BART FIVE FACTOR ANALYSIS – NOX ANALYSIS

ADDENDUM TO THE JULY 24, 2012 BART FIVE FACTOR 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 

April 2013 

Addendum to the July 24, 2012 BART Five Factor Analysis 

Version 1 
 

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NOx BART Analysis – Bailey and McClellan 

TABLE OF CONTENTS

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

1.1 INTRODUCTION ..................................................................................................... 1-3

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

1.3 IDENTIFICATION OF AVAILABLE RETROFIT NOX CONTROL TECHNOLOGIES FOR 

BAILEY UNIT 1 AND MCCLELLAN UNIT 1 ......................................................................... 1-4

1.4 ELIMINATE TECHNICALLY INFEASIBLE NOX CONTROL TECHNOLOGIES ............... 1-5

1.4.1 COMBUSTION CONTROLS .................................................................................... 1-5

1.4.1.1 Flue Gas Recirculation (FGR) ............................................................. 1-5

1.4.1.2 Overfire Air (OFA) .............................................................................. 1-5

1.4.1.3 Low NOX Burners ................................................................................ 1-6

1.4.2 POST COMBUSTION CONTROLS ........................................................................... 1-6

1.4.2.1 Selective Catalytic Reduction .............................................................. 1-6

1.4.2.2 Selective Non-Catalytic Reduction ...................................................... 1-7

1.5 RANK OF TECHNICALLY FEASIBLE NOX CONTROL OPTIONS BY EFFECTIVENESS .. 1-7

1.6 EVALUATION OF IMPACTS FOR FEASIBLE NOX CONTROLS ................................... 1-8

1.6.1 COST OF COMPLIANCE ........................................................................................ 1-9

1.6.2 ENERGY IMPACTS & NON-AIR IMPACTS .......................................................... 1-13

1.6.3 REMAINING USEFUL LIFE ................................................................................. 1-13

1.7 EVALUATION OF VISIBILITY IMPACT OF FEASIBLE NOX CONTROLS ................... 1-13

1.8 PROPOSED BART FOR NOX FOR BAILEY UNIT 1 AND MCCLELLAN UNIT 1 ......... 1-21

APPENDIX A .............................................................................................................................22

APPENDIX B .............................................................................................................................23

APPENDIX C .............................................................................................................................25
 

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NOx BART Analysis – Bailey and McClellan 

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 TECHNOLOGIES1-8

TABLE 1-3. SUMMARY OF COST EFFECTIVENESS FOR BAILEY UNIT 1 NOX CONTROLS ................... 1-12

TABLE 1-4. SUMMARY OF COST EFFECTIVENESS FOR MCCLELLAN UNIT 1 NOX CONTROLS ........... 1-12

TABLE 1-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT COMBUSTION CONTROLS FOR 

NOX CONTROL ...................................................................................................................... 1-15

TABLE 1-6. SUMMARY OF EMISSION RATES MODELED TO REFLECT SCR FOR NOX CONTROL ....... 1-15

TABLE 1-7. SUMMARY OF EMISSION RATES MODELED TO REFLECT COMBUSTION CONTROLS +

SNCR FOR NOX CONTROL ................................................................................................... 1-15

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

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

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

BAILEY UNIT 1 (2001-2003) – NATURAL GAS ..................................................................... 1-18

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

MCCLELLAN UNIT 1 (2001-2003) – FUEL OIL ..................................................................... 1-19

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

MCCLELLAN UNIT 1 (2001-2003) – NATURAL GAS ............................................................. 1-20
 

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NOx BART Analysis – Bailey and McClellan 

1. NOX BART EVALUATION

1.1 INTRODUCTION

This report is an addendum to “BART Five-Factor Analysis” submitted to ADEQ on July 24, 2012 

for the Bailey and McClellan Generating Stations. The original submittal included analyses for SO2

and PM but not NOX. This addendum is the analysis for NOX for the two plants. All information in 

Section 2 “Introduction and Background” of the original analysis is relevant to this analysis. As in 

the original submittal, it is proposed to burn natural gas as the primary fuel and switch to low-sulfur 

fuel oil as the back-up fuel. 

