From: Haidar Alrawi <Haidar.Alrawi@tn.gov>

To: Bill Neuffer/RTP/USEPA/US@EPA

Cc: John Trimmer <John.Trimmer@tn.gov>

Date: 03/15/2012 02:42 PM

Subject: US Nitrogen PSD Application

Mr. Nueffer:

Attached, please find the PSD permit application (public version) of the U.S. Nitrogen facility (Midway, 

TN) in addition to the final determination review document. The PSD BACT analysis for the nitrous oxide 

(N2O) emissions from the Nitric Acid Plant is discussed starting on page 4-22 of the application. Also, 

Table 4-7, on page 4-26 lists the proposed control technologies that would be utilized for N2O emissions 

and the associated destruction efficiences.

The BACT determination for the N2O emissions is also discussed on page 5 of the final determination 

document.

The basis of the proposed control technologies (i.e., primary and tertiary) came from the attached 

October 2010 EPA OAR guidance document " Available and Emerging Technologies for Reducing 

Greenhouse Gas Emissions from the Nitric Acid Production Industry that you are familiar with. 

Please let me know if you have any questions, or need additional information.

Regards,

Haidar

Haidar Al-Rawi, P.E., BCEE

TN Air Pollution Control

(615) 532-0578 (voice)

(615) 532-0614 (fax)

E-mail: Haidar.Alrawi@tn.gov
 

US NITROGEN, LLC 

PREVENTION OF SIGNIFICANT DETERIORATION 

CONSTRUCTION PERMIT APPLICATION 

US NITROGEN, LLC 

471 POTTERTOWN ROAD 

MIDWAY, TENNESSEE 

EnSafe Project Number: 

0888810409 

Prepared for: 

 

25800 Science Park Drive, Suite 300 

Cleveland, Ohio 44122 

 

Prepared by: 

EnSafe Inc. 

220 Athens Way, Suite 410 

Nashville, Tennessee 37228 

(615) 255-9300 

(800) 588-7962 

www.ensafe.com 

August 2011, Revision 1.0 
i

Table of Contents 

1.0 INTRODUCTION ........................................................................................................... 1-1

2.0 PROJECT DESCRIPTION ............................................................................................... 2-1

2.1 Site Description ................................................................................................. 2-1

2.2 Proposed Operations ......................................................................................... 2-1

2.2.1 Steam Generating Boiler ......................................................................... 2-1

2.2.2 Ammonia Plant ....................................................................................... 2-6

2.2.3 Nitric Acid Plant ...................................................................................... 2-8

2.2.4 ANSOL Plant......................................................................................... 2-10

2.2.5 Nitric Acid Storage Tank ........................................................................ 2-11

2.2.6 ANSOL Storage Tank ............................................................................ 2-11

2.2.7 Cooling Tower ...................................................................................... 2-11

2.2.8 Firewater Pump .................................................................................... 2-11

2.2.9 Flare .................................................................................................... 2-12

2.3 Project Emissions ............................................................................................ 2-12

3.0 REGULATORY ANALYSIS ............................................................................................... 3-1

3.1 National Ambient Air Quality Standards ............................................................... 3-1

3.2 PSD Requirements ............................................................................................. 3-2

3.2.1 General Requirements ............................................................................ 3-2

3.2.2 Control Technology Review ..................................................................... 3-4

3.2.3 Source Impact Analysis ........................................................................... 3-5

3.2.4 Air Quality Monitoring Requirements ........................................................ 3-6

3.2.5 Source Information/Good Engineering Practice Stack Height ..................... 3-7

3.2.6 Additional Impact Analysis ...................................................................... 3-8

3.3 Nonattainment Rules ......................................................................................... 3-8

3.4 Emission Standards ........................................................................................... 3-8

3.4.1 New Source Performance Standards — 40 CFR 60 .................................... 3-8

3.4.2 National Emission Standards for Hazardous Air Pollutants (MACT) — 

40 CFR 63 .............................................................................................. 3-9

3.4.3 Tennessee Air Permitting Requirements ................................................. 3-10

3.5 Other Requirements ........................................................................................ 3-10

3.5.1 Title V Program .................................................................................... 3-10

3.5.2 Risk Management Program ................................................................... 3-10

3.5.3 General Duty Clause ............................................................................. 3-11

4.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS .................................................... 4-1

4.1 Point Source Emissions ...................................................................................... 4-3

4.1.1 Ammonia Plant — Trains 1 and 2 ............................................................ 4-5

4.1.2 Nitric Acid Plant ...................................................................................... 4-7

4.1.3 Steam-Generating Boiler ....................................................................... 4-11

4.1.4 Firewater Pump .................................................................................... 4-13

4.1.5 Flare .................................................................................................... 4-14

4.2 Greenhouse Gases (CO2e) ................................................................................ 4-15

4.2.1 Dilute GHG Emissions Resulting From Combustion .................................. 4-16

4.2.2 Concentrated CO2 Emissions from the Ammonia Plant CO2 Vents ............. 4-18

4.2.3 N2O Emissions from the Nitric Acid Plant ................................................ 4-22

5.0 AIR QUALITY ANALYSIS ............................................................................................... 5-1
ii

6.0 ADDITIONAL IMPACT ANALYSIS ................................................................................... 6-1

6.1 Growth Analysis ................................................................................................ 6-1

6.2 Soils Analysis .................................................................................................... 6-1

6.3 Vegetation Impacts ........................................................................................... 6-2

Figures 

Figure 1 Site Location Map .............................................................................................. 2-2

Figure 2 Proposed Site Map (Topographic) ....................................................................... 2-3

Figure 3 Proposed Site Map ............................................................................................. 2-4

Figure 4 Emission Point Locations .................................................................................... 2-5

Tables 

Table 1-1 PSD Significance Thresholds Compared to Potential Emissions ............................. 1-2

Table 2-1 Projected Annual Emissions .............................................................................. 2-13

Table 3-1 NAAQS and PSD Increments and Significance Levels ........................................... 3-2

Table 3-2 PSD Significant Emission Rates and Monitoring De Minimis Levels ........................ 3-3

Table 3-3 Class I Areas within 300 km of Proposed US Nitrogen Site ................................... 3-6

Table 4-1 US Nitrogen Potential Emissions of GHGs ............................................................ 4-3

Table 4-2 US Nitrogen Emission Point Sources and Respective Potential Emissions ............... 4-3

Table 4-3 Summary of Proposed BACT for Each US Nitrogen Emission Source ...................... 4-4

Table 4-4 Financial Comparison of US Nitrogen Ammonia Plant NOX Reduction Options ........ 4-7

Table 4-5 Financial Comparison of US Nitrogen Nitric Acid Plant NOX Reduction Options ..... 4-10

Table 4-6 Financial Comparison of US Nitrogen Boiler NOX Reduction Options .................... 4-13

Table 4-7 Financial Comparison of Nitric Acid Plant N2O Reduction Options ........................ 4-26

Table 6-1 Injury Threshold Concentrations for NOX............................................................. 6-3

Appendices 

Appendix A Application Forms

Appendix B Emission Calculations

Appendix C Air Dispersion Modeling and Class II Visibility Analysis

Appendix D Correspondence with Federal Land Managers

Appendix E RBLC Search Summary Tables

Appendix F Austin Powder Cost of Capital

Appendix G BACT Financial Analysis Worksheets
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

1-1

1.0 INTRODUCTION 

US Nitrogen, LLC, a wholly-owned subsidiary of Austin Powder Inc., proposes to construct and 

operate a facility to manufacture nitric acid, ammonia (NH3), and liquid ammonium nitrate solution 

(ANSOL). The facility will be located on approximately 400 acres at 471 Pottertown Road, 

Midway, Greene County, Tennessee, near the intersection of US Highway 11E (Andrew Johnson Highway) 

and I-81. The approximate Universal Transverse Mercator (UTM) coordinates of the facility are 

319,733 meters east and 4,006,685 meters north (UTM Zone 17, NAD 83). 

The proposed project will result in an increase in air emissions in Greene County, Tennessee, which 

currently is designated as an attainment or unclassified area for all National Ambient Air Quality 

Standards (NAAQS). The federal and state Prevention of Significant Deterioration (PSD) rules 

require a review of new or modified sources that increase air emissions above certain threshold 

amounts. In addition, nitric acid production is included in the PSD rules as one of 28 source 

categories that have lower thresholds for requiring a PSD construction permit. Because 

the threshold amounts will be exceeded by the proposed project, the project is subject to PSD 

review under the regulations governing PSD (40 Code of Federal Regulations [CFR] 52.21), and 

the proposed facility will be classified as a Title V major source of air pollution under 40 CFR 70.2. 

The proposed project is subject to PSD review for the following pollutants: 

Nitrogen Oxides (NOX) 

Greenhouse Gases (GHGs) 

Emissions of other pollutants are estimated to be below the thresholds triggering PSD review. 

Table 1-1 summarizes the emissions from the proposed project and identifies which pollutants are 

subject to PSD review. A more detailed description of project emissions and regulatory applicability 

is included in Section 3. 

Greene County is classified as an attainment or unclassified area for all criteria pollutants and is

classified as a PSD Class II area. The PSD review has been performed according to the regulations 

applying to this area designation. 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

1-2

Table 1-1

PSD Significance Thresholds Compared to Potential Emissions 

Criteria Pollutant 

PSD Significant 

Emission Rate 

(TPY) 

Total Emissions 

from US Nitrogen 

Sources (TPY) 

Total Emissions 

Including Potential 

Commercial Facility 

(TPY) 

PSD 

Review 

Required?

Greenhouse Gases (CO2e1) 75,000 197,598 112,188 Yes 

Particulate Matter (PM) 25 22.63 23.22 No 

PM10 15 10.65 11.11 No 

PM2.5 10 8.15 8.61 No 

Sulfur Dioxide (SO2) 40 0.50 0.50 No 

Nitrogen Oxides (NOX) 40 76.43 76.43 Yes 

Carbon Monoxide (CO) 100 90.36 87.40 No 

VOCs 40 4.93 4.93 No 

Lead 0.6 — — No 

Fluorides 3 — — No 

Sulfuric Acid Mist 7 — — No 

Hydrogen Sulfide 10 — — No 

Total Reduced Sulfur 10 — — No 

Reduced Sulfur Compounds 10 — — No 

Note: 

1. CO2e = Carbon dioxide equivalents 

This application will provide information to support a construction permit approval based on 

the following demonstrations and analyses of the project: 

 Neither PSD ambient air increments nor NAAQS will be violated. 

 Emissions resulting from operation of the proposed source will not significantly impact any 

nonattainment area. 

 Best Available Control Technology (BACT) will be applied to each emission unit that will 

have a significant emission. 

 Economic growth, soils, and vegetation will not be subjected to signifcant adverse impact. 

The remainder of the air permit application presents the demonstrations and analyses mentioned 

above. Section 2 contains a description of the proposed project operations while Section 3 contains 

an analysis of the applicable regulations. Section 4 provides a BACT analysis, and Section 5 

presents an analysis of the impact on air quality. The additional impact analysis is contained in 

Section 6. The permit application forms, emissions calculations, BACT RACT/BACT/LAER 

Clearinghouse (RBLC) search results, air quality modeling protocol, outputs from air dispersion 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

1-3

modeling, meteorological data summaries, receptor set descriptions, pollutant impact plots, BACT 

financial analysis worksheets, correspondence with the Federal Land Managers, and documentation 

of Austin Powder’s cost of capital are included in the appendices. 

With this application, US Nitrogen provides a detailed demonstration of compliance with all federal 

and State of Tennessee requirements for air quality protection prior to construction of the proposed 

new production facility. A construction permit application has been completed and is provided in 

Appendix A. Therefore, US Nitrogen requests that a construction permit be granted under 

the PSD provisions of Tennessee Division of Air Pollution Control (TDAPC) Rule 1200-03-09-.01. 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-1

2.0 PROJECT DESCRIPTION 

US Nitrogen proposes to build and operate a nitric acid, NH3, and ANSOL production facility at 

this location for the purpose of vertical supply chain integration with other Austin Powder locations 

throughout the United States. US Nitrogen’s parent company, Austin Powder, operates similar 

facilities throughout the world, meeting recognized environmental, safety, and pollution control 

requirements. The ANSOL produced here will be combined offsite with other substances under 

certain conditions as an ingredient in explosives. However, explosives will not be manufactured at 

this location. 

2.1 Site Description 

The proposed US Nitrogen facility will be constructed on approximately 400-acre site near 

Midway, Greene County, Tennessee. A site locality map (Figure 1) and a topographic map 

(Figure 2) provide details of the location and property boundaries of the proposed site. A site plan 

with site boundaries (Figure 3) and an emissions point location map (Figure 4) are included. 

The northern end of the area is adjacent to Pottertown Road in the Pottertown community. 

The area extends to the west and south adjacent to the Southern Rail line and includes most of 

West Seven Springs Road. The site is adjacent to the DTR Tennessee facility, Forest Road, and 

US Highway 11E (Andrew Johnson Highway) at the northwest corner of the proposed site. 

2.2 Proposed Operations 

The proposed operations are based on standard best practices commonly found in facilities 

producing nitric acid, NH3, and ANSOL primarily using natural gas cracking and steam. 

Facility processes and equipment are described in the following sections. 

2.2.1 Steam Generating Boiler 

US Nitrogen proposes to install a natural gas-fired boiler that will be used to provide the steam 

needed to operate the various processes and equipment at the facility. The boiler will have 

a maximum heat input capacity of 130 Million British Thermal Units per hour (MMBtu/hr) and will 

use only natural gas as fuel. 

 
2-2
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-3

 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-4

DWAY
2-5

Figure 4 Emission Point Locations 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-6

2.2.2 Ammonia Plant 

The NH3 plant will consist of two trains, capable of producing a total of 200 tons of synthetic NH3

per day, or 68,000 tons per year. Synthetic ammonia refers to NH3 that has been synthesized from 

natural gas. The natural gas molecules are reduced to carbon and hydrogen. The hydrogen is 

then purified and reacted with nitrogen, which is obtained from the air, at a molar ratio of 3 to 1. 

The gas is then compressed and condensed to a liquid. 

The process of reducing the natural gas molecules to carbon and hydrogen is called 

the catalytic steam reforming method. Six steps are required to produce synthetic NH3 using 

this method: 

(1) Natural gas desulfurization 

(2) Catalytic steam reforming 

(3) CO shift 

(4) Carbon Dioxide (CO2) removal 

(5) Methanation 

(6) NH3 synthesis 

The first, third, fourth, and fifth steps remove impurities such as sulfur, CO, CO2, and water from 

the feedstock, hydrogen, and synthesis gas streams. In the second step, hydrogen is 

manufactured and nitrogen (air) is introduced. The sixth step produces anhydrous NH3 from 

the synthetic gas. 

2.2.2.1 Natural Gas Desulfurization 

In this step of the NH3 synthesis process, sulfur contained in the natural gas feedstock is removed 

using zinc oxide. 

2.2.2.2 Catalytic Steam Reforming 

After desulfurization, the natural gas feed is mixed automatically with steam in 

the Steam-Feed Preheater, and the mixture is sent to the primary reformer. The reformer uses 

indirect heating fired on natural gas. The process stream passes downward through the catalyst 

filled tubes in the reforming furnace, producing a gas containing hydrogen, CO, CO2, steam, and 

methane. The partially reformed gas then flows to the Secondary Reformer, where it is combined 

with preheated, compressed air in a specially designed mixer to form a final “synthesis gas” having 

a hydrogen-to-nitrogen ration of 3 to 1. This process step is an exothermic reaction that does not 

require an external source of heat. The gas leaving the secondary reformer is then quenched with 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-7

process condensate. Below the combustion chamber is a catalyst bed in which the remaining 

methane, approximately 70%, is converted to hydrogen and carbon oxides (CO and CO2). 

2.2.2.3 Carbon Monoxide Shift 

CO is formed as a byproduct in the catalytic steam reforming process as described above. Most of 

the CO and water contained in the hot synthesis gas stream are converted to CO2 and hydrogen in 

the CO Converter in the presence of a conversion catalyst. Unreacted steam is condensed and 

separated from the synthesis gas in the Knockout Drum. 

2.2.2.4 Carbon Dioxide Removal 

After the CO shift, the CO2 is removed from the process gas by cooling the gas and sending it 

through the CO2 Absorber, an absorption tower. There, the CO2 is removed from the gas by 

absorption in methyl diethanolamine (MDEA) solution. The MDEA solution is regenerated in 

the Amine Regenerator and recirculated through the CO2 Absorber in a continuous cycle. Initially, 

the CO2 gas (approximately 91% pure) will be captured and vented to the atmosphere. At a later 

date, efforts will be made to capture this CO2 for commercial use at another facility. 

2.2.2.5 Methanation 

Upon leaving the CO2 absorber, the synthesis gas consists primarily of uncombined hydrogen and 

nitrogen with residual amounts of CO2 and CO. The final purification of the reformed gas takes 

place by reheating the gas and passing it through the Methanator. In the Methanator, 

the carbon oxides contained in the gas are catalytically converted to methane and water. 

The purified synthesis gas is cooled; the water vapor condensed and separated, and flows to 

the compressor Knockout Drum. 

2.2.2.6 Ammonia Synthesis 

In this final step, the hydrogen and nitrogen-rich synthesis gas is converted to NH3. The process is 

not 100% efficient, and some of the unconverted synthesis gas leaving this step is mixed with 

incoming raw synthesis gas and recycled back through the process. 

