October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034--500

Appendix A 

NOx BART Review for the Mohave Generating Station 
NOx BART REVIEW 

For 

MOHAVE 

GENERATING STATION 

UNITS 1&2 

CLARK COUNTY, NEVADA 

Date Issued: July 28, 2008 
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential 7/28/08 

©2008 Babcock Power Inc. All Rights Reserved

 

This document was prepared solely for use by, and solely for the benefit of Navasota Energy 

for the purpose of supporting the BART analysis for the Mohave Generating Station. Any 

other recipient of this document uses it without the permission of Riley Power and thereby 

releases Riley Power from liability of any kind. Riley Power has taken certain steps to 

evaluate possible changes to the Mohave Generating Station, but the information herein is not 

intended as a design, nor even a basis for design. Riley Power expressly disclaims any 

warranty, expressed or implied, with respect to use of the information or concepts disclosed in 

this document for any purpose other than that set out in the underlying contract between Riley 

Power and Navasota Energy. 
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APPENDIX A: 

Babcock Power Inc. NOx BART Review 

for the Mohave Generating Station
Mohave Generating Station U 1&2 

Clark County, NV 

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1.0 EXECUTIVE SUMMARY

1.1 OBJECTIVE 

Evaluate the Mohave Generating Station options to reduce NOx emissions. 

The predicted NOx values in this report will be used for the preparation of the 

BART evaluation. 

1.2 FINDINGS 

The evaluation of the boiler emissions profiles in this report are based on the 

future predicted operating conditions as shown in Table A-1. 

Table A-1 – Predicted Operating Conditions 

 Natural Gas Firing 

Predicted operation

Natural Gas Firing 

Max. operation 

Fuel Flow Rate 7,163,100 SCFH 7,635,659 SCFH 

Fuel HHV 1032 Btu/ft3 1032 Btu/ft3 

Heat Input (per boiler) M Btu/hr 7,392.3 7,880.0 

 

Flue Gas Flow 

(from combustion) Lb/hr 6,049,300 6,448,300 

Air Heater Leakage (12%) Lb/hr 725,916 773,796 

Flue Gas Flow to Stack Lb/hr 6,775,216 7222,096 

FG Temp. Leaving AH oF 252 252 

FG Temp. Leaving AH K 395.4 395.4 

FG Density (@ temp above) Lb/ft3 0.053 0.053 

Flue Gas Flow Rate 

(to stack per boiler) ACFM 2,130,570 2,271,100 

Total Flue Gas Flow Rate 

(to stack – both boilers) ACFM 4,261,140 4,542,200 

 

Stack Height ft (m) 500 (152.4) 

Base Site Elevation ft (m) 712 (217) 

Stack Diameter ft (m) 32.5 (9.91) 

Flow Area ft2 (m2) 829.6 (77.1) 

Flue Gas Exit Velocity ft/s (m/s) 85.6 (26.1) 91.3 (27.8) 

Utility boilers firing fossil fuels have generally employed two techniques for 

reducing NOx emissions including modifications to the combustion system 

and the use of chemical reagents. These methods of NOx control can be used 

in combination to help further reduce NOx emissions. Each of the different 
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emissions controls has inherent advantages and disadvantages that can be 

compared and evaluated. The three areas that are usually compared and 

evaluated include: level of NOx reduction, initial “Capital” costs, and annual 

operating costs. 

Modifications to the combustion system are designed to reduce the 

temperature of the combustion zone thereby reducing the thermal NOx. 

Typical modifications to the combustion system include: 

o Low excess air operation 

 The typical excess air design range for natural gas is 8-12%. 

 Operating at lower excess airs works to reduce the flame 

temperatures thereby reducing thermal NOx. 

 Low excess air operation can be done in conjunction with low 

NOx burner modifications and is typically achieved through 

testing and tuning of the combustion system 

 Low excess air levels can result in an increase in CO emissions 

o Operating with Burners out of service 

 Operating with burners out of service is a method of staging 

the combustion zone with out overfire air ports. 

 This method controls thermal NOx by reducing flame 

temperatures. 

 Minimal capitol cost to upgrade the combustion control 

system. 

o Low NOx burners 

 Reduces the NOx emissions by controlling the mixing of fuel 

and air during combustion. 

 Low NOx burners reduce flame temperatures thereby reducing 

the production of thermal NOx 

 Low NOx burners can be used with Overfire air to achieve 

further staging of the combustion zone and further NOx 

reduction. 

 Low NOx burners can also be used in conjunction with Flue 

Gas Recirculation. 

 Low NOx burners alone are the base case for NOx emissions. 

o Overfire air 

 Overfire air ports divert some of the combustion air away from 

the burners (primary combustion zone) to lower the 

combustion temperatures and therefore NOx emissions

 Overfire air ports are typically located above the top row of 

burners. 

 This technology can be used with other NOx control 

techniques such as Low NOx burners and Flue Gas 

Recirculation. 
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 Minimal impact on boiler performance and operation (i.e. 

minimal increase in CO emissions and opacity) 

 Modifications include the addition of ductwork, air registers, 

airflow measurement, and boiler wall openings. 

o Flue gas recirculation 

 Flue gas from the outlet of the boiler is mixed with the 

combustion air to the burners. 

 Reduces the combustion temperatures to achieve a reduction in 

NOx. 

 Increases the flue gas flow through the convective pass of the 

boiler thereby increasing heat transfer. 

 Retrofitting the boiler with this system involves new fans, 

ductwork and dampers, control system, flow measurement and 

a mixing device. 

 Increase in plant operating cost as a result of the FGR fan 

motor power absorption. 

The second method of NOx control is performed after combustion has taken 

place and NOx molecules have been formed. NOx reduction in this case is 

achieved by the use of chemical reaction between the NOx in the flue gas and 

ammonia. There are two methods that are used to initiate the chemical 

reaction: 

o Selective Non-Catalytic Reduction (SNCR) 

 Ammonia or Urea is injected into the flue gas to act as the 

chemical reagent in the reaction with NOx. 

 The ammonia or urea is injected in the area were the flue gas is 

in the temperature range of 1600oF to 2200oF. 

 NOx reduction levels is dependent on injection point, residence 

time within the temperature range, and mixing efficiency. 

 NOx reductions are limited on the Mohave Boilers due to 

• Already low levels of NOx 

• Physical size of the boiler 

• CO levels entering the SNCR zone 

• Temperature profiles in the boiler 

• Low residence times 

 Ammonia slip of 6 ppmv dry corrected to 3% oxygen 

 Modifications include: 

• A reagent transfer, storage and pumping station 

• Reagent transport system (Pumps, flow meters, heaters) 

• Control system 

• Injection equipment including furnace penetrations 

o Selective Catalytic Reduction (SCR) 

 Lower reaction temperatures then SNCR (600 – 800 oF) 

 The reaction takes place in a bed of catalyst. 
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 Can be designed as either a stand alone reactor vessel or for 

natural gas part of the ductwork (in-duct SCR) 

 NOx emissions reduction of 90% with an ammonia slip of 2 

ppm. 

 The addition of a SCR system involves the following

modifications and additional equipment: 

• Reagent (ammonia or urea) transfer, storage and 

pumping station 

• Reagent injection grid and mixing devices 

• SCR system controls for reagent flow, temperature, 

boiler load, NOx emissions monitoring and control, and 

system safety 

• Reactor and catalyst 

• Structural considerations for both the reactor and boiler 

proper 

• FD and ID fan upgrades including their electrical 

system 

• Boiler system upgrades (e.g., implosion study) 

• Economizer modifications if necessary to achieve 

proper reactor temperatures over the boiler load range 

A summary of the BART technology and cost review are presented in Table A-2. A 

detailed discussion of NOx formation and control options is provided in the next 

section. 

