step 1. Control ranges were developed using a combination of literature control 

ranges and efficiencies. 

1.3.1 COMBUSTION CONTROLS

1.3.1.1 FLUE GAS RECIRCULATION (FGR)

FGR uses flue gas as an inert material to reduce flame temperatures. In a 

typical flue gas recirculation system, flue gas is collected from the combustion 

chamber or stack and returned to the burner via a duct and blower. The 

addition of flue gas reduces the oxygen content of the “combustion air” (air + 

flue gas) in the burner. The lower oxygen level in the combustion zone reduces 

flame temperatures; which in turn reduces thermal NOx formation. When 

operated without additional controls, the NOx control range for oil and gas fired 

boilers with FGR is approximately 0.2-0.4 lb/MMBtu.2 This control is a 

technically feasible option for the control of NOx from Bailey Unit 1 and 

McClellan Unit 1. 

1.3.1.2 OVERFIRE AIR (OFA)

OFA diverts a portion of the total combustion air from the burners and injects it 

through separate air ports above the top level of burners. Staging of the 

combustion air creates an initial fuel-rich combustion zone with a lower peak 

flame temperature. This reduces the formation of thermal NOx by lowering 

combustion temperature and limiting the availability of oxygen in the 

combustion zone where NOx is most likely to be formed. OFA as a single NOx

 

2 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options.” Utility Boiler section. July 1994. 
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NOx BART Analysis – Bailey and McClellan

control technique results in estimated NOx emissions rate from gas and oil fired

boilers of 0.2-.3 lb/MMBtu.3 This control is a technically feasible option for the 

control of NOx from Bailey Unit 1 and McClellan Unit 1.

1.3.1.3 LOW NOX BURNERS

LNB technology utilizes advanced burner design to reduce NOx formation 

through the restriction of oxygen, lowering of flame temperature, and/or 

reduced residence time. NOx creation rates typically peak at oxygen levels of 

five to seven percent.4 LNB is a staged combustion process that is designed to 

split fuel combustion into two zones. In the primary zone, NOx formation is 

limited by one of two methods. Under staged fuel-rich conditions, low oxygen 

levels limit flame temperatures resulting in less NOx formation. The primary 

zone is then followed by a secondary zone in which the incomplete combustion 

products formed in the primary zone act as reducing agents. Alternatively, 

under staged fuel-lean conditions, excess air will reduce flame temperature to 

reduce NOx formation. In the secondary zone, combustion products formed in 

the primary zone act to lower the local oxygen concentration, resulting in a 

decrease in NOx formation. 

When combined with OFA, the estimated NOx control emission rate is 0.20

lb/MMBtu for both oil and gas firing scenarios.

5 LNB systems are technically 

feasible for the control of NOx from Bailey Unit 1 and McClellan Unit 1.

1.3.2 POST COMBUSTION CONTROLS

1.3.2.1 SELECTIVE CATALYTIC REDUCTION

SCR refers to the process in which NOx is reduced by ammonia over a 

heterogeneous catalyst in the presence of oxygen. The process is termed 

selective because the ammonia preferentially reacts with NOx rather than 

oxygen, although the oxygen enhances the reaction and is a necessary 

component of the process. The overall reactions are:

4NO + 4NH3 + O2  4N2 + 6H2O

2NO2 + 4NH3 + O2  3N2 + 6H2O

The SCR process requires a reactor, a catalyst, and an ammonia storage and 

injection system. The effectiveness of an SCR system is dependent on a variety 

of factors, including the inlet NOx concentration, the exhaust temperature, the 

ammonia injection rate, and the type of catalyst. The estimated NOx control for 

SCR on gas fired boilers is 80-90% and is 70-80% for oil fired boilers.

6 This 

control is a technically feasible option for the control of NOx from Bailey Unit 

1 and McClellan Unit 1.

 

3 Ibid.

4 http://www.energysolutionscenter.org/boilerburner/Workshop/RCTCombustion.htm.

5 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options.” Utility Boiler section. July 1994. 

6 “Preferred and Alternative Methods of Estimate Air Emissions from Boilers.” January 2010. Table 2.2-2
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1.3.2.2 SELECTIVE NON-CATALYTIC REDUCTION

In SNCR systems, a reagent is injected into the flue gas in the furnace within an 

appropriate temperature window. The NOx and reagent (ammonia or urea) 

react to form nitrogen and water. A typical SNCR system consists of reagent 

storage, multi-level reagent-injection equipment, and associated control 

instrumentation. The SNCR reagent storage and handling systems are similar 

to those for SCR systems. However, both ammonia and urea SNCR processes 

require three or four times as much reagent as SCR systems to achieve similar 

NOx reductions. When combined with LNB/OFA the estimated NOx control 

for SNCR on oil and gas fired boilers is estimated to be 10% greater than 

LNB/OFA alone.

7 This control is a technically feasible option for the control 

of NOx from Bailey Unit 1 and McClellan Unit 1.

1.4 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY 

EFFECTIVENESS

The third step in the BART analysis is to rank the technically feasible options according to 

effectiveness. Table 1-2 provides a ranking of the control levels for the controls listed in the 

previous section for Bailey Unit 1 and McClellan Unit 1.

