## BART F IVE 

## F ACTOR 

## A NALYSIS



## – NO X 

## A NALYSIS


## A DDENDUM TO THE 

## J ULY 

## 24, 2012 BART F IVE 

## F ACTOR 

## 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

April 2013 Addendum to the July 24, 2012 BART Five Factor Analysis Version 1

### Arkansas 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 I NTRODUCTION 

### ..................................................................................................... 1-3 1.2 C ROSS 

### -S TATE 

### A IR 

### P OLLUTION 

### R ULE AND 

### BART ................................................. 1-3 1.3 I DENTIFICATION 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 ......................................................................... 1-4 1.4 E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### NO X 

### C ONTROL 

### T ECHNOLOGIES 

### ............... 1-5 1.4.1 C OMBUSTION 

### C ONTROLS 

### .................................................................................... 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 NO X 

### Burners ................................................................................ 1-6 1.4.2 P OST 

### C OMBUSTION 

### C ONTROLS 

### ........................................................................... 1-6 1.4.2.1 Selective Catalytic Reduction .............................................................. 1-6 1.4.2.2 Selective Non-Cataly tic Reduction ...................................................... 1-7 

### 1.5 R ANK OF 

### T ECHNICALLY FEASIBLE 

### NO X 

### C ONTROL 

### O PTIONS BY 

### E FFECTIVENESS 

### .. 1-7 1.6 E VALUATION OF 

### I MPACTS FOR 

### F EASIBLE 

### NO X 

### C ONTROLS 

### ................................... 1-8 1.6.1 C OST OF 

### C OMPLIANCE 

### ........................................................................................ 1-9 1.6.2 E NERGY 

### I MPACTS 

### & N ON 

### -A IR 

### I MPACTS 

### .......................................................... 1-13 1.6.3 R EMAINING 

### U SEFUL 

### L IFE 

### ................................................................................. 1-13 

### 1.7 E VALUATION OF 

### V ISIBILITY 

### I MPACT OF 

### F EASIBLE 

### NO X 

### C ONTROLS 

### ................... 1-13 1.8 P ROPOSED 

### B ART FOR 

### NO X FOR 

### B AILEY 

### U NIT 

### 1 AND 

### M C 

### C LELLAN 

### U NIT 

### 1 ......... 1-21

A PPENDIX 

### A ............................................................................................................................. 22

A PPENDIX 

### B ............................................................................................................................. 23

A PPENDIX 

### C ............................................................................................................................. 25

### 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 

### 1-8

TABLE 

### 1-3. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### B AILEY 

### U NIT 

### 1 NO X 

### C ONTROLS 

### ................... 1-12

TABLE 

### 1-4. S UMMARY OF 

### C OST 

### E FFECTIVENESS FOR 

### M C 

### C LELLAN 

### U NIT 

### 1 NO X 

### C ONTROLS 

### ........... 1-12

T ABLE 

### 1-5. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### C OMBUSTION 

### C ONTROLS FOR 

### NO X 

### C ONTROL 

### ...................................................................................................................... 1-15

T ABLE 

### 1-6. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### SCR FOR 

### NO X 

### C ONTROL 

### ....... 1-15

T ABLE 

### 1-7. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### C OMBUSTION 

### C ONTROLS 

### + SNCR FOR 

### NO X 

### C ONTROL 

### ................................................................................................... 1-15

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 

### .............................................................................. 1-17

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 

### ..................................................................... 1-18

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 

### ..................................................................... 1-19

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 

### ............................................................. 1-20

### Arkansas Electric Cooperative Corporation 1-3 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

## 1. NO X 

## BART E VALUATION



## 1.1 I NTRODUCTION
This report is an addendum to “BART Five-Factor Analysis” submitted to ADEQ on July 24, 2012 for the Bailey and McClellan Gene rating Stations. The original submittal included analyses for SO 2 

### and PM but not NO X 

### . This addendum is the analysis for NO X 

### for the two plants. All information in Section 2 “Introduction and Background” of the original an alysis is relevant to this analysis. As in the original submittal, it is proposed to burn natura l 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 NO X 

### control systems summarized in Tables 1-8 through 1-11, when burning na tural gas there are zero days of greater than 0.5 deciviews for Bailey and only three days of gr eater 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 SO 2 

### emissions. These impacts will be mitigated by AECC switching to a lower sulfur fuel oil as de termined in the analysis for SO 2 

### submitted in the July 24, 2012 report. 1



### Based on the information listed above, it seems unwar ranted to require ratepayers to fund the installation of any physical NOx c ontrols on either of these units wh en 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 lo ad 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 tim e 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 effectiv eness values will be even higher).