Table A-2 MGS BART Technology Options Summary 

 NOx 

Emissions 

(lb/MMBtu)

Capital 

Costs 

(106

 $) 

Operating 

Costs 

(106 $/yr) 

Ammonia 

Slip 

(ppm)* 

LNB + OFA 0.10 8 0 - 

LNB+OFA+FGR 0.07 75-150 4 - 

LNB+OFA+SNCR 0.08 60 7.5 6 

LNB+OFA+SCR (in-line) 0.03 105 – 180 12 2 

LNB+OFA+SCR (stand alone) 0.01 200 12 2 

*ppmv dry corrected to 3% oxygen 
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2.0 DISCUSSION OF NOx FORMATION AND AVAILABLE CONTROLS

2.1 NOx FORMATION 

Oxides of nitrogen (NOx) are formed during the combustion process of natural gas 

via three distinct mechanisms. The first mechanism, called “thermal” NOx, refers to 

the NOx that is formed through the oxidation of nitrogen that is present in the air and 

is supplied to complete the combustion process. Thermal NOx typically represents 

virtually all of the NOx generated during natural gas combustion. The second 

mechanism, called “fuel” NOx, refers to the NOx that is formed through the 

oxidation of the nitrogen that is chemically bound in the fuel itself. There is no 

“fuel” NOx produced during natural gas combustion. The third and final mechanism, 

“prompt” NOx, refers to the NOx that is formed within the flame front from 

hydrocarbon fragments that react with molecular nitrogen. Prompt NOx represents a 

very small amount (approximately 2 – 10 ppm1) of the total NOx emissions generated 

during fuel oil combustion. A review of basic NOx emissions formation during the 

combustion process is important in understanding how NOx control technologies 

described in this report act in reducing NOx emissions, their impact on unit operation. 

This would then allow in the selection of “best available retrofit technology” 

(BART). 

“Thermal” NOx formation has been adequately described by the Zeldovich 

mechanism and it is dependent on temperature, local fuel and oxygen concentrations 

and residence time at the reaction temperature. Molecular nitrogen present in the air 

that is supplied to complete combustion is a fairly inert material, that under high 

temperatures (typically >2800 °F) it dissociates and reacts with oxygen to form 

mainly nitric oxide (NO) and small quantities (<5%) of nitrogen dioxide (NO2). The 

Zeldovich mechanism indicates that the rate of “thermal” NOx formation is 

exponentially proportional to temperature of the reaction and proportional to the local 

oxygen concentration. 

“Fuel” NOx is formed by the direct oxidation of the nitrogen that is organically 

bound in the fuel. It can represent a significant (~ 50%) of the total NOx that is 

formed and emitted during fuel oil combustion even though a small portion of the 

fuel bound nitrogen is converted to NOx. Its rate of formation is not dependent on 

temperature but rather on the oxygen concentration during the early stages of 

combustion but less so to combustion temperatures. 

Since the Mohave units will be converted to natural gas resulting in all of the NOx 

emissions produced are due to “thermal” NOx. 

 

1

 All ppm numbers referred in this report are by volume, dry and corrected to 3% oxygen 
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2.2 NOx EMISSIONS CONTROL 

There are basically two techniques that have been used in reducing and 

controlling NOx emissions generated by utility boilers combusting fossil 

fuels: 

• Modifications to the combustion process 

• Use of chemical reagents to reduce NOx to molecular nitrogen 

Both of these general techniques by themselves or in combination have been used 

throughout the industry with various degrees of success to achieve reductions in 

NOx emissions.

2.2.1 Modifications to the Combustion Process/Optimization 

Over the past forty years it has been shown that modifying or “retrofitting” 

the combustion process through the reduction of oxygen concentrations 

during the initial stages of natural gas combustion, thereby reducing the 

temperatures of combustion, and/or reducing the amount of oxygen that is 

present have resulted in significant reductions in NOx emissions from utility 

boilers. These modifications to the combustion process have included 

changes to the unit’s operation such as low excess air, burners out of service 

(BOOS) and general optimization of the combustion system settings or the 

installation of equipment such as low NOx burners (LNB) and overfire air 

(OFA) ports. 

The Mohave units are tangentially fired supercritical boilers originally 

designed to fire pulverized coal, natural gas or a combination of both to 

achieve full load. Typical emissions from these units averaged 0.4 – 0.5 

lbs/MBtu fired at full load boiler operation on coal. 

2.2.1.1 Low Excess Air Operation 

Operating natural gas fired utility boilers at Low Excess Air (LEA) 

levels is an operational change that has been shown to provide some 

improvement in NOx reductions. This operation provides for a 

reduction in the amount of available oxygen to the combustion zone 

lowering the overall NOx formation stoichiometry and combustion 

temperatures. A natural gas fired boiler would typically operate at 

excess air levels of 8 –12%. This level of operating excess air is 

anticipated for the Mohave units. Further reducing operating excess 

air levels could have negative emission and operating impact by 

increasing the amount of combustible losses (e.g., CO and 

particulates). It is anticipated that the proposed excess air level of 8 – 
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12% provides for the best compromise in terms of emissions and unit 

performance. 

This method of NOx control can be used in conjunction with other 

combustion modifications such as low NOx burners, overfire air and 

flue gas recirculation. An excess air level of 8-12% is recommended 

for the design of the fuel burning equipment and after modifications 

are made the unit may be able to further reduce NOx emissions by 

lowering excess air levels. Testing and tuning of the combustion 

system is typically performed when lowering the excess air. This is 

done while the boiler is on-line so that the overall unit performance 

(i.e. steam temperatures and CO emissions) can be monitored while 

changes are being made. 

2.2.1.2 Burners-Out-of-Service 

Burners-out-of-service (BOOS) is an inexpensive and proven means of 

achieving staged combustion (i.e., the reduction of burner zone 

stoichiometry) and subsequent reduction in NOx emissions, without 

the use of overfire air ports. Staged combustion involves the 

generation of fuel-rich zone during the initial stages of the fuel 

combustion that reduces the oxygen concentration and flame 

temperatures. The remainder of air necessary to complete combustion 

is added downstream through overfire (OFA) ports in another section 

of the furnace (i.e., the “second stage”) resulting in an overall 

reduction of NOx emissions. BOOS eliminate the need of capital and 

installation expenditures of OFA ports. Figure A-1 provides a 

graphical indication of the BOOS concept. 
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Figure A-1 - Typical Burner out of Service (BOOS) arrangement 

BOOS operation is accomplished by eliminating fuel flow to selected 

burner and only providing air through them. Fuel flow to remaining 

burners is increased to maintain the heat input required to produce the 

fuel rich atmosphere required for reducing NOx emissions. The 

BOOS takes the place of OFA ports and assists in completing the 

combustion. This technique has been used extensively through out the 

U.S. on heavy oil and gas fired units over the past 30+ years due to its 

simplicity and low cost and has resulted in significant (25 – 50%) NOx 

reductions. Typically the numbers of burners removed from operation 

in the unit is 20 –25% of the total. Generally removing burners from 

service in the upper rows of the burner array results in the lowest NOx 

emission levels. 

The advantage of the BOOS technique is that it offers significant NOx 

emissions reductions, at minimal capital costs, it can be implemented 

in a short period of time and it is applicable to all types of utility 

boilers. Large site-to-site variations in the effectiveness of the BOOS 

technique have been encountered depending on the unit’s design, and 

burner arrangement (the larger number of burners the larger the NOx 

reduction achieved and design flexibility allowed).

