## BART F IVE 

## F ACTOR 

## A NALYSIS



## – NO X 

## A NALYSIS



## A RKANSAS 

## E LECTRIC 

## C OOPERATIVE 

## C ORPORATION



## B AILEY AND 

## M C 

## C LELLAN 

## G ENERATING 

## S TATIONS

Prepared By:

T RINITY C ONSULTANTS , I NC

. 120 East Sheridan, Suite 205 Oklahoma City, Oklahoma 73104 (405) 228

- 3292

T RINITY C ONSULTANTS , I NC

. 977 Ridge Drive, Suite 380 Lenexa, Kansas 66219 (913) 894

- 4500

In conjunction with:

A RKANSAS E LECTRIC COOPERATIVE CORPORATION

PO Box 194208 Little Rock, Arkansas (501) 570

- 2420

Trinity Project No. 123701.0036

September 2012
Version 1Arkansas Electric Cooperative Corporation 1

- 1 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan 

## T ABLE OF 

## C ONTENTS



### 1. NO X 

### BART E VALUATION



### ................................ ................................ ................... 1

- 3 1.1 C ROSS



### - S TATE 

### A IR 

### P OLLUTION 

### R ULE AND 

### BART

................................ ................. 1

- 3 1.2 I DENTIFICATION OF 

### A VAILABLE 

### R ETROFIT 

### NO X 

### C ONT ROL 

### T ECHNOLOGIES 

### F OR 

### B AILEY 

### U NIT 

### 1 AND 

### M C 

### C LELLAN 

### U NIT 

### 1

................................ ................................ ......... 1

- 3 1.3 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES



### ............... 1

- 4

1.3.1 C OMBUSTION C ONTROLS

................................ ................................ .................... 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 NO X Burners

................................ ................................ ................ 1

- 5
1.3.2 P OST C OMBUSTION C ONTROLS

................................ ................................ ........... 1

- 5
1.3.2.1 Selective Catalytic Reduction

................................ .............................. 1

- 5
1.3.2.2 Selective Non

- Catalytic Reduction

................................ ...................... 1

- 6 

### 1.4 R ANK OF 

### T ECHNICALLY FEASIBLE 

### NO X 

### C ONTROL 

### O PTION S BY 

### E FFECTIVENESS



### .. 1

- 6 1.5 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### NO X 

### C ONTROLS



### ................................ ... 1

- 7
1.5.1 C OST OF C OMPLIANCE

................................ ................................ ........................ 1

- 8
1.5.2 E NERGY I MPACTS & N ON

- A IR I MPACTS

................................ .......................... 1

- 11
1.5.3 R EMAINING U SEFUL L IFE

................................ ................................ ................. 1

- 11 

### 1.6 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### NO X 

### C ONTROLS



### ................... 1

- 11 1.7 P ROPOSED 

### B ART FOR 

### NO X FOR 

### B AILEY 

### U NIT 

### 1 AND 

### M C 

### C LELLAN 

### U NIT 

### 1

......... 1

- 19

A PPENDIX 

### A

................................ ................................ ................................ ................................ .Arkansas Electric Cooperative Corporation 1

- 2 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan 

## L IST OF 

## T ABLES

T ABLE 1

- 1. A VAILABLE NO X C ONTROL T ECHNOLOGIES FOR B AILEY U NIT 1 AND M C C LELLAN U NIT 1

................................ ................................ ................................ ................................ .............. 1

- 4

T ABLE 1

- 2. C ONTROL E FFECTIVENESS OF T ECHNICALLY F EASIBLE NO X C ONTROL T ECHNOLOGIES 1

- 7

TABLE 1

- 3. S UMMARY OF C OST E FFECTIVENESS FOR B AILEY U NIT 1 NO X C ONTROLS

................... 1

- 10

TAB LE 1

- 4. S UMMARY OF C OST E FFECTIVENESS FOR M C C LELLAN U NIT 1 NO X C ONTROLS

........... 1

- 10

T ABLE 1

- 5. S UMMARY OF E MISSION R ATES M ODELED TO R EFLECT LNB/OFA FOR NO X C ONTROL 1

- 13

T ABLE 1

- 6. S UMMARY OF E MISSION R ATES M ODELED TO R EFLECT SCR FOR NO X C ONTROL

....... 1

- 13

T ABLE 1

- 7. S UMMARY OF E MISSION R ATES M ODELED TO R EFLECT LNB/OFA + SNCR FOR NO X C ONTROL

................................ ................................ ................................ .............................. 1