## 1.2 C ROSS 

## -S TATE 

## A IR 

## P OLLUTION 

## R ULE AND 

## BART

On June 7, 2012 EPA published a final rule allo wing states participating in the Cross-State Air Pollution Rule (CSAPR) trading program to use CS APR 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 NO x 

### 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)

### Arkansas Electric Cooperative Corporation 1-4 Trinity Consultants NO x 

### 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 determ ination, AECC has conducted a full five factor analysis to determine BART for NO x 

### for Bailey Unit 1 and McClellan Unit 1.



## 1.3 I DENTIFICATION 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 temperatur es. The origin 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. Nitrogen 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 and combustion fl ame 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 pr oduced by burners in the wall-fired boilers. Tangentially fired boilers typi cally have lower uncontrolled NO x 

### emissions than wall-fired boilers. Therefore baseline NO x 

### 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 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 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 NO x 

### Burners (LNB), reduce the peak flame te mperature and excess air in the furnace which minimizes NO x 

### formation. Post-combustion controls, su ch 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)

### Arkansas Electric Cooperative Corporation 1-5 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan



## 1.4 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 combina tion of literature control ranges and efficiencies.



### 1.4.1 C OMBUSTION 

### C ONTROLS



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

### This control is a technically feasible option for the control of NO x 

### from Bailey Unit 1 and McClellan Unit 1.



### 1.4.1.2 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 

### is most likely to be formed. OFA as a single NO x 

### control technique results in estimated NO x 

### emissions rate from gas and oil fired boilers of 0.2-0.3 lb/MMBtu. 4



### In discussions with consultants who ha ve 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 NO x 

### 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 Me nu of Options.” Utility Boil er section. July 1994. 4 Ibid.

### Arkansas Electric Cooperative Corporation 1-6 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

### 1.4.1.3 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. 5 

### 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 st aged fuel-rich conditions, low oxygen levels limit flame temperatures resulting in less NO x 

### formation. The primary zone is then followed by a secondary zo ne 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. LNB systems are technically feasible for the control of NO x 

### from Bailey Unit 1 and McClellan Unit 1.

When combined with OFA, the estimated NO x 

### 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 ra te of 0.15 lb/MMBtu, is evaluated in the remaining steps of this analysis.



### 1.4.2 P OST 

### C OMBUSTION 

### C ONTROLS



### 1.4.2.1 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 enhan ces the reaction 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 effectiveness 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. 8 

### This control is a technically feasible option for the control of NO x 

### from Bailey Unit 1 and McClellan Unit 1.

5 http://www.energysolutionscenter.org/boi lerburner/Workshop/RCTCombustion.htm. 6 “Controlling Nitrogen Oxides Under the Clean Air Act: A Me nu of Options.” Utility Boil er section. July 1994. 7 Based on a first-cut budgetary planning estimate provi ded by Babcock Power Services on February 28, 2013. 8 “Preferred and Alternative Methods of Estimate Air Emissions from Boilers.” Janua ry 2010. Table 2.2-2

### Arkansas Electric Cooperative Corporation 1-7 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

### 1.4.2.2 S ELECTIVE 

### N ON 

### -C ATALYTIC 

### R EDUCTION


### In SNCR systems, a reagent is injected in to 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 ty pical SNCR system consists of reagent storage, multi-level reagent-injecti on 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 NO x 

### reductions. When combined with combustion controls the estimated NO x 

### 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 NO x 

### from Bailey Unit 1 and McClellan Unit 1.



## 1.5 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 th e control levels for the controls listed in the previous section for Bailey Unit 1 and McClellan Unit 1.