BOOS can be implemented to existing utility boilers without 

significant modifications to the existing combustion equipment or to 

the boiler in general. Typically the modifications required would be to 

upgrade the boiler control system and combustion instrumentation and 

increasing fuel flow to the reduced number of operating burners. 
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The current Mohave units having been designed for pulverized coal 

and natural gas firing lend themselves to BOOS since the existing 

burner corner (tangential) openings are oversized for natural gas. The 

proposed conversion of the units calls for the use of the excess space 

as overfire (OFA) ports for NOx emissions control. 

2.2.1.3 Low NOx Burners (LNB) 

Low NOx burners (LNB) are designed to reduce NOx emissions by 

controlling the mixing of fuel and air during the initial stages of 

combustion. The basic concept that forms the basis of the LNB design 

is to delay the mixing of the fuel and air during the initial stages of the 

combustion process. This delay is achieved through the physical 

separation of some of the air from the fuel, or through aerodynamic 

means by imparting swirl to the air, or both. The production of NOx is 

minimized under these conditions since the availability (concentration) 

of oxygen to react with the liberated organically bound nitrogen is 

minimized (see Figure A-2). 

Figure A-2 - Typical Low NOx Burner Concept 

The Mohave units are tangentially – fired boilers that are characterized 

by their inherent lower NOx emissions when compared to wall – fired 

boilers. Tangentially – fired boilers introduce the fuel and air at the 

corners of the combustion chamber (furnace) in an alternating manner. 

As a result the mixing of fuel and air is delayed resulting in lower 

temperatures and hence lower NOx emissions. It has been shown that 

the most effective way of reducing emissions in these units is to design 

OFA ports that further delay the introduction of air in the combustion 

process further reducing NOx emissions. This is proposed approach 

for the Mohave units. 
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2.2.1.4 Overfire Air (OFA) 

Overfire air (OFA) involves the use of air injection ports above the 

main combustion (burner) zone in the upper furnace to divert a portion 

of the combustion air away from the initial combustion zone (burners). 

Figure A-3 shows a typical OFA system for a utility boiler. 

Figure A-3 - Typical OFA system for a wall-fired utility boiler 

The quantity of air that is diverted to the OFA ports typically varies 

from 5 to 25% with the primary objective being to reduce oxygen 

concentrations and temperatures in the primary combustion zone 

thereby reducing NOx emissions. The air injected through the OFA 

ports assists in completing combustion. This technology has been 

applied to control NOx emissions to power boilers over the past 35+ 

years with success. The technology can be used in combination with 

other NOx control techniques such as low NOx burners (LNB), flue 

gas recirculation (FGR) on several units in the US with success and is 

applicable to all utility boilers with its effect on NOx reductions being 

additive. Its success and applicability depends on boiler design (i.e., 

available boiler height to install the OFA ports and complete 

combustion) and available space to route the combustion air necessary 

for the OFA ports. 

The NOx reduction that has been achieved with OFA ports has ranged 

between 10 to 30% with some units as high as 40% from uncontrolled 

levels. Typical boiler modifications include the addition of new boiler 
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wall openings, and an air register assembly to control mixing and flow 

of the OFA with the furnace gasses. Ductwork that delivers the air 

from its main supply to the OFA ports is also required along with the 

necessary structural supports and thermal expansion joints. Flow 

measurement and control of the air flow to each OFA ports may also 

be required such that OFA flow can be optimized to maximize NOx 

emissions reductions with minimal impact on boiler performance and 

operation (i.e., increased combustibles and opacity). 

The Mohave units will be equipped with OFA ports to provide the 

maximum NOx emissions reduction via retrofit technology resulting in 

anticipated NOx emissions of 0.1 lbs/MBtu when firing natural gas at 

boiler full load. 

2.2.1.5 Flue Gas Recirculation (FGR) 

Flue gas recirculation (FGR) refers to the mixing of the combustion 

products (flue gas) with combustion air to reduce NOx emissions. 

FGR lowers oxygen concentration during the initial stages of 

combustion along with combustion temperature reducing NOx 

emissions. Since flue gas is inert (consists mainly of nitrogen, carbon 

dioxide and water vapor) it is important that the oxygen concentration 

of combustion air/flue gas mixture is kept above 17% (as compared to 

air of 21%) in order to ensure that sufficient oxygen for the 

combustion of natural gas is available. Failure to do so could result in 

unsafe operating conditions. 

The flue gas is typically taken from the outlet of the boiler upstream of 

the air heater and is then mixed with hot combustion air exiting the air 

heater (see Figure A-4 for typical approaches to FGR). 
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Figure A-4 - Typical utility boiler FGR system 

For utility boiler applications the mixture is then transported to the 

burners (windbox) through the existing combustion air ductwork. To 

reduce the cost of application “induced” FGR has also been used. 

During this approach flue gas from the stack is transported to the inlet 

of the forced draft (FD Fan) using the induction force of the FD fan 

itself (see Figure A-5). 

Figure A-5 - Typical Induced FGR system(20) 
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This approach is less expensive since it does not require a dedicated 

FGR fan and mixing device, however is limited to the capability of the 

existing FD Fan and ductwork. 

FGR has been in use for over 30 years on boilers firing natural gas as 

one of the main techniques in reducing NOx emissions. It has been 

and can be retrofitted to most utility heavy boilers although an 

engineering study would need to be performed to establish its 

compatibility with existing boiler and burner designs. The study 

should at a minimum establish burner air/FGR flow requirements, air 

ductwork size and velocities, boiler convective section heat transfer 

impact, existing fan (forced and induced) capacity, and furnace 

pressure limits. 

The NOx reduction levels achieved though the use of FGR in heavy 

oil combustion are primarily dependent on: (1) FGR flow rate, (2) 

excess air levels, (3) burner stoichiometry, and (4) burner/furnace heat 

release rate. In general FGR is effective in reducing the levels of 

“thermal” NOx produced due to its dilution effect on the combustion 

and its reduction of combustion temperatures. Typically the NOx 

reductions that are achieved with the use of FGR range on the order of 

20 – 50% from uncontrolled levels. 

To retrofit FGR in a natural gas fired boiler one would need to 

establish first if the unit has an existing FGR system for controlling 

steam temperatures. If the boiler is equipped with an existing FGR 

system the capability of the existing FGR fan would need to be 

evaluated to establish if it can provide the necessary flows and 

pressures required for NOx control FGR system. If the existing fan is 

not adequate (typically existing FGR fans are not capable) it needs to 

either be upgraded or replaced and the existing motor electrical system 

be upgraded. If the unit does not have an existing FGR fan a new fan 

along with the necessary equipment (transformer, switchgear, etc.) 

will need to be purchased and installed, along with the necessary 

ductwork from the boiler (extraction point), to the fan and then to the 

combustion air duct. Mixing devices to thoroughly mix the gas with 

the air and gas flowing measuring devices will also need to be 

supplied. It is not advisable to mix FGR with the OFA, so if the unit 

is already equipped with OFA a “fresh” air system needs to be 

maintained to supply the OFA. 

FGR can have some significant impacts on boiler operation and its 

implementation needs to follow a careful study. Since it dilutes the 

oxygen content of the combustion air careful consideration should be 
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given to flame (combustion) stability. This is typically done by 

limiting the amount of FGR that is mixed with the combustion air to 

the mixture minimum oxygen content of 17%. 

The addition of FGR increases the total mass flow of the flue gases 

passing the boiler’s convective heat transfer surfaces (i.e., superheater, 

reheater, and economizer). This results in increased heat transfer and 

hence in increased steam and heating surface metal temperatures 

leading to premature failures. This increase in flow is most critical 

during boiler full load operation while at lower loads the increased 

FGR flow could be helpful in meeting steam temperature 

requirements. Careful operation will be required to minimize furnace 

vibrations that are the result of flame instability and the emissions of 

combustibles (CO), opacity and particulates that could result from the 

application of FGR. 