Regarding the results of the visibility improvements associated with NOX control systems 

summarized in Tables 1-8 through 1-11, when burning natural gas there are zero days of greater than 

0.5 deciviews for Bailey and only three days of greater than 0.5 deciviews for McClellan (with a 

maximum impact of 0.670 deciviews). The deciview impacts associated with fuel oil combustion in 

Tables 1-8 and 1-10 are due to SO2 emissions. These impacts will be mitigated by AECC switching 

to a lower sulfur fuel oil as determined in the analysis for SO2 submitted in the July 24, 2012 report.1 

Based on the information listed above, it seems unwarranted to require ratepayers to fund the 

installation of any physical NOx controls on either of these units when the proposed fuel switch will 

reduce visibility impacts to very low levels. Also, both of these facilities are located in the Entergy 

load control area. Beginning in 2014, this load control area will be managed by the Midwest 

Independent Transmission System Operator (MISO). MISO operates in a day-ahead market which 

essentially sets the dispatch order of generating units based on the cost of operation. Therefore, older 

and less efficient units such as Bailey Unit 1 and McClellan Unit 1 will likely not operate as much as 

they have in recent years. Lower operating time equates to lower annual emissions which will 

increase the cost effectiveness values (dollars per ton of pollutant removed – or $/ton) shown in 

Tables 1-3 and 1-4. This analysis demonstrates that the cost effectiveness does not justify installation 

of controls, and due to expected lower operation it’s likely that in the future the economics will be 

even worse (i.e., the cost effectiveness values will be even higher). 

1.2 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.2 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 the DC Circuit Court’s decision is overturned and CSAPR is reinstated, AECC is 

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

 1 The previously submitted SO2 and PM analyses were verbally agreed upon by EPA in an August 16, 2012 

conference all to discuss the July 24, 2012 submittal. 

2 EME Homer City Generation v. EPA, --F. 3d --, No. 11-1302 (DC Cir 2012) 
 

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NOx BART Analysis – Bailey and McClellan 

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. 

1.3 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 and combustion flame temperatures. 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 tangentially-fired 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 the method of 

firing, combustion flame temperatures, 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 

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) 
 

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NOx BART Analysis – Bailey and McClellan 

1.4 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. 

1.4.1 COMBUSTION CONTROLS

1.4.1.1 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 (wall-fired) with FGR is approximately 0.2-0.4 lb/MMBtu.3 This 

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

1 and McClellan Unit 1. 

1.4.1.2 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

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

boilers of 0.2-0.3 lb/MMBtu.4 

In discussions with consultants who have performed OFA retrofits on similar 

units, AECC learned that some boilers may be restricted from this technology 

due to physical size and space restraints. Further analysis is required to 

determine if (1) the dimensions of the Bailey and McClellan main boilers have 

sufficient upper furnace volume for OFA mixing and complete combustion; and 

(2) if there are physical space requirements for OFA ports and air supply ducts. 

For purposes of this report, this control is considered a technically feasible 

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

results of the five factor analyses deem OFA to be BART for either unit, then 

further analyses must be performed to determine if OFA is technically feasible 

on these units. 

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

4 Ibid. 
 

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1.4.1.3 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.5 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. LNB systems are technically feasible for the 

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

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

lb/MMBtu for both oil and gas firing scenarios.6 Moreover, the suite of all 

three combustion controls – LNB combined with OFA and FGR – should result 

in an emission rate of 0.15 to 0.20 lb/MMBtu.7 This combination of 

combustion controls, with an emission rate of 0.15 lb/MMBtu, is evaluated in 

the remaining steps of this analysis. 

1.4.2 POST COMBUSTION CONTROLS

1.4.2.1 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.8 This 

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

1 and McClellan Unit 1. 

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

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

7 Based on a first-cut budgetary planning estimate provided by Babcock Power Services on February 28, 2013. 

8 “Preferred and Alternative Methods of Estimate Air Emissions from Boilers.” January 2010. Table 2.2-2 
 

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1.4.2.2 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 combustion controls the estimated NOx

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

than combustion controls alone.9 This control is a technically feasible option 

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

1.5 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. 