- 13

T ABLE 1

- 8. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON
B AILEY U NIT 1 (2001

- 2003)

– F UEL O IL

................................ ................................ .............. 1

- 15

T ABLE 1

- 9. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON
B AILEY U NIT 1 (2001

- 2003)

– N ATURAL G AS

................................ ................................ ..... 1

- 16

T ABLE 1

- 10. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON
M C C LELLAN U NIT 1 (2001

- 2003)

– F UEL O IL

................................ ................................ ..... 1

- 17

T ABLE 1

- 11. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON
M C C LELLAN U NIT 1 (2001

- 2003)

– N ATURAL G AS

................................ ............................. 1

- 18Arkansas Electric Cooperative Corporation 1

- 3 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan 

## 1. N O X 

## BART E VALUATION



## 1.1 C ROSS



## - S TATE 

## A IR 

## P OLLUTION 

## R ULE 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 I mplementation Plans (FIPs)

, including several FIPs that EPA recently finalized that rel y on CSAPR as an alternative to BART ( i.e., FIPs for 

### Georgia, Indiana, Iowa, Kentucky, Michigan, Missouri, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, and W est 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 NO
x 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 alte rnative to a source specific BART determination. Finally, i n the event that Arkansas requires a source

- specific BART determination, AECC has conducted a full five factor analysis to determine BART for NO
x for Bailey Unit 1 and McClellan Unit 1

.



## 1.2 I DENTIF ICATION OF 

## A VAILABLE 

## R ETROFIT 

## NO X 

## C ONTROL 

## T ECHNOLOGIES 

## F OR 

## B AILEY 

## U NIT 

## 1 AND 

## M C 

## C LELLAN 

## U NIT 

## 1

Nitrogen oxides, NO
x , are produced during fuel combustion when nitrogen contained in both the fuel and the combustion air is exposed to high temperatures. The or igin of the nitrogen (i.e. fuel vs. combustion air) has lead to the use of the terms “thermal” NO
x and “fuel” NO
x when describing NO
x emissions . Thermal NO
x emissions are produced when elemental nitrogen in the combustion air is exposed to a high temperature zone and oxidized. Fuel NO
x emissions are created during the rapid oxidation of nitrogen compounds contained in the fuel.

Nitrogen oxide (NO) is typically the predominant form of NO
x from fossil fuel combustion . N itrogen dioxide (NO
2 ) makes up the remainder of the NO
x . The formation of NO
x 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 discret e 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

uncont rolled NO
x emissions than wall

- fired boilers. Therefore baseline NO
x 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 NO
x control technologies. The available retrofit NO
x control technologies are summarized in Table 1

- 1 for Bailey Unit 1 and McClellan Unit 1

.

NO
x emissions controls, as l isted 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)Arkansas Electric Cooperative Corporation 1

- 4 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan NO
x Burners (LNB), reduce the peak flame temperature and excess air in the furnace w hich minimizes NO
x formation. Post

- combustion controls, such as selective catalytic reduction (SCR) and selective non

- catalytic reduction (SNCR) convert NO
x in the flue gas to molecular nitrogen and

water.

T ABLE 1

- 1

. A VAILABLE NO X C ONTROL T ECHNOLOGIES FOR B AILEY U NIT 1 AND M C C LELLAN U NIT 1

NO
x Control Technologies

Combustion Controls Flue Gas Recirculation (FGR)
Overfire Air (OFA)

Low NO
x Burners (LNB)

Post

- Combustion Controls Selective Catalytic Reduction (SCR)

Selective Non

- Catalytic Reduction (SNCR)



## 1.3 E LIMINATE 

## T ECHNICALLY 

## I NFEASIBLE 

## NO X 

## C ONTROL 

## T ECHNOLOGIES

Step 2 of the BART determination is to eliminate technically infeasible NO
x control technologies that were identified in Step 1. Control ranges were developed using a combination of literature control ranges and efficiencies.