The capital costs of FGR systems are estimated to be in the range of 

$35 - $502

/kW, however if significant upgrades to existing equipment 

are required such as modifications of heating surfaces, FGR fan 

replacement, boiler structural and controls upgrades, these costs could 

be significantly higher. “Induced” FGR implementation has 

significantly lower costs (<$40/kW) due to the elimination of the FGR 

dedicated fan and its ancillary equipment and controls, along with a 

significant reduction in FGR ductwork. 

A review of the Mohave units indicates that the applicability of FGR 

recirculation would provide some reduction in NOx emissions (from 

0.1 to 0.075 lbs/MBtu) however at a high cost of retrofit. Specifically 

the following modifications to the unit will be required: 

• Installation of two FGR recirculation fans per unit

• Installation of required switchgear for the fan motors 

• Flue gas and air mixing devices 

• Removal/addition of convective section surface 

• Upgrade of furnace materials 

• Modifications to unit’s control system 

• Addition of “fresh” air system for the OFA ports 

The addition of the FGR system would represent increased operating 

costs due to the power required to operate the FGR fans as well as 

increased unit maintenance. The addition of an “induced” FGR 

 

2 The costs included in this report have been adjusted to reflect 2004 costs in US $, however over the past 

four years there have been unprecedented increases in the price of steel, and materials in general
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system was also evaluated, and it was deemed not to be cost effective 

since the Mohave units are pressurized. The IFGR system to be 

applied at the Mohave units would require their conversion to 

balanced draft necessitating the addition of Induced Draft (ID) fans 

and re-enforcement of the units to withstand the significant increase in 

negative pressure from the current design. 

2.2.2 Post – Combustion NOx Emissions Control 

NOx emissions can be controlled following their generation from the 

combustion of fossil fuels through the use of chemical reagents such 

as ammonia or urea. There are two major commercially available 

processes that can be used using this basic principle: 

 Selective Non – Catalytic Reduction (SNCR) 

 Selective Catalytic Reduction (SCR) 

In both of these processes the following chemical reaction forms the 

basis for the reduction of NOx: 

2NH3 + 2NO + 1/2O2  2N2 + 3H2O (1) 

Urea has also been used as an ammonia (NH3) substitute with the 

overall NOx reduction reaction being: 

(NH2)2CO + 2NO + 1/2O2  2H2O + CO2 + 2N2 (2) 

The basic difference between these process (SNCR and SCR) is that in 

the SCR process reaction (1) is used and is assisted through the use of 

a catalyst. 

2.2.2.1 Selective Non – Catalytic Reduction (SNCR) 

The Selective Non – Catalytic Reduction (SNCR) process is 

accomplished within the boiler and typically uses ammonia (NH3) or 

urea [(NH2)2CO] as the chemical reagent. Either of those reagents can 

be injected directly into the flue gas to react and reduce NOx 

according to reactions (1) or (2) above. The optimum reaction 

temperature for either reaction is in the range of 1600 to 2200 °F. This 

is a critical process parameter in that injection at higher temperatures 

(>2200 °F) would result in the conversion of ammonia or urea to NOx 

while injection at lower temperatures (<1600 °F) would result in the 

reagent remaining un-reacted (increased quantities of ammonia slip). 
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Urea based SNCR uses an aqueous solution of urea (typically 30 –

50% by weight) while the ammonia process uses either anhydrous or 

aqueous solution. The injection location of the reagent is important 

and should be given careful consideration. To allow for better mixing 

and for variation of flue gas temperatures as a result of boiler load 

variations multiple injection ports and levels have been used in 

commercial applications of the SNCR process. The majority of 

experience with SNCR systems is with urea based systems. A typical 

utility SNCR system is shown in Figure A-6. 

Figure A-6 - Typical SNCR system for utility boiler

application

The temperature of flue gas at the point of reagent injection and the 

available residence time within the optimum reaction temperature 

window along with mixing efficiency are the key ingredients in 

achieving maximum NOx reductions with the SNCR process. The 

SNCR process can be retrofit to most if not all residual oil fired utility 

boilers however the NOx reductions achieved are very site specific 
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since they are highly dependent on the temperature and residence time 

profiles of the individual boiler. It is therefore recommended that a 

study is performed to establish the residence times of the flue gases in 

the reaction temperature window, the location of the temperature 

window, ease of access for installation of the reagent injection ports at 

that temperature window, and the ability to achieve rapid and 

complete mixing of the reagent within that temperature window. 

Typical boiler modifications and equipment required for retrofitting 

SNCR to a natural gas boiler include: 

 Urea or ammonia loading and storage station including safety 

equipment for the prevention of spills and reagent escape 

 Reagent transport equipment, including pumps, flow meters, 

controls, heaters and carrying medium (e.g., air) if required 

 Reagent injection equipment (e.g., lances), installation of 

furnace penetrations at the appropriate location 

 Process control system to control injection rates as a function 

of boiler load and NOx emissions levels required 

A SNCR process schematic is shown in Figure A-7. 

Figure A-7 - SNCR process schematic
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Typical capital costs of the SNCR process range from $20 to $40/kW. 

The cost of the reagents is a major operating expense with the cost of 

ammonia and urea being tied to the cost of natural gas. Typical 

operating and maintenance (O&M) costs range from $1 to $5/kW-yr, 

while annualized technology costs are $3 - $30/kW. 

An analysis of the Mohave units indicates that NOx emissions reductions 

using NSCR will be only on the order of 15 – 25% in addition to those 

achieved with OFA. The primary reasons for these low reductions are: 

• Low NOx levels flowing into the SNCR control zone 

• The unit’s physical size 

• CO levels entering the SNCR 

• Temperature levels present in the boiler 

• Low available residence times in the appropriate temperature window 

2.2.2.2 Selective Catalytic Reduction (SCR) 

The Selective Catalytic Reduction (SCR) process involves the 

following two chemical reactions: 

2NH3 + 2NO + 1/2O2  2N2 + 3H2O (3) 

4NH3 + 2NO2 + O2  3N2 + 6H2O (4) 

Ammonia (NH3) is injected and mixed with the products of 

combustion (flue gases) and reacts with NOx over a bed of catalyst 

producing molecular nitrogen and water vapor. The use of catalyst 

lowers the reaction temperature from the typical 1600 – 2100 °F to a 

600 – 800 °F. Since over 95% of the NOx contained in the flue gases 

consists of NO reaction (3) above is the predominant reaction. 

Approximately one mole of ammonia (17 lbs by weight) to one mole 

of NO (30 lbs by weight) is required to produce NOx emissions 

reductions of 90% at an ammonia slip (un-reacted) level of 2 ppm. 

The ammonia reagent is typically anhydrous or aqueous ammonia or 

derived through the thermal hydrolysis of urea. 

SCR catalysts generally consist of a base material such as titanium 

oxide (TiO2) or a zeolite. The primary ingredient is vanadium

pentoxide (V2O5) including some other metals such as molybdenum, 

cobalt, tungsten, chromium, iron, nickel and chromium. Structurally 

here are three basic types of catalysts: 

o Honeycomb 

o Plate 
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o Corrugated 

All three have been used in residual oil applications however the most 

commonly used has been the honeycomb. Catalyst is specified 

according to the NOx removal rate required, hours of life, ammonia 

“slip”, space velocity, and pitch (e.g., the size of each honeycomb). 