 9 Ibid. 
 

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NOx BART Analysis – Bailey and McClellan 

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

TECHNOLOGIES

1.6 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 
 

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NOx BART Analysis – Bailey and McClellan 

1.6.1 COST OF COMPLIANCE

The capital costs, operating costs, and cost effectiveness of combustion controls, SNCR 

and SCR were estimated for the cost analysis. 

AECC was informed by consultants familiar with these types of retrofit projects that 

obtaining true vendor estimates would be costly and add significantly to the timing of the 

analysis submittal. As an example, AECC was told that a vendor would have to develop 

computer models of the Bailey and McClellan boilers to determine the costs and emission 

control effectiveness of their equipment. This would cost several thousand dollars and take 

approximately three months to get results. Based on this information, AECC requested 

only a “budgetary” cost estimate from Babcock Power Systems. However, these estimates 

are in line with previous studies after adjusting for inflation. 

Control Costs

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

calculations were estimated based on vendor estimates, engineering estimates, and 

published calculations methods using EPA’s Control Cost Manual. 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 A 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. 

In order to be consistent with the previously submitted SO2 and PM BART analysis from 

July 24, 2012, AECC calculated the annual heat input for each boiler by multiplying the 

average fuel usage from 2007 to 2011 by the average heat content of the fuel during that 

same time. 

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

AECC in their air emission inventories.10 The controlled annual emission rates are based 

on the lb/MMBtu levels believed to be achievable from the control technology multiplied 

by the baseline heat inputs to the boilers in MMBtu/yr. The baseline heat inputs are the 

sum of the baseline heat inputs for natural gas and fuel oil. The baseline heat inputs for 

 10 AECC now owns lower emitting, more efficient generation units than were owned in 2001-2003, and Bailey 

and McClellan are not typically dispatched as frequently as they used to be. The Oswald Plant, a 540 MW natural gas fired 

combined cycle plant, was purchased by AECC in 2005. In September 2012, AECC purchased a 660 MW natural gas fired 

combined cycle plant, Magnet Cove Generation Station, in the same load control area. Load control will continue to be 

distributed between the plants. Hours of operation from the units remain similar from year to year. However, load control 

varies from year to year. For example, in the 2009-2011 timeframe McClellan was dispatched to continually operate at a low 

load for transmission reliability purposes. So, in summary, the 2001-2003 timeframe does not represent most recent fuel 

prices nor the most recent operating conditions. Therefore, 2009-2011 is a more appropriate baseline emission period for 

this analysis. 
 

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NOx BART Analysis – Bailey and McClellan 

natural gas are based on the average natural gas usage for each unit from 2007 -2011

multiplied by the average heat content of natural gas for the same time period. The baseline 

heat inputs for fuel oil are based on the average fuel oil usage for each unit from 2007- 

2011 multiplied by the average heat content of fuel oil for the same time period. The data 

used to determine the baseline heat inputs is provided in Appendix B. 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 combustion 

controls, as well as between combustion controls + SNCR and combustion controls. 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.11 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.12 

Table 1-3 and Table 1-4 indicate that the cost effectiveness of combustion controls at a 

NOx level of 0.15 lb/MMBtu is approximately $37,000 per ton of NOx removed for Bailey 

Unit 1 and $6,300 per ton of NOx removed for McClellan Unit 1. Table 1-3 also indicates 

that the incremental costs over combustion controls at Bailey Unit 1 is nearly $87,000 per 

ton of NOx removed for combustion controls + SNCR and over $40,000/ton for SCR. 

Table 1-4 shows that the incremental costs over combustion controls at McClellan Unit 1 is 

over $32,000 per ton of NOx removed for combustion controls + SNCR and nearly 

$9,000/ton for SCR. 

AECC believes that the cost effectiveness (dollars per ton of pollutant removed) of combustion 

controls for these units will be higher (worse) in future years due to reduced operation of the units. 