### 1.3.1 C OMBUSTION 

### C ONTROLS



### 1.3.1.1 F LUE 

### G AS 

### R ECIRCULATION 

### (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 NO
x formation. When operated without additional controls, the NO
x control range for oil and gas fired boilers with FGR is approximately 0.2

- 0.4 lb/MMBtu. 2 This control is a techni cally feasible option for the control of NO
x from Bailey Unit 1 and McClellan Unit 1

.



### 1.3.1.2 O VERFIRE 

### A IR 

### (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 NO
x by lowering combustion temperature and limiting the availability of oxygen in the combustion zone where NO
x i s most likely to be formed. OFA as a single NO
x

2 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options.” Utility Boiler section. July 1994.Arkansas Electric Cooperative Corporation 1

- 5 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan

control technique results in estimated NO
x 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 NO
x from Bailey Unit 1 and McCle llan Unit 1

.



### 1.3.1.3 L OW 

### NO X 

### B URNERS

LNB technology utilizes advanced burner design to reduce NO
x formation through the restriction of oxygen, lowering of flame temperature, and/or reduced residence time. NO
x 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, NO
x formation is limited by one of two methods. Under staged fuel

- rich condition s , low oxygen levels limit flame temper atures resulting in less NO
x 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 NO
x formation. In the secondary zone, combustion products formed in the primary zone act to lower the local oxygen concentration, resulting in a decrease in NO
x formation.

When combined with OFA, t he estimated NO
x control emission rate is 0. 20 lb/MMBtu for both oil and gas firing scenarios

. 5 LNB systems are technic ally feasible for the control of NO
x from Bailey Unit 1 and McClellan Unit 1

.



### 1.3.2 P OST 

### C OMBUSTION 

### C ONTROLS



### 1.3.2.1 S ELECTIVE 

### C ATALYTIC 

### R EDUCTION

SCR refers to the process in which NO
x is reduced by ammonia over a heterogeneous catalyst in the presence of oxygen. The process is termed selective because the ammonia preferentially reacts with NO
x rather than oxygen, although the oxygen enhances the reac tion and is a necessary component of the process. The overall reactions are:

4NO + 4NH 3 + O 2  4N 2 + 6H 2 O

2NO 2 + 4NH 3 + O 2  3N 2 + 6H 2 O

The SCR process requires a reactor, a catalyst, and an ammonia storage and injection system. The effectiv eness of an SCR system is dependent on a variety of factors, including the inlet NO
x concentration, the exhaust temperature, the ammonia injection rate, and the type of catalyst. The estimated NO
x 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 NO
x from Bailey Unit 1 and McClellan Unit 1

.

3 Ibid.
4 http://www.energysol utionscenter.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

- 2Arkansas Electric Cooperative Corporation 1

- 6 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan



### 1.3.2.2 S ELECTIVE 

### N ON



### - C ATALYTIC 

### R EDUCTION

In SNCR systems, a reagent is injected into the flue gas in the furnace within an appropriate temperature window. The NO
x 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 SNC R 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
NO
x reductions. When combined with LNB/OFA the estimated NO
x control for SNCR on oil an d 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 NO
x from Bailey Unit 1 and McClellan Unit 1

.



## 1.4 R ANK OF 

## T ECHNICALLY FEASIBLE 

## NO X 

## C ONTROL 

## O PTIONS BY 

## E FFECTIVENESS

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 Uni t 1 and McClellan Unit 1

.