Typical pitch for heavy oil applications ranges between 3.5 to 7 mm 

depending on the ash content of the fuel. The volume of catalyst 

required depends on the operating temperature, NOx removal required, 

and gas flow (i.e., boiler size). 

The vessel (reactor) where the reducing reaction takes place contains 

the catalyst and is typically located between the boiler outlet and the 

air heater due to the NOx reduction reaction temperature requirements 

(see Figure A-8). 

Figure A-8 - Typical aqueous ammonia SCR system for utility boiler 

with separate reactor 

In some applications where there is no available space the SCR system 

has been located close to the boiler stack downstream of the air heater 

and other air pollution control devices. In those cases the flue gas 

needs to be reheated to achieve proper reaction temperatures. The 

benefits of this approach is lower construction costs, reduced size of 

catalyst (clean flue gas), however increased operating costs due to the 

reheating of the flue gas and the increased capital costs (purchase of 
Mohave Generating Station U 1&2 

Clark County, NV 

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©2008 Babcock Power Inc. All Rights Reserved

gas – to – gas heat exchanger) make the overall costs of this design 

higher. 

For natural gas applications the reactor can be a separate vessel or it 

can be part of the ductwork or as is commonly called “in-line” (see 

Figure A-9). 

In-line SCR systems are typically applied to residual oil and gas fired 

units. Due to the lower velocities (approximately half to one-third of 

typical flue gas velocities) required for the NOx reduction reaction to 

take place in the catalyst laden reactor the existing ductwork is 

replaced with larger size. 

Figure A-9 - In-line SCR system for natural gas-fired boiler 

application 

The addition of a SCR system is a major project, requiring careful 

study and typically involves the following modifications and 

additions: 

o Reagent (ammonia or urea) transfer, storage and pumping 

station 

o Reagent injection grid and mixing devices 
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Clark County, NV 

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o SCR system controls for reagent flow, temperature, boiler load, 

NOx emissions monitoring and control, and system safety 

o Reactor and catalyst 

o Structural considerations for both the reactor and boiler proper 

o FD and ID fan upgrades including their electrical system 

o Boiler system upgrades (e.g., implosion study) 

o Economizer modifications if necessary to achieve proper 

reactor temperatures over the boiler load range 

A typical ammonia storage and supply system schematic for utility 

boiler application is shown in Figure A-10. 

Figure A-10 - Typical ammonia storage and supply system 

The capital costs of the application of SCR to a natural gas unit range 

from $70 to $120/kW depending on unit size, available space, and 

SCR design (separate versus “in-line” reactor). In-line SCR is less 

expensive. O&M costs average about $8/kW-yr while overall 

technology annualized costs average about $12/kW. 

SCR systems have been applied extensively throughout Japan, Europe 

and the U.S. In the U.S. approximately 100 GW of electric generation 

has been equipped with SCR systems and of those approximately 6 

GW are oil and natural gas fired units (mainly gas fired in California). 

The NOx removal efficiency has been averaging 85% to 90% for all 

those units with levels as low as 10 ppm for gas fired utility boilers. 
Mohave Generating Station U 1&2 

Clark County, NV 

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The installation of SCR on a natural gas fired boiler would increase 

overall system pressure drop (approximately 6 – 8 inches w.c.) 

resulting in increased fan power consumption and loss of overall plant 

efficiency. 

The application of an in-line SCR system at the Mohave units would 

require the following systems: 

• Ammonia, or aqueous ammonia or urea storage and supply 

system 

• Modification to the boiler’s flue system (between economizer 

outlet and air heater inlet) to provide catalyst space 

• Catalyst 

• Addition of mixing devices and reagent injection system 

• Control system additions and modifications 

• Conversion of the unit to balanced draft 

• Installation of ID fan(s) and necessary switchgear 

It is estimated that the cost of in-line SCR addition at the Mohave 

units will be in the order of $130 - $150 million. The cost of the 

conversion to balanced draft would increase the project cost by an 

additional $30 - $50 million. 
Mohave Generating Station U 1&2 

Clark County, NV 

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3.0 WORK CITED

1. “North American Combustion Handbook” Volumes I & II, North American 

Manufacturing Company, Cleveland, OH, 2001 

2. Afonso, R.F., et. al., “Salem Harbor 4/ Brayton Point 4: NOx Reduction Testing 

on Oil-Fired Boilers”, Presented at the EPRI NOx Controls for Utility Boilers 

Workshop, 1992 

3. “Module 6: Air Pollutants & Control Techniques - - Nitrogen Oxides” 

http://www.epa.gov/eogapti1/module6/nitrogen/control/control.htm#combust 

4. Bisonett, G.L., et. al., “Comparative Assessment of NOx Reduction Techniques 

for Gas- and Oil-Fired Utility Boilers”, Proceedings: 1991 Joint Symposium on 

Stationary NOx Control, EPRI Report GS-7447, Vol. 2, 1991 

5. “Alternative Control Techniques Document – NOx Emissions from Utility 

Boilers”, US EPA Office of Air Quality Planning and Standards, EPA-453/R-94-

023, 1994 

6. Hayden, J., et. al., “Advanced Overfire Air Retrofit for Summer Ozone 

Compliance” 

http://www.fwc.com/publications/tech_papers/powgen/pdfs/2403235.pdf 

7. Kerho, S.E., et. Al., “Reduced NOx, Particulate and Opacity on the Kahe unit 6 

Low NOx Burner System”, Proceedings: 1991 Joint Symposium on Stationary 

NOx Control, EPRI Report GS-7447, Vol. 2, 1991 

8. Frederick, N., et. al., “NOx Control on a Budget: Induced Flue Gas 

Recirculation”, Power Engineering, July 2003 

9. Witkamp, J.G., et. al., “Demonstration of Advanced, Low NOx Combustion 

Techniques at the Gas/Oil – Fired Flevo Power Station unit 1” Proceedings:1991 

Joint Symposium on Stationary NOx Control, EPRI Report GS-7447, Vol. 2, 

1991 

10. Mormile, D.J., et. al., “NOx Inventory and Retrofit Assessment”, Proceedings: 

1987 Symposium on Stationary Combustion Nitrogen Oxides Control, EPRI 

Report CS-5361, Vol. 2, 1987 

11. McDannell, M.D., et. al., “Low NOx Levels Achieved by Improved Combustion 

Modification on two 480 MW Gas – Fired Boilers”, Proceedings: 1991 Joint 

Symposium on Stationary Combustion NOx Control, EPRI Report GS-7447, Vol. 

2, 1991 

12. Horn, K., et. al., “Low NOx Combustion Modifications on a 300 MW Gas – and 

Oil – Fired Utility Steam Generator”, Proceedings PowerGen 1997, Dallas, TX 

13. Srivastava, et. al., “Menu of NOx Emission Control Options for Coal-Fired 

Electric Utility Boilers”, presented at the 2003 A&WMA Conference, San Diego, 

CA, 2003 

14. Bayard de Volo, N., et. al., NOx Reduction and Operational Performance of two 

Full – Scale Utility Gas/Oil Burner Retrofit Installations”, Proceedings: 1991 

Joint Symposium on Stationary Combustion NOx Control”, EPRI Report GS7477, Vol. 2, 1991 
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential A-24 7/25/08 

©2008 Babcock Power Inc. All Rights Reserved

15. Yee, J.L.B., et. al., “Retrofit of an Advanced Low – NOx Combustion System at 

Hawaiian Electric’s Oil – Fired Kahe Generating Station”, Proceedings: 1989 

Symposium on Stationary Nitrogen Oxide Control, EPRI Report GS – 6423, Vol. 