This is because of the move to MISO in 2014 and planned transmission system upgrades. MISO 

dispatch order will favor newer, more efficient units to be called upon to operate first. Bailey and 

McClellan are older, less-efficient units and will be least likely to operate for economic purposes. 

Also, McClellan Unit 1 has operated the past few years primarily for transmission reliability 

purposes. However, once the transmission system is upgraded in the near future McClellan will not 

 11 “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. 

12 Ibid. 
 

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NOx BART Analysis – Bailey and McClellan 

be needed for transmission reliability purposes; therefore, operation will be greatly reduced. Lower 

operation equates to lower annual emissions which equates to a worse cost effectiveness for control 

additions.
Arkansas Electric Cooperative Corporation 1-12 

NOx BART Analysis – Bailey and McClellan 

TABLE 1-3.

SUMMARY OF 

COST 

EFFECTIVENESS FOR 

BAILEY 

UNIT 1 NOX CONTROLS

TABLE 1-4.

SUMMARY OF 

COST 

EFFECTIVENESS FOR 

M

C

CLELLAN 

UNIT 1 NOX CONTROLS
 

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NOx BART Analysis – Bailey and McClellan 

1.6.2 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. 

1.6.3 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. 

1.7 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 combustion controls, combustion controls + 

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 combustion controls, 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 

combustion controls is 0.15 lb/MMBtu for natural gas and fuel oil at both units. Control using 

combustion controls + SNCR has an associated emission level of 0.12 lb/MMBtu for Bailey Unit 1 

natural gas and fuel oil, as well as McClellan Unit 1 natural gas, and an associated emission level of 

0.10 lb/MMBtu for McClellan Unit 1 fuel oil. Control using combustion controls + SNCR results in 

a 10% improvement over the control efficiency of combustion controls alone. These levels were 

multiplied by the maximum hourly heat input to derive the hourly emission rates used in the 

modeling. 
 

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NOx BART Analysis – Bailey and McClellan 

Tables 1-5 through 1-7 summarize the NOx emission rates that were modeled to reflect the 

combustion controls, SCR, and combustion controls + 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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NOx BART Analysis – Bailey and McClellan 

TABLE 1-5. SUMMARY OF EMISSION RATES MODELED TO REFLECT COMBUSTION CONTROLS 

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 0.5 202.5 10.2 0.3 0.0 0.0 7.4 2.5 

Bailey, Unit 1 – 

Fuel Oil 2,375.8 202.5 49.4 4.0 12.1 30.2 0.7 2.4 

McClellan, Unit 1 – 

Natural Gas 0.6 215.5 10.9 0.3 0.0 0.0 7.9 2.7 

McClellan, Unit 1 – 

Fuel Oil 2,747.5 215.5 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 COMBUSTION CONTROLS +

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 0.5 162.9 10.2 0.3 0.0 0.0 7.4 2.5 

Bailey, Unit 1 – 

Fuel Oil 2,375.8 161.9 49.4 4.0 12.1 30.2 0.7 2.4 

McClellan, Unit 1 – 

Natural Gas 0.6 171.5 10.9 0.3 0.0 0.0 7.9 2.7 

McClellan, Unit 1 – 

Fuel Oil 2,747.5 144.0 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 1-16 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 1-17 

NOx BART Analysis – Bailey and McClellan 

TABLE 1-8.

SUMMARY OF 

VISIBILITY IMPROVEMENT 

ASSOCIATED WITH NOX CONTROL 

SYSTEM ON 

BAILEY 

UNIT 

OIL

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness 

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) 

Baseline Emission Rate 0.969 0.330 8 - 0.695 0.347 7 - 0.686 0.367 6 - 1.589 Combustion Controls 0.919 0.325 7 1.52% 0.671 0.332 6 4.32% 0.627 0.339 5 7.63% 1.412 SCR 0.896 0.323 6 2.12% 0.660 0.325 6 6.34% 0.614 0.325 4 11.44% 1.325 Combustion Controls + SNCR 0.910 0.325 6 1.52% 0.667 0.329 6 5.19% 0.618 0.333 5 9.26% 1.377 

*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 m

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

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

NOx BART Analysis – Bailey and McClellan 

TABLE 1-9.