The plant contains one multi-service reciprocating Compressor. The Compressor has four services: 

NH3 synthesis gas, NH3 recycle gas, process air, and refrigeration NH3. The Compressor is of 

horizontal-opposed configuration and is driven by an electric motor coupled to the compressor 

shaft. Lubrication of the frame is provided by a frame driven oil pump. A water-cooled oil cooler 

and an oil filter are included in the frame lubricating system. 
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US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-8

After methanation, the synthesis gas is compressed and joined by the recycled synthesis gas and 

passed through the Gas Filter to remove entrained compressor oil and water. Any NH3 in 

the synthesis gas, which is condensed at this point in the process, is separated from 

the unconverted synthesis gas and sent to the separator. The gas from the filter then passes 

through the shell side of the Loop Heat Exchanger. The gas is cooled in the Loop Heat Exchanger 

and then flows through the Secondary Ammonia Condenser, where it is further cooled, thereby 

condensing a large portion of the NH3 present in the gas. Cooling takes place by evaporation of 

refrigerant NH3 in a closed-system. 

The NH3-synthesis gas mixture flows to the Secondary Ammonia Separator, where the liquid NH3 is 

separated before the gas passes through the tube side of the Loop Heat Exchanger. 

The unconverted synthesis gas flows to the Ammonia Converter, where the gas stream is 

preheated by a heat exchanger in the Converter and flows downward through the catalyst bed. 

The converter uses an iron oxide catalyst to react hydrogen and nitrogen to form NH3. 

NH3 in the gas leaving the Converter passes to the Primary Ammonia Condenser, where 

water cooling reduces the temperature of the gas stream and thereby condenses a portion of 

the product NH3. From the Primary Ammonia Condenser, the NH3-synthesis gas mixture flows to 

the Primary Ammonia Separator where the liquid NH3 is separated. The synthesis gas is returned as 

recycled gas to the Compressor, except for a small quantity which is purged to control the quantity 

of inert gases (methane and argon) in the system. Ammonia sent to the separator is flashed to 

remove impurities from the liquid. The NH3-rich flashed vapor then undergoes pressure reduction 

to be condensed in a chiller, where anhydrous NH3 flows to the Battery Limits and is stored as 

a liquid until it is used to produce nitric acid, ANSOL, and/or sold commercially. 

2.2.3 Nitric Acid Plant 

The nitric acid plant will have the capacity to produce up to 500 tons per day of weak nitric acid. 

Weak nitric acid can have concentrations ranging from 30 to 70 percent nitric acid. To produce 

nitric acid, US Nitrogen will utilize a high-temperature catalytic oxidation process using the NH3

produced in the process described previously in Section 2.2.2. This process will consist of 

three steps: 

(1) NH3 oxidation, 

(2) Nitric oxide oxidation, and 

(3) Absorption. 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-9

2.2.3.1 Ammonia Oxidation 

In this process, the NH3 is mixed with ambient air, heated, and then passed over a platinum 

catalyst, where the NH3 is oxidized to nitric acid. The raw materials required for production of 

nitric acid are atmospheric air and NH3. These raw materials are combined at elevated temperature 

and pressure and passed over a platinum-containing catalyst, where the NH3 reacts with oxygen in 

the air. The resultant process gas is passed through the heat exchanger train where 

the major portion of this reaction energy is recovered as heat. 

2.2.3.2 Nitric Oxide Oxidation 

The nitric oxide rich gas stream is first cooled in a waste heat recovery boiler and then further 

cooled in a cooler condenser. Under these conditions, the nitric oxide formed during the NH3

oxidation step is further oxidized to nitrogen dioxide and nitrogen tetroxide. A portion of 

the reaction energy recovered in the heat exchanger train is used to reheat the tail gas to provide 

power for the air compressor by driving a hot gas expander. 

2.2.3.3 Absorption 

The final step sends the nitrogen dioxide and nitrogen tetroxide mixture from the condensation 

step to the bottom of an absorption tower, where it flows countercurrent to water introduced at the 

top of the tower. Nitric acid is formed by contact of the nitrogen dioxide and tetroxide with water 

and is removed at the bottom of the absorption tower. The bottom absorption tray produces acid 

at the product concentration, which then flows into the bleacher section. In the bleacher, 

the product acid contacts a counter-current flow of bleach air which strips the remaining dissolved 

NOX from the acid. The stream of clear, bleached acid is then allowed to flow under pressure 

to storage. 

The heat produced in the oxidation and absorption reactions is removed by cooling water passing 

through coils on the trays in the lower section of the column. Tail gas, now reduced in NOX content 

to approximately 1,000 parts per million (ppm) by volume, leaves the absorber and flows to the tail 

gas reheating system. Tail gas first enters the bleach air cooler before entering the shell side of 

the tail gas heater. The tail gas is preheated sufficiently to avoid process gas condensation in 

the tail gas heater and then enters the tail gas heater. 

The tail gas is heated to approximately 600°F in the tail gas heater. It then flows to the expander 

gas heater where it is further heated to 1200°F after being fed to the steam superheater. Tail gas 

from the hot gas expander then flows to the NOX emission control system. 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-10

The majority of the compression power required for the plant is extracted from the heated tail gas 

in the hot gas expander. The tail gas is discharged from the expander, flows through the NOX

emission control system and into the economizer to preheat boiler feedwater. The tail gas then 

exhausts to the atmosphere through the stack. 

2.2.4 ANSOL Plant 

The ANSOL plant will have the capacity to produce a maximum of 420 tons of ANSOL per day, or 

130,000 tons per year. ANSOL is produced by the neutralization of nitric acid with NH3. 

The resulting aqueous ammonium nitrate solution will be sent to various Austin Nitrogen facilities 

for further processing, or sold as a raw material to customers. 

ANSOL (84 % by weight) is produced in the neutralizer by the reaction between NH3 vapor and 

nitric acid. The NH3 required for the reaction is provided by vaporizing liquid NH3. Nitric acid is 

supplied from the battery limits to the neutralizer. The NH3 is mixed with the nitric acid by 

a sparger system in the bottom of the neutralizer. The NH3 flow to the neutralizer is flow 

ratio-controlled to the nitric acid flow to obtain the proper reaction. A smaller amount of acid is 

added to the neutralizer based on the pH of the neutralizer mixture and is used for fine control. 

Product ANSOL overflows from the neutralizer to the ANSOL surge tank where it is then pumped to 

the storage tanks. 

The heat of reaction generated in the neutralizer boils off steam, which passes overhead into 

the ammonium nitrate scrubber along with a small amount of unreacted NH3. The steam is used to 

vaporize the NH3 feed. The function of the ammonium nitrate scrubber is to condense enough 

steam to control the ammonium nitrate concentration of the scrubber and consequently 

the neutralizer and to remove the unreacted NH3 in the rising gases. Dilute ammonium nitrate is 

externally cooled in the circulated ANSOL cooler, and upon recirculation to the scrubber packing, 

condenses water from the stream for concentration control and neutralizes the unreacted NH3 in 

the gas stream. A small amount of nitric acid is added to the ammonium nitrate scrubber to 

maintain the acid-rich conditions necessary for neutralization of the unreacted NH3. Dilute 

ammonium nitrate formed in the scrubber overflows back to the neutralizer. 

The overhead gases from the ammonium nitrate scrubber, which are now primarily water, are fed 

to the vent scrubber for removal of remaining traces of NH3 and entrained ammonium nitrate. 

The vent scrubber is circulated with process condensate that is externally cooled in the circulated 

condensate cooler. The cooled, circulated, process condensate condenses a portion of the water in 
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US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-11

the overhead gases in the packed bed section. The amount of water condensed is controlled to 

provide the absorber feedwater required for the nitric acid plant. 

2.2.5 Nitric Acid Storage Tank 

US Nitrogen will install one nitric acid storage tank capable of storing 1,667 tons of weak nitric acid 

(60%). The tank will have an estimated capacity of 500,000 gallons. The vents from the nitric acid 

tank will be piped to the NOX emission control system at the nitric acid plant under vacuum. 

Approximately every 90 days the NOX emission control system will be shut down for approximately 

24 hours. During that time, the ANSOL production process will continue running, which will pull 

nitric acid from the tank, while no additional nitric acid is added. 

2.2.6 ANSOL Storage Tank 

US Nitrogen will install one ANSOL storage tank capable of storing 2,956 tons, on an 84% basis. 

The tank will have an estimated capacity of 700,000 gallons. The ANSOL tank will be heated with 

steam to maintain a temperature at or above 170 ̊F. ANSOL will start to solidify or crystallize to 

ammonium nitrate at or below temperatures of 168 ̊F. 

2.2.7 Cooling Tower 

Cooling water will be used in various places throughout the plant for process cooling needs. 

The cooling tower will utilize a wet, mechanical induced-draft design, incorporating two or three cells. 

As the cooling water is used in the process, it is heated. The warm cooling water is pumped to 

the cooling tower, where the heat is rejected to the atmosphere. The cooling water is pumped to 

the top of the cooling tower cell and flows over a series of louvers or baffles as gravity pulls it to 

the basin. As air is forced through the louvers by mechanical fans, a portion of the warm water 

evaporates, effectively cooling the remaining water supply. During this process, some minute 

amounts of water become entrained in the airflow and leave the cooling tower in the form of drift 

and mist. Since a cooling tower tends to concentrate dissolved solids (within set design 

parameters), this entrained water becomes a source of particulate matter (PM) emissions. 

The cooling tower will have three cells and serve the design heat duty with a recirculating 

cooling water flow rate of 45,000 gallons per minute. The drift rate will not exceed 0.0005%. 

2.2.8 Firewater Pump 

US Nitrogen will install a diesel-powered emergency firewater pump to provide fire-fighting 

capability. The diesel engine, which will be rated at approximately 400 horsepower (hp), will be 

routinely tested, as required by Federal, state, and local fire codes. The engine will be 
PSD Permit Application 

US Nitrogen 

Midway, Tennessee 

August 2011, Revision 1.0 

2-12

Tier II-compliant to meet required emissions standards under 40 CFR 60, Subpart IIII, for 

stationary compression ignition internal combustion engines. 

2.2.9 Flare 

A flare stack will be installed primarily to mitigate CO emissions during NH3 unit startup and to 

combust vent gas during safety relief. Normal emissions from the flare will be no more than those 

associated with operation of the 5 MMBtu/hr flare pilots and purge gas. 

2.3 Project Emissions 

Table 2-1 below summarizes the projected annual emissions from this project. Calculations 

supporting projected annual emissions are contained in Appendix B. 

 
2-13

Table 2-1 

Projected Annual Emissions (TPY) 

Source Description PM PM10 PM2.5 SO2 NOX VOC CO CO2 CH4 Cooling Tower 0.59 0.46 0.46 — — — — — — Firewater Pump 0.01 0.01 0.01 0.04 0.13 0.05 0.11 24 0.001 Boiler 3.19 3.19 3.19 0.25 4.28 2.31 17.14 50,061 0.944 Flare 0.00 0.00 0.00 0.01 2.32 0.47 2.71 2,848 0.053 Plant Road1 7.97 2.12 0.23 — — — — — — Nitric Acid Plant — — — — 54.80 — — — — 2ANSOL Plant 7.97 1.97 1.36 — — — — — — Ammonia Train 1 — Flue Gas 1.45 1.45 1.45 0.10 7.45 1.05 30.66 22,380 0.422 Ammonia Train 1 — CO2 Vent — — — — — — 4.54 45,394 — Ammonia Train 2 — Flue Gas 1.45 1.45 1.45 0.10 7.45 1.05 30.66 22,380 0.422 Ammonia Train 2 — CO2 Vent — — — — — — 4.54 45,394 — 

Total US Nitrogen Emissions: 22.63 10.65 8.15 0.50 76.43 4.93 90.36 188,481 1.842 2

Emissions from Potential Commercial Facility Non-Condensable Gas Vent — — — — — — 6.12 5,305 3.440 Cooling Tower 0.59 0.46 0.46 — — — — — — 

Total Project Emissions 

Including Potential Facility2: 23.22 11.11 8.61 0.50 76.43 4.93 87.40 102,998 5.282 2

Note: 

1. Emissions include truck traffic from proposed commercial facility, which would share the same entrance road. 2. The US Nitrogen ammonia plant CO2 vents would be routed to the proposed commercial facility, therefore, Total Project Emissions = 

– Ammonia Train CO2 Vents + Emissions from Potential Commercial Facility. 

3. CO2e = Carbon dioxide equivalents
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3.0 REGULATORY ANALYSIS 

The proposed US Nitrogen facility will be subject to both federal and State of Tennessee air quality 

regulations. These regulations impose permitting requirements and specific standards for expected 

air emissions. The standards and regulations that apply to the proposed US Nitrogen facility 

include: 

 NAAQS established by the United States Environmental Protection Agency (EPA) for specific 

criteria pollutants (40 CFR 50) 

 New Source Review to determine if the facility meets the requirements of the PSD 

regulations (40 CFR 52.21) 

 New Source Performance Standards (NSPS) which impose emission standards on 

new facilities (40 CFR 60) 

 Hazardous Air Pollutant (HAP) regulations for specific categories and subcategories of HAPs 

(40 CFR 63) 

 Tennessee Air Pollution Control Regulations. 

Detailed discussions of these regulations as they pertain to the proposed US Nitrogen facility are 

provided in the following sections. 

3.1 National Ambient Air Quality Standards 

The Clean Air Act (CAA) Amendments of 1970 mandated that the EPA establish NAAQS to protect 

the public health and welfare. The EPA has promulgated standards for six criteria pollutants: 

PM less than or equal to 10 microns in size (PM10) and less than or equal to 2.5 microns in size (PM2.5), 

SO2, CO, ozone (O3), NO2, and lead (Pb). 

The primary NAAQS are promulgated to protect the public health, and the secondary NAAQS are 

promulgated to protect the public welfare from any known or anticipated adverse effects associated 

with the presence of pollutants in the ambient air. Areas in violation of the NAAQS are designated 

as nonattainment areas and new sources to be located in or near these areas may be subject to 

more stringent air permitting requirements. The existing applicable NAAQS are presented in 

Table 3-1. 
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Table 3-1 

NAAQS and PSD Increments and Significance Levels 

(μg/m3

, unless otherwise noted)[1,2]

Pollutant and Time Period 

NAAQS PSD 

Primary Secondary 

Class I 

Increment 

Class II 

Increment 

Significance 

Levels 

PM10

Annual Arithmetic Mean — — 4 17 1 

24-Hour Average 150 150 8 30 5 

PM2.5

Annual Arithmetic Mean 15.0 15.0 1 4 0.30 

24-Hour, 98th Percentile 35 35 2 9 1.2 

SO2

Annual Arithmetic Mean 80 — 2 20 1 

24-Hour Average 365 — 5 91 5 

3-Hour Average — 1,300 25 512 25 

1-Hour Average 196 — — — 7.84 

NO2

Annual Arithmetic Mean 100 100 2.5 25 1 

1-Hour Average 188 — — — 7.52 

CO 

8-Hour Average 10,000 — — — 500 

1-Hour Average 40,000 — — — 2,000 

O3

8-Hour Average (2008 standard)3 0.075 ppm 0.075 ppm — — —

8-Hour Average (1997 Standard) 0.08 ppm 0.08 ppm — — —

1-Hour Average 0.12 ppm 0.12 ppm — — —

Pb 

Rolling 3-Month Average 0.15 0.15 — — —

Quarterly 1.5 — — — —

Notes: 

1. NAAQS Sources: 40 CFR Part 50 and TAPCR 1200-03-03-.03(1)(a);PSD Class Increments and Significance Level 

Sources: 40 CFR Part 52.21(c) and TAPCR 1200-03-09-.01(m) 

2. μg/m3 denotes microgram per cubic meter 

3. The 2008 ozone standard is currently under reconsideration by EPA and has not yet taken effect 

3.2 PSD Requirements 

3.2.1 General Requirements 

Under federal and State of Tennessee PSD review requirements, all major new or modified sources 

of air pollutants regulated under the CAA must be reviewed and a pre-construction permit issued. 

Tennessee’s State Implementation Plan (SIP), which contains PSD regulations, has been approved 

by EPA, and EPA has granted PSD approval authority to the TDAPC. 

A “major facility” is defined as any one of 28 named source categories that have the potential to 

emit 100 tons per year (TPY) or more or any other stationary facility that has the potential to emit 

250 TPY or more of any pollutant regulated under the CAA. “Potential to emit” means 
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the capability, at maximum design capacity, to emit a pollutant after the application of 

control equipment. 

A “major modification” is defined under PSD regulations as a change at an existing major facility 

that increases emissions by greater than significant amounts. PSD significant emission rates are 

shown in Table 3-2. 

Table 3-2 

PSD Significant Emission Rates and Monitoring De Minimis Levels [1]

Pollutant 

PSD Significant 

Emission Rate (TPY) 

De Minimis Ambient Levels 

Concentration 

(μg/m3

)[2] Averaging Time 

PM 25 10 24-Hour 

PM10 15 10 24-Hour 

PM2.5 10 — — 

SO2 40 13 24-Hour 

NOX 40 14 Annual 

CO 100 575 8-Hour 

Ozone (VOCs or NOX) 40 — — 

Pb 0.6 0.1 3-Month 

Fluorides 3 0.25 24-Hour 

Sulfuric Acid Mist 7 — — 

Hydrogen Sulfide (H2S) 10 0.2 1-Hour 

Total Reduced Sulfur (including H2S) 10 10 1-Hour 

Reduced Sulfur Compounds (including H2S) 10 10 1-Hour 

Greenhouse Gases (CO2e)[3] 75,000 — —

Notes: 

1. Source: 40 CFR 52.21 

2. μg/m3 = microgram per cubic meter 

3. CO2e = Carbon dioxide equivalents 

EPA has promulgated regulations that define certain increases above ambient air quality baseline 

concentrations for NO2 and CO as constituting significant deterioration. The EPA class designations 

and allowable PSD increments are presented in Table 3-1. The State of Tennessee adopted 

the EPA class designations and allowable PSD increments for NO2 and CO increments. 