2, 1989 

16. DeMichelle, G., et. al., “Application of Reburning Technologies for NOx 

Emissions Control on Tangentially, Oil – Fired Boilers”, Presented at the EPRI 

NOx Controls for Utility Boilers Workshop, July 1992 

17. Nylander, J. H., et. al., “Demonstration of an Automated Urea Injection System at 

Encina Unit 2”, Proceedings: 1989 Symposium on Stationary Nitrogen Oxide 

Control”, EPRI Report GS-6324, Vol. 2, 1989 

18. Abele, A. R., et. al., “Performance of Urea NOx Reduction Systems on Utility 

Boilers, Proceedings: 1991 Joint Symposium on Stationary Combustion Nox 

Control, EPRI Report GS-7447, Vol. 2, 1991 

19. “Flue Gas Recirculation Background” 

http://www.etecinc.net/index.cfm?area=ip&ip_page=ip&cat_id=4

20. Staudt, J., “Status Report on NOX Control Technologies and Cost Effectiveness 

for Utility Boilers”, Northeast States for Coordinated Air Use Management, 

Boston, MA, 1998 

21. “Module 6: Air Pollutants & Control Techniques - - Nitrogen Oxides” 

http://www.epa.gov/eogapti1/module6/nitrogen/control/control.htm#noncat

22. Mussati, D.C., et. al., “Chapter 1 – Selective Non-catalytic Reduction (SNCR)”, 

EPA/452/B-02-001, October 2000 

23. “Module 6: Air Pollutants & Control Techniques - - Nitrogen Oxides” 

http://www.epa.gov/eogapti1/module6/nitrogen/control/control.htm#cat 

24. McLaughlin, B.R., et. al., “Selective Catalytic Reduction (SCR) Retrofit at San 

Diego Gas & Electric Company South Bay Generating Station”, Presented at 

EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, August 

1997 

25. Perry, J.H. editor, “Chemical Engineer’s Handbook”, Fourth Edition, 1969 

26. “Air Pollution Control Technology Fact Sheet – Selective Non-Catalytic 

Reduction (SNCR)”, EPA-452/F-03-031

27. “Air Pollution Control Technology Fact Sheet – Selective Catalytic 

Reduction” EPA-452/F-03-032

28. Arai, M., “Flue Gas Recirculation for Low NOx Combustion System”, 

Proceedings of 2000 International Joint Power Generation Conference, 

Miami FL, July 2000

29. “EPA Air Pollution Control Cost Manual”, Sixth Edition, EPA Report 

EPA/452/B-02-001 

30. Study of Hazardous Air Pollutant Emissions from Electric Utility Steam 

Generating Units – Final Report to Congress”, EPA Report EPA-453/R-98-004a, 

February 1998 

31. Hunt, T., et. al., “Integrated Dry NOx/SO2 Emissions Control System”, Final 

Report, Volume 1: Public Design, DOE Contract No. DE-FC-91PC90550, 

November 1997 
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential A-25 7/25/08 

©2008 Babcock Power Inc. All Rights Reserved

32. Chu, P., et. al., “Power Plant Evaluation of the Effect of SCR Technology on 

Mercury”, Presented at the Combined Power Plant Air Pollutant Mega 

Symposium, May 2003 
 October 2008 BART Determination for MGS: Natural Gas Firing 

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Appendix B 

Guidance on CALMET Settings 
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National Park Service guidance on CALMET settings 
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Excerpts from recent EPA Region IX guidance on BART modeling for Navajo Nation EGUs 

1) CALMET settings 

“After discussion with Federal Land Managers representatives, we request the following changes to input 

switches for the CALMET meteorological processor: 

• NOOBS = 0, to use both surface and upper observations; 

• IEXTRP = -4, to extrapolate surface wind observations to the upper layers using similarity theory, and 

ignore layer 1 from the upper air soundings; 

• ITPROG = 1, to use surface station temperature and the MM5 for upper air. 

These settings are more appropriate for BART determination modeling, as opposed to ‘subject to BART’ 

modeling that the WRAP modeling protocol addressed.” 

2) Ammonia background 

“We withdraw the request for additional reprocessing using a 1 ppb ammonia background concentration, as 

we believe the background values already used are appropriate.” 
 October 2008 BART Determination for MGS: Natural Gas Firing 

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Appendix C 

Factors Influencing NOx Emissions Effects on Visibility 
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Secondary pollutants such as nitrates and sulfates are significant contributors to the visibility extinction in 

Class I areas. The CALPUFF model was used to determine the effect of these pollutants on Class I areas, 

associated with the candidate BART control options. CALPUFF uses the EPA-approved MESOPUFF II 

chemical reaction mechanism to convert SO2 and NOx emissions to secondary sulfates and nitrates. The 

discussion below describes how the secondary pollutants are formed and the factors affecting their formation. 

Formation of Sulfates 

The rate of transformation of gaseous SO2 to ammonium sulfate (NH4)2SO4 aerosol is dependent upon solar 

radiation, ambient ozone concentration, atmospheric stability, and relative humidity, as shown in Figure C-1 

(taken from the CALPUFF users guide, 2000). Homogeneous gas phase reaction is the dominant SO2

oxidation pathway during clear, dry conditions (Calvert et al., 1978). CALPUFF assumes that the sulfate 

reacts preferentially with ammonia (NH3) to form ammonium sulfate and that any remaining ammonia is 

available to form ammonium nitrate (NH4NO3). 

Figure C-1 MESOPUFF II SO2 Oxidation 

Formation of Nitrates 

The oxidation of NOx to nitric acid (HNO3) depends on the NOx concentration, ambient ozone concentration, 

and atmospheric stability. Some of the nitric acid is then combined with available ammonia in the atmosphere 

to form ammonium nitrate aerosol in an equilibrium state that is a function of temperature, relative humidity, 

and ambient ammonia concentration, as shown in Figure C-2 (from the CALPUFF users guide). 

Figure C-2 MESOPUFF II NOx Oxidation 

In CALPUFF, total nitrate (TNO3 =HNO3 + NO3) is partitioned into each species according to the equilibrium 

relationship between gaseous HNO3 and NO3 aerosol. This equilibrium is a function of ambient temperature 

and relative humidity. Moreover, the formation of nitrate strongly depends on availability and amount of NH3 to 
BART Determination for MGS: Natural Gas Firing July 2008

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form ammonium nitrate, as shown in Figure C-3 (from CALPUFF courses given by TRC). The figure on the 

left shows that with 1 ppb of available ammonia and fixed temperature and humidity (for example, 275 deg K 

and 80% humidity), only 50% of the total nitrate forms particulate matter. When the available ammonia is 

increased to 2 ppb, as shown in the figure on the right, as much as 80% of the total nitrate is in the particulate 

form. Figure C-3 also shows that colder temperatures and higher relative humidity significantly favor nitrate 

formation and vice versa. A summary of the conditions affecting nitrate formation are listed below: 

• Colder temperature and higher relative humidity create favorable conditions to form nitrate particulate 

matter, and therefore more ammonium nitrate is formed; 

• Warm temperatures and lower relative humidity create less favorable conditions to form nitrate 

particulate matter, and therefore less ammonium nitrate is formed; 

• Sulfate preferentially scavenges ammonia over nitrates. In areas where sulfate concentrations are 

high and ambient ammonia concentrations are low, there is less ammonia available to react with 

nitrate, and therefore less ammonium nitrate is formed. 

Figure C-3 NO3/HNO3 Equilibrium Dependency on Temperature and Humidity 

Ambient Ammonia Background Concentrations 

CALPUFF modeling of the baseline and BART control options emissions was conducted with the following 

sets of background ammonia values. The actual ammonia values used for each of the eleven Class I areas 

are listed in Table C-1. 