9 Ibid.

### Arkansas Electric Cooperative Corporation 1-8 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



## 1.6 E VALUATION OF 

## I MPACTS FOR 

## F EASIBLE 

## NO X 

## C ONTROLS
Step four for the BART analysis is the impact an alysis. 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

### Arkansas Electric Cooperative Corporation 1-9 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

### 1.6.1 C OST OF 

### C OMPLIANCE


### 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 w ith 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 w as 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 Cont rol Cost Manual. The capital costs were annualized over a 30-year period and then adde d 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 cont rolled annual emission rate from the baseline annual emission rate.

In order to be consistent with the previously submitted SO 2 

### 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 aver age heat content of the fuel during that same time.

The baseline annual emission ra tes 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 ach ievable 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 gene ration units than were ow ned 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.

### Arkansas Electric Cooperative Corporation 1-10 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan natural gas are based on the average na tural gas usage for each unit from 2007 -2011 multiplied by the average heat content of natura l gas for the same time period. The baseline heat inputs for fuel oil are based on the av erage fuel oil usage for each unit from 2007- 2011 multiplied by the average heat content of fu el oil for the same time period. The data used to determine the baseline h eat 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 SO 2 

### and PM analysis.

Cost Effectiveness The cost effectiveness in dollars per ton of NO x 

### 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 contro ls + 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 fo r all types of boilers other than cyclone boilers, combustion control technology is generally more cost-effective than postcombustion controls. EPA estimates that a pproximately 75 percent of the BART units (non-cyclone) could meet 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. 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 NO x 

### removed. 12



### Table 1-3 and Table 1-4 indicate that the cost effectiveness of combustion controls at a NO x 

### level of 0.15 lb/MMBtu is a pproximately $37,000 per ton of NO x 

### removed for Bailey Unit 1 and $6,300 per ton of NO x 

### removed for McClellan Unit 1. Table 1-3 also indicates that the incremental costs over combustion cont rols at Bailey Unit 1 is nearly $87,000 per ton of NO x 

### removed for combustion controls + SNCR and over $40,000/ton for SCR. Table 1-4 shows that the incremental costs ove r combustion controls at McClellan Unit 1 is over $32,000 per ton of NO x 

### 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 fu ture 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 ope rate 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 fe w 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 Guid elines for Best Available Retrofit Technology (BART Determinations; Final Rule.” CFR Vol. 77, No. 1 28. Wednesday, July 6, 2005, Rule s and Regulations. Pages 39134-39135. 12 Ibid.

### Arkansas Electric Cooperative Corporation 1-11 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan be needed for transmission reliability purposes; ther efore, operation will be greatly reduced. Lower operation equates to lower annual emissions which eq uates to a worse cost effectiveness for control additions.Arkansas Electric Cooperative Corporation 1-12 Trinity ConsultantsNOxBART Analysis – Bailey and McClellanTABLE1-3.SUMMARY OFCOSTEFFECTIVENESS FORBAILEYUNIT1NOXCONTROLSTABLE1-4.SUMMARY OFCOSTEFFECTIVENESS FORMCCLELLANUNIT1NOXCONTROLS

### Arkansas Electric Cooperative Corporation 1-13 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

### 1.6.2 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 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. A mmonia slip from SCR and SNCR systems occurs either 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 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 impa cts associated with the use of LNB, OFA, or FGR.



### 1.6.3 R EMAINING 

### U SEFUL 

### L IFE


### 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 capita l cost recovery period, which is 30 years.



## 1.7 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 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 combus tion controls, SCR and SNCR systems, the NO x 

### emission rates associated with the control systems were modeled using CALPUFF. The controlled emission level associated with SCR systems at Ba iley Unit 1 is 0.04 lb/MMB tu for natural gas and 0.08 lb/MMBtu for fuel oil, while the emission leve l 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 natura l 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. Co ntrol 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 de rive the hourly emission rates used in the modeling.

### Arkansas Electric Cooperative Corporation 1-14 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 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.