HAPs previously regulated under the National Emission Standards for Hazardous Air Pollutants 

(NESHAP) program are exempt from federal PSD applicability because the HAPs are now regulated 

under Title III of the CAA Amendments of 1990. 

PSD review is used to determine whether significant air quality deterioration will result from 

the new or modified facility. Federal PSD requirements are contained in 40 CFR 52.21, 

Prevention of Significant Deterioration of Air Quality. The State of Tennessee has adopted 
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PSD regulations in TAPCR 1200-03-09-.01(4). Major new facilities and major modifications are required 

to undergo the following analysis related to PSD for each pollutant emitted in significant amounts 

 Control technology review 

 Source impact analysis 

 Air quality analysis (monitoring) 

 Source information 

 Additional impact analyses 

In addition to these analyses, a new facility must also be reviewed with respect to 

Good Engineering Practice (GEP) stack height regulations. Discussions concerning each of 

these requirements are presented in the following sections. 

The projected emissions from this proposed project are estimated to exceed the significant 

emission rates for multiple pollutants, as summarized in Table 1-1. Therefore, PSD review 

is required. 

3.2.2 Control Technology Review 

PSD regulations concerning control technology review require that all applicable federal and state 

emission standards be met, and that BACT be applied to control emissions of subject pollutants 

from the source. The BACT requirements are applicable to pollutants that exceed 

the PSD-significance level if the facility is a new source that qualifies as a major PSD source, or to 

all regulated pollutants for which the increase in emissions from the facility or modification exceeds 

the significant emission rates listed in Table 3.2. Basically, major sources must install the most 

effective emission controls considered technically feasible by the permitting authority, taking into 

consideration environmental, energy, and economic impacts. 

The requirement for BACT was contained in the PSD requirements prescribed by 

the CAA Amendments of 1977. The premise behind the BACT requirement was that it would 

optimize the consumption of the available PSD air quality increments and thereby maximize 

the potential for future economic growth without significantly degrading air quality. Guidelines for 

the evaluation of BACT can be found in EPA’s Guidelines for Determining Best Available Control 

Technology (EPA, 1978) and the PSD Workshop Manual (EPA, 1980). These guidelines were 

established by EPA to provide a consistent approach to BACT and to ensure that the impacts of 

alternative emission control systems are measured by the same set of parameters. In addition, 

through implementation of these guidelines, BACT in one area may not be identical to BACT in 
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another area. According to EPA (1980), “BACT analyses for the same types of emissions unit and 

the same pollutants in different locations or situations may determine that different control 

strategies should be applied to the different sites, depending on site-specific factors. Therefore, 

BACT analyses must be conducted on a case-by-case basis.” Further discussion of BACT, including 

a full BACT analysis for all applicable pollutants, can be found in Section 4. 

3.2.3 Source Impact Analysis 

All PSD applicants must conduct air quality analyses to assess the ambient impacts associated with 

construction and operation of the facility. A separate air quality analysis must be submitted for 

each regulated pollutant for which the applicant proposes to emit in a significant amount from 

a new or modified major source. The main purpose of the analysis is to demonstrate that 

the new emissions from the source, in conjunction with related emissions from other sources, will 

not cause or contribute to a violation of any applicable NAAQS or PSD increment. 

Additional studies are performed to evaluate effects on visibility and soils and vegetation. 

The PSD regulations specifically provide for the use of atmospheric dispersion models in performing 

analyses, estimating baseline and future air quality levels, and determining compliance with NAAQS 

and allowable PSD increments. Designated EPA models normally must be used in performing 

the impact analysis. Specific applications for other than EPA approved models require EPA’s 

consultation and prior approval. Guidance for the use and application of dispersion models is 

presented in 40 CFR 51, Appendix W — Guideline on Air Quality Models. The source impact 

analysis for criteria pollutants to address compliance with the NAAQS and PSD increments may be 

limited to the new or modified source if the net increase in impacts as a result of the new or 

modified source is below significance levels, as presented in Table 3.1. As is demonstrated in 

Section 5 and Appendix C, the proposed US Nitrogen facility will be in compliance with all applicable 

NAAQS and PSD increments. 

Class I areas are pristine areas (e.g., National Parks and Wilderness Areas) that have been 

designated by Congress and are afforded a greater degree of air quality protection. There are 

six Class I areas located within 300 kilometers (km) of the facility. Table 3-3 lists the Class I areas 

within 300 km of the site of the proposed US Nitrogen facility and their relative distances from 

the proposed facility location. 
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Table 3-3

Class I Areas within 300 km of Proposed US Nitrogen Site 

Class I Area Managed By Distance from US Nitrogen (km) 

Great Smoky Mountains NP National Park Service 47 

Shining Rock US Forest Service 85 

Linville Gorge US Forest Service 102 

Joyce Kilmer - Slickrock US Forest Service 116 

Cohutta US Forest Service 187 

Mammoth Cave NP National Park Service 288 

US Nitrogen consulted with the Federal Land Managers (FLMs) responsible for the Class I areas 

within 300 km of the proposed US Nitrogen site regarding the need for modeling analyses to assess 

the impacts of emissions from this source on Class I visibility and air quality related values (AQRV). 

The FLMs for the National Park Service and the Forest Service each indicated that the increase in 

emissions due to this proposed project would likely result in no adverse impacts to any AQRVs at 

their respective Class I areas. Therefore, additional impact analysis is not required at this time. 

Copies of correspondence with the FLMs are included in Appendix D. There are several receptors 

at the Great Smoky Mountain National Park that are located less than 50 km from the proposed 

site. The FLMs requested a near-field impacts and visibility analysis for these receptors. The Class 

I analysis documented in Section 5 and Appendix C demonstrate impacts less than the Class I 

significant impact levels and no adverse effects on visibility.

3.2.4 Air Quality Monitoring Requirements 

In some circumstances, an application for a PSD permit must contain an analysis of continuous 

ambient air quality data in the area affected by the proposed major stationary facility or major 

modification. For a new major facility, the affected pollutants are those that the facility potentially 

would emit in significant amounts. For a major modification, the pollutants are those for which 

the new emissions increase exceeds the significant emission rate. However, if the predicted 

ambient impact (i.e., the modeled concentration for the applicable averaging time, caused by 

the proposed significant emission increase) is below the prescribed significant monitoring value, 

the applicant can be exempt from this data requirement. 

Where required, ambient air monitoring for a period of up to one year is generally appropriate to 

satisfy the PSD monitoring requirements. A minimum of four months of data is required. 

Existing data from the vicinity of the proposed source may be used if the data meet certain 

quality assurance requirements, otherwise, additional data may be needed. Guidance on designing 

a PSD monitoring network is provided in EPA’s Ambient Monitoring Guidelines for Prevention of 

Significant Deterioration (EPA, 1987a). 
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As described in the air modeling report in Appendix C, NO2 impacts from the facility are less than 

the de minimis levels presented in Table 3-2; thus, air monitoring is not required. 

3.2.5 Source Information/Good Engineering Practice Stack Height 

Source information must be provided to adequately describe the proposed project. General process 

descriptions for the proposed operations at the new US Nitrogen Facility are presented in Section 2. 

The 1977 CAA Amendments require that the degree of emission limitation required for control of 

any pollutant not be affected by a stack height that exceeds GEP or any dispersion technique. 

On July 8, 1985, EPA promulgated final stack height regulations (EPA, 1985a). Identical regulations 

have been adopted by Tennessee (TDAPC Rule 1200-03-24). GEP stack height is defined as 

the highest of: 

1. 65 meters (213 feet); or 

2. A height established by applying the formula: 

Hg = H + 1.5L 

Where Hg is the GEP stack height, H is the height of the structure or nearby 

structure, and L is the lesser dimension (height or projected width) of nearby 

structure(s); or 

 

3. A height demonstrated by a fluid model or field study. 

“Nearby” is defined as a distance up to five times the lesser of the height or width dimensions of 

a structure or terrain feature, but not greater than 0.8 km. Although GEP stack height regulations 

require that the stack height used in modeling for determining compliance with NAAQS and PSD 

increments not exceed the GEP stack height, the actual stack height may be greater. 

The stack height regulations also allow increased GEP stack height beyond that resulting from 

the above formula in cases where plume impaction occurs. Plume impaction is defined as 

concentrations measured or predicted to occur when the plume interacts with the elevated terrain. 

Elevated terrain is defined as terrain that exceeds the height calculated by the GEP stack 

height formula. 
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3.2.6 Additional Impact Analysis 

In addition to air quality impact analyses, federal and TDAPC PSD regulations require analyses of 

the impairment to visibility and the impacts on soils and vegetation that would occur as a result of 

the proposed source [40 CFR 52.21(o)]. These analyses are to be conducted primarily for PSD 

Class I areas. Impacts as a result of general commercial, residential, industrial, and other growth 

associated with the source also must be addressed and are discussed in Section 6. These analyses 

are required for each pollutant emitted in significant amounts. 

3.3 Nonattainment Rules 

Based on the current nonattainment provisions, all major new facilities and modifications to existing 

major facilities located in a nonattainment area must undergo nonattainment review. A new major 

facility is required to undergo this review if the proposed pieces of equipment have the potential to 

emit 100 TPY or more of the nonattainment pollutant. A major modification at a major facility is 

required to undergo review if it results in a significant net emission increase of 40 TPY or more of 

the nonattainment pollutant or if the modification is major (i.e., 100 TPY or more). 

The proposed US Nitrogen site is located in Greene County, which is classified as 

an attainment/unclassified area for all criteria pollutants. Therefore, nonattainment requirements 

are not applicable. 

3.4 Emission Standards 

3.4.1 New Source Performance Standards — 40 CFR 60 

The NSPS are a set of national emissions standards that apply to specific categories of 

new sources. As stated in the CAA Amendments of 1977, these standards “shall reflect the degree 

of emission limitation and the percentage reduction achievable through application of 

the best technological system of continuous emissions reduction the Administrator determines has 

been adequately demonstrated.” A review of 40 CFR 60 was performed to identify potentially 

applicable requirements. 

40 CFR 60, Subpart A — General Provisions. Subpart A specifies notification, recordkeeping, 

performance testing, and monitoring requirements. This subpart applies to all sources subject to 

this part (40 CFR 60). 

40 CFR 60, Subpart IIII — Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines. This subpart applies to owners and operators of stationary compression 

ignition (CI) internal combustion engines (ICE) that commence construction after July 11, 2005. 
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The proposed firewater pump engine will be subject to Subpart IIII. This engine is subject to 

the emission standards listed in Table 4 of this subpart. 

40 CFR 60, Subpart Db — Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units. This subpart applies to each steam generating unit that commences 

construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity 

of greater than 100 MMBtu/hr. The proposed steam generating boiler will have a maximum heat 

input capacity of 130 MMBtu/hr. 

40 CFR 60, Subpart G — Standards of Performance for Nitric Acid Plants. This subpart applies to 

each nitric acid production unit that begins construction or modification after August 17, 1971. 

This process will be subject a NOX emission limitation and continuous emissions 

monitoring requirements. 

3.4.2 National Emission Standards for Hazardous Air Pollutants (MACT) — 40 CFR 63 

The EPA has promulgated emissions standards for HAPs for various industrial categories. 

These NESHAPs that resulted from the 1990 CAA Amendments are based on the use of 

Maximum Achievable Control Technology (MACT). The adopted standards are contained in 

40 CFR 63. Affected sources are required to apply MACT for the promulgated industrial category or 

to obtain a case-by-case MACT determination from the applicable regulatory authority after 

submitting a MACT analysis. The proposed US Nitrogen facility will be an area source of HAP 

emissions, emitting less than 10 tons per year of each individual HAP and less than 25 tons per 

year of a combination of HAPs. 

40 CFR 63, Subpart A — General Provisions. Subpart A specifies notification, recordkeeping, 

performance testing, and monitoring requirements. This subpart applies to all sources subject to 

this part (40 CFR 63). 

40 CFR 63, Subpart ZZZZ — National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines. As a new stationary RICE located at an area 

source of HAPs, per §63.6590(c)(1), the firewater pump engine must meet the requirements of 

Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart IIII for compression ignition 

engines. Therefore, as discussed earlier, this engine is subject to the requirements of 40 CFR 60, 

Subpart IIII — Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines. 
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40 CFR 63, Subpart JJJJJJ — National Emission Standards for Hazardous Air Pollutants for 

Industrial, Commercial, and Institutional Boilers Area Sources. Per §63.11195(e), gas-fired boilers, 

as defined in §63.11237, are not subject to any requirements of Subpart JJJJJJ. 

3.4.3 Tennessee Air Permitting Requirements 

The TDAPC regulations require any new source to obtain an air permit prior to construction. 

Major new sources must meet the appropriate PSD and/or nonattainment requirements as 

discussed previously. Required permits and approvals for air pollution sources include NSR for 

nonattainment areas, PSD, NSPS, NESHAP, construction permits, and operating permits. 

The requirements for construction permits are contained in TDAPC Rule 1200-03-09-.01. 

3.5 Other Requirements 

3.5.1 Title V Program 

The 1990 CAA Amendments also established a federally-mandated air operating permit program. 

The program requires the states to adopt regulations consistent with the CAA and the implementing 

regulations promulgated by EPA in 40 CFR 70. The program applies to Title V or Part 70 sources 

that include major stationary sources of air pollutants. The State of Tennessee has adopted 

the requirements of 40 CFR 70 in TDAPC Rule 1200-03-09-.02 which specify that all affected 

sources have a Title V permit to operate. The projected emissions from this proposed project are 

estimated to exceed the thresholds for Title V applicability. 

3.5.2 Risk Management Program 

The 1990 CAA Amendments required both the EPA to issue regulations which would help prevent 

accidental releases of hazardous chemicals. EPA was required to address the consequences of 

accidental releases beyond a facility's property. The EPA met their obligation with the promulgation 

of 40 CFR 68, Accidental Release Prevention Requirements: Risk Management Programs Under 

the Clean Air Action Section 112(r)(7) in June 1996. The rule applies to all stationary sources that 

have a regulated substance present in a process in more than the listed threshold quantity. 

If the threshold quantity for a regulated substance is exceeded, then the facility would need to 

develop a risk management plan. The NH3 to be used at this facility will be anhydrous (100%) NH3 

which is above the regulated NH3 solution level of 20 percent aqueous NH3 solution. 

Thus, the facility is required to prepare a risk management plan. 
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3.5.3 General Duty Clause 

The facility is also subject to the general duty clause under Section 112(r)(I) of the CAA. 

The general duty clause directs owners and operators of stationary sources to identify hazards 

that may result from accidental releases, to design and maintain a safe facility, and to minimize 

the consequences of releases when they occur. The general duty clause applies to 

all stationary sources that have any "extremely hazardous substance" that are not limited to the list 

of regulated substances under Section 112(r) or under Occupational Safety and Health 

Administration’s regulations. 
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4.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS 

The PSD regulations require new and modified major stationary sources to apply BACT to 

each emission unit which is subject to regulation under the CAA and which has the potential to emit 

air pollutants in significant amounts as defined by 40 CFR 52.21(b)(23)(i) and 

TAPCR 1200-03-09-.01(4)(b)(24). The PSD regulations are applicable to sources located 

in attainment areas. Greene County is classified as attainment or unclassified for all 

regulated pollutants. 

BACT is essentially an emission limitation based on the maximum degree of reduction for 

each pollutant, on a case-by-case basis, taking into account technical feasibility, energy, 

environmental, and economic impacts. In no event can the application of BACT result in 

the emission of any pollutant which would exceed the emissions allowed by an applicable NSPS or 

NESHAP. The BACT is defined in the CAA as a numerical emission limit. The numerical limit can be 

based on the application of air pollution control equipment, specific production processes, methods, 

systems or techniques, or fuel cleaning or combustion techniques. 

Applicability 

The US Nitrogen facility is a major stationary source. The pollutants subject to review under 

the PSD regulations, and for which BACT analysis is required are shown in Table 1-1. 

BACT Analysis Approach 

Under the PSD program, newly constructed and modified major stationary sources in areas which 

are in attainment of the NAAQS must implement BACT. Economic as well as energy and 

environmental impacts are considered in a BACT analysis. The “top-down” BACT approach requires 

that a source not only consider the most stringent emission limits previously approved, but it also 

must evaluate all demonstrated and potentially applicable technologies, including innovative 

controls and lower polluting processes. These technologies and emission limits are identified 

through a review of EPA’s RACT/BACT/LAER Clearinghouse (RBLC), Federal/State/Local new source 

review permits, technical journals and reports, and other sources (See Appendix E for RBLC 

searches). If the proposed BACT is equivalent to the most stringent emission limit, no further 

analysis is necessary. However, if the most stringent emission limit is not selected, additional 

analyses are required. 

Once the most stringent emission limit has been identified, its technical feasibility must be 

determined. A technology that is available and is applicable to the source under review is 

considered technically feasible. A control technique is considered available if it has reached 
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the licensing and commercial sales stage of development. In general, a control option is 

considered applicable if it has been, or is soon to be, developed on the same or similar source type. 