7 Ibid.Arkansas Electric Cooperative Corporation 1

- 7 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan T ABLE 1

- 2

. C ONTROL E FFECTIVENESS OF T ECHNICALLY F EASIBLE NO X C ONTROL T ECHNOLOGIES



## 1.5 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## NO X 

## C ONTROLS

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 sourceArkansas Electric Cooperative Corporation 1

- 8 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan 

### 1.5.1 C OST OF 

### C OMPLIANCE

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 pr ovided 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 rate s were the average rate s 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 SO 2 and PM analysis.

Cost Effectiveness
The cost effectiveness in dol lars per ton of N O
x reduced was determined by dividing the annualized cost of control by the annual tons reduced. An i ncremental cost analys i s was also performed to show the incremental increase in costs between SCR and an LNB/OFA system, as well as betwe en 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 co st

- effective than post

combustion controls. EPA estimates that approximately 75 percent of the BART units (non

- cyclone) could mee t the presumptive NO
x limits at a cost of $100 to $1,000 per ton of
NO
x 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 comb ustion controls. The EPA estimates that the costs of such controls are usually less than $1,500 per
ton of NO
x removed. 9

8 “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART Determinations; Final Rule.” CFR Vol. 77, No. 128. We dnesday, July 6, 2005, Rules and Regulations. Pages 39134

- 39135.

9 Ibid.Arkansas Electric Cooperative Corporation 1

- 9 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan

Table 1

- 3 and Table 1

- 4 indicate that the cost effectiveness of LNB/OFA at a NO
x level of
0. 2 lb/MMBtu is approximately $ 100 ,000 pe r ton of NO
x removed for Bailey Unit 1 and $ 16,5 00 per ton of NO
x 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 NO
x 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 NO
x removed and is over $ 16 ,000 per ton for SCR.Arkansas Electric Cooperative Corporation 1

- 10 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan TABLE 1

- 3

. S UMMARY OF C OST E FFECTIVENESS FOR B AILEY U NIT 1 N O X C ONTROLS

TABLE 1

- 4

. S UMMARY OF C OST E FFECTIVENESS FOR M C C LELLAN U NIT 1 N O X C ONTROLSArkansas Electric Cooperative Corporation 1

- 11 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan 

### 1.5.2 E NERGY 

### I MPACTS 

### & N ON



### - A IR 

### I MPACTS

SCR and SNCR systems require electricity to operate the ancillary equipment. The need for electricity to help power some of the ancillary equipment c reates 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
eit her from ammonia injection at temperatures too low for effective reaction with NO
x , 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

re leased 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 R EMAINING 

### U SEFUL 

### L IFE

The remaining useful life of Bailey Unit 1 and McClellan Unit 1 d o es not impact the annualized capital costs of potential controls because the useful li fe of the boiler is anticipated to be at least as long as the capital cost recovery period, which is 30 years.



## 1.6 E VALUATION OF 

## V ISIBILITY 

## I MPACT OF 

## F EASIBLE 

## NO X 

## C ONTROLS

A final impact analysis was conducted to assess the visibility improvement for existing emiss ion rates when compared to the emission rates associated with LNB/OFA, LNB/OFA/SNCR and S CR systems. The AECC Five Factor Analysis submitted in August 2012 documented the existing visibility impairment attributable to Bailey Unit 1 and McClellan Unit 1 , i n 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 NO
x emission rates associated with the control systems were model ed using CALPUFF. The controlled emission level associated with SCR systems at Bailey Unit 1 is 0. 0 4 lb/MMBtu for natural gas and 0.0 8 lb/MMBtu for fuel oil, while the emission level for SCR at McClellan Unit 1 is 0.0 5 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 as sociated emission level of 0.17 at B ailey with natural gas and 0.17 with fuel oil. At McClellan Unit 1, LNB/OFA + SNCR results in a NO
x level of 0.1 7 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 t he hourly emission rates used in the mo deling.Arkansas Electric Cooperative Corporation 1

- 12 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan Tables 1

- 5 through 1

- 7 summarize the NO
x 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 bas eline modeling.Arkansas Electric Cooperative Corporation 1

- 13 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan T ABLE 1

- 5

. S UMMARY OF E MISSION R ATES M ODELED TO R EFLECT LNB/OFA FOR NO X C ONTROL

Unit / Fuel SO 2 NO
x Total PM 10 SO 4 PM c PM f 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 4 9.4 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