### Arkansas Electric Cooperative Corporation 1-15 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 

### C OMBUSTION 

### C ONTROLS
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 0.5 202.5 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



### 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 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



### T ABLE 

### 1-7. S UMMARY OF 

### E MISSION 

### R ATES 

### M ODELED TO 

### R EFLECT 

### C OMBUSTION 

### C ONTROLS 

### + 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 0.5 162.9 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 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 

### percentile modeled visibility impact, and the number of days with a modeled visibility impact greater than 0.5 Δ dv. The visibility improvement shown in the table was calculated as the difference between the existing

### Arkansas Electric Cooperative Corporation 1-16 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan visibility impairment and the visibility impairment associated with a retrofitted system with the specific control as measured by the 98 th 

### percentile.Arkansas Electric Cooperative Corporation 1-17 Trinity ConsultantsNOxBART Analysis – Bailey and McClellanTABLE1-8.SUMMARY OFVISIBILITYIMPROVEMENTASSOCIATED WITHNOXCONTROLSYSTEM ONBAILEYUNIT1(2001-2003)–FUELOILCaney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement*Baseline Emission Rate0.969 0.330 8 - 0.695 0.347 7 - 0.686 0.367 6 - 1.589 0.378 12 -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 0.369 8 2.38%SCR 0.896 0.323 6 2.12% 0.660 0.325 6 6.34% 0.614 0.325 4 11.44% 1.325 0.364 8 3.70%Combustion Controls +SNCR0.910 0.325 6 1.52% 0.667 0.329 6 5.19% 0.618 0.333 5 9.26% 1.377 0.367 8 2.91%*Improvement is based on the 98thpercentile impact (Δdv) compared to the baseline impact (Δdv)†The visibility improvement shown in the table has been calculated from 98thpercentile baseline and controlled impactsthat include more decimal places thanwhat is shown in the table. Due to rounding of the baseline and controlled 98thpercentile impacts shown in the table, the visibility improvement calculated fromthe baseline and controlled 98thpercentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.Arkansas Electric Cooperative Corporation 1-18 Trinity ConsultantsNOxBART Analysis – Bailey and McClellanTABLE1-9.SUMMARY OFVISIBILITYIMPROVEMENTASSOCIATED WITHNOXCONTROLSYSTEM ONBAILEYUNIT1(2001-2003)–NATURALGASCaney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement*Baseline Emission Rate0.219 0.083 0 - 0.170 0.072 0 - 0.238 0.073 0 - 0.443 0.102 0 -Combustion Controls 0.104 0.039 0 53.01% 0.080 0.034 0 52.78% 0.115 0.035 0 52.05% 0.208 0.051 0 50.00%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%Combustion Controls +SNCR0.086 0.032 0 61.45% 0.066 0.028 0 61.11% 0.095 0.029 0 60.27% 0.169 0.043 0 57.84%*Improvement is based on the 98thpercentile impact (Δdv) compared to the baseline impact (Δdv)†The visibility improvement shown in the table has been calculated from 98thpercentile baseline and controlled impactsthat include more decimal places thanwhat is shown in the table. Due to rounding of the baseline and controlled 98thpercentile impacts shown in the table, the visibility improvement calculated fromthe baseline and controlled 98thpercentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.†Note that the “Visibility Improvements” listed in this table are percent improvements of zero visibility impact contributions.Arkansas Electric Cooperative Corporation 1-19 Trinity ConsultantsNOxBART Analysis – Bailey and McClellanTABLE1-10.SUMMARY OFVISIBILITYIMPROVEMENTASSOCIATED WITHNOXCONTROLSYSTEM ONMCCLELLANUNIT1(2001-2003)–FUELOILCaney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement*Baseline Emission Rate3.007 0.621 22 - 1.319 0.266 5 - 0.660 0.230 2 - 0.546 0.227 2 -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 0.203 0 10.57%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%Combustion Controls +SNCR2.594 0.542 18 12.72% 1.090 0.264 3 0.75% 0.646 0.203 1 11.74% 0.471 0.200 0 11.89%*Improvement is based on the 98thpercentile impact (Δdv) compared to the baseline impact (Δdv)†The visibility improvement shown in the table has been calculated from 98thpercentile baseline and controlled impactsthat include more decimal places thanwhat is shown in the table. Due to rounding of the baseline and controlled 98thpercentile impacts shown in the table, the visibility improvement calculated fromthe baseline and controlled 98thpercentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.Arkansas Electric Cooperative Corporation 1-20 Trinity ConsultantsNOxBART Analysis – Bailey and McClellanTABLE1-11.SUMMARY OFVISIBILITYIMPROVEMENTASSOCIATED WITHNOXCONTROLSYSTEM ONMCCLELLANUNIT1(2001-2003)–NATURALGASCaney Creek Wilderness Upper Buffalo Wilderness Hercules Glades Wilderness Mingo NWR

Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement* Maximum Impact ( Δ dv) 98% Impact ( Δ dv) # Days > 0.5 Δ dv Visibility Improvement*Baseline Emission Rate0.670 0.125 3 - 0.258 0.052 0 - 0.092 0.040 0 - 0.132 0.058 0 -Combustion Controls 0.356 0.068 0 45.60% 0.136 0.028 0 46.15% 0.048 0.021 0 47.50% 0.070 0.031 0 46.55%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%Combustion Controls +SNCR0.289 0.056 0 55.20% 0.110 0.023 0 55.77% 0.039 0.018 0 55.00% 0.056 0.026 0 55.17%*Improvement is based on the 98thpercentile impact (Δdv) compared to the baseline impact (Δdv)†The visibility improvement shown in the table has been calculated from 98thpercentile baseline and controlled impactsthat include more decimal places thanwhat is shown in the table. Due to rounding of the baseline and controlled 98thpercentile impacts shown in the table, the visibility improvement calculated fromthe baseline and controlled 98thpercentile impacts shown in the table may be slightly different than the visibility improvement reflected in the table.†Note that the “Visibility Improvements” listed in this table are percent improvements for essentially zero visibility impact contributions (except for only threedays of alleged visibility impact contributions to the Caney Creek Wilderness).

### Arkansas Electric Cooperative Corporation 1-21 Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan The operation of combustion controls r esults in an estimated 0.005 to 0.028 Δ dv improvement (1.52-7.63 percent) of the 98 th 

### 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 Δ dv 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 Δ dv improvement (0.75 to 10.79 percent) of the 98 th 

### 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 Δ dv improvement (45.60-47.50 percent) in th e natural gas scenario.

Further, the operation of SCR systems results in an estimated 0.007 to 0.042 and 0.059 to 0.081 Δ dv improvement (2.12 to 11.44 percent and 79.41 to 83.13 percent) of the 98 th 

### percentile visibility impairment attributable to Bailey Unit 1 at the m odeled 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 Δ dv improvement (1.52 to 9.26 and 57.84 to 61.45 percent) of the 98 th 

### 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 Δ dv improvement (0.75 to 11.76 and 76.92 to 79.31 percent) of the 98 th 

### 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 Δ dv improvement 0.75 to 12.72 and 55.00 to 55.77 percent) of the 98 th 

### percentile from fuel oil and natural gas, respectively.



## 1.8 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, AE CC will rely on CSAPR to satisfy its regional haze obligations at Bailey Unit 1 and Mc Clellan 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 bo ilers is excessively cost prohibitive at nearly $37,000 per ton of NO x 

### reduced for combustion controls at Bailey Unit 1 and over $6,000 per ton of NO x 

### reduced for combustion controls at McClellan Un it 1. In addition, the cost effectiveness is up to $49,000 per ton for the other cont rols. 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 0.067 Δ dv for the most “cost effective” control in the la rgest impacted area), none of the controls are determined to satisfy BART. Thus there are no ch anges or add-on controls proposed as BART for NO x 

### Bailey Unit 1 or McClellan Unit 1.

Also, as previously discussed, the cost effectiveness for these units is exp ected to be worse for both units in future years because of decreased annual operation.