If the control technique is technically feasible, that control is considered to be BACT unless 

economic, energy, or environmental impacts preclude its use. Therefore, if the chosen technology 

is not applicable or is technically or economically infeasible for the source in question, the next 

most stringent emission limits are evaluated. The process continues until an emission level cannot 

be eliminated. 

Impact Analysis of Control Alternatives 

When the most stringent technically feasible emission limitation is not selected as BACT, 

justification must be provided in terms of adverse environmental, energy, or economic impacts. 

The net environmental impact is the first analysis performed for each alternative. Both beneficial 

impacts and adverse impacts should be included in the analysis, including air pollutants not 

currently regulated under the CAA. Therefore, an analysis of unregulated air pollutants and their 

potential impact is required as part of the BACT analysis. 

The second analysis involves energy impacts. The direct energy impacts of the control alternatives 

are estimated in terms of energy consumption (Btu, barrels of oil, kWh, etc.) In addition, 

the impacts of relying on scarce fuels must be considered because of the possibility of a change in 

availability in subsequent years. 

The third analysis involves evaluating the economic impacts of control alternatives with primary 

consideration to the cost effectiveness (dollars per ton of pollutant removed) for each option. 

The analysis generally includes an estimate of capital annualized costs for each alternative based 

on vendor quotes and established EPA cost-estimating procedures. For the purposes of 

these economic impact analyses, a capital recovery rate of 15% was used which deviates from 

the guidance provided in the EPA Cost Control Manual. This rate was used to more accurately 

reflect the actual weighted cost of capital to US Nitrogen from both debt and equity sources, plus 

an allowance for the considerable risk associated with the construction and operation of this facility. 

(See Appendix F for a detailed analysis of US Nitrogen’s cost of capital.)

Enforceability 

An emission limit must be proposed for each emission unit subject to BACT and the emission limit 

must be federally enforceable. That is, the emission limit must be short-term and specific such that 

regulatory agency personnel can determine compliance at any time. 
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GHG BACT Analysis 

As of January 2, 2011, new EPA rules regulating GHG emissions from large facilities came into 

effect. The new rules modify certain permitting requirements under the Federal CAA, including 

PSD, to require that regulated facilities include GHG emissions in their permits. EPA’s new rules 

now provide that any facility that triggers PSD requirements for pollutants other than GHGs also will 

be subject to PSD requirements, including BACT, for GHGs if the new or modified source increases 

emissions by more than 75,000 TPY of CO2e. A summary of GHG pollutants for US Nitrogen is 

given in Table 4-1. Total GHG potential emissions exceed 75,000 TPY. 

Table 4-1 

US Nitrogen Potential Emissions of GHGs (TPY)

Pollutant Emissions (TPY) CO2e (TPY) 

CO2 188,481.6 188,481.6 

CH4 1.84 38.7 

N2O 29.3 9,078.0 

4.1 Point Source Emissions 

As stated earlier (See Section 1.0.), point sources at the US Nitrogen facility which emit NOX and 

GHG’s were considered in the BACT analysis. For simplicity and clarity, all GHG’s are considered 

together in this BACT analysis and are handled separately from the NOX emissions 

(See Section 4.2.). A summary of the individual emission point sources is shown in Table 4-2. 

While this section includes a brief description of the processes that result in the emissions being 

addressed in the BACT analysis, Section 2.2 provides a detailed description of all facility processes. 

Table 4-2 

US Nitrogen Emission Point Sources and Respective Potential Emissions (TPY) 

Source Description NOX CO2 CH4 N2O 

Ammonia Plant Train 1 — Flue Gas 7.5 22,380.0 0.422 0.042 

Ammonia Plant Train 1 — CO2 Vent — 45,394.3 — — 

Ammonia Plant Train 2 — Flue Gas 7.5 22,380.0 0.422 0.042 

Ammonia Plant Train 2 — CO2 Vent — 45,394.3 — — 

Nitric Acid Plant 54.8 — — 29.1 

Steam-Generating Boiler 4.3 50,061.1 0.944 0.094 

Firewater Pump 0.1 23.9 0.001 0.000 

Flare 2.3 2,848.0 0.053 0.006 

A summary of the proposed BACT for each NOX and GHG point source is shown in Table 4-3.
4-4 

Table 4-3

Summary of Proposed BACT for Each US Nitrogen Emission Source 

Pollutant Emission Source 

Control Technologies Considered 

In Descending Order of Reduction 

Lowest RBLC 

Emission Rate 

Control Technology

Associated With 

Lowest RBLC Rate 

Emission Rate 

Proposed As BACT 

Control T

Proposed 

NOX

Ammonia Plant Flue 

SCR 

0.41 lbs NOX/T NH3 LNB 0.41 lbs NOX/T NH3 SCR 

LNB SNCR 

Nitric Acid Plant 

SCR 

0.524 lbs NOX/T HNO3 SCR 0.6 lbs NOX/T HNO3 Extended absorp

NSCR Extended absorption 

Steam Boiler 

SCR plus LNB plus FGR 

0.01 lbs/MMBtu LNB 0.01 lbs/MMBtu UNLB plus FGR 

ULNB plus FGR LNB and FGR 

Firewater Pump Diesel engine design in accordance with 40 CFR 60, Subpart IIII 3.2 g/kWh None 3.0 g/hp-h Comply with 40 

IIII 

Flare Maintain high combustion efficiency by complying with 40 CFR 60.18 1.1 lbs/hr None 3.1 lbs/hr during SU, 0.49 lbs/hr during NO Comply with 40 

GHG From Combustion Sources 

All Combustion Sources 

CCS 

NA NA Various Energy and proc

Energy and process efficiency 

Concentrated CO2

Ammonia Plant CO2

vent 

CCS 

NA NA 90,788.6 TPY CO2e Process efficienc

Process efficiency 

N2O Nitric Acid Plant 

Tertiary controls — Catalytic Decomposition 

NA NA 29.1 TPY N2O 9021 TPY CO2e Primary plus ter

(catalytic decom

Tertiary controls — NSCR Primary controls 
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4.1.1 Ammonia Plant — Trains 1 and 2 

4.1.1.1 Process Description 

The Ammonia Plant will consist of two trains, capable of producing a total of 200 tons of synthetic 

NH3 per day (100 tons per train), or 68,000 tons per year. Synthetic NH3 refers to NH3 that has 

been synthesized from natural gas. The natural gas molecules are reduced to carbon and 

hydrogen. The hydrogen is then purified and reacted with nitrogen, which is obtained from the air, 

at a molar ratio of 3:1. The gas is then compressed and condensed to a liquid. 

The process of reducing the natural gas molecules to carbon and hydrogen is called 

the catalytic steam reforming method. Six steps are required to produce synthetic NH3 using 

this method: 

(1) Natural gas desulfurization 

(2) Catalytic steam reforming 

(3) CO shift 

(4) CO2 removal 

(5) Methanation 

(6) NH3 synthesis 

The first, third, fourth, and fifth steps remove impurities such as sulfur, CO, CO2, and water from 

the feedstock, hydrogen, and synthesis gas streams. In the second step, hydrogen is 

manufactured and nitrogen (air) is introduced. The sixth step produces anhydrous NH3 from 

the synthetic gas. 

4.1.1.2 Flue Gas 

The reaction in the primary reformer is highly endothermic; therefore, external heat must be added 

by the combustion of natural gas. The flue gas leaving the primary reformer is controlled at 

approximately 1950°F. It is cooled in an air preheater coil, waste heat boiler and the economizer 

before being exhausted to the atmosphere at 425°F. 

4.1.1.2.1 Flue Gas NOX Emissions 

There are three control technologies/methods available for reducing the NOX content of flue gas 

emissions from ammonia plants. These include, in descending order of removal efficiency, 

(1) Selective Catalytic Reduction (SCR), (2) low-NOX burners (LNB), and (3) Selective Non-catalytic 

Reduction (SNCR). 
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LNB’s minimize the formation of NOX by controlling the quantities and the way in which fuel and air 

are introduced and mixed in the reformer. LNB’s have the smallest impact on operating costs. 

SNCR and SCR are fundamentally similar, in that they use an NH3-containing reagent to react with 

the NOX produced in the reformer to convert the NOX to nitrogen and water. SNCR accomplishes 

this at higher temperatures (1700°F-2000°F) in the upper reformer region, while SCR operates at 

lower temperatures (about 700°F) and hence, needs a catalyst to produce the desired reaction 

between NH3 and NOX. SCR technology is capable of achieving much larger reductions in NOX

emissions, up to 90 percent, compared to 30 to 60 percent reductions achievable by SNCR. 

While the difference between the SNCR and SCR may seem minor, they result in significant 

differences in performance. In the case of SNCR, the reaction occurs in a somewhat uncontrolled 

fashion (e.g., the existing upper reformer becomes the NOX control reaction vessel, which is 

not what it was originally designed to be) while in the SCR case, a dedicated reactor and 

the reaction-promoting catalyst ensure a highly controlled, efficient reaction. Because of 

the uncontrolled manner in which the mixing of the flue gas and NH3 occurs in the upper part of 

the reformer and the need to achieve higher removal efficiencies to match the lowest emission rate 

found in the RBLC search, SNCR was not considered technically feasible. 

The results of a RBLC search using keywords “ammonia,” “reformer” and “fertilizer” identified 

three similar sources (See Appendix E for the details of the search). The lowest limit identified in 

the RBLC for NH3 reformers was 11.93 lbs/hr for a 700 ton per day (TPD) plant, or 0.41 lbs NOX/ton 

of NH3 (TNH3). The control method specified for this source is LNB and good combustion practices. 

4.1.1.2.1.1 Economic Analysis 

The economic impact of using SCR and LNB to reduce ammonia plant flue gas NOX emissions was 

evaluated by determining the cost per ton of NOX removed for each technology. Detailed Financial 

Analysis Worksheets are included in Appendix G, while Table 4-4 summarizes the results of 

the analysis.

The US Nitrogen facility will make use of existing ammonia and nitric acid plant equipment which 

are being re-located to the Greene County facility, including existing primary reformers for 

each train. In order to achieve an emission rate in the range of the lowest rate identified during 

the RBLC search using LNB, the reformers would need to rebuilt, thus significantly increasing costs. 
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Table 4-4

Financial Comparison of US Nitrogen Ammonia Plant NOX Reduction Options 1,2

 LNB SCR 

Inlet NOX (TPY) 52.3 52.3 

Outlet NOX (TPY) 19.7 7.5 

Reduction Efficiency (%) 62 86 

NOX Reduced (TPY) 32.6 44.8 

Total Capital Investment ($) $5,759,1003 $538,403 

Capital Recovery Cost ($/yr) $920,0823 $86,016 

O&M Annual Expense ($/y) $172,773 $117,627 

Total Annual Cost ($) $1,092,855 $203,643 

Cost Of NOX Removed ($/T) $33,523 $4,546 

Notes: 

1. See Appendix G, Tables G-1 and G-2 for detailed financial analysis worksheets. 

2. All costs, except the cost of each ton of NOX removed, and all emissions are per Ammonia Plant 

train, therefore each must be multiplied times two for the entire Ammonia Plant. 

3. Reflects the cost to rebuild the primary reformer to accommodate new LNB’s. 

4.1.1.2.1.2 Energy Impacts 

SCRs normally consume electrical energy, however, in the case of an SCR on the US Nitrogen 

Ammonia Plant, the NH3 can be mixed in an existing fan from the primary reformer, thus requiring 

no additional electricity. Use of LNB’s can result in some relatively minor reductions in efficiency. 

4.1.1.2.1.3 Environmental Impacts 

SCRs consume NH3 and unreacted NH3 will be emitted to the atmosphere (NH3 slip). NH3 is 

a precursor to the formation of PM10 and PM2.5 in the atmosphere. LNBs do not result in the direct 

emission of additional air pollutants and result in very minor indirect emissions. LNB’s require no 

reagents like NH3. 

4.1.1.2.1.4 Proposed BACT 

Because the use of LNB would require the re-building of the reformers, thus increasing capital costs 

considerably, an emission limit of 1.71 lbs/hr or 0.41 lbs NOX/TNH3 using SCR is proposed as BACT. 

This limit would apply to Ammonia Plant Trains 1 and 2. 

4.1.2 Nitric Acid Plant 

4.1.2.1 Process Description 

The nitric acid plant will have the capacity to produce up to 500 tons per day of weak nitric acid. 

Weak nitric acid can have concentrations ranging from 30 to 70 percent nitric acid. To produce 

nitric acid, US Nitrogen will utilize a high-temperature catalytic oxidation process using the NH3

produced in the process described previously. This process will consist of three steps: 
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(1) Ammonia oxidation, 

(2) Nitric oxide oxidation, and 

(3) Absorption. 

4.1.2.1.1 Ammonia Oxidation 

In this process, the NH3 is mixed with ambient air, heated, and then passed over 

a platinum catalyst, where the NH3 is oxidized to nitric acid. The raw materials required for 

production of nitric acid are atmospheric air and NH3. These raw materials are combined at 

elevated temperature and pressure and passed over a platinum-containing catalyst, where the NH3

reacts with oxygen in the air. The resultant process gas is passed through the heat exchanger train 

where the major portion of this reaction energy is recovered as heat. 

4.1.2.1.2 Nitric Oxide Oxidation 

The nitric oxide rich gas stream is first cooled in a waste heat recovery boiler and then further 

cooled in a cooler condenser. Under these conditions, the nitric oxide formed during the NH3 

oxidation step is further oxidized to nitrogen dioxide and nitrogen tetroxide. A portion of 

the reaction energy recovered in the heat exchanger train is used to reheat the tail gas to provide 

power for the air compressor by driving a hot gas expander. 

4.1.2.1.3 Absorption 

The final step sends the nitrogen dioxide and nitrogen tetroxide mixture from the condensation 

step to the bottom of an absorption tower, where it flows countercurrent to water introduced at 

the top of the tower. Nitric acid is formed by contact of the nitrogen dioxide and tetroxide with 

water and is removed at the bottom of the absorption tower. The bottom absorption tray produces 

acid at the product concentration which then flows into the bleacher section. In the bleacher, 

the product acid contacts a counter-current flow of bleach air which strips the remaining dissolved 

NOX from the acid. The stream of clear, bleached acid is then allowed to flow under pressure 

to storage. 

4.1.2.2 Nitric Acid Plant Stack NOX Emissions 

There are three control technologies/methods available for reducing the NOX content of 

stack emissions from nitric acid plants. These include, in descending order of removal efficiency, 

(1) SCR, (2) nonselective catalytic reduction (NSCR), and (3) extended absorption. 

All are considered technically feasible for use at the US Nitrogen facility. 
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Extended absorption reduces NOX emissions by increasing the efficiency of the existing process 

absorption tower or adding absorption tower height. In the catalytic reduction process, tail gases 

from the absorption tower are heated to ignition temperature, mixed with fuel (natural gas, NH3, 

hydrogen, propane, butane, or naphtha) and passed over a catalyst bed. In the presence of 

the catalyst, the fuels are oxidized and the NOX is reduced to nitrogen gas. 

There are two types of catalytic reduction used in nitric acid plants – NSCR and SCR. With NSCR 

systems, free oxygen in the tail gas must be eliminated by adding a fuel (usually natural gas) and, 

after completing this step, to provide for the reaction with the NOX, in the presence of a catalyst, to 

produce a tail gas with a reduced NOX concentration. The catalysts used in NSCR usually contain 

platinum or palladium. These noble metals are deposited on either alumina pellets or honeycomb 

type of substrate. 

With NSCR systems, most of the hydrocarbons from the natural gas are converted to CO2 and CO, 

resulting in additional emissions of 6,000-7,000 ppm CO2 and 300-400 ppm of CO, as well as 

some unburned hydrocarbons. 

With SCR systems, oxygen is not consumed before the NOX is reduced, and the NOX in the tail gas 

is selectively reduced in the presence of a catalyst. The SCR system can be installed on either side 

of the hot tail gas expander. The location depends on the temperature of the tail gas as it enters 

the expander. A small quantity of NH3 is mixed with the tail gas in a static mixer prior to being fed 

over the catalyst. In the reactor, tail gas flows through the catalyst where NOX is reduced to 

nitrogen. The tail gas leaves the reactor with a reduced NOX concentration of 33-150 ppm, 

depending on the NOX concentration at the inlet to the SCR, the amount of catalyst, and 

the reaction time. For nitric acid plants the inlet NOX concentration can range from 1,000-3,000 ppm 

depending on the extent to which NOX is reduced in the absorption tower. 

SCR systems are easier to operate than NSCR systems and they begin reducing NOX during plant 

startup much earlier than NSCR. Although there are some additional emissions of NH3 (known as 

slip) with SCR operation, there are no increases in emissions of CO2, CO, or unburned 

hydrocarbons. 

The results of a RBLC search of nitric acid plants identified eleven similar sources (See Appendix E 

for the details of the search.). The lowest emission limit identified in the RBLC was 0.524 lbs 

NOX/ton of 100% acid produced (T100% Acid). The control method specified is SCR. 
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A review of the permit for the facility for which this emission limit was set revealed the following 

information. The permit addresses two nitric acid plants — Plant 7 and Plant 9. Both plants existed 

at the time of the issuance of the permit. The limit of 0.524 lbs NOX/T100% Acid was set for Plant 7 

while a limit of 0.6 lbs NOX/T100% Acid was set for Plant 9. Plant 7 was equipped with SCR while 

Plant 9, at the time of the issuance of the permit, employed hydrogen peroxide injection. 