SUMMARY OF 

VISIBILITY IMPROVEMENT 

ASSOCIATED WITH NOX CONTROL 

SYSTEM ON 

BAILEY 

UN

NATURAL 

GAS

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness 

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) 

Baseline Emission Rate 0.219 0.083 0 - 0.170 0.072 0 - 0.238 0.073 0 - 0.44Combustion Controls 0.104 0.039 0 53.01% 0.080 0.034 0 52.78% 0.115 0.035 0 52.05% 0.20SCR 0.037 0.014 0 83.13% 0.028 0.013 0 81.94% 0.042 0.013 0 82.19% 0.06Combustion Controls + SNCR 0.086 0.032 0 61.45% 0.066 0.028 0 61.11% 0.095 0.029 0 60.27% 0.16

*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 m

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

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected 

†Note that the “Visibility Improvements” listed in this table are percent improvements of zero visibility impact contributions.
Arkansas Electric Cooperative Corporation 1-19 

NOx BART Analysis – Bailey and McClellan 

TABLE 1-10.

SUMMARY OF 

VISIBILITY IMPROVEMENT 

ASSOCIATED WITH NOX CONTROL 

SYSTEM ON 

M

C

CLELLAN 

FUEL 

OIL

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness 

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) 

Baseline Emission Rate 3.007 0.621 22 - 1.319 0.266 5 - 0.660 0.230 2 - 0.546 Combustion Controls 2.663 0.554 19 10.79% 1.128 0.264 4 0.75% 0.648 0.209 1 9.13% 0.483 SCR 2.627 0.548 18 11.76% 1.108 0.264 4 0.75% 0.647 0.207 1 10.00% 0.477 Combustion Controls + SNCR 2.594 0.542 18 12.72% 1.090 0.264 3 0.75% 0.646 0.203 1 11.74% 0.471 

*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 m

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

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected 
Arkansas Electric Cooperative Corporation 1-20 

NOx BART Analysis – Bailey and McClellan 

TABLE 1-11.

SUMMARY OF 

VISIBILITY IMPROVEMENT 

ASSOCIATED WITH NOX CONTROL 

SYSTEM ON 

M

C

CLELLAN 

NATURAL 

GAS

Caney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness 

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) 

Baseline Emission Rate 0.670 0.125 3 - 0.258 0.052 0 - 0.092 0.040 0 - 0.13Combustion Controls 0.356 0.068 0 45.60% 0.136 0.028 0 46.15% 0.048 0.021 0 47.50% 0.07SCR 0.128 0.027 0 78.40% 0.048 0.012 0 76.92% 0.016 0.009 0 77.50% 0.02Combustion Controls + SNCR 0.289 0.056 0 55.20% 0.110 0.023 0 55.77% 0.039 0.018 0 55.00% 0.05

*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 m

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

the baseline and controlled 98th percentile impacts shown in the table may be slightly different than the visibility improvement reflected 

†Note that the “Visibility Improvements” listed in this table are percent improvements for essentially zero visibility impact contribution

days of alleged visibility impact contributions to the Caney Creek Wilderness). 
 

Arkansas Electric Cooperative Corporation 1-21 Trinity Consultants 

NOx BART Analysis – Bailey and McClellan 

The operation of combustion controls results in an estimated 0.005 to 0.028 Δdv improvement (1.52-7.63 

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 0.038 to 0.051 Δdv improvement (50.00-53.01 percent) in the 

natural gas scenario. The operation of combustion controls results in an estimated 0.002 to 0.067 Δdv 

improvement (0.75 to 10.79 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 0.019 to 0.057 Δdv improvement 

(45.60-47.50 percent) in the natural gas scenario. 