 

7 Ibid.
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TABLE 1-2. CONTROL EFFECTIVENESS OF TECHNICALLY FEASIBLE NOX CONTROL 

TECHNOLOGIES

1.5 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS 

Step four for the BART analysis is the impact analysis. The BART determination guidelines list four 

factors to be considered in the impact analysis:

▲ Cost of compliance

▲ Energy impacts

▲ Non-air quality impacts; and

▲ The remaining useful life of the source

Control Technology

Bailey Unit 1 

Natural Gas 

Baseline NOx 

Rate1 

(lb/MMBtu)

Bailey Unit 1 

Fuel Oil 

Baseline NOx 

Rate1 

(lb/MMBtu)

Bailey Unit 1 

Natural Gas 

Estimate NOx 

Controlled Rate 

(lb/MMBtu)

Bailey Unit 1 

Fuel Oil Estimate 

NOx Controlled 

Rate (lb/MMBtu)

SCR20.04 0.05

LNB/OFA + SNCR30.17 0.17

LNB/OFA 0.20 0.20

FGR 0.2-0.4 0.2-0.4

OFA 0.2-0.3 0.2-0.3

Control Technology

McClellan 

Unit 1 

Natural Gas 

Baseline NOx 

Rate1 

(lb/MMBtu)

McClellan 

Unit 1 Fuel 

Oil 

Baseline NOx 

Rate1 

(lb/MMBtu)

McClellan Unit 1 

Natural Gas 

Estimate NOx 

Controlled Rate 

(lb/MMBtu)

McClellan Unit 1 

Fuel Oil Estimate 

NOx Controlled 

Rate (lb/MMBtu)

SCR20.03 0.12

LNB/OFA + SNCR30.17 0.15

LNB/OFA 0.20 0.20

FGR 0.2-0.4 0.2-0.4

OFA 0.2-0.3 0.2-0.3

0.29 0.30

2

 SCR controlled rate based on a reduction of 85% for gas-fired boilers and 75% for oil-fired 

boilers.

1

 Baseline NOx rates are representative of 30-day rolling average rates as reported in EPA's Clean 

Air Market Database (CAMD).

3

 LNB/OFA + SNCR control efficiency was calculated by first calculating the control efficiency 

of LNB/OFA and then adding an additonal 10%. For Bailey Natural Gas: (0.29-

0.2)/(0.29)*100% + 10% = 41%. 

0.31 0.50
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1.5.1 COST OF COMPLIANCE

The capital costs, operating costs, and cost effectiveness of LNB/OFA, LNB/OFA + SNCR 

and SCR were estimated for the cost analysis. 

Control Costs

The capital and operating costs of the controls that were used in the cost effectiveness 

calculations were estimated based on vendor estimates and published calculations methods. 

The capital costs were annualized over a 30-year period and then added to the annual 

operating costs to obtain the total annualized costs. The details of the capital and operating 

cost estimates are provided in Appendix B of this report. 

Annual Tons Reduced

The annual tons reduced that were used in the cost effectiveness calculations were 

determined by subtracting the estimated controlled annual emission rate from the baseline

annual emission rate. 

The baseline annual emission rates were the average rates from 2009-2011, as reported by 

AECC in their air emission inventories. The controlled annual emission rate is based on 

the lb/MMBtu level believed to be achievable from the control technology multiplied by 

the baseline heat input to the boiler in MMBtu/yr. The baseline heat input per fuel is based 

on the average fuel usage from 2007 -2011 multiplied by the average heat content of that 

particular fuel (fuel oil or natural gas) from that same time period. A five year review of 

fuel usage and heat input was used to be consistent with the previously submitted SO2 and 

PM analysis.

Cost Effectiveness

The cost effectiveness in dollars per ton of NOx reduced was determined by dividing the 

annualized cost of control by the annual tons reduced. An incremental cost analysis was 

also performed to show the incremental increase in costs between SCR and an LNB/OFA 

system, as well as between LNB/OFA + SNCR and LNB/OFA. The cost effectiveness 

analysis is summarized in Table 1-3 and Table 1-4. 

In the BART guidelines, EPA calculated that for all types of boilers other than cyclone 

boilers, combustion control technology is generally more cost-effective than postcombustion controls. EPA estimates that approximately 75 percent of the BART units 

(non-cyclone) could meet the presumptive NOx limits at a cost of $100 to $1,000 per ton of 

NOx removed based on the use of combustion control technology.8 For the units that could 

not meet the presumptive limits using combustion control technology, EPA estimates that 

almost all of these sources could meet the presumptive limits using advanced combustion 

controls. The EPA estimates that the costs of such controls are usually less than $1,500 per 

ton of NOx removed.9 

 

8 “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART Determinations; 

Final Rule.” CFR Vol. 77, No. 128. Wednesday, July 6, 2005, Rules and Regulations. Pages 39134-39135.