• Class I areas located in areas of higher ammonia emission sources (shown in Figure B-4) and with 

mild winters are modeled with ammonia background of 1 ppb all year, in accordance with the WRAP 

BART protocol. These Class I areas are: Joshua Tree W, San Gorgonio W, Agua Tibia W, San 

Jacinto W, Domeland W, and Cucamonga W. The ammonia background of 1 ppb is used to model 

the baseline, BART option 3 (LNB/OGA/FGR) and option 5 (LNB/OFA) emissions. 

• Class I areas located in the region of sparse ammonia emission sources (shown in Figure B-4) and 

with more substantial winter seasons are modeled with monthly variable ammonia background that 

have been approved for multiple PSD projects by the Federal Land Managers. The monthly ammonia 

background values are 0.2 ppb in January-February and December; 0.5 ppb in March-April and 

October-November; and 1 ppb in May-September). The Class I areas assigned these background 

values are Grand Canyon NP, Zion NP, Sycamore Canyon W, Pine Mountain W, and Mazatzal W. 
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The ammonia background values mentioned above were recently approved by the Federal Land 

managers for the nearby Toquop Energy Project (TEP) PSD permit application (northwest of 

Mesquite, Nevada) and also previously for the Desert Rock Energy Facility PSD permit application 

(Navajo Nation, New Mexico). These background ammonia values are based upon direct 

measurements (some in the Grand Canyon) as well as seasonal considerations. In general, it is 

important to note that the likely over-prediction by CALPUFF of nitrates in winter as noted by Morris et 

al. (2005) can be partially addressed by using a monthly variation of background ammonia 

concentrations. The default value of 1.0 ppb for arid lands as referenced in the IWAQM Phase 2 

document (1998) is valid at 20°C, but the same document cites a strong dependence with ambient 

temperature, with variations of a factor of 3-4. This same dependence is seen at the CASTNET 

monitor at Bondville, Illinois (see page 5 at http://www.ladco.org/tech/ 

monitoring/docs_gifs/NH3proposal-revised3.pdf). In addition, a study of light-affecting particles in 

southwest Wyoming indicated that nitrates were over-predicted by a factor of 3 for a constant 

ammonia concentration of 1.0 ppb, and by a factor of 2 for an ammonia concentration of 0.5 ppb (see 

slide 57 at 

http://www.air.dnr.state.ga.us/airpermit/psd/dockets/longleaf/facilitydocs/050711_CALPUFF_eval.pdf). 

Since there are no large sources of ammonia due to agricultural activities the Class I areas in Arizona 

and Utah, it is appropriate to introduce a monthly varying ammonia background concentration to the 

CALPUFF modeling. These ammonia background concentrations without change (ignoring additional 

ammonia from the plant itself) for all BART options except for SNCR operation. 

• Excess ammonia emissions associated with SCR as well as SNCR operations were modeled with 

CALPUFF to determine the 8th highest 24-hour ammonia concentration averaged over three 

meteorological years in all Class I areas. Predicted ammonia concentrations were less than 10% of 

the background ammonia concentrations at all Class I areas except for the Grand Canyon NP (winter 

months only ) for SNCR operation, so only the winter season background concentrations at the Grand 

Canyon were adjusted upward by 0.04 ppb (only for SNCR operation) to account for the additional 

ammonia due to plant emissions, as shown in Table C-1. The POSTUTIL program (CALPUFF postprocessor) was used to re-compute regional haze impacts with the adjusted ammonia background at 

Grand Canyon. 

As discussed above, the formation of nitrate is highly sensitive to availability of ammonia to form ammonium 

nitrate. Ammonium nitrate is a visibility-degrading pollutant. For the purpose of evaluating NOx emissions 

control options, the ambient ammonia background concentrations at the Grand Canyon were refined to factor 

in excess ammonia emission increases associated with SNCR operations. The installation of SCR creates 

slightly higher levels of primary sulfate emissions (H2SO4) that were also accounted for in the CALPUFF 

modeling. 
BART Determination for MGS: Natural Gas Firing July 2008

06200-034--500

Table C-1 Ambient Ammonia Background Concentrations 

Class I Area January – 

February 

March – 

April 

May – 

September

October – 

November December Modeling 

Option 

0.2 0.5 1 0.5 0.2 baseline, 1-3, 5 Grand Canyon NP 0.24 0.5 1 0.5 0.24 4 

Zion NP 0.2 0.5 1 0.5 0.2 baseline, 1-5 

Sycamore Canyon W 0.2 0.5 1 0.5 0.2 baseline, 1-5 

Pine Mountain W 0.2 0.5 1 0.5 0.2 baseline, 1-5 

Mazatzal W 0.2 0.5 1 0.5 0.2 baseline, 1-5 

Domeland W 1 1 1 1 1 baseline, 1-5 

Joshua Tree W 1 1 1 1 1 baseline, 1-5 

San Gorgonio W 1 1 1 1 1 baseline, 1-5 

Agua Tibia W 1 1 1 1 1 baseline, 1-5 

San Jacinto W 1 1 1 1 1 baseline, 1-5 

Cucamonga W 1 1 1 1 1 baseline, 1-5 

Figure C-4 Ammonia Emissions Density 
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034--500

Appendix D 

Re-Calculating CALPOST Visibility Outputs 

with the New IMPROVE Algorithm 
BART Determination for MGS: Natural Gas Firing July 2008

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BART Determination for MGS: Natural Gas Firing July 2008

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BART Determination for MGS: Natural Gas Firing July 2008

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BART Determination for MGS: Natural Gas Firing July 2008

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BART Determination for MGS: Natural Gas Firing July 2008

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BART Determination for MGS: Natural Gas Firing 

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BART Determination for MGS: Natural Gas Firing July 2008

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July 2008 BART Determination for MGS: Natural Gas Firing 

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 October 2008 BART Determination for MGS: Natural Gas Firing 

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Appendix E 

CALPUFF Modeling Results and Graphic Charts using the New 

IMPROVE Equation 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Table E-1 Regional Haze Results of Modeled BART Options for Each Met Year 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Table E-1 Regional Haze Results of Modeled BART Options for Each Met Year 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure E-1 8th Highest Visibility Impact due to BART Option 1 

8th Highest Regional Haze Impacts due to LNB+OFA+SCR (Stand Alone) Controls

0.00.10.20.30.40.50.6

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure E-2 8th Highest Visibility Impact due to BART Option 2 

8th Highest Regional Haze Impacts due to LNB+OFA+SCR (In-Line) Controls

0.00.10.20.30.40.50.6

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure E-3 8th Highest Visibility Impact due to BART Option 3 

8th Highest Regional Haze Impacts due to LNB+OFA+FGR Controls

0.00.10.20.30.40.50.6

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure E-4 8th Highest Visibility Impact due to BART Option 4 

8th Highest Regional Haze Impacts due to LNB+OFA+SNCR Controls

0.00.10.20.30.40.50.6

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mountain

W

Class I Area

8th Highest deciview

Met Year 200Met Year 200Met Year 200Met Year Ave 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure E-5 8th Highest Visibility Impact due to BART Option 5 

8th Highest Regional Haze Impacts due to LNB+OFA Controls

0.00.10.20.30.40.50.6

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 2Met Year 2Met Year 2Met Year A
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034--500

Appendix F 

CALPUFF Modeling Results and Graphic Charts using the Old 

IMPROVE Equation
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

TableF-1 Regional Haze Impacts Due to Baseline Emissions 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

FigureF-1 8th Highest Regional Haze Impacts for Each Modeled Year Due to Baseline Emissions 