Further, the operation of SCR systems results in an estimated 0.007 to 0.042 and 0.059 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 to Bailey Unit 1 at the modeled Class I areas from fuel oil and natural gas, 

respectively, while combustion controls + SNCR results in an estimated 0.005 to 0.034 and 0.044 to 0.059 

Δdv improvement (1.52 to 9.26 and 57.84 to 61.45 percent) of the 98th percentile from fuel oil and natural 

gas, respectively. Operation of SCR systems results in an estimated 0.002 to 0.073 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 to McClellan Unit 1 at the modeled Class I areas from fuel oil and natural gas, respectively, 

while combustion controls + SNCR results in an estimated 0.002 to 0.079 and 0.022 to 0.069 Δdv 

improvement 0.75 to 12.72 and 55.00 to 55.77 percent) of the 98th percentile from fuel oil and natural gas, 

respectively. 

 

1.8 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 nearly $37,000 per ton of NOx reduced for combustion controls at Bailey Unit 1 and over $6,000 per 

ton of NOx reduced for combustion controls at McClellan Unit 1. In addition, the cost effectiveness is up 

to $49,000 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 0.067 

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. 

Also, as previously discussed, the cost effectiveness for these units is expected to be worse for both units 

in future years because of decreased annual operation.
 

Arkansas Electric Cooperative Corporation 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

122 122 136 136

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) 122000 122000 136000 136000

Z = 0.86 0.82 0.87 0.84

Capital Cost ($) $11,909,536 $11,708,183 $12,790,607 $12,675,562

(D) ($/kW) 98 96 94 93

Annualized Capital Cost ($/yr) $959,747 $943,520 $1,030,749 $1,021,478

G = 1.00 1.00 1.00 1.00

H = (MMBtu/hr) 1350 1350 1436 1436

D = ($/kW) 98 96 94 93

E = ($/yr) $78,603 $77,274 $84,418 $83,659

F = ($/yr) $563,393 $534,923 $617,702 $670,486

Total Annual Cost ($/yr) $1,601,743 $1,555,718 $1,732,870 $1,775,622

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

SCR Capital and O&M Cost Estimate

MW

Baseline NOx Emission Rate (lb/MMBtu)2

Max Heat Input (MMBtu/hr)

Capital Recovery Factor (CRF)

0.35

75 300,000 









  A

Z D

E  D AC

    0.05 0.4 Z  B /1.5 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. 

0.35

75 300,000 









  A

Z D

E  D AC

F  G225  0.37B H  C /100 8760 / 2000 1.0051.05  0.025 D  A Z 1.45 A

    0.05 0.4 Z  B /1.5 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) 122000 122000 136000 136000

Unit Size, MW (MW)1 122 122 136 136

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) $7,700,000 $7,700,000 $7,400,000 $7,400,000

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) $65,307 $65,307 $70,016 $70,016

2. Capital recovery = Equipment CRF x TCI $620,515 $620,515 $596,339 $596,339

1. $/yr =Direct Annual Costs + Indirect Annual Costs $700,477 $700,477 $746,051 $746,051

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.

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. EPA Region 

VII document, " NOx Controls for Existing Utility Boilers" by Bill Neuffer, ESD/QAQPS Table 1 summarizes that LNB at a PC Wall-fired boiler results in a NOx cost 

effectiveness of $160-$450/ton while LNB at an Oil/Gas Wall-fired boiler results in a NOx cost effectivness of $750-$1700/ton. Therefore, AECC assert that the ERG cost 

estimate while not directly applicable to oil/gas boilers is at least conservative in estimating a higher cost than might be expected at oil/gas boilers.

3, 4: Capital Costs estimates provided by Babcock Power on February 28, 2013. The estimates do not represent a firm offer to sell but rather are good approximations that require further refinements before purchase.

LNB/OFA Capital and O&M Cost Estimate
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)5 0.293 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 ΔFuel Cost (N) N = ΔFuel × Costfuel × top $19,239 $12,285 $102,931 $105,897

Additional fuel required (ΔFuel, MMBtu/hr)17 ΔFuel= (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%

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)

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

Arkansas Electric Cooperative Corporation Trinity Consultants 

NOx BART Analysis – Bailey and McClellan 

APPENDIX B 

 ADDITIONAL DATA

 
 

Arkansas Electric Cooperative Corporation Trinity Consultants 

NOx BART Analysis – Bailey and McClellan 

Fuel Usage for 2007‐2011

   Bailey McClellan

   Natural Gas Fuel Oil Natural Gas Fuel Oil

   (MMscf) (Gallons) (MMscf) (Gallons)

2007 131 75,247 1,552 3,683,332

2008 217 17,392 2,138 2,243,823

2009 209 429,379 1,196 2,822,603

2010 523 413,112 2,463 471,405

2011 759 329,146 2,740 189,567

Average 368 252,855 2,018 1,882,146

Heat Value for Natural Gas

Bailey* McClellan*

Month BTU/scf Month BTU/scf

Jun‐11 1,013 Jul‐11 1,011

The natural gas heating value changes only slightly over time.