9 Ibid.
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NOx BART Analysis – Bailey and McClellan

Table 1-3 and Table 1-4 indicate that the cost effectiveness of LNB/OFA at a NOx level of 

0.2 lb/MMBtu is approximately $100,000 per ton of NOx removed for Bailey Unit 1 and 

$16,500 per ton of NOx removed for McClellan Unit 1. Table 1-3 also indicates that the 

cost for LNB/OFA/SNCR for Bailey Unit 1 is over $97,000 per ton of NOx removed and is

nearly $85,000 per ton for SCR. Table 1-4 shows cost for LNB/OFA/SNCR for McClellan

Unit 1 is over $22,000 per ton of NOx removed and is over $16,000 per ton for SCR. 
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TABLE 1-3. SUMMARY OF COST EFFECTIVENESS FOR BAILEY UNIT 1 NOX CONTROLS

TABLE 1-4. SUMMARY OF COST EFFECTIVENESS FOR MCCLELLAN UNIT 1 NOX CONTROLS

Baseline 

Emission 

Rate

Natural Gas 

Controlled 

Emission Level

Fuel Oil 

Controlled 

Emission Level

Natural Gas 

Annual Heat 

Input4

Fuel Oil 

Annual Heat 

Input4

Controlled 

Emission 

Rate

NOx 

Reduced Capital Cost

Total 

Annual 

Cost

Cost 

Effectiveness

 Incremental 

Cost 

(tpy) (lb/MMBtu) (lb/MMBtu) (MMBtu/yr) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/ton) ($/ton)

LNB/OFA149.81 0.20 0.20 371,866 39,193 41.11 8.70 9,287,625 901,947 103,623 -

LNB/OFA/SNCR249.81 0.17 0.17 371,866 39,193 35.13 14.68 13,491,349 1,424,627 97,018 87,406

SCR349.81 0.04 0.08 371,866 39,193 9.65 40.16 25,155,493 3,401,502 84,700 79,464

4

 Annual heat input was determined using multiplying the average fuel usage from 2007 to 2011 times the average heat content of the fuel during that time.

1

 LNB Cost information: Please refer to Appendix B.

2

 SNCR Cost information: Please refer to Appendix B. Because SNCR costing is dependent upon outlet emission rate, which is dependent upon fuel type the least expensive SNCR option 

3

 SCR Cost information: Please refer to Appendix B. Because SCR costing is dependent upon outlet emission rate, which is dependent upon fuel type the least expensive SCR option has 

been chosen as a conservative estimate.

Baseline 

Emission 

Rate

Natural Gas 

Controlled 

Emission Level

Fuel Oil 

Controlled 

Emission Level

Natural Gas 

Annual Heat 

Input4

Fuel Oil 

Annual Heat 

Input4

Controlled 

Emission 

Rate

NOx 

Reduced Capital Cost

Total 

Annual 

Cost

Cost 

Effectiveness

 Incremental 

Cost 

(tpy) (lb/MMBtu) (lb/MMBtu) (MMBtu/yr) (MMBtu/yr) (tpy) (ton/yr) ($) ($/yr) ($/ton) ($/ton)

LNB/OFA1294.04 0.20 0.20 2,040,117 291,733 233.18 60.86 9,664,386 1,002,981 16,481 -

LNB/OFA/SNCR2294.04 0.17 0.15 2,040,117 291,733 194.27 99.77 13,997,639 2,247,918 22,530 31,991

SCR3294.04 0.05 0.12 2,040,117 291,733 65.01 229.03 26,421,423 3,655,575 15,961 15,773

3

 SCR Cost information: Please refer to Appendix B. Because SCR costing is dependent upon outlet emission rate, which is dependent upon fuel type the least expensive SCR option has 

been chosen as a conservative estimate.

4

 Annual heat input was determined using multiplying the average fuel usage from 2007 to 2011 times the average heat content of the fuel during that time.

1

 LNB Cost information: Please refer to Appendix B.

2

 SNCR Cost information: Please refer to Appendix B. Because SNCR costing is dependent upon outlet emission rate, which is dependent upon fuel type the least expensive SNCR option 

has been chosen as a conservative estimate.
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NOx BART Analysis – Bailey and McClellan

1.5.2 ENERGY IMPACTS & NON-AIR IMPACTS

SCR and SNCR systems require electricity to operate the ancillary equipment. The need 

for electricity to help power some of the ancillary equipment creates a demand for energy 

that currently does not exist. 

SCR and SNCR can potentially cause significant environmental impacts related to the 

storage of ammonia. The storage of aqueous ammonia above 10,000 lbs is regulated by a 

risk management program (RMP), since the accidental release of ammonia has the 

potential to cause serious injury and death to persons in the vicinity of the release. SCR 

and SNCR will likely also cause the release of unreacted ammonia to the atmosphere. 

This is referred to as ammonia slip. Ammonia slip from SCR and SNCR systems occurs 

either from ammonia injection at temperatures too low for effective reaction with NOx, 

leading to an excess of unreacted ammonia, or from over-injection of reagent leading to 

uneven distribution; which also leads to an excess of unreacted ammonia. Ammonia 

released from SCR and SNCR systems will react with sulfates and nitrates in the 

atmosphere to form ammonium sulfate and ammonium nitrate. Together, ammonium 

sulfate and ammonium nitrate are the predominant sources of regional haze.

There are no significant energy or non-air impacts associated with the use of LNB, OFA, 

or FGR. 

1.5.3 REMAINING USEFUL LIFE

The remaining useful life of Bailey Unit 1 and McClellan Unit 1 does not impact the 

annualized capital costs of potential controls because the useful life of the boiler is

anticipated to be at least as long as the capital cost recovery period, which is 30 years.