The permit states that the limit for Plant 7 (0.524 lbs NOX/T100% Acid) was set based on the fact that 

the SCR currently operating at Plant 7 was achieving that emission rate. The permit states that 

the emission rate for Plant 9 (0.6 lbs NOX/T100% Acid) was set based on the “preponderance 

of evidence” that SCR can routinely achieve that rate. 

4.1.2.2.1 Economic Analysis 

The economic impact of using NSCR and SCR to reduce NOX emissions from the nitric acid plant 

stack beyond the reductions achieved by the existing extended absorption tower was evaluated by 

determining the cost per ton of NOX removed for each. Detailed Financial Analysis Worksheets are 

included in Appendix G, while Table 4-5 summarizes the results of the analysis. Note that because 

NSCR reduces both NOX and N2O, for the purposes of the financial analysis, the costs of the NSCR 

have been split 80% for NOX reductions and 20% for N2O reductions. This split is based on the fact 

that incoming NOX concentrations to the NSCR would be approximately 2,000 ppm while incoming 

N2O concentrations would be approximately 500 ppm. 

Table 4-5

Financial Comparison of US Nitrogen Nitric Acid Plant NOX Reduction Options1

 NSCR2 SCR 

Inlet NOX (TPY) 1,643.9 1,842.9

Outlet NOX (TPY) 82.6 54.8 

Reduction Efficiency (%) 95 97 

NOX Reduced (TPY) 1,561.3 1,788.1 

Capital Recovery Cost ($) $1,519,840 $943,939 

Annualized Capital Investment ($/yr) $242,812 $150,805 

O&M Annual Expense ($/y) $671,390 $263,224 

Total Annual Cost ($) $914,202 $414,029 

Cost Of NOX Removed ($/T) $586 $232 

Notes: 

1. See Appendix G, Tables G-3 and G-4 for detailed financial analysis worksheets. 

2. Applied 80% of NSCR costs to the reduction of NOX and 20% to the reduction of N2O. 
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4.1.1.2.2.2 Energy Impacts 

Both NSCRs and SCRs consume electrical energy. In the case of the NSCR, additional electrical 

usage is estimated to be 30 megawatt hours per year (MWh/yr) while additional electrical usage for 

the SCR is estimated to be 44 MWh/yr. In addition, the NSCR would consume an estimated 

92.9 MMscf/yr (94,758 MMBtu/yr) of natural gas. 

4.1.1.2.2.3 Environmental Impacts 

Both NSCRs and SCRs consume resources — NH3 or natural gas. With an SCR unreacted NH3

would be emitted to the atmosphere (NH3 slip). NH3 is a precursor to the formation of PM10 and 

PM2.5 in the atmosphere. The additional electrical usage of both NSCR and SCR will result in 

the indirect emission of NOX, SO2, and CO2 from the generation of electricity. As stated earlier, with 

the NSCR system, most of the hydrocarbons from the natural gas are converted to CO2 and CO, 

resulting in additional emissions of 6,000-7,000 ppm CO2 and 300-400 ppm of CO, as well as 

some= unburned hydrocarbons. As noted earlier, NSCR reduces both NOX and N2O. 

4.1.1.2.2.4 Proposed BACT

As stated earlier, the US Nitrogen facility will make use of existing ammonia and nitric acid plant 

equipment which are being re-located to the Greene County facility. The existing nitric acid plant 

absorption tower is designed to reduce NOX emissions to 1,500-2,000 ppm, which is about 

1,500 ppm lower than the concentration emitted from an absorption tower designed for commercial 

purposes only, with no reduction for NOX control purposes. Therefore, extended absorption, at 

no additional cost to the facility, will initially reduce NOX emissions by about 50%. 

Based on this analysis an emission limit of 12.5 lb/hr or 0.6 lbs NOX/T100% Acid using a combination of 

extended absorption and SCR is proposed as BACT. The extended absorption will reduce the NOX

concentration from about 3,000 ppm to about 1,500 ppm, while the SCR will reduce 

the concentration from about 1,500 ppm to 33 ppm. This will result in an overall NOX reduction of 

approximately 99%. 

4.1.3 Steam-Generating Boiler 

4.1.3.1 Process Description 

US Nitrogen proposes to install a natural gas-fired boiler that will be used to provide the steam 

needed to operate the various processes and equipment at the facility. The boiler will have 

a maximum heat input capacity of 130 MMBtu/hr and will use only natural gas as fuel. 
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4.1.3.2 Boiler NOX Emissions 

There are three possible control technologies for reducing NOX emissions from natural gas-fired 

boilers in the 100–200 MMBtu/hr range. These include, in descending order of removal efficiency, 

(1) SCR with LNB and flue gas recirculation (FGR), (2) ultra-low-NOX burners (ULNB) with FGR, and 

(3) LNB with FGR. All are considered technically feasible for use at the US Nitrogen facility. 

LNBs and ULNBs minimize the formation of NOX by controlling the quantities and the way in which 

fuel and air are introduced and mixed in the boiler. LNBs have the smallest impact on 

operating costs. 

With an SCR, a small quantity of NH3 is mixed with the boiler exhaust gas in a static mixer prior to 

being fed over the catalyst. In the reactor, the NH3/exhaust gas mixture flows through the catalyst 

where NOX is reduced to nitrogen. 

The results of a RBLC search for 100-200 MMBtu/hr, natural gas-fired boilers identified 

eighteen similar sources (See Appendix E for the details of the search.). The lowest emission limit 

identified in the RBLC was 1.8 lbs/hr for a 175 MMBtu/hr boiler. Although no control method is 

specified in the RBLC, a review of the “Preliminary Determination Summary” for the permit 

associated with this emission limit indicates the applicant proposed to use LNB to meet 

the emission limitation. Further investigation revealed that the 1.8 lbs/hr emission limit is 

equivalent, in that case, to 0.01 lb/MMBtu or 9 ppmv NOX, dry, corrected to 3% oxygen, averaged 

over three hours, which was designed to be consistent with State of Texas BACT guidance. 

4.1.3.2.1 Economic Analysis 

The economic impact of using SCR plus LNB and FGR, ULNB plus FGR, and LNB plus FGR to reduce 

boiler NOX emissions was evaluated by determining the cost per ton of NOX removed for each 

technology. Detailed Financial Analysis Worksheets are included in Appendix G, while Table 4-6 

summarizes the results of the analysis. 
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Table 4-6 

Financial Comparison of US Nitrogen Boiler NOX Reduction Options1

LNB + FGR ULNB + FGR SCR+LNB+FGR 

Inlet NOX (TPY) 47.8 47.8 47.8 

Outlet NOX (TPY) 14.3 4.3 1.4 

Reduction Efficiency (%) 70 91 97 

NOX Reduced (TPY) 33.5 43.5 46.4 

Total Capital Investment ($) $337,325 $607,185 $1,462,846 

Capital Recovery Cost ($/yr) $53,892 $97,005 $233,706 

O&M Annual Expense ($/y) $10,120 $18,216 $162,227 

Total Annual Cost ($) $64,011 $115,220 $395,934 

Cost Of NOX Removed ($/T) $1,911 $2,649 $8,533 

Note: 

1. See Appendix G, Tables G-5 through G-7 for detailed financial worksheets. 

4.1.3.2.2 Energy Impacts 

SCRs consume energy. In the case of an SCR on the boiler, this usage is estimated to be 

approximately 44 MWh/yr. 

4.1.3.2.3 Environmental Impacts 

SCRs consume NH3. With an SCR, un-reacted NH3 would be emitted to the atmosphere (NH3 slip). 

NH3 is a precursor to the formation of PM10 and PM2.5 in the atmosphere. The additional electrical 

usage will result in the indirect emission of NOX, SO2, and CO2 from the generation of electricity. 

4.1.3.2.4 Proposed BACT

Based on this analysis, a NOX emission limit of 0.01 lb/MMBtu (1.3 lb/hr) using ULNB in combination 

with FGR is proposed as BACT. The SCR plus LNB and FGR option is considered an unacceptable 

alternative for BACT since the incremental cost ($96,798/T) of the small additional NOX reduction 

(2.9 T/yr) is unreasonably high, there is additional consumption of resources (NH3) and electrical 

energy, there are both direct (NH3) and indirect (NOX, SO2, and CO2) emission of additional 

air pollutants, and the ULNB plus FGR option can achieve an emission rate equal to the lowest rate in 

the RBLC. 

4.1.4 Firewater Pump 

4.1.4.1 Process Description 

US Nitrogen will install a diesel-powered emergency firewater pump to provide fire-fighting 

capability. The diesel engine, which will be rated at approximately 400 hp, will be routinely tested, 

as required by Federal, state, and local fire codes. The engine will be Tier II-compliant to meet 

required emissions standards under 40 CFR 60, Subpart IIII, for stationary compression ignition 

internal combustion engines. 
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4.1.4.2 Pump NOX Emissions 

As mentioned above, the firewater diesel engine will be subject to 40 CFR 60 Subpart IIII (NSPS). 

The emission standard for stationary fire pump engines (Table 4 to Subpart IIII of Part 60 — 

Emission Standards for Stationary Fire Pump Engines) is 3.0 grams per hp-hour (g/hp-h) or 

4.0 grams per kilowatt-hour (g/kW-h). 

The results of a RBLC search for diesel powered “firewater pumps” identified thirty-three similar 

sources (See Appendix E for the details of the search.). The lowest emission limit identified in 

the RBLC was 3.2 g/kW-h or 1.58 lbs/hr for a 300 hp diesel engine. The control method listed in 

the RBLC is “none.” 

4.1.4.3 Proposed BACT 

Complying with 40 CFR 60 Subpart IIII (3.0 g/hp-hr) is proposed as BACT. 

4.1.5 Flare 

4.1.5.1 Process Description 

A flare stack will be installed primarily to mitigate CO emissions during ammonia plant startup and 

to combust vent gas during safety relief. Normal emissions from the flare will be no more than 

those associated with operation of the 5 MMBtu/hr flare pilots and purge gas. It is assumed 

that only one ammonia plant will start up at any given time. The flare burner is a smokeless flare 

with no PM emissions. Startup will occur a maximum of three times per year for 36 hours per 

event. The emissions from the vents last approximately 12 hours per event. During startup, 

the maximum heat input, including the heat value of the natural gas as well as the gases from 

the ammonia plant, is expected to be 45.6 MMBtu/hr.

4.1.5.2 Flare NOX Emissions 

The only control technology/method available for the control NOX emissions from flares is to 

maintain a high (at least 98%) combustion efficiency. 40 CFR 60.18 specifies the requirements 

for achieving and maintaining this efficiency. This is considered technically feasible for 

the US Nitrogen facility. 

The results of a RBLC search using the keywords “flare” and “ammonia” identified only one similar 

source (See Appendix E for the details of the search.). The emission limit identified in the RBLC 

was 1.1 lbs/hr. No control method is specified in the RBLC. 
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The EPA AP-42 NOX emission factor for flares is 0.068 lb/MMBtu and the AP-42 NOX emission factor 

for uncontrolled combustion of natural gas is 100 lbs/106

 standard cubic feet (scf) of natural gas. 

Based on the maximum heat input during startup of 45.6 MMBtu/hr, the proposed NOX emission 

rate during the 36 hours per year of startup is 3.1 lbs/hr. During normal operations the emission 

rate will be 0.49 lbs/hr. 

4.1.5.3 Proposed BACT 

Operating the flare in compliance with 40 CFR 60.18 with an emission limit during startup of 

3.1 lbs/hr and an emission limit during normal operations of 0.49 lb/hr is proposed as BACT. 

4.2 Greenhouse Gases (CO2e) 

Table 4-1 summarizes the GHG emissions from the US Nitrogen facility while Table 4-2 provides 

the details of the emissions for each emission source. These GHG emissions fall into 

three categories, and for simplicity, were addressed in this analysis in those three categories. 

The three categories are: 

 Relatively dilute GHG emissions resulting from combustion 

 Concentrated CO2 emissions (greater than 90% CO2) from the ammonia plant CO2 vents 

 N2O emissions from the nitric acid plant 

The relatively dilute GHG emissions resulting from combustion include emissions from the following: 

 Ammonia Plant, Train 1 flue gas 

 Ammonia Plant, Train 2 flue gas 

 Steam-Generating Boiler 

 Firewater Pump 

 Flare 

Because little information was available in the RBLC for GHG emissions at the time of this analysis, 

two recent documents issued by EPA were used as the primary source of information on control 

technologies for the US Nitrogen GHG emissions. Those two documents are: Available and 

Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, Commercial, and 

Institutional Boilers, USEPA, Research Triangle Park, October 2010 and Available and Emerging 

Technologies for Reducing Greenhouse Gas Emissions from the Nitric Acid Production Industry, 

USEPA, Research Triangle Park, December 2010. 
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4.2.1 Dilute GHG Emissions Resulting From Combustion 

For this category of emission sources there are two control technologies/methods available for 

reducing GHG emissions and they are, in descending order of control efficiency, (1) carbon capture 

and sequestration (CCS) and (2) energy/process efficiency methods. CCS was not considered 

technically feasible for any of these emission sources since it has not been demonstrated at 

the commercial level for any of these types of sources. 

4.2.1.1 Ammonia Plant, Trains 1 and 2 Flue Gas 

The flue gas streams from each train are the same. As discussed in Section 4.1.1.2, the emissions 

from the flue result primarily from the combustion of natural gas. Natural gas is the fuel option 

that results in the lowest amount of CO2 being formed during combustion. The natural gas 

combustion process will be optimized for maximum fuel efficiency to the extent practicable. 

The proposed GHG BACT emission limits per train are as follows (See Appendix B for a detailed 

description of the basis for these limits.): 

 CO2 22,380.0 TPY 

 CH4 0.422 TPY 

 N2O 0.042 TPY 

4.2.1.2 Steam-Generating Boiler 

As discussed in Section 4.1.3, the steam-generating boiler will be a 130 MMBtu/hr natural gas-fired 

boiler. The boiler will provide steam for plant processes. The boiler is expected to operate at 

75% capacity and will be limited to a maximum use of 840 million standard cubic feet (MMscf) of 

natural gas per year. 

The boiler will burn only natural gas, the fuel option with the lowest CO2 emission rate, and be 

designed with ULNB plus FGR for NOX control (See Section 4.1.3.), the latest instrumentation and 

controls for controlling efficiency, and insulation to minimize energy leakage. The boiler will be 

operated with a thermal efficiency of 81% or greater. 

The proposed GHG BACT emission limits are as follows (See Appendix B for a detailed description 

of the basis for these limits.): 

 CO2 50,061.1 TPY 

 CH4 0.944 TPY 
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 N2O 0.094 TPY 

4.2.1.3 Firewater Pump 

As discussed in Section 4.1.4, the fire water pump is a 400 hp diesel engine. It will be run no more 

than one hour per week for testing. It may run for any number of hours during an actual 

emergency. The maximum number of normal operating hours per year is expected be no more 

than 100. The diesel engine will be designed for energy efficient operation. 

The proposed GHG BACT emission limits are as follows (See Appendix B for a detailed description 

of the basis for these limits.): 

 CO2 23.9 TPY 

 CH4 0.001 TPY 

 N2O 0.000 TPY 

4.2.1.4 Flare 

As discussed in Section 4.1.5, the flare is used to control emissions from startup vents during 

ammonia plant startup, as well as NH3 releases during upsets. It is assumed that only one train of 

the ammonia plant will start up at any given time. The flare burner size is 5 MMBtu/hr and is an 

energy efficient, smokeless flare (no PM emissions). Ammonia plant startup will occur a maximum 

of three times per year for 36 hours per event. During startup, the maximum heat input, including 

the heat value of the pilot natural gas as well as the gases from the plant, is expected to be 

45.6 MMBtu/hr. 

As also described in Section 4.1.5, the flare will be designed and will operate in accordance with 

40 CFR 60.18. The requirements in 40 CFR 60.18 are intended to result in a combustion efficiency 

of 98% or higher to ensure that the flare serves its purpose of reducing emissions of CO, NH3, and 

other components in the gases flowing to the flare. Maximizing the combustion efficiency of the 

flare maximizes the amount of CO2 and other GHG’s produced by the flare. During normal 

operations, only natural gas, the fuel option with the lowest CO2 emission rate, will be combusted. 

BACT is proposed to be energy efficient combustion in accordance with 40 CFR 60.18 with 

proposed GHG BACT emission limits as follows (See Appendix B for a detailed description of 

the basis for these limits.): 
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Normal Operations 

 CO2 2,559.8 TPY 

 CH4 0.048 TPY 

 N2O 0.005 TPY 

Startup 

 CO2 287.8 TPY 

 CH4 0.005 TPY 

 N2O 0.001 TPY 

4.2.2 Concentrated CO2 Emissions from the Ammonia Plant CO2 Vents 

The concentrated CO2 emissions are emitted from the CO2 vents at the Ammonia Plant — 

Trains 1 and 2. CO2 emissions result from NH3 synthesis after the CO shift. The CO2 is removed 

from the process gas by cooling the gas and sending it through the CO2 Absorber, an absorption 

tower. There, the CO2 is removed from the gas by absorption in MDEA solution. The MDEA 

solution is regenerated in the Amine Regenerator and re-circulated through the CO2 Absorber in 

a continuous cycle. Initially, the CO2 gas will be captured and vented to the atmosphere. At a later 

date, efforts will be made to capture this CO2 for commercial use at another facility. 

The concentration of CO2 in this gas stream is approximately 91 percent. 

There are two control technologies/methods available for reducing the content of GHG’s in the CO2

vents. They are, in descending order of removal efficiency, (1) CCS and (2) energy/process 

efficiency methods. The fact that the CO2 concentration in the vents is high makes CCS 

a potentially technically feasible option. Process (i.e., combustion in the primary reformers) 

efficiency methods that minimize the formation of CO, and thus, CO2, are also considered 

technically feasible. 