### Arkansas Electric Cooperative Corporation Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

## A PPENDIX 

## A

NO X 

### C ONTROL 

### C OST 

### C ALCULATIONSBailey 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 Cos t ($) $11,909,536 $11,708,183 $12,790,607 $12,675,562 (D) ($/kW) 98 96 94 93 Annualized Capital Cos t ($/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 Cos t ($/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)

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 ($/yr) G = Annual capacity factor (expressed as a fraction, hours operated divided by 8760) B = Inlet NOx (lb/MMBtu); range of 0.15 - 2.5 lb/MMBtu H = Heat input (MMBtu/hr) C = NOX removal efficiency; range of 80-95% D = Capital cost ($/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 lif e CRF = 0.08 a. Equipment CRF, 30-yr life, 7% interes t

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, Octobe r 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/Cost s Equatio n 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 Investment 3,4 TCI ($) =19.4 x kW x (300/MW)^0.359 x (CI 2012 /CI 2004 ) $7,700,000 $7,700,000 $7,400,000 $7,400,000

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 ) $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 Cost s $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 Analysi s 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 o f the ERG Analysis. Source: All costs were estimated using ERG, 2005. Analysis of Combustion Controls for Reducing NOx Emissions from Coal-fired E GUs 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 ex pected 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 s ell but rather are good approximations that require further refinements before purchase. LNB/OFA Capital and O&M Cost EstimateCapital 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 (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 p lant × CF SNC R 0.12 0.12 0.59 0.59 Plant Capacity Factor (CF p lant ) 2 0.12 0.12 0.59 0.59 SNCR Capacity Factor (CF SCN R ) 3 CF SNCR = t SNC R /365 1 1 1 1 Assumed NOx removal efficiency ( η NO x

) 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 wate r , $/gal) 7 $0.00362 $0.00362 $0.00362 $0.00362 Fuel Cost (Cost fuell , $/MMBtu) 8 $6.19 $4.68 $5.97 $5.70 Fuel Heat Content (Btu/lb) 9 18,054 20,209 18,054 20,209 Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment life 0.08 0.08 0.08 0.08 a. Equipment CRF, 30-yr life, 7% interest
Cost Index 10 a. January 2012 Cost Index 593.6 b. 1998 Cost Index 389.5 Capital Costs Direct Capital Cost (A) DC ($) = ($950/MMBtu) × Q B × ((2375 MMBtu/hr/Q B )^0.577) × (0.66 + 0.85 η NO x ) × (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 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 = Vol reagen t

(gal) × Cost reagen t

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

Cost

rea g , 50% Urea solution ($/gal) 12 1.54 1.54 1.54 1.54 Volume of Reagent Tank (Vol reagen t

(gal)) Vol reagen t

(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 reagen t 79.66 67.23 86.47 93.07 Mass flow rate of urea solution (m sol , lb/hr) 14 m sol = m reagen t /C ureasol 756.02 638.09 820.66 883.34 Mass flow rate of reagent (m reagen t , lb/hr) 15 m reagen t = (NOx in x Q B x η NO x × NSR x M reagen t )/(M NO x x SR T ) 378.01 319.05 410.33 441.67 Normalized Stoichiometric Ratio (NSR) NSR = ([2 × NOx in + 0.7] × η NO x )/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 rea g × 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 wate r × Cost wate r × t op $1,332 $1,124 $7,390 $7,955 Water flowrate for SNCR system (q wate r , gal/hr) 16 q wate r = (m sol / ρ wate r ) × [(C ureasolstored /C ureasolinj ) - 1] 362.38 305.86 393.37 423.41
Annual Δ Fuel Cost (N) N = Δ Fuel × Cost fuel × t op $19,239 $12,285 $102,931 $105,897 Additional fuel required ( Δ Fuel, MMBtu/hr) 17 Δ Fuel= (Hv × m reagen t × [(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 2002)

2 Plant capacity factor from "Inputs' tab

3 t SCN R 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 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 ρ reagen t = 71.0 lb/ft 3

14 C ureasol = 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, 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.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 Estimate 1

### Arkansas Electric Cooperative Corporation Trinity Consultants NO x 

### BART Analysis – Bailey and McClellan 

## A PPENDIX 

## B

A DDITIONAL 

### D ATA

### Arkansas Electric Cooperative Corporation Trinity Consultants NO x 

### 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 NO x 

### BART Analysis – Bailey and McClellan 

## A PPENDIX 

## C

V ENDOR 

### E STIMATES FOR 

### C OMBUSTION 

### C ONTROLS

### 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: A ECC Baile y & 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: A ECC Baile y & 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 1Total 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 N eponset 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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