T ABLE 1

- 6

. S UMMARY OF E MISSION R ATES M ODELED TO R EFLECT SCR FOR NO X C ONTROL

Unit / Fuel SO 2 NO
x Total PM 10 SO 4 PM c PM f 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 4 9.4 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

T ABLE 1

- 7

. S UMMARY OF E MISSION R ATES M ODELED TO R EFLECT LNB/OFA + SNCR FOR NO X C ONTROL

Unit / Fuel SO 2 NO
x Total PM 10 SO 4 PM c PM f 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 4 9.4 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

Table s 1

- 8 though 1

- 1 1 provide a comparison of the existing visibility impairment and the visibility impairment associated with the addition of NO
x controls on Bailey Unit 1 and McClellan Unit 1 in all affected Class I areas , including the maximum modeled visibility impact, 98 th percen tile modeled visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δdv. T h e visibility improvement shown in the table was calculated as the difference between the existingArkansas Electric Cooperative Corporation 1

- 14 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan visibility impairment and the visibility impa irment associated with a retrofitted system with the specific control as measured by the 98 th percentile.Arkansas Electric Cooperative Corporation 1

- 15 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan T ABLE 1

- 8

. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON B AILEY U NIT 1 ( 2001

- 2003 )

– F UEL O IL

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% 1.32 5 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 98 th percentile impact (Δdv) compared to the baseline impact (Δdv) †The visibility improvement shown in the table has been calculated from 98 th percentile baseline and controlled impacts that include more decimal places than what is shown in the table. Due to rounding o f the baseline and controlled 98 th percentile impacts shown in the table, the visibility improvement calculated from

the baseline and controlled 98 th 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

NO
x BART Analysis

– Bailey and McClellan T ABLE 1

- 9

. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON B AILEY U NIT 1 (2001

- 2003)

– N ATURAL G AS

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)

# Day s > 0.5 Δdv Visibility Improvement*

Baseline Emissio n 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 98 th percentile impact (Δdv) compared to the baseline impact (Δdv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement calculated from

the baselin e and controlled 98 th 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

NO
x BART Analysis

– Bailey and McClellan T ABLE 1

- 10

. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON M C C LELLAN U NIT 1 (200 1

- 2 0 03 )

– F UEL O IL

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. 73 1 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 98 th percentile impact (Δdv) compared to the baseline impact (Δdv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement calculated from

the baseline and controlled 98 th 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

NO
x BART Analysis

– Bailey and McClellan T ABLE 1

- 11

. S UMMARY OF V ISIBILITY I MPROVEMENT A SSOCIATED WITH NO X C ONTROL S YSTEM ON M C C LELLAN U NIT 1 (2001

- 2003)

– N ATURAL G AS

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*

B aseline 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 3 0.00% 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% 0.05 4 0.024 0 40.00% 0.078 0.035 0 39.66%
*Improvement is based on the 98 th percentile impac t (Δdv) compared to the baseline impact (Δdv) †The visibility improvement shown in the table has been calculated from 98 th 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 98 th percentile impacts shown in the table, the visibility improvement calculated from

t he baseline and controlled 98 th 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

NO
x 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

per cent) of the 98 th percentile visibility impairm ent 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 98 th percentile visibility impairm ent attributable to McClellan Unit 1 at the modeled Class I areas in the fuel oil burning scenario and 0.012 to 0.032 Δdv imp rovement (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 98 th 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 98 th percentile from fuel oil and natural gas, respectively

. O peration 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 98 th 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 98 th percentile from fuel oil and natural gas, respectively

.