4.2.2.1 Carbon Capture and Sequestration 

CCS involves capturing CO2, transporting it, as necessary, and permanently storing it instead of 

releasing it into the atmosphere. 

4.2.2.1.1 Capture 

Isolation of relatively pure CO2 is technically feasible since the existing gas stream has a CO2

concentration of 91%. Some additional concentration of the CO2, as well as the removal of water, 

will be required, which is also technically feasible. 
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4.2.2.1.2 Transportation 

Long-term carbon storage is possible only in a very limited number of sites in the southeastern 

US and the US Nitrogen site is not a suitable storage location. Accordingly, the captured CO2 must 

be transported to a suitable storage site in order to achieve any environmental benefit. Pipelines 

are the most common method for transporting large quantities of CO2 over long distances. 

Approximately 3,600 miles of CO2 pipeline operate today in the United States. These pipelines 

generally carry CO2 from naturally-occurring underground reservoirs, natural gas processing 

facilities, NH3 manufacturing plants, and large coal gasification projects to oil fields. 

Pipeline transportation of CO2 is typically accomplished with CO2 that is compressed to pressures of 

1,200 to 2,000 pounds per square inch. This compression requires high levels of energy 

consumption. In addition, water must be eliminated from CO2 pipeline systems, as the presence of 

water results in formation of carbonic acid, which is extremely corrosive to carbon steel pipe. 

The primary compressor stations are located at the CO2 source and at the storage site with booster 

compressors located as needed along the pipeline. In overall construction, CO2 pipelines are similar 

to natural gas pipelines, requiring the same attention to design, monitoring for leaks, and 

protection against overpressure, especially in populated areas. All of these technical issues can be 

addressed through modern pipeline construction and maintenance practices; therefore, transporting 

the CO2 from the CO2 vents at the US Nitrogen facility is considered technically feasible. 

4.2.2.1.3 Storage 

There are several options for permanent storage of CO2. They include gaseous storage in various 

geological formations (including saline formations, exhausted oil and gas fields, and un-mineable 

coal seams), liquid storage in the ocean, and terrestrial sequestration. Liquid storage in the ocean 

was not considered in this analysis since the US Nitrogen facility location is at least 300 miles from 

the ocean. 

4.2.2.1.3.1 Geologic Formations 

The geologic formations considered appropriate for CO2 storage are layers of porous rock deep 

underground that are “capped” by a layer or multiple layers of non-porous rock above them. 

In this application, a well is drilled down into the porous rock and pressurized CO2 is injected into it. 

Under high pressure, CO2 turns to liquid and can move through a formation as a fluid. 

Once injected, the liquid CO2 tends to be buoyant and will flow upward until it encounters a barrier 

of non-porous rock, which can trap the CO2 and prevent further upward migration. 
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The degree to which a specific underground formation is amenable to CO2 storage can be difficult 

to determine. Research is being performed today which is aimed at developing the ability to 

characterize a formation before CO2 injection in order to predict its CO2 storage capacity. 

Discussed below are the geologic formations that have some potential for application to 

the US Nitrogen facility. 

4.2.2.1.3.1.1 Depleted Oil and Gas Reservoirs 

These are formations that held crude oil and natural gas at some time. In general, they are 

characterized by a layer of porous rock with a layer of non-porous rock which forms a dome. 

This dome offers great potential to trap CO2 and makes these formations excellent storage 

opportunities. As a value-added benefit, CO2 injected into a depleting oil reservoir can enable 

recovery of additional oil and gas, because when it is injected into a depleted oil bearing formation, 

the CO2 dissolves in the trapped oil and reduces its viscosity. This improves the ability of oil to 

move through the pores in the rock and flow with a pressure differential toward a recovery well. 

It is estimated that 50 to 90 billion metric tons of storage potential exists in mature oil and gas 

reservoirs identified by the Regional Carbon Sequestration Partnerships (RCSPs). Formed by 

the US Department of Energy in 2003, the seven Partnerships span 40 states, three Indian nations, 

and four Canadian provinces. According to the Southeast Regional Carbon Sequestration 

Partnership (SERCSP), there are no known oil or gas reservoirs providing CO2 sequestration 

opportunities within the immediate vicinity of the US Nitrogen facility in Greene County, Tennessee, 

but there may be some potential storage capacity in southwestern Virginia, approximately 

100 miles from the facility. Although no extensive investigation has been undertaken, these oil 

fields potentially provide a storage opportunity that can be considered technically feasible. 

4.2.2.1.3.1.2 Un-Mineable Coal Seams 

Un-mineable coal seams are those that are too deep or too thin to be mined economically. All coals 

have varying amounts of CH4 adsorbed onto pore surfaces, and wells can be drilled into 

un-mineable coal beds to recover this coal bed CH4 (“CBM”). Initial CBM recovery methods, 

dewatering and depressurization, leave an appreciable amount of CBM in the reservoir. Additional 

CBM recovery can be achieved by sweeping the coal bed with nitrogen or CO2, which preferentially 

adsorbs onto the surface of the coal, releasing the CH4. It is estimated that 150 to 200 billion 

metric tons of CO2 sequestration potential exists in un-mineable coal seams identified by the RCSPs. 

According to SERCSP, none of these seams are in the vicinity of the US Nitrogen facility, but there 

may be some potential storage capacity in un-mineable seams of the central Appalachian coal basin 

of southwestern Virginia, approximately 100 miles from the facility. Although no extensive 
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investigation has been undertaken, these un-mineable coal seams potentially provide 

a sequestration opportunity that can be considered technically feasible. 

4.2.2.1.3.1.3 Saline Formations 

Saline formations are layers of porous rock that are saturated with brine. They are much more 

commonplace than coal seams or oil and gas bearing rock, and represent an enormous potential for 

CO2 storage capacity. The RCSPs estimate a range of 3,300 to 12,000 billion metric tons of 

sequestration potential in saline formations. However, much less is known about saline formations 

than is known about crude oil reservoirs and coal seams, and there is a greater amount of 

uncertainty associated with their ability to store CO2. Saline formations contain minerals that could 

react with injected CO2 to form solid carbonates. The carbonate reactions have the potential to be 

both a positive and a negative. They can increase permanence but they also may plug up 

the formation in the immediate vicinity of an injection well. Additional research is required to better 

understand these potential obstacles and how best to overcome them. Such saline formations do 

not exist in the vicinity of the US Nitrogen facility, but according to SERCSP, there may be 

some potential storage capacity in the Mt. Simon basin of middle Tennessee, approximately 

125 miles from the facility. Although no extensive investigation has been undertaken, these 

oil fields potentially provide a sequestration opportunity that can be considered potentially 

technically feasible. 

Based on this analysis of geologic storage options, it is clear that the CO2 from the CO2 vents at 

the US Nitrogen facility would have to be transported by pressurized pipeline at least 100 miles. 

Based on Figure 4.3 of the IPPC Special Report on Carbon Dioxide Capture and Storage (page 191), 

the initial investment for just the pipeline, not including booster stations and not accounting for 

the hilly, mountainous terrain of northeast Tennessee and southwestern Virginia, ranges from 

$400,000 to $1,000,000 per kilometer. Based on a pipeline 160 kilometers long, the investment 

just for the US Nitrogen pipeline would be at least $64,000,000 which is equal to an annualized 

cost of approximately $10,225,000. At this annual cost, the cost per ton of CO2 transported would 

be about $115. For this reason, transport of the CO2 from the US Nitrogen CO2 vents to a geologic 

formation was determined to be economically infeasible and no further analysis of storage in 

geologic formations was conducted. 
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4.2.2.1.3.1.4 Terrestrial Ecosystems 

Terrestrial sequestration is the enhancement of CO2 uptake by plants that grow on land and in 

freshwater, as well as the enhancement of carbon storage in soils where it may remain more 

permanently stored. Terrestrial sequestration provides an opportunity for relatively low-cost CO2

emissions offsets. Examples include tree-plantings, no-till farming, and forest preservation. 

To date, there are no actual commercial applications of terrestrial sequestration of a CO2 stream of 

90,000 tons per year, therefore, the terrestrial sequestration option was considered technically 

infeasible and was not further evaluated as BACT. 

4.2.2.2 Proposed BACT 

Based on this analysis of CCS, a CO2 emission limit of 45,394.3 TPY using process (i.e., combustion) 

efficiencies in the primary reformers (see Section 4.2.1.1) is proposed as BACT. This would apply 

to both Trains 1 and 2 of the Ammonia Plant. (See Appendix B for a detailed description of 

the basis for this limit.) 

4.2.3 N2O Emissions from the Nitric Acid Plant 

N2O is an unwanted by-product of the manufacture of nitric acid. It is formed alongside the main, 

desired product during the catalytic oxidation of NH3 in air over noble metal gauzes. N2O is 

a potent greenhouse gas with a Global Warming Potential (GWP) of 310. 

The production of nitric acid takes place in three main process steps as indicated by 

the following reactions: 

1. NH3 combustion to form NO: 

NH3 is reacted with air on noble metal catalyst in the oxidation section of nitric acid plants. 

Nitric oxide and water are formed in this process according to the following equation: 

4NH3 +5O2 →4NO+6H2O

Simultaneously, N2O, nitrogen and water are formed as well, in accordance with the following equations: 

4NH3 +3O2 →2N2 +6H2O

4NH3 +4O2 →2N2O+6H2O 
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NO yield depends mainly on pressure and temperature in the NH3 oxidation process and usually is 

in a range of 95% to 97%. 

2. NO is oxidized to nitrogen dioxide (NO2): 

2NO+O2 →2NO2

3. Absorption of NO2 in water to form nitric acid (HNO3): 

3NO2 + H2O → 2HNO3 + NO 

Based on similar nitric acid plant designs where the N2O has been measured with no reduction 

systems installed, it is estimated that the N2O formation across the NH3 oxidation catalyst at 

the US Nitrogen plant will be on the order of 1,500-1,800 ppm. Therefore, this is the concentration 

used in this analysis as the uncontrolled concentration. 

4.2.3.1 N2O Reduction Methods 

There are three categories of control technologies/methods available for reducing 

the N2O concentration in this emission source. These three categories are, in descending order of 

removal efficiency: (1) tertiary, (2) secondary and (3) primary controls. 

 Tertiary controls/methods reduce N2O by installing a catalytic reactor either upstream or 

downstream of the tail gas expansion unit following NH3 oxidation. Tertiary processes can 

be further broken down into two technologies/methods. Catalytic reduction uses 

a hydrocarbon over a noble metal catalyst to chemically reduce all the oxygen in 

the tail gas, including the chemical oxygen (i.e., NO, N2O and NO2), while catalytic 

decomposition uses a specially formulated catalyst to chemically decompose the N2O to 

nitrogen and oxygen. 

 Secondary controls/methods reduce N2O immediately after it is formed in the NH3 oxidation 

step. This control/method employs a specially formulated catalyst to decompose the N2O to 

nitrogen and oxygen. 
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 Primary controls/methods reduce the amount of N2O formed in the NH3 oxidation step. 

This is accomplished by modifying the catalyst used in the oxidation process and/or 

modifying the operating conditions of the process. 

4.2.3.1.1 Primary Controls/Methods 

Primary reduction is accomplished in the following manner. Upon leaving the NH3 oxidation 

reactor, some of the N2O is destroyed in the part of the plant upstream of the absorption tower by 

high temperature homogeneous gas phase decomposition and by catalytic decomposition on 

platinum deposits formed from metal lost from the NH3 oxidation catalyst. 

This takes place in all nitric acid plants and can be enhanced by providing residence time at 

elevated temperatures above 800o

C. For the US Nitrogen nitric acid plant, this reduction method 

can reduce the N2O from 1,500-1,800 ppm to approximately 500 ppm. It has been assumed that 

once the reactant gas is lowered to less than 500o

C, all N2O reduction ceases and the N2O acts as 

an inert gas through the rest of the process and is discharged in the exhaust stack with the rest of 

the tail gas, which is mainly nitrogen. 

Primary control is considered technically feasible for the US Nitrogen nitric acid plant. 

4.2.3.1.2 Secondary Controls/Methods 

Secondary N2O reduction is classified as a reducing step that takes place directly underneath 

the NH3 oxidation catalyst. This secondary reduction takes place across a catalyst that is 

specially formulated to selectively reduce N2O and to not affect the NO that is produced in 

the NH3 oxidation reactor. 

With this secondary reduction process, the reactor design must take into account design 

parameters that limit catalyst loss and hold NH3 bypassing to a minimum. Also, with secondary 

reduction, the NH3 oxidation reactor design must incorporate the needed volume for the placement 

of the reducing catalyst directly below the platinum gauze. This is very costly because the reactor 

design must be more robust to handle the higher pressure drop across the NH3 oxidation reactor. 

Higher pressure drop across the reactor lowers the usable life of the reactor and causes 

bypassing of NH3 around the platinum catalyst. NH3 bypassing occurs when the clearances in the 

reactor catalyst hold-down system become distorted beyond the ability of gasketing. NH3 will 

bypass the platinum catalyst and the secondary reaction of NH3 to nitrogen and water 
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will take precedence over formation of NO. This bypassing leads to adverse reactions that lower 

the NH3 conversion efficiency. 

As mentioned earlier, the US Nitrogen facility will make use of existing nitric acid plant equipment 

which is being re-located to the Greene County facility. It is not practical to incorporate 

the changes to the plant design that would be required for secondary control, therefore, 

secondary control is not considered technically feasible for the US Nitrogen nitric acid plant. 

4.2.3.1.3 Tertiary Reduction 

Tertiary reduction of N2O occurs in the tail gas stream prior to the tail gas entering the hot gas 

expander. The tail gas, containing approximately 500 ppm of N2O, enters a reactor where the gas 

is contacted with a specially formulated catalyst. Tertiary reduction technologies fall into 

two categories — catalytic reduction and catalytic decomposition. NSCR has been used in nitric 

acid plants in the past to reduce NOX. 

With NSCR, a reagent fuel, such as natural gas, is used to reduce both NOX and N2O over a catalyst 

to produce N2 and water. Catalysts for NSCR are usually based on platinum, vanadium pentoxide, 

iron oxide or titanium. NSCR systems require a minimum inlet temperature of 900°F to ignite 

natural gas. As its name implies, NSCR is “non-selective” catalytic reduction, meaning that it 

reduces all oxidized components in the tail gas. Consequently, to preferentially reduce NOX and N2O 

in the gas stream, all of the free oxygen must first be reduced. This oxygen reduction is an 

exothermic process which produces about 295°F per 1% of oxygen destroyed. The US Nitrogen 

nitric acid plant will have an inlet tail gas free oxygen concentration of 2.9%, the reduction of which 

would add about 855°F to the gas stream. Since this would result in a tail gas temperature well 

above any catalyst operating temperature, the tail gas would have to be cooled prior to entering 

the NSCR. NSCR has a N2O reduction efficiency of 80-95%. 

With NSCR systems, most of the hydrocarbons from the natural gas are converted to CO2 and CO, 

resulting in additional emissions of 6,000-7,000 ppm CO2 and 300-400 ppm of CO, as well as some 

10-20 ppm of unburned hydrocarbons. 

With catalytic decomposition, no additional reducing agents or additives are required and 

no undesirable by-products, such as CO2, CO, or unburned hydrocarbons are emitted. The basis of 

decomposition technology is to decompose the N2O to form N2 and O2. A catalyst is used to drive 

the decomposition. This catalyst is stable in the presence of NOX and NH3, allowing placement 

either upstream or downstream of an SCR used to reduce NOX. Catalytic decomposition is also 
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easier to operate than NSCR and begins reducing N2O during plant startup much earlier than 

does NSCR. 

Both of the tertiary processes described above are considered technically feasible for 

the US Nitrogen nitric acid plant. 

4.2.3.2 Economic Analysis 

Based on the foregoing description of the technically feasible options for control of N2O emissions 

from the US Nitrogen facility, a financial comparison of the options was conducted. Detailed 

financial analysis worksheets are included in Appendix G, while Table 4-7 summarizes the results of 

the analysis. 

Table 4-7

Financial Comparison of Nitric Acid Plant N2O Reduction Options1

Primary 

Reduction 

Tertiary Reduction 

Using NSCR 

Tertiary Reduction 

Using Catalytic Decomposition 

Inlet N2O (TPY) 2,047.0 581.4 581.4 

Outlet N2O (TPY) 581.4 24.1 29.1 

Reduction Efficiency (%) 72 96 95 

N2O Removed (TPY) 1,465.6 557.3 552.3 

N2O Removed (TPY CO2e) 454,336 165,9222 171,232 

Total Capital Investment ($) $189,980 $379,960 $2,255,932 

Capital Recovery Cost ($/yr) $30,351 $60,703 $360,411 

O&M Annual Expense ($/yr) $76,584 $166,295 $270,572 

Total Annual Cost ($/yr) $106,936 $226,998 $630,983 

Cost of CO2e Removed ($/T) $0.24 $1.37 $3.69 

Notes: 1. See Appendix G, Tables G-8 through G-10 for detailed financial worksheets. 

2. As a result of the combustion of the natural gas in the NSCR, an additional 6,841 TPY of CO2 is produced. 

Therefore, the net CO2e removed is 172,763 TPY N2O as CO2e minus 6,841 TPY CO2 produced. 

As can be seen from Table 4-7, primary controls have the lowest cost per ton CO2e removed, 

while tertiary controls have the highest. 