Average Heat Input for Fuel Oil

Bailey* McClellan*

Month BTU/gal Month BTU/gal

Jan‐04 154,419 Mar‐07 161,916

Feb‐04 153,942 Mar‐07 162,049

Mar‐04 155,441 Mar‐07 162,081

Mar‐04 155,641 Mar‐07 156,067

Mar‐04 153,907 Mar‐07 153,574

Apr‐04 152,543 Jul‐07 164,304

Jul‐04 154,838 Jul‐07 164,468

Jul‐04 155,780 Jun‐08 157,485

Aug‐04 154,179 Feb‐09 149,470

Sep‐04 155,102 Feb‐09 157,598

Aug‐05 157,164 Mar‐09 148,931

Oct‐05 156,930 Mar‐09 153,658

Nov‐05 155,216 May‐09 143,621

Jan‐06 152,268 Jun‐09 160,833

Feb‐06 152,790 Average 156,861

May‐06 154,267

Average 154,652
 

Arkansas Electric Cooperative Corporation Trinity Consultants 

NOx BART Analysis – Bailey and McClellan 

APPENDIX C 

VENDOR ESTIMATES FOR COMBUSTION CONTROLS
FW: AECC Bailey & McClellan Units

Stephen Cain <scain@aecc.com> 03/01/2013 08:24 AM

To: "Kasi Dubbs (KDubbs@trinityconsultants.com)" 

<KDubbs@trinityconsultants.com>

Cc: "Jeremy Jewell (JJewell@trinityconsultants.com)" 

<JJewell@trinityconsultants.com>

Bcc:

Client: AECC 123701.0036

Category: Received Files

Kasi,

Below are LNB/OFA estimates from Babcock Power.  Please contact me after you’ve had a chance to

evaluate them.

Thanks,

Stephen Cain

Manager – Environmental Compliance

Arkansas Electric Cooperative Corporation

501.570.2420

From: David Harris 

Sent: Thursday, February 28, 2013 5:05 PM

To: Stephen Cain; Curtis Warner

Subject: FW: AECC Bailey & McClellan Units

FYI

From: JCreelman@babcockpower.com [mailto:JCreelman@babcockpower.com] 

Sent: Thursday, February 28, 2013 4:00 PM

To: David Harris

Cc: MHead@babcockpower.com; Bruce Tripplett; SSudhakar@babcockpower.com

Subject: AECC Bailey & McClellan Units

Mr. Harris

Please see below order of magnitude estimates for the Bailey Unit 1 and McClellan Unit 1 Power Plants, 

per your request. These estimates are provided to you for budgeting and planning purposes only and do 

not represent a firm offer to sell. RPI referenced indicative units where we have executed similar work 

scopes recently in order to derive these estimates. Therefore they represent good approximations, 

however they would need to be refined before offering firm price or emission expectations.

For the design, supply and erection, including all engineering, quality and project management required 

to supply new Low NOx Natural Gas burners (#6 secondary fuel), OFA, and FGR system (10%), the 

order of magnitude cost estimates and emissions are as follows:

McClellan Unit 1
 Total Cost: $7,400,000

Bailey Unit 1

 Total Cost: $7,700,000

Please let us know if you have any further questions.

Thank you 

Joshua Creelman

Joshua Creelman

Babcock Power Inc.

5 Neponset Street

Worcester, MA 01606

 

T: 508-854-1259 F: 508-854-4639

M: 774-437-9295

 

JCreelman@babcockpower.com

http://www.babcockpower.com

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