1.6 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS 

A final impact analysis was conducted to assess the visibility improvement for existing emission rates 

when compared to the emission rates associated with LNB/OFA, LNB/OFA/SNCR and SCR systems. 

The AECC Five Factor Analysis submitted in August 2012 documented the existing visibility 

impairment attributable to Bailey Unit 1 and McClellan Unit 1, in which two baselines were modeled: 

one for natural gas firing and one for fuel oil firing. In order to assess the visibility improvement 

associated with LNB/OFA, SCR and SNCR systems, the NOx emission rates associated with the 

control systems were modeled using CALPUFF. The controlled emission level associated with SCR 

systems at Bailey Unit 1 is 0.04 lb/MMBtu for natural gas and 0.08 lb/MMBtu for fuel oil, while the 

emission level for SCR at McClellan Unit 1 is 0.05 lb/MMBtu for natural gas and 0.12 lb/MMBtu for 

fuel oil. The controlled emission level associated with the LNB/OFA system is 0.20 lb/MMBtu for 

both units. Control using LNB/OFA + SNCR has an associated emission level of 0.17 at Bailey with 

natural gas and 0.17 with fuel oil. At McClellan Unit 1, LNB/OFA + SNCR results in a NOx level of

0.17 lb/MMBtu for natural gas and 0.150 lb/MMBtu with fuel oil. These levels were multiplied by 

the maximum hourly heat input to derive the hourly emission rates used in the modeling. 
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Tables 1-5 through 1-7 summarize the NOx emission rates that were modeled to reflect the 

LNB/OFA, SCR and LNB/OFA/SNCR systems, respectively. The emission rates for the other 

pollutants shown in Tables 1-5 through 1-7 are the same as in the baseline modeling. 
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TABLE 1-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA FOR NOX

CONTROL

Unit / Fuel SO2 NOx

Total 

PM10 SO4 PMc PMf SOA EC

Scenario (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

Bailey, Unit 1 –

Natural Gas 0.5 270.0 10.2 0.3 0.0 0.0 7.4 2.5

Bailey, Unit 1 –

Fuel Oil 2,375.8 270.0 49.4 4.0 12.1 30.2 0.7 2.4

McClellan, Unit 1 –

Natural Gas 0.6 287.3 10.9 0.3 0.0 0.0 7.9 2.7

McClellan, Unit 1 –

Fuel Oil 2,747.5 287.3 48.2 4.8 11.5 28.7 0.8 2.3

TABLE 1-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL

Unit / Fuel SO2 NOx

Total 

PM10 SO4 PMc PMf SOA EC

Scenario (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

Bailey, Unit 1 –

Natural Gas 0.5 59.4 10.2 0.3 0.0 0.0 7.4 2.5

Bailey, Unit 1 –

Fuel Oil 2,375.8 101.5 49.4 4.0 12.1 30.2 0.7 2.4

McClellan, Unit 1 –

Natural Gas 0.6 66.0 10.9 0.3 0.0 0.0 7.9 2.7

McClellan, Unit 1 –

Fuel Oil 2,747.5 178.7 48.2 4.8 11.5 28.7 0.8 2.3

TABLE 1-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT LNB/OFA + SNCR FOR NOX

CONTROL

Unit / Fuel SO2 NOx

Total 

PM10 SO4 PMc PMf SOA EC

Scenario (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr)

Bailey, Unit 1 –

Natural Gas 0.5 230.4 10.2 0.3 0.0 0.0 7.4 2.5

Bailey, Unit 1 –

Fuel Oil 2,375.8 229.4 49.4 4.0 12.1 30.2 0.7 2.4

McClellan, Unit 1 –

Natural Gas 0.6 243.3 10.9 0.3 0.0 0.0 7.9 2.7

McClellan, Unit 1 –

Fuel Oil 2,747.5 215.8 48.2 4.8 11.5 28.7 0.8 2.3

Tables 1-8 though 1-11 provide a comparison of the existing visibility impairment and the visibility 

impairment associated with the addition of NOx controls on Bailey Unit 1 and McClellan Unit 1 in all 

affected Class I areas, including the maximum modeled visibility impact, 98th percentile modeled 

visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δdv. The

visibility improvement shown in the table was calculated as the difference between the existing 
Arkansas Electric Cooperative Corporation 1-14 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

visibility impairment and the visibility impairment associated with a retrofitted system with the 

specific control as measured by the 98th percentile. 
Arkansas Electric Cooperative Corporation 1-15 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

TABLE 1-8. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON BAILEY UNIT 1 (2001-2003) – FUEL 

OIL

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Visibility Improvement*

Baseline Emission Rate 0.969 0.330 8 - 0.695 0.347 7 - 0.686 0.367 6 - 1.589 0.378 12 -

LNB/OFA 0.935 0.326 7 1.21% 0.679 0.337 6 2.88% 0.647 0.348 5 5.18% 1.470 0.372 10 1.59%

SCR 0.896 0.323 6 2.12% 0.660 0.325 6 6.34% 0.614 0.325 4 11.44% 1.325 0.364 8 3.70%

LNB/OFA + SNCR 0.926 0.325 7 1.52% 0.674 0.334 6 3.75% 0.635 0.343 5 6.54% 1.435 0.370 8 2.12%

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv)