4.2.3.3 Energy Impacts 

NSCRs consume electrical energy and natural gas. The additional electrical usage attributable to 

N2O reduction is estimated to be 7.5 MWh/yr, while the additional natural gas consumed that is 

attributable to N2O reduction is estimated to be 23 MMscf/yr (23,460 MMBtu/yr). 

Catalytic decomposition requires an additional 385 MWh/yr in electrical usage. 
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4.2.3.4 Environmental Impacts 

NSCRs consume natural gas. The additional electrical usage of both NSCR and catalytic 

decomposition will result in the indirect emission of NOX, SO2, and CO2 from the generation of 

electricity. As stated earlier, with the NSCR system, most of the hydrocarbons from the natural gas 

are converted to CO2 and CO, resulting in additional emissions of 6,000-7,000 ppm CO2 and 

300-400 ppm of CO, as well as some unburned hydrocarbons. However, as noted earlier, NSCR 

reduces both N2O and NOX. 

4.2.3.5 Proposed BACT 

To determine the economic reasonableness of each of the control options evaluated in Table 4-7, 

a comparison was made of the cost per short ton of CO2e removed for each option to the price of 

Carbon Financial Instruments (CFI’s) traded on the Chicago Climate Exchange (CCX) over 

the past year (mid-May 2010 through mid-May 2011). It should be noted that trades on the CCX 

are generally based on voluntary reductions. The average price traded over the past year on 

the CCX is $1.51/short ton CO2e. This average price was based primarily on trades of offsets 

such as agricultural CH4 offsets, agricultural soil offsets, coal mine CH4 offsets, forestry offsets, 

fuel switching offsets, landfill CH4 offsets, organic waste disposal CH4 offsets, and renewable energy 

offsets. For comparative purposes, the current value of Certified Emission Reductions (CERs) in 

Europe (where GHG emission reductions are mandated) on the Intercontinental Exchange (ICE) is 

approximately $11.50/short ton CO2e. 

Based on this analysis, the per ton cost of primary control, as well as that of tertiary control using 

NSCR, are within the range of prices per ton of CO2e currently being traded in the voluntary 

US market. Although the cost per ton to reduce N2O using NSCR is lower than the cost of making 

an equal reduction using catalytic decomposition, US Nitrogen strongly prefers to use catalytic 

decomposition. Catalytic decomposition systems are much easier to operate, require no 

consumption of additional resources like natural gas, result in no additional direct emissions of 

pollutants (CO, CO2, and unburned hydrocarbons), and are much quicker and easier to operate 

during startup and shutdown. Consequently, a N2O emission limit of 29.1 TPY (9,021 TPY CO2e) 

using a combination of the primary controls described above and catalytic decomposition is 

proposed as BACT. This approach will result in about a 98% reduction in N2O emissions from 

the nitric acid plant. 
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5.0 AIR QUALITY ANALYSIS 

An air quality modeling analysis was conducted to assess the ambient impacts from the proposed 

project. This analysis satisfies the regulatory requirements for: 

 Source Impact Analysis of 40 CFR 52.21(k), and 

 Air Quality Analysis of 40 CFR 52.21(m). 

The source impacts analysis requires a demonstration that the project will not cause or contribute 

to a violation of a NAAQS or any applicable maximum allowable increase over the baseline 

concentration (increment). Air quality analysis requirements address the potential requirement for 

preconstruction ambient air quality monitoring. The air quality analysis quantifies only the impacts 

of the pollutants that are emitted in amounts in excess of PSD significant emission levels. 

For the proposed project, NOX emissions will be emitted in significant quantities and were therefore 

evaluated in the modeling analysis. 

Only the emissions from the proposed new facility were initially evaluated in the Source Impact 

Analysis of 40 CFR 52.21(k) and Air Quality Analysis of 40 CFR 52.21(m) for determining if 

the project significantly impacted local air quality. The resultant modeled concentrations were 

compared to the ambient significance levels for Class II areas. In addition, there are 

six Class I areas that are located within 300 km of the US Nitrogen facility. Class I areas are 

pristine areas (e.g., National Parks and Wilderness Areas) that have been designated by Congress 

and are afforded a greater degree of air quality protection. All other areas are designated as 

Class II areas. 

The FLMs were contacted and, based upon project emissions and distance from the nearest Class I 

area, they determined that a more detailed evaluation was not required. However, there are 

several receptors at the Great Smoky Mountain National Park that are less than 50 km (but greater 

than 45 km) from the proposed site. As a result, these receptors were modeled to determine if 

there would be any NO2 or plume impacts at this park. 

The results of this significant impacts analysis demonstrate that the proposed project will result in 

ambient impacts of NOX in excess of Class II significance levels. Therefore, a refined air quality 

analysis to calculate concentrations for comparison to the NAAQS and increments was required for 

this pollutant. NAAQS and increment impacts were determined to be acceptable. NO2 Class I 

impacts were determined to be less than significant. In addition, the near-field visibility analysis 
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results demonstrate that visibility is will not be affected. Furthermore, the preconstruction ambient 

monitoring exemption levels were determined not to be exceeded. 

A more detailed description of the modeling procedures and results is presented in Appendix C. 
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6.0 ADDITIONAL IMPACT ANALYSIS 

PSD regulations require an additional impacts analysis of each pollutant emitted by a source, 

including the analysis of the effects on local soils and vegetation. The depth of the analysis 

performed generally depends on existing air quality, the quantity of air emissions, and 

the sensitivity of local soils and vegetation. Greene County is currently as an attainment or 

unclassified area with respect to each criteria pollutant NAAQS. Based on the results of modeling 

discussed in Section 5.0 Air Quality Analysis and in Appendix C, this project will not result in 

ambient air quality impacts above any of the PSD significance levels and all pollutant concentrations 

beyond the facility boundary are below their applicable de minimis monitoring levels. 

6.1 Growth Analysis 

Air quality impacts projected for the area as a result of general commercial, residential, industrial, 

and other growth associated with this project are expected to be insignificant. Greene Country 

experienced a 9.4% growth in population during the past decade, bringing the total population to 

68,831. The US Nitrogen facility, when fully operational, will employ approximately eighty 

employees; thus, a maximum of eighty new households could be added to the surrounding 

communities, including Greene County. Such a population increase would add <0.5% to Greene 

County’s total population. Due to the nature of the project and projected population increases, US 

Nitrogen anticipates negligible emissions from associated growth in the local area. 

6.2 Soils Analysis 

Because most air pollutants are ultimately deposited primarily upon soil, the potential impact of 

these pollutants on terrestrial ecosystems is important. Pollutant emissions can impact the soil, 

ground and surface waters, and plant growth. In some cases these pollutants can accumulate in 

the soil system or become concentrated in plants and animals. In other instances, these pollutants 

may cause leaching of soil nutrients (e.g., acid deposition) or contribute to nutritional imbalances in 

plant communities (e.g., excessive nitrogen deposition). The NOX emissions from the facility are not 

expected to have any significant impact on soils that would affect vegetative growth or 

chemical composition of the soil. 

The site is located in Greene County, Tennessee, near the Midway community, in 

the Mosheim Geological Quadrangle. Land use in the immediate vicinity of the plant varies widely, 

being primarily industrial to the north of the site, residential to the south and east, and agricultural 

to the west. 
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Soils in the immediate vicinity of the plant site are predominately well to intermediately drained 

Dunmore and Dandridge loams composed of silts and shaly and cherty clays. Soils along 

the Great Valley are predominately Statler shaly silt loams. There are some steep slopes to 

the eastern site boundary along the ridgeline (up to 60%), but generally slopes in the area 

are 12-30%. 

It is not anticipated that soils in the area would be adversely impacted by any of the additional 

emissions resulting from the project. 

6.3 Vegetation Impacts 

Total pollutant impacts from this project are not expected to approach threshold levels for pollutant 

damage to vegetation in the area. The potential impacted vegetation is mostly residential and 

forest vegetation. The NOX maximum modeled 1-hr impact of 56.7 μg/m3

 is 6% of the maximum 

hourly screening concentration of 940 μg/m3

. The screening concentration level for NOX is 

3,760 μg/m3

 over a 4-hour period as listed in A Screening Procedure for the Impacts of Air Pollution 

Sources on Plants, Soils, and Animals (US EPA, Dec 1980). All other criteria pollutants do not

require such assessment due to their insignificant emission rates. Most of the designated 

vegetation screening levels are equivalent to or less stringent than the NAAQS and/or 

PSD increments; therefore, satisfaction of NAAQS and PSD increment assures compliance with 

sensitive vegetation screening levels. 

Acute levels of pollutants demonstrated to cause plant growth effects are not anticipated to be 

approached as a result of facility emissions. Furthermore, chronic pollution effects, either direct 

effects or possible effects from secondary pollutants formed such as ozone, are not anticipated. 

This is due to the low increment in pollutant loading that is anticipated to result from the emissions. 

Specifically, the following table characterizes injury threshold concentrations for NOX for plants 

native to the Southeastern United States: 
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Table 6-1

Injury Threshold Concentrations for NOX

Common Name Scientific Name NOX

Bryophyte (moss) Various Bryophyte sp. 65 (24 hours) 

Birch Betula sp. 120 (chronic) 

Common Sunflower Helianthus annuals 375 (chronic) 

Alfalfa Medicago sativa 1,000 (5 hours) 

Peach Prunus persica >5,240 (1 hour) 

>2,100 (3 hours) 

Garden Pea Pisum sativum 850 (7 hours) 

Cultivated Tobacco Nicotiana tabacum 2,000 (3.5 hours) 

Perennial ryegrass Lolium perenne 125 (chronic) 

Note: 

Source: World Health Organization, 2000 

With a modeled 1-hour maximum impact 56.7 μg/m3

, US Nitrogen will not surpass even the lowest 

threshold of impact – 65 μg/m3 for 24 hours for common moss. As such, US Nitrogen will not have 

a significant impact or cause injury to nearby vegetation. 
Appendix A 

Application Forms
Appendix B 

Emission Calculations 
Appendix C 

Air Dispersion Modeling and Class II Visibility Analysis 
Appendix D 

Correspondence with Federal Land Managers 

 
Appendix E 

RBLC Search Summary Tables 

 
Appendix F 

Austin Powder Cost of Capital 

 
Appendix G 

BACT Financial Analysis Worksheets 



















Office of Air and Radiation October 2010 

 

AVAILABLE AND EMERGING TECHNOLOGIES FOR 

REDUCING GREENHOUSE GAS EMISSIONS FROM 

THE NITRIC ACID PRODUCTION INDUSTRY 
Available and Emerging Technologies for Reducing 

Greenhouse Gas Emissions from the Nitric Acid Production 

Industry 

Prepared by the 

Sector Policies and Programs Division 

Office of Air Quality Planning and Standards 

U.S. Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

October 2010 

Table of Contents 

 Abbreviations and Acronyms p.1 

I Introduction p.2 

 Description of the Nitric Acid Production Process p.2 

 N2O Emissions and Nitric Acid Production Process p.5 

II. Summary of Control Measures p.5 

 Primary Controls p.7 

 Secondary Control p.7 

 Tertiary Controls p.9 

 Selective Catalytic Reduction p.12 

III. Energy Efficiency Improvements p.13 

 EPA Contacts p.15 

 References p.16 

 Appendix A – Southeast Idaho Energy p.18 

Appendix B - US Nitric Acid Plants p.19 

 Appendix C – CDM Monitoring Reports p.21 
1 

Abbreviations and Acronyms 

atm Pressure in atmospheres 

BACT Best Available Control Technologies 

Btu British Thermal Unit 

Btu/lb Btu per lb of 100% nitric acid 

CAR Climate Action Reserve 

CDM Clean Development Mechanism 

CHP Combined Heat and Power 

CO2 Carbon dioxide 

CO2e Carbon dioxide equivalent 

EU European Union 

GHG Greenhouse Gases 

H2 Hydrogen 

IPCC Intergovernmental Panel on Climate Change 

IPPC Industrial Pollution Prevention and Control 

JI Joint Implementation 

kg N2O/tonne kilograms of N2O per tonne of 100% nitric acid 

kg CO2e/tonne kilograms of CO2e per tonne of 100% nitric acid 

lb N2O/ton pounds of N2O per ton of 100% nitric acid 

MTPD Million tons per day 

N2 Nitrogen 

NH3 Ammonia 

NO Nitric oxide 

NO2 Nitrogen dioxide 

NOx Nitrogen oxides 

NSCR Nonselective Catalytic Reduction 

N2 O4 Nitrogen tetraoxide 

N2O Nitrous oxide 

O2 Oxygen 

PSD Prevention of Significant Deterioration 

SCR Selective Catalytic Reduction 

TPD Tons per day 
2 

I. Introduction 

This document is one of several white papers that summarize readily available 

information on control techniques and measures to mitigate greenhouse gas (GHG) emissions 

from specific industrial sectors. These white papers are solely intended to provide basic 

information on GHG control technologies and reduction measures in order to assist States and 

local air pollution control agencies, tribal authorities, and regulated entities in implementing 

technologies or measures to reduce GHGs under the Clean Air Act, particularly in permitting 

under the prevention of significant deterioration (PSD) program and the assessment of best 

available control technology (BACT). These white papers do not set policy, standards or 

otherwise establish any binding requirements; such requirements are contained in the applicable 

EPA regulations and approved state implementation plans. 

II. Purpose of this Document 

This document provides information on control techniques and measures that are 

available to mitigate greenhouse gas (GHG) emissions from the nitric acid production industry at 

this time. Because the primary GHG emitted by the nitric acid production industry is nitrous 

oxide (N2O), the control technologies and measures presented in this document focus on this 

pollutant. While a large number of available technologies are discussed here, this paper does not 

necessarily represent all potentially available technologies or measures that that may be 

considered for any given source for the purposes of reducing its GHG emissions. N2O has a 

global warming potential that is 310 times that of CO2 due to its long atmospheric lifetime 

relative to carbon dioxide. 

The information presented in this document does not represent U.S. EPA endorsement of 

any particular control strategy. As such, it should not be construed as EPA approval of a 

particular control technology or measure, or of the emissions reductions that could be achieved 

by a particular unit or source under review. 

As of the date of this document, the only known BACT determination for GHG 

emissions in the nitric acid industry was made by the State of Idaho on November 30, 2009. The 

agency issued a Permit To Construct for the Southeast Idaho Energy, LLC plant Advanced 

Energy Center in American Falls, Idaho. More details on this determination are contained in 

Appendix A. 

 

Description of the Nitric Acid Production Process (U.S. EPA, AP-42 Background Report) 

 There are two different nitric acid production methods: weak nitric acid and high-strength 

nitric acid. The first method utilizes oxidation, condensation, and absorption to produce nitric 

acid at concentrations between 30 and 70 percent nitric acid. High-strength acid (90 percent or 

greater nitric acid) can be produced from dehydrating, bleaching, condensing, and absorption of 

the weak nitric acid. The basic process technology has not changed over time. Most US plants 

were built between 1960 and 2000. There are presently 39 active weak nitric acid production 

plants and one high-strength nitric acid production plant. These plants are listed in Appendix B. 
3 

Also, additional information is contained in, "Technical Support Document for the Nitric Acid 

Production Sector: Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 22, 

2009.” 

Weak Nitric Acid Production 

 

 Weak nitric acid is produced by a three-step high-temperature catalytic ammonia 

oxidation process. An overall process flow diagram is shown in Figure 1. Each step of the 

process relates to a specific chemical reaction. A mixture of ammonia and water is reacted in a 

catalytic converter to produce nitric oxide (NO) and water. This exothermic reaction results in a 

93 to 98 percent yield of NO. Higher temperatures and lower pressures result in a higher yield of 

NO while lower temperatures and higher pressures result in the production of more nitrogen (N2) 

and N2O. Oxidation temperatures typically range from 750 – 900 C (1,380 – 1,650 F). 

Conversion efficiency of ammonia to NO is 96 – 98%. (ACT p. 3-4) The heat byproduct is 

usually recovered and utilized for steam generation in a waste heat boiler. This steam is then 

used for liquid ammonia evaporation in addition to non-process plant requirements.

The NO produced from ammonia oxidation is then oxidized. Residual oxygen and the 

NO process stream react in a cooler/condenser to form nitrogen dioxide (NO2) and nitrogen 

tetroxide (N2O4), a liquid dimer. This process step is temperature and pressure dependant. Low 

temperatures and high pressures result in better oxidation. 

 The final step for the production of weak nitric acid is absorption. The NO2 and liquid 

dimer mixture are pumped into the bottom of an absorption tower, with additional liquid dimer 

introduced at a higher point in the tower. Deionized process water is added at the top of the 

absorption tower. The water flows countercurrently through the NO2/dimer mixture and 

absorption occurs on bubble cap or sieve trays. Any residual NO2 is removed by a secondary air 

stream. 

 Weak nitric acid production utilizes either a single- or dual-stage pressure system. The 

most common employed method is single pressure. In a single pressure plant, air fed into the 

plant is compressed to the process pressure, and this single pressure is used in both the ammonia 

oxidation and nitrogen oxides absorption phases. Medium pressure plants operate at (4 -8 atm). 

High pressure plants operate at (8 – 14 atm). In 1991, the majority of new smaller capacity 

plants (< 300 TPD) used high pressure (US EPA, Dec. 1991).

The dual pressure system is used because NO conversion is favored under lower 

pressures while NO2 and nitric acid formation are favored at higher pressures during the final 

reaction by combining low pressure ammonia oxidation with high pressure absorption. 