## 1.7 P ROPOSED 

## B ART FOR 

## NO X FOR 

## B AILEY 

## U NIT 

## 1 AND 

## M C 

## C LELLAN 

## U NIT 

## 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 NO
x at Bailey Unit 1 and McClellan Unit 1.

The cost effectiveness of all the NO
x controls evaluated for both the boilers is excessively cost prohibitive

at over $100 ,000 per ton of NO
x reduced for LNB/OFA at Bailey Unit 1 and over $16 ,000 per ton of NO
x reduced for LNB/OFA at McClellan Unit 1. In addition, the cost eff ectiveness is up to $ 97 ,0 0 0 per ton for the other controls. Based on the relatively low NO
x emissions from the boilers as compared to SO 2 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

. Thu s there are no changes or add

- on controls proposed as BART for NO
x Bailey Unit 1 or McClellan Unit 1.Arkansas Electric Cooperative Corporation 1

- 20 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellanArkansas Electric Cooperative Corporation 1

- 21 Trinity Consultants

NO
x BART Analysis

– Bailey and McClellan 

## A PPENDIX 

## A

NO X 

### C ONTROL 

### C OST 

### C ALCUL A TIONSBailey 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

MW 1

Baseline NOx Emission Rate (lb/MMBtu) 2
Max Heat Input (MMBtu/hr) Capital Recovery Factor (CRF)

35.0 000

, 300 75 

    

= A

Z D

C A D E × × = ( ) ( ) 

## [ ] 4.0 05.0 100 / 5.1/ C B Z =

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 ($/yr) G = Annual capacity factor (expressed as a fraction, hours operated divided by 8760) B = Inlet NOx (lb/MMBtu); range of 0.15 - 2.5 lb/MMB tu H = Heat input (MMBtu/hr) C = NOX removal efficiency; range of 80-95% D = Capital cost ($/kW) A = Plant capacity (kW)

Capital Recovery Factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = inter est 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, stat ion 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. 35.0 000

, 300 75 

    

= A

Z D

C A D E × × =

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

## [ ] 4.0 05.0 100 / 5.1/ C B Z =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 Investment 3,4
TCI ($) =19.4 x kW x (300/MW)^0.359 x (CI 2012 /CI 2004 ) $9,287,625 $9,287,625 $9,664,386 $9,664,386

Direct Annual Operating Costs $/yr

Variable O&M Costs 5 =(0.08 mills/kW-hr/1000) x (1 kW-hr/10,000 Btu) x H x C x 10^6 Btu/mmBtu x (CI 2012 /CI 2004 ) $14,655 $14,655 $79,695 $79,695

Indirect Annual Costs, $/yr

1. Fixed O&M Costs 6 = $0.29/kW x Nameplate capacity (MW) x (1000 kW/MW) x (300/MW)^0.359 x (CI 2012 /CI 2004 ) $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 wa s 0.027 mills/kW-hr. This is the rate listed inTab le 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 ra nge 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 Em issions from Coal-fired EGUs in the WRAP Region Sep tember 6, 2005. Section 4.3 and Appendix D. A cost method de veloped for coal-fired EGUs was utilized for the co mbination natural gas or residual oil-fired boilers being addressed by this report, since the number of EGUs of similar si ze 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 cap acity 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 costCapital Costs

Technology
SNCR

Parameters/Costs Equation Bailey Natural Gas Bailey Fuel Oil #6 McClellan Natur al Gas McClellan Fuel Oil #6 Boiler design capacity, mmBtu/hr (Q B ) Q B 1350 1350 1436 1436 3-yr Average operating time (t op , hrs/yr) t op = CF total × 8760 hrs/yr 1015 1015 5190 5190 Total Capacity Factor (CF total ) CF total = CF plant × CF SNCR 0.12 0.12 0.59 0.59
Plant Capacity Factor (CF plant ) 2 0.12 0.12 0.59 0.59
SNCR Capacity Factor (CF SCNR ) 3 CF SNCR = t SNCR /365 1 1 1 1
Assumed NOx removal efficiency ( η NOx ) 4 57.5% 52.5% 57.5% 52.5%
Uncontrolled NOx rate (NOx in, lb/MMBtu) 5 0.293 0.301 0.306 0.497
Electricity Cost (Cost elect , $/kwh) 6 $0.05 $0.05 $0.05 $0.05