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and controlled impacts that include more decimal places than 

what is shown in the table. Due to rounding of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement calculated from 

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.
Arkansas Electric Cooperative Corporation 1-16 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

TABLE 1-9. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON BAILEY UNIT 1 (2001-2003) –

NATURAL GAS

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Visibility Improvement*

Baseline Emission Rate 0.219 0.083 0 - 0.170 0.072 0 - 0.238 0.073 0 - 0.443 0.102 0 -

LNB/OFA 0.137 0.051 0 38.55% 0.105 0.045 0 37.50% 0.150 0.045 0 38.36% 0.274 0.066 0 35.29%

SCR 0.037 0.014 0 83.13% 0.028 0.013 0 81.94% 0.042 0.013 0 82.19% 0.069 0.021 0 79.41%

LNB/OFA + SNCR 0.118 0.044 0 46.99% 0.091 0.039 0 45.83% 0.130 0.039 0 46.58% 0.235 0.057 0 44.12%

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv)

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and controlled impacts that include more decimal places than 

what is shown in the table. Due to rounding of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement calculated from 

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.
Arkansas Electric Cooperative Corporation 1-17 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

TABLE 1-10. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON MCCLELLAN UNIT 1 (2001-2003) –

FUEL OIL

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Visibility Improvement*

Baseline Emission Rate 3.007 0.621 22 - 1.319 0.266 5 - 0.660 0.230 2 - 0.546 0.227 2 -

LNB/OFA 2.731 0.566 20 8.86% 1.166 0.264 4 0.75% 0.651 0.211 1 8.26% 0.495 0.205 0 9.69%

SCR 2.627 0.548 18 11.76% 1.108 0.264 4 0.75% 0.647 0.207 1 10.00% 0.477 0.201 0 11.45%

LNB/OFA + SNCR 2.663 0.554 19 10.79% 1.128 0.264 4 0.75% 0.648 0.209 1 9.13% 0.483 0.203 0 10.57%

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv)

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and controlled impacts that include more decimal places than 

what is shown in the table. Due to rounding of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement calculated from 

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.
Arkansas Electric Cooperative Corporation 1-18 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

TABLE 1-11. SUMMARY OF VISIBILITY IMPROVEMENT ASSOCIATED WITH NOX CONTROL SYSTEM ON MCCLELLAN UNIT 1 (2001-2003) –

NATURAL GAS

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv Visibility Improvement* Maximum Impact (Δdv) 98% Impact (Δdv) # Days > 0.5 Δdv

Visibility Improvement*

Baseline Emission Rate 0.670 0.125 3 - 0.258 0.052 0 - 0.092 0.040 0 - 0.132 0.058 0 -

LNB/OFA 0.465 0.088 0 29.60% 0.178 0.036 0 30.77% 0.063 0.028 0 30.00% 0.091 0.041 0 29.31%

SCR 0.128 0.027 0 78.40% 0.048 0.012 0 76.92% 0.016 0.009 0 77.50% 0.025 0.012 0 79.31%

LNB/OFA + SNCR 0.399 0.076 0 39.20% 0.153 0.031 0 40.38% 0.054 0.024 0 40.00% 0.078 0.035 0 39.66%

*Improvement is based on the 98th percentile impact (Δdv) compared to the baseline impact (Δdv)

†The visibility improvement shown in the table has been calculated from 98th percentile baseline and controlled impacts that include more decimal places than 

what is shown in the table. Due to rounding of the baseline and controlled 98th percentile impacts shown in the table, the visibility improvement calculated from 

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.
Arkansas Electric Cooperative Corporation 1-19 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

The operation of an LNB/OFA system results in an estimated 0.004 to 0.019 Δdv improvement (1.21-5.18

percent) of the 98th percentile visibility impairment attributable to Bailey Unit 1 at the modeled Class I 

areas in the fuel oil burning scenario and 0.027 to 0.036 Δdv improvement (35.29-38.55 percent) in the 

natural gas scenario. The operation of an LNB/OFA system results in an estimated 0.002 to 0.055 Δdv 

improvement (0.75 to 9.69 percent) of the 98th percentile visibility impairment attributable to McClellan 

Unit 1 at the modeled Class I areas in the fuel oil burning scenario and 0.012 to 0.032 Δdv improvement 

(29.6-30.77 percent) in the natural gas scenario. The actual Δdv improvement associated with use of 

LNB/OFA is quite small. 

Further, the operation of SCR systems results in an estimated 0.007 to 0.042 and 0.046 to 0.081 Δdv 

improvement (2.12 to 11.44 percent and 79.41 to 83.13 percent) of the 98th percentile visibility 

impairment attributable Bailey Unit 1 at the modeled Class I areas from fuel oil and natural gas, 

respectively, while LNB/OFA + SNCR results in an estimated 0.005 to 0.024 and 0.033 to 0.045 Δdv 

improvement (1.52 to 6.54 and 44.12 to 46.99 percent) of the 98th percentile from fuel oil and natural gas, 

respectively. Operation of SCR systems results in an estimated 0.002 to 0.076 and 0.031 to 0.098 Δdv 

improvement (0.75 to 11.76 and 76.92 to 79.31 percent) of the 98th percentile visibility impairment 

attributable McClellan Unit 1 at the modeled Class I areas from fuel oil and natural gas, respectively, 

while LNB/OFA + SNCR results in an estimated 0.002 to 0.074 and 0.021 to 0.049 Δdv improvement 

0.75 to 10.79 and 39.2 to 40.38 percent) of the 98th percentile from fuel oil and natural gas, respectively. 