8th Highest Regional Haze Impacts due to Baseline Emissions

0.00.51.01.52.02.53.03.54.04.5

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year Av
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Table F-2 Regional Haze Results of Modeled BART Options for Each Met Year 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Table F-2 Regional Haze Results of Modeled BART Options for Each Met Year 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-2 8th Highest Visibility Impact due to BART Option 1 

8th Highest Regional Haze Impacts due to LNB+OFA+SCR (Stand Alone) Controls

0.00.10.20.30.40.50.60.70.8

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-3 8th Highest Visibility Impact due to BART Option 2 

8th Highest Regional Haze Impacts due to LNB+OFA+SCR (In-Line) Controls

0.00.10.20.30.40.50.60.70.8

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-4 8th Highest Visibility Impact due to BART Option 3 

8th Highest Regional Haze Impacts due to LNB+OFA+FGR Controls

0.00.10.20.30.40.50.60.70.8

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 20Met Year 20Met Year 20Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-5 8th Highest Visibility Impact due to BART Option 4 

8th Highest Regional Haze Impacts due to LNB+OFA+SNCR Controls

0.00.10.20.30.40.50.60.70.8

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mountain

W

Class I Area

8th Highest deciview

Met Year 200Met Year 200Met Year 200Met Year Ave 
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-6 8th Highest Visibility Impact due to BART Option 5 

8th Highest Regional Haze Impacts due to LNB+OFA Controls

0.00.10.20.30.40.50.60.70.8

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

8th Highest deciview

Met Year 2Met Year 2Met Year 2Met Year A
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-7 8th Highest Visibility Impact due Five BART NOx Control Options 

8th Highest Regional Haze Impacts due to Five BART NOx Controls Options

0.00.10.20.30.40.50.60.7

Grand Canyon

NP

Joshua Tree

NM

Zion NP Sycamore

Canyon W

Agua Tibia W Cucamonga W San Gorgonio

W

San Jacinto W Mazatzal W Pine Mounta

W

Class I Area

2001-03 Ave 8th Highest dv

LNB+OFA+SCR LNB+OFA+SCR LNB+OFA+FGRLNB+OFA+SNCLNB+OFA
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-8 Total Number of Days Removed Above 0.5 delta-dv Relative to the Baseline Case 

1505 1483 1473 145

1501

0

200400600800

1000120014001600

LNB+OFA+SCR (Stand

Alone)

LNB+OFA+SCR (In-Line) LNB+OFA+FGR LNB+OFA+SNCR LNB+O

# of Days Removed
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-9 Number of Days Removed at Each Class I Area Above 0.5 delta-dv Relative to the Baseline Case 

249

238 232 222 213 213 213 213

121 121 121 

287 287 287 

116 116 116 

516

501 508 504 515

252

213

121

287

116

0

100200300400500600

LNB+OFA+SCR (Stand

Alone)

LNB+OFA+SCR (InLine) LNB+OFA+FGR LNB+OFA+SNCR LNB+

# of Days Removed

Grand Canyon Joshua Tree NMZion NPSycamore Cany5 Other CA Cla2 Other AZ Cla
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-10 Annual Cost of NOx Controls vs. Visibility Improvements at the Closest Class I Areas 

0

1020304050

4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 

2001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)

Grand Canyon NPJoshua Tree NP

Baseline

LNB+OFA+SNCR

LNB+OFA

LNB+OFA+FGR

LNB+OFA+SCR In-Line

LNB+OFA+SCR Stand-Alone
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-11 Annual Cost of NOx Controls vs. Visibility Improvements at the Other California Class I Areas 

0

1020304050

1.4 1.2 1.0 0.8 0.6 0.4 0.2 

2001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)

Agua Tibia WCucamonga WSan Gorgonio WSan Jacinto WDomeland W

Baseline

LNB+OFA+SNCR

LNB+OFA

LNB+OFA+FGR

LNB+OFA+SCIn-LineLNB+OFA+SCStand-Alone
July 2008 BART Determination for MGS: Natural Gas Firing 06200-034--500

Figure F-12 Annual Cost of NOx Controls vs. Visibility Improvements at the Other Non-California Class I Areas 

0

1020304050

1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 

2001-2003 Average 8th Highest delta-dv

Cost at 12% Interest Rate (MM$/year)

Sycamore Canyon WMazatzal WPine Mountain WZion NP

Baseline

LNB+OFA+SNCR

LNB+OFA

LNB+OFA+FGR

LNB+OFA+SCR In-Line

LNB+OFA+SCR Stand-Alone
 October 2008 BART Determination for MGS: Natural Gas Firing 

06200-034--500

Appendix G 

Projected NOx Emissions on Natural Gas Over Mohave’s Future 

Operating Range Based on 2005 Actual Reporting for the Mohave 

Generating Station 
ANTICIPATED NOX EMISSIONS 

OVER THE OPERATING RANGE 

BASED ON 2005 ACTUAL REPORTING 

 FOR 

MOHAVE GENERATING STATION 

Date Issued: October 8, 2008 
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential 7/21/08 

©2008 Babcock Power Inc. All Rights Reserved

This document was prepared solely for use by, and solely for the benefit of Navasota Energy. 

Any other recipient of this document uses it without the permission of Riley Power and thereby 

releases Riley Power from liability of any kind. Riley Power has taken certain steps to 

evaluate possible changes to the Mohave Generating Station, but the information herein is not 

intended as a design, nor even a basis for design. Riley Power expressly disclaims any 

warranty, expressed or implied, with respect to use of the information or concepts disclosed in 

this document for any purpose other than that set out in the underlying contract between Riley 

Power and Navasota Energy. 
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential -G- 10/8/08 

©2008 Babcock Power Inc. All Rights Reserved

APPENDIX G: 

Anticipated NOx Emissions 

Over the Operating Range 

Based on 2005 Actual Reporting 

For 

Mohave Generating Station 
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential G-1 10/8/08 

©2008 Babcock Power Inc. All Rights Reserved

1. NOx Emissions 

An analysis was performed comparing NOx in lb/MBtu versus lb/hr NOx, at various 

boiler loads. To do this the hourly EPA NOx data for 2005 Quarter 1 thru 4 was 

downloaded, this data is indicated as the blue data points on Figure 1 & 2 below. In 

order to mimic the same operating conditions while firing gas we applied a multiplier 

to the coal firing NOx data from 2005 to make the full load NOx average 0.10 

lb/MBtu. Table 5 and Figures 1 & 2, show that there are load conditions where the 

unit would operate above the 0.10 lb/MBtu value. This is especially important for a 

unit that will be cycling as the average may be skewed by these transient operating 

conditions. 

Table 5 

Example Case Analysis 

Comparing lb/MBtu and lb/hr NOx Emissions 

Figure 1 

Mohave Unit 1 - NOx (lb/hr) vs Heat Input

EPA NOx Database 2005 Q1-4

0.00

500.00

1000.00

1500.00

2000.00

2500.00

3000.00

3500.00

4000.00

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

Heat Input, MBtu/hr

NOx, lb/hr

Gas Firing (Projected) Coal Firing (Actual 2005)

Load, MW Heat Input, MBtu/hr NOx, lb/MBtu NOx, lb/hr

750 7500 0.1 750

500 5000 0.15 750

250 2500 0.07 175

<100 1000 0.2 200
Mohave Generating Station U 1&2 

Clark County, NV 

Proprietary and Confidential G-2 10/8/08 

©2008 Babcock Power Inc. All Rights Reserved

Figure 2 

Mohave Unit 1 - NOx vs Heat Input

EPA NOx Database 2005 Q1-4

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000

Heat Input, MBtu/hr

NOx, lb/MBtu

Gas Firing (Projected) Coal Firing (Actual 2005)