Water Cost (Cost water , $/gal) 7 $0.00362 $0.00362 $0.00362 $0.00362
Fuel Cost (Cost

fuell , $/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 = inter est rate, a = equipment life 0.08 0.08 0.08 0.08 a. Equipment CRF, 30-yr life, 7% interest

Cost Index 10
a. January 2012 Cost Index 593.6
b. 1998 Cost Index 389.5 Capital Costs Direct Capital Cost (A) DC ($) = ($950/MMBtu) × Q B × ((2375 MMBtu/hr/Q B )^0.577) × (0.66 + 0.85 η NOx ) × (CI 2011 /CI 1998 ) $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 Faci lities Cost + Engineering and Home Office Fees + Pr ocess 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 = Vol reagent (gal) × Cost

reagent ($/gal) $41,218 $34,789 $44,743 $48,160

Cost reag , 50% Urea solution ($/gal) 12 1.54 1.54 1.54 1.54 Volume of Reagent Tank (Vol reagent (gal)) Vol reagent (gal) = q sol x days of reagent supply × 24 hr/day 26,765 22,590 29 ,054 31,273
Urea solution volumetric flow rate (q sol , gal/hr) 13 q sol = (m sol x 7.481 gal/ft 3 )/ ρ reagent 79.66 67.23 86.47 93.07
Mass flow rate of urea solution (m sol , lb/hr) 14 m sol = m reagent /C ureasol 756.02 638.09 820.66 883.34
Mass flow rate of reagent (m reagent , lb/hr) 15 m reagent = (NOx in x Q B x η NOx

× NSR x M reagent )/(M NOx x SR T ) 378.01 319.05 410.33 441.67 Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOx in + 0.7] × η NOx )/NOx in 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 = q sol × Cost reag × t op $124,563 $105,134 $691,095 $743,876 Annual Electricity Cost (L) L = P × Cost elect × t op $2,507 $2,318 $13,911 $16,400 Power (P, kW) P = (0.47 × NOx in × NSR × Q B )/9.5 49.39 45.65 53.61 63.20 Annual Water Cost (M) M = q water × Cost water × t op $1,332 $1,124 $7,390 $7,955
Water flowrate for SNCR system (q water , gal/hr) 16 q water = (m sol / ρ water ) × [(C ureasolstored /C ureasolinj ) - 1] 362.38 305.86 393.37 423.41

Annual ∆ Fuel Cost (N) N = ∆ Fuel × Cost fuel × t op $19,239 $12,285 $102,931 $105,897
Additional fuel required ( ∆ Fuel, MMBtu/hr) 17 ∆ Fuel= (Hv × m reagent × [(1/C ureasolinj ) - 1])/10 6 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 2 002)

2 Plant capacity factor from "Inputs' tab

3 t SCNR assumed to be 365 days

4 η NOx (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 C learinghouse, http://www.arkansasiec.org/newsmanage r/templates/?a=71&z=1

7 Water cost estimate from Bentonville, AR commercia l rate of $0.00362/gal, http://www.bentonvillear.co m/utbc_rates.html

8 Update with source of natural gas and fuel oil cost s

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 ρ reagent = 71.0 lb/ft 3

14 C ureasol = urea solution concentration = 50% Selective Non-Catalytic Reduction Capital and O&M C ost Estimate 1

12 Five-yr average urea cost = $356.11/metric ton, fro m 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, C ureasolstored = 50% Concentration of urea injected into SNCR system , C ureasolinj = 10% From EPA APCCM, 2002 15 M reagent = 60.6 g/mol (molecular weight of urea)

M NOx = 46.01 g/mol (molecular weight of NO 2 ) SRT = 2 (ratio of equivalent moles NH 3 per mole of urea) 9 Fuel heat content from 'Inputs' tab Density of natural gas = 0.056 lb/scf (http://www.e ngineeringtoolbox.com/gas-density-d_158.html), Spec ific gravity of fuel oil = 0.92, which gives a dens ity of 7.67 lb/gal (http://www.hess.com/ehs/msds/99 07no6fueloil.pdf)