 

1.7 PROPOSED BART FOR NOX FOR BAILEY UNIT 1 AND MCCLELLAN UNIT 1

If CSAPR is upheld and implemented in Arkansas, AECC will rely on CSAPR to satisfy its regional haze 

obligations at Bailey Unit 1 and McClellan Unit 1. In the alternative, AECC proposes that no additional 

add-on controls constitute BART for NOx at Bailey Unit 1 and McClellan Unit 1.

The cost effectiveness of all the NOx controls evaluated for both the boilers is excessively cost prohibitive 

at over $100,000 per ton of NOx reduced for LNB/OFA at Bailey Unit 1 and over $16,000 per ton of NOx

reduced for LNB/OFA at McClellan Unit 1. In addition, the cost effectiveness is up to $97,000 per ton 

for the other controls. Based on the relatively low NOx emissions from the boilers as compared to SO2

emissions when burning fuel oil and the correspondingly low improvement to the visibility impairment 

attributable to the boilers based on the application of the controls (only up to 0.055 Δdv for the most “cost 

effective” control in the largest impacted area), none of the controls are determined to satisfy BART. 

Thus there are no changes or add-on controls proposed as BART for NOx Bailey Unit 1 or McClellan 

Unit 1. 
Arkansas Electric Cooperative Corporation

1-20 Trinity Consultants

NO

x BART Analysis 

– Bailey and McClellan
Arkansas Electric Cooperative Corporation 1-21 Trinity Consultants

NOx BART Analysis – Bailey and McClellan

APPENDIX A

NOX CONTROL COST CALCULATIONS
Bailey Natural Gas Bailey Fuel Oil McClellan Natural Gas McClellan Fuel Oil

396 396 421 421

0.293 0.301 0.306 0.497

1350 1350 1436 1436

0.08 0.08 0.08 0.08

Primary Fuel Natural Gas Fuel Oil Natural Gas Fuel Oil

B = (lb/MMBtu) 0.293 0.301 0.306 0.497

C = (%) 85 75 85 75

A = (kW) 395685 395685 421009 421009

Z = 0.86 0.82 0.87 0.84

Capital Cost ($) $25,588,108 $25,155,493 $26,661,229 $26,421,423

(D) ($/kW) 65 64 63 63

Annualized Capital Cost ($/yr) $2,062,054 $2,027,191 $2,148,533 $2,129,207

G = 1.00 1.00 1.00 1.00

H = (MMBtu/hr) 1350 1350 1436 1436

D = ($/kW) 65 64 63 63

E = ($/yr) $168,882 $166,026 $175,964 $174,381

F = ($/yr) $1,255,553 $1,208,285 $1,331,078 $1,373,583

Total Annual Cost ($/yr) $3,486,488 $3,401,502 $3,655,575 $3,677,172

Equation 1

Where:

D = Capital cost ($/kW)

B= NOX (lb/10^6 Btu) at the inlet of the SCR reactor

C = NOx removal efficiency (%) 

A = Plant capacity (kW)

Equation 2

Equation 3

SCR Capital and O&M Cost Estimate

MW1

Baseline NOx Emission Rate (lb/MMBtu)2

Max Heat Input (MMBtu/hr)

Capital Recovery Factor (CRF)

35.0

75 300,000 











=

A

Z

D

E = D× A×C

[( ) ( ) ]

05.0 4.0

Z = B 5.1/ C /100

Equation 3

Where:

E = Fixed O&M cost ($/yr)

D = Capital cost ($/kW) from Equation 1

A = Plant capacity (kw)

C = A constant, 0.0066 yr-1

Equation 4

F = Variable O&M Cost ($/yr)

G = Annual capacity factor (expressed as a fraction, hours operated divided by 8760)

B = Inlet NOx (lb/MMBtu); range of 0.15 - 2.5 lb/MMBtu

H = Heat input (MMBtu/hr)

C = NOX removal efficiency; range of 80-95%

D = Capital cost ($/kW)

A = Plant capacity (kW)

Capital Recovery Factor (CRF)

CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life CRF = 0.08

a. Equipment CRF, 30-yr life, 7% interest

1 1 MMBtu = 293.1 kwh 

2

 Baseline NOx rate from Clean Air Markets Database, 30-day rolling average

 Fixed Costs include elements such as labor, station power, capital additions/improvements

Source: Cost of Selective Catalytic Reduction (SCR) Application for NOx Control on Coal-Fired Boilers, EPA/600/R-01/087, October 2001. 

35.0

75 300,000 











=

A

Z

D

E = D× A×C

F = G{225×[ 37.0 B × H ×(C /100)× (8760 / 2000)]× .1 005× 05.1 + .0 025× D × A× Z + 45.1 × A}

[( ) ( ) ]

05.0 4.0

Z = B 5.1/ C /100
Parameters/Costs Equation Bailey Natural Gas Bailey Fuel Oil McClellan Natural Gas McClellan Fuel Oil

Boiler design capacity, mmBtu/hr (C) 1350 1350 1436 1436

Annual operating hours, 3-yr average hr/yr (H) 1015 1015 5190 5190

Unit Size, kW (kW) 395685 395685 421009 421009

Unit Size, MW (MW)1

396 396 421 421

Capital recovery factor

 = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = 

equipment life 0.08 0.08 0.08 0.08

a. Equipment CRF, 30-yr life, 7% interest

Cost Index (CI)2

a. January 2012 593.6

b. 2004 444.2

Total Capital Investment3,4

TCI ($) =19.4 x kW x (300/MW)^0.359 x (CI2012/CI2004) $9,287,625 $9,287,625 $9,664,386 $9,664,386

Direct Annual Operating Costs $/yr

Variable O&M Costs5

=(0.08 mills/kW-hr/1000) x (1 kW-hr/10,000 Btu) x H x C x 

10^6 Btu/mmBtu x (CI2012/CI2004) $14,655 $14,655 $79,695 $79,695

Indirect Annual Costs, $/yr

1. Fixed O&M Costs6

= $0.29/kW x Nameplate capacity (MW) x (1000 kW/MW) x 

(300/MW)^0.359 x (CI2012/CI2004) $138,836 $138,836 $144,468 $144,468

2. Capital recovery = Equipment CRF x TCI $748,456 $748,456 $778,818 $778,818

1. $/yr =Direct Annual Costs + Indirect Annual Costs $901,947 $901,947 $1,002,981 $1,002,981

Notes:

1: 1 MMBtu = 293.1 kwh 

2:Cost Index: Chemical Engineering Plant Cost Index (CEPCI). Chemical Engineering Journal. 

4: Scaling factor = (300/Nameplate capacity)^0.359

5: The variable rate used for variable O&M costs was 0.027 mills/kW-hr. This is the rate listed inTable 4-8 of the ERG Analysis

6: The fixed cost rate used for fixed O&M costs was $0.29/kw. This represents the mid-point of the range listed in Table 4-8 of the ERG Analysis.

LNB Capital and O&M Cost Estimate

Source: All costs were estimated using ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-fired EGUs in the WRAP Region September 6, 

2005. Section 4.3 and Appendix D. A cost method developed for coal-fired EGUs was utilized for the combination natural gas or residual oil-fired boilers being addressed by 

this report, since the number of EGUs of similar size and fuel type to the boilers being addressed by this report is small and cost estimates are not as established. 

3: Capital Costs range from $14.8 to $24 per kW capacity of boiler for ULNBO (LNB-OFA) in Table 4-8 of the ERG Analysis cited above, so the the mid-point of this range ($19.4/kW) was used in this analysis to use an 

average cost
Capital Costs

Technology

SNCR

Parameters/Costs Equation Bailey Natural Gas Bailey Fuel Oil #6 McClellan Natural Gas McClellan Fuel Oil #6

Boiler design capacity, mmBtu/hr (QB) QB 1350 1350 1436 1436

3-yr Average operating time (top, hrs/yr) top = CFtotal × 8760 hrs/yr 1015 1015 5190 5190

Total Capacity Factor (CFtotal) CFtotal = CFplant × CFSNCR 0.12 0.12 0.59 0.59

Plant Capacity Factor (CFplant)

2

0.12 0.12 0.59 0.59

SNCR Capacity Factor (CFSCNR)

3 CFSNCR = tSNCR/365 1 1 1 1

Assumed NOx removal efficiency (ηNOx)

4

57.5% 52.5% 57.5% 52.5%

Uncontrolled NOx rate (NOxin, lb/MMBtu)50.293 0.301 0.306 0.497

Electricity Cost (Costelect, $/kwh)6$0.05 $0.05 $0.05 $0.05

Water Cost (Costwater, $/gal)7$0.00362 $0.00362 $0.00362 $0.00362

Fuel Cost (Costfuell, $/MMBtu)8$6.19 $4.68 $5.97 $5.70

Fuel Heat Content (Btu/lb)9

18,054 20,209 18,054 20,209

Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life 0.08 0.08 0.08 0.08

a. Equipment CRF, 30-yr life, 7% interest

Cost Index10

a. January 2012 Cost Index 593.6

b. 1998 Cost Index 389.5

Capital Costs 

Direct Capital Cost (A) DC ($) = ($950/MMBtu) × QB × ((2375 MMBtu/hr/QB)^0.577) × (0.66 + 0.85ηNOx) × (CI2011/CI1998) $3,075,516 $2,961,732 $3,161,209 $3,044,254

Indirect Installation Costs ($)

General Facilities 0.05 × A $153,776 $148,087 $158,060 $152,213

Engineering and Home Office Fees 0.10 × A $307,552 $296,173 $316,121 $304,425

Process Contingency 0.05 × A $153,776 $148,087 $158,060 $152,213

Total Indirect Installation Costs (B) = General Facilities Cost + Engineering and Home Office Fees + Process Contingency $615,103 $592,346 $632,242 $608,851

Other Installation Costs ($)

Project Contingency (C) C = 0.15 × (A + B) $553,593 $533,112 $569,018 $547,966

Total Plant Cost (D) D = A + B + C $4,244,213 $4,087,191 $4,362,468 $4,201,071

Allowance for Funds During Construction (E) E = 0 (Assumed for SNCR) $0 $0 $0 $0

Royalty Allowance (F) F = 0 (Assumed for SNCR) $0 $0 $0 $0

Preproduction Cost (G) G = 0.02 × (D + E) $84,884 $81,744 $87,249 $84,021

Inventory Capital (H)11 H = Volreagent (gal) × Costreagent ($/gal) $41,218 $34,789 $44,743 $48,160

Costreag, 50% Urea solution ($/gal)12 1.54 1.54 1.54 1.54

Volume of Reagent Tank (Volreagent (gal)) Volreagent (gal) = qsol x days of reagent supply × 24 hr/day 26,765 22,590 29,054 31,273

Urea solution volumetric flow rate (qsol, gal/hr)13

qsol = (msol x 7.481 gal/ft3)/ρreagent 79.66 67.23 86.47 93.07

Mass flow rate of urea solution (msol, lb/hr)14 msol = mreagent/Cureasol 756.02 638.09 820.66 883.34

Mass flow rate of reagent (mreagent, lb/hr)15 mreagent = (NOxin x QB x ηNOx × NSR x Mreagent)/(MNOx x SRT) 378.01 319.05 410.33 441.67

Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOxin + 0.7] × ηNOx)/NOxin 2.52 2.27 2.47 1.79

Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no catalyst) $0 $0 $0 $0

Total Capital Investment (TCI) (Capital Cost) TCI = D + E + F + G + H + I $4,370,315 $4,203,724 $4,494,461 $4,333,253

Annual Costs ($)

Annual Maintenance Cost (J) J = 0.015 × TCI $65,555 $63,056 $67,417 $64,999

Annual Reagent Cost (K) K = qsol × Costreag × top $124,563 $105,134 $691,095 $743,876

Annual Electricity Cost (L) L = P × Costelect × top $2,507 $2,318 $13,911 $16,400

Power (P, kW) P = (0.47 × NOxin × NSR × QB)/9.5 49.39 45.65 53.61 63.20

Annual Water Cost (M) M = qwater × Costwater × top $1,332 $1,124 $7,390 $7,955

Water flowrate for SNCR system (qwater, gal/hr)16

qwater = (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 362.38 305.86 393.37 423.41

Annual ∆Fuel Cost (N) N = ∆Fuel × Costfuel × top $19,239 $12,285 $102,931 $105,897

Additional fuel required (∆Fuel, MMBtu/hr)17 ∆Fuel= (Hv × mreagent × [(1/Cureasolinj) - 1])/106

 Btu/MMBtu 3.06 2.58 3.32 3.58

Direct Annual Costs (DAC)/Variable O&M DAC = J + K + L + M + N + O $213,197 $183,917 $882,745 $939,127

Indirect Annual Costs (IDAC)/Annualized Capital 

Cost IDAC = CFR × TCI $352,188 $338,763 $362,192 $349,201

Total Annualized Costs (TAC) TAC = DAC + IDAC $565,385 $522,680 $1,244,937 $1,288,328

1

 All SNCR costing equations from EPA Air Pollution Control Cost Manual (APCCM), 6th Edition (January 2002)

2 Plant capacity factor from "Inputs' tab

3

 tSCNR assumed to be 365 days

4

 ηNOx (NOx removal efficiency) based on control rates in "Preferred and Alternative Methods of Estimate Air Emissions from Boilers." January 2010. Table 2.2-2

5 Baseline NOx rate from Clean Air Markets Database, 30-day rolling average

6

 Electricity cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1

7

 Water cost estimate from Bentonville, AR commercial rate of $0.00362/gal, http://www.bentonvillear.com/utbc_rates.html

8 Update with source of natural gas and fuel oil costs

10 From Chemical Engineering Plant Cost Index (CEPCI)

11 Cost of keeping reagent on site, i.e., the first fill of the reagent tanks. 

13

ρreagent = 71.0 lb/ft3

14 Cureasol = urea solution concentration = 50%

Selective Non-Catalytic Reduction Capital and O&M Cost Estimate1

12 Five-yr average urea cost = $356.11/metric ton, from http://www.indexmundi.com/commodities/?commodity=urea&months=180

Density of 50% urea solution = 9.5 lb/gal (50% urea solution) based on EPA APCCM, 2002

Equates to $1.54/gal

17 Approximate heat of vaporization of water at 310°F, Hv = 900 Btu/lb From EPA APCCM, 2002

16 Concentration of stored urea, Cureasolstored = 50%

 Concentration of urea injected into SNCR system, Cureasolinj = 10%

 From EPA APCCM, 2002

15 Mreagent = 60.6 g/mol (molecular weight of urea)

 MNOx = 46.01 g/mol (molecular weight of NO2)

 SRT = 2 (ratio of equivalent moles NH3 per mole of urea)

9

 Fuel heat content from 'Inputs' tab

Density of natural gas = 0.056 lb/scf (http://www.engineeringtoolbox.com/gas-density-d_158.html), Specific gravity of fuel oil = 0.92, which gives a density of 7.67 lb/gal (http://www.hess.com/ehs/msds/9907no6fueloil.pdf)