Ammonia oxidation is usually carried out at slightly negative pressure to about 4 atm. The 

reaction heat is recovered by a waste heat boiler, which supplies steam for the turbine driven 

compressor. After passing thru the cooler/condenser, the gases are compressed to the absorber 

pressure between 8 and 14 atm. In this system, the nitric acid produced during absorption is sent 

to an external bleacher where dissolved NO is removed. These gases are compressed and passed 

through the absorber. The resulting tail gas is sent back to the ammonia oxidizer, where it is 

heated and sent to an energy-recovery turbine. The resulting energy that is recovered is used to 

drive the compressor. Dual pressure plants have the advantage of superior ammonia conversion 
4 

efficiency i.e. less ammonia raw material is necessary to produce nitric acid. Further, dual 

pressure plants have a longer catalyst life, and require less frequent catalyst replacement. The 

disadvantage of dual pressure plants is their substantially higher capital cost for construction and 

installation versus single pressure plants. 

Figure 1 - Process Flow Diagram for Weak Nitric Acid Production – Single Pressure – Source: 

U.S.EPA, January 1996. 
5 

High-Strength Nitric Acid Production Process 

 High-strength nitric acid can be produced from the weak nitric acid. Figure 2 presents a 

process flow diagram of the high-strength nitric acid production process. The secondary 

production of high strength acid from weak acid is not known to result in additional N2O 

emissions. Sulfuric acid is fed with weak nitric acid into a packed dehydrating column. The 

resulting acid vapor is condensed to form 98 to 99 percent nitric acid. 

Figure 2 ‐ Process Flow Diagram for High‐Strength Nitric Acid Production from Weak Nitric Acid

Source: U.S.EPA, January 1996. 

N2O emissions and Nitric Acid Production Process 

 N2O emissions from nitric acid are a byproduct of the process stream and therefore 

characterized as “industrial process” emissions. Ammonia oxidation is the main source of N2O 

emissions from nitric acid production. The amount of N2O formed depends on combustion 

conditions in the oxidizing unit, catalyst compositions, catalyst age, and burner design. 

 

The IPCC Guidelines for National Greenhouse Gas Inventories (2006) estimates that 

uncontrolled emissions are approximately 12 lb N2O/ton for low pressure processes, 17 lb 

N2O/ton for medium pressure processes, and 21.9 lb N2O/ton for high pressure processes. More 

details on N2O formation are contained in Perez-Ramirez, J. et al, 2003. 

 In the US, N2O emissions contributed approximately 4.6% of total GHG emissions in 

2008 in terms of CO2 equivalents. The nitric acid production process is the third largest source 

of N2O emissions in the US, comprising 6% of total N2O emissions or 19 million metric tons 

(tonnes) of CO2 equivalents (EPA 2010 Inventory). 
6 

II. Summary of Control Measures

 Table 1 summarizes the GHG control measures presented in this document. Where 

available, the table includes the emission reduction potential, energy savings, costs, and 

feasibility of each measure. 

Table 1. Summary of GHG Control Measures in the Nitric Acid Production Industry 

Pollutant Control 

Technology 

Emission 

Reduction 

(%) 

Energy 

Savings 

Capital 

Costs 

($/ton 

CO2e) 

Operating 

Costs ($/ton 

CO2e) 

Demonstrated in 

Practice? 

N2O Primary 30 - 85 None Unknown Unknown Yes 

N2O Secondary 70 -90 None Unknown 0.12 – 0.97 Yes 

N2O NSCR > 80 None 6.27 0.14 – 0.22 Yes 

N2O Other Tertiary 

Controls 

>80 None 2.18 – 3.55 0.14 – 1.91 Yes 

Source: EPA 2006; European Commission August 2007 

Three types of controls exist for N2O at nitric acid plants based on the location of the control 

within the nitric acid production process: (Durilla, 2009) 

• Primary – reduces the amount of N2O formed in the ammonia oxidation step. This 

can be done by modifying the catalyst used in the oxidation process and/or modifying 

the operating conditions of this process 

• Secondary – reduces N2O immediately after it is formed in the ammonia oxidation 

step. 

• Tertiary – reduces N2O by installing a catalytic reactor either upstream or 

downstream of the tailgas expansion unit following ammonia oxidation. 

The most common applied controls are secondary and tertiary controls. These control 

technologies employ abatement or decomposition control techniques. These technologies are 

capable of and typically achieve greater than 80 percent reduction of N2O emissions. A 2006 

EPA economic report constructed marginal abatement curves to be used for modeling the cost of 

emissions reductions of non-CO2 greenhouse gases globally in the 2010 to 2020 timeframe 

(EPA, June 2006). In the nitric acid sector, the report utilized engineering reports to characterize 

catalytic reduction methods developed by several companies. The capital costs for control 

technology ranged from $2 to $6 per ton of carbon equivalent removed. Operating costs ranged 

from $0.14 to $1.91 per ton carbon equivalent removed (US EPA; June 2006). 

Most of the technologies discussed here were first developed in Europe to support 

national commitments or emissions targets established under the Kyoto Protocol. Under the 

recently updated European Union Industrial Pollution Prevention and Control (IPPC) Directive, 

member countries are required to set permit limits for N2O emissions based on the best available 

technologies. Controls have also been evaluated in the context of offsets programs such as 
7 

Climate Action Reserve (CAR), Clean Development Mechanism (CDM), and Joint 

Implementation (JI) under the Kyoto Protocol. Detailed descriptions on the monitoring of 

emissions with application of these controls at plants located world-wide are found at the United 

Nations Framework Convention on Climate Change website: http://unfccc.int. Information on 

N2O controls and related projects is available on CAR’s website at 

http://www.climateactionreserve.org/how/protocols/adopted/nap/current-nitric-acid-productionproject-protocol/. Detailed descriptions on monitoring of emissions with the application of these 

controls at plants located world-wide are found at the United Nations Framework Convention on 

Climate Change web site: http://unfccc.int. (8/13/09 email Carolyn Slaughter to Bill Neuffer). 

A count of the projects listed in the CDM shows 66 nitric acid lines using N2O controls at 

nitric acid plants outside the US. Fifty three lines use secondary controls and 13 use tertiary 

controls (http://cdm.unfccc.int/Projects/projsearch.html). These numbers do not include the use 

of nonselective catalytic reduction (NSCR) which is used in 14 process trains in the US. Also, 

there are at least another 10 European lines using secondary controls and 4 additional European 

lines using tertiary controls. (European Commission, August 2007). 

At an adhoc European Climate Change Programme (ECCP) stakeholder’s meeting, 

benchmark values of GHG emissions from various industries were discussed. These values 

represent the average performance (arithmetic mean) of the 10% most efficient installations. The 

value for nitric acid was 342 kg CO2e/tonne or 1.1 kg N2O/tonne or 2.2 lb N2O/ton. Units using 

NSCR were excluded in this calculation as units are not required to monitor other GHG 

(methane, CO2) that are emitted from NSCR units. (Product Benchmark, 2010). 

Primary Control – Suppression of N2O formation

One primary control is the extension of the NH3 oxidation reactor. Yara has developed 

and patented a technology that consists of an “empty” reaction chamber of approximately 10 ft in 

length between the platinum catalyst and the first heat exchanger. This allows an additional 

residence time of 1 to 3 seconds. Reductions are estimated to be 70% to 85% (4 to 6 lb N2O/ton 

100% acid or about 400 ppm). This technique is applicable to new plants with low additional 

investments. For existing plants, costs are much higher as a new reactor may be required along 

with other plant modifications. (European Commission, August 2007). 

Another primary control is modifying the ammonia oxidation gauzes. These catalysts can 

be improved platinum catalysts. A few plants have shown a 30 -40 % N2O reduction. 

Alternative oxidation catalysts (not platinum based) can achieve 80 – 90% reduction but lower 

NO is produced. (European Commission, August 2007). 

Data from 14 European units with improved oxidation catalyst showed a range of 3.6 –9.7 

kg N2O/tonne (7.2 – 19.4 lb N2O/ton). The average was 6.2 kg N2O/tonne (12.4 lb N2O/ton). 

(European Commission, February 2008). 
8 

Secondary Control - Catalytic N2O decomposition in the Oxidation Reactor 

 For this control, a catalyst is located immediately downstream of the NH3 oxidation step. 

Using this catalyst, N2O is decomposed to N2 and O2 almost instantly as shown in Equation 1. 

Four companies (Yara, BASF, Johnson Matthey, and Hereaus) have developed selective 

catalysts for the removal of N2O. The catalyst is contained in the ammonia burner and is termed 

“selective” as it promotes the reaction (1) below the decomposition of N2O to N2 and O2. No 

major modification of the ammonia oxidation reactor is typically required and the installation of 

this catalyst has shown no effect on ammonia conversion. The placement of the catalyst in the 

ammonia burner allows for reduction of N2O emissions by increasing the residence time of the 

gas in the burner. The average lifetime for the pellet catalyst is 4 years (ICAC, 2009). Up to 

90% reduction is possible (ICAC, 2009) and rates of 130 to 400 ppm of N2O are achievable. 

Yara’s system (Figure 3) was first installed in 2002 and is presently operating in 17 plants. The 

plants applying the secondary controls range in size from 200 to 2,650 million tons per day 

(MTPD). 

 2 N2O -Æ 2N2 + O2 (1) 

 One reference states this control has the lowest capital cost as minimal modifications are 

required to the reactor for the ammonia oxidation catalyst. There are no additional operating 

costs. A total of 63 process lines at nitric acid plants worldwide have implemented this 

technology. As drafts of this report were being prepared, no US nitric acid facility was known to 

have installed or applied secondary controls in the U.S. (Durilla, 2009). However, a recent 

article discusses a secondary catalyst being installed at El Dorado’s Nitrogen LP’s Baytown, 

Texas plant (Industrial GHG, 6/17/10). The project is expected to begin operating before July 1, 

2010. The facility has applied to obtain GHG emission credits under the Climate Action Reserve 

program. Also, Terra Industries has installed secondary catalysts in Yazoo City, Mississippi and 

Claremore, Oklahoma. 

 Emission test results for secondary control were obtained from 2 sources – European 

Commission (February 2008) and monitoring reports from CDM projects (Appendix C). These 

results are summarized in Table 2. The CDM includes 2 units with percent reductions (9, 39%) 

much lower than the other 34 units tested. Thirty of the 36 units tested had efficiencies greater 

than 70%. Twenty four of 36 units had efficiencies greater than 80%. 

Table 2. N2O Emission Test Results- Secondary Controls (lb N2O/ton) 

Source Units tested Range Average % Reduction 

Range 

% Reduction 

Average 

EC 8 1.8 – 5.0 3.2 Unknown Unknown 

EC 4* 3.0 – 3.8* 3.4* Unknown Unknown 

CDM Projects 36 0.15 – 11.6 4.1 9 – 98 76 

* With Improved oxidation catalyst 
9 

 

Figure 3 – Yara Secondary N2O Control from Nitric Acid Production 

Source: ICAC, 2009. 

Tertiary Controls –Catalytic Reduction

 

Nonselective Catalytic Reduction (NSCR) is a common control technology utilized at 

nitric acid production facilities to reduce NOx emissions where a reagent fuel, such as natural 

gas, propane, butane, or ammonia plant purge gas (mainly H2) is used as a reagent to reduce 

NOx, and N2O over a catalyst to produce N2 and water. Similar to a three-way catalytic 

converter, reductions of NOx and N2O occur while other emissions are oxidized. Catalysts for 

NSCR are usually based on platinum, vanadium pentoxide, iron oxide or titanium. Catalyst 

supports are typically made of alumina pellets or a ceramic honeycomb substrate. NSCR has a 

N2O reduction efficiency of 80-95 percent (European Commission, August 2007). As far as 

selection of a NOx control, NSCR is typically used at plants that have the capability to preheat 

tailgas to 200 - 450o C and requires a greater reagent input than SCR (RTI, 2009). As stated 

earlier, 14 process trains in the US use NSCR. These facilities have installed NSCR to control 

NOx emissions and as an additional benefit NSCR reduces N2O emissions. The emissions from 

one US plant with NSCR were 0.43 lb N2O/ton. In numerous nitric acid plants outside of the 

US, NSCR/catalytic reduction is used in conjunction with SCR. 

 

 A European report (Fraunhofer, 2009) estimates that the average emissions from NSCR 

are 2.0 lb N2O/ton when the additional CO2 and methane emitted from operation of the NSCR 

are included. Average emissions from NSCR, according to this report, are shown in Table 3. 
10 

Table 3. Emissions from NSCR 

Pollutant Concentration (ppm) Emissions 

(lb N2O/ton) 

N2O 50 0.66 

Methane 4,500 1.5 

CO2 1,000 0.04 

NOx 150 

NH3 100 

Uhde has developed a process referred to as EnviNOx

®. More details are shown in 

Figures 4 and 5. There are two variants of the EnviNOx

® process depending on the tail gas 

temperature. Variant 1 is discussed under the next section – catalytic decomposition. Variant 2 

is suitable for lower tail gas temperatures ranging from 300 to 520 C. 

The low temperature variant utilizes hydrocarbons, such as natural gas, to drive catalytic 

reduction. The reaction vessel is positioned upstream of the tailgas expander (turbine). 

Ammonia is mixed with the tailgas that contains both N2O and NOx. The mixture passes through 

a single catalyst bed where parallel reduction of the pollutants takes place. The addition of 

hydrocarbons to drive this reaction is not thought to produce significant CO2 emissions when 

compared to the reduction of N2O in the unit (Uhde, 2005). This process utilizes a tailgas reactor 

positioned directly upstream of the tailgas expander (turbine). 

Figure 4 – Uhde Combination N2O and NOX Control for Nitric Acid Production Plants 

Source: ICAC, 2009. 
11 

Figure 5 – Uhde EnviNOx

® Reactor in Linz, Austria 

Source: ICAC, 2009. 

 Süd-Chemie has developed an NSCR process for removal of N2O from tailgas streams. 

The EnviCat® N2O is designed for tailgas temperatures less than 400°C. This system was 

developed in cooperation with Uhde. A vanadium-free catalyst is used to convert N2O and NOx

to nitrogen, oxygen, and water. This particular catalyst also removes the ammonia that was 

added to drive the reaction between the catalyst and N2O, thus preventing ammonia leakage. 

Conversion rates greater than 98 percent have been achieved with the EnviCat® N2O system right 

below the platinum gauze (Süd-Chemie, n.d.). 

 

 Süd-Chemie has another NSCR unit designed to reduce N2O and NOx emissions. The 

EnviCat® unit works best for tailgas temperatures greater than 400°C. This unit is a direct 

disintegration process with the catalyst positioned close to the reactor. Residual hydrocarbons 

are required in the tailgas stream to provide efficient control. Both N2O and NOx react with the 

hydrocarbons to break down the compounds to nitrogen and oxygen. In some cases, additional 

methane or hydrogen is necessary if the residual amount of hydrocarbons is too low for effective 

control (Süd-Chemie, n.d.). 
12 

Tertiary Controls – Catalytic Decomposition 

Decomposition technology, which can be high temperature or low temperature, does not 

require any additional reducing agents or additives, and no undesirable byproducts are formed 

from the reaction. The basis of decomposition technology is to simply decompose N2O to form 

nitrogen and oxygen (ICAC, 2009). A catalyst is used to drive the decomposition. This catalyst 

is stable in the presence of NOx and ammonia, allowing placement either upstream or 

downstream of the SCR used to reduce NOx (ICAC, 2009). Decomposition can remove up to 99 

percent of the N2O in the process stream. 

Uhde has developed a process referred to as EnviNOx

®. More details are shown in 

Figures 4 and 5. There are two variants of the EnviNOx

® process depending on the tail gas 

temperature. Variant 1 is discussed under this section – catalytic decomposition. Variant 1 is 

good for higher tail gas temperatures ranging from 425 to 520 C. For these temperatures, 

EnviNOx

® is a two stage process. In the first stage, N2O is decomposed to oxygen and nitrogen 

in a catalyst bed. The resulting tailgas is then mixed with ammonia and enters a second catalyst 

bed where NOx is reduced to water vapor and nitrogen. The N2O is further removed in this 

catalyst bed. (Uhde, 2005 and ThyssenKrupp, 2005). 

Another decomposition technology is the CRI N2O Abatement Technology (C-NAT). A 

pellet catalyst is contained within a lateral flow reactor. The tailgas is forced laterally through 

the packed-bed design to achieve more efficient utilization of the catalyst surface area than 

traditional catalyst design. This technology works best at temperatures between 450°C and 

650°C. Removal of N2O is typically within the range of 70-95 percent (CRI, 2009). 

 

 Shell has a similar C-NAT system that operates at temperatures as low as 300°C. Like 

the other direct decomposition systems, no additional reducing agents are required. The Shell CNAT system achieves greater than 98 percent reduction of N2O (ICAC, 2009). 

 Emission test results for tertiary controls were obtained from 2 sources – European 

Commission (February 2008) and monitoring reports from CDM projects (Appendix B). These 

results are summarized in Table 4. 

Table 4. N2O Emission Test Results- Tertiary Controls (lb N2O/ton) 

Source Units tested Range Average % Reduction 

Range 

% Reduction 

Average 

EC 7 0.02 – 0.48 0.18 Unknown Unknown 

CDM Projects 11 0.41 – 2.2 1.2 88 - 98 94 

 

Selective Catalytic Reduction

SCR is not an effective control technology for N2O emissions (Perez-Ramirez et al 2003). 

The CAR’s Nitric Acid Production Project Protocol elaborates that SCRs can have at least a 

slight unintentional impact on N2O emissions (+/- <5%) of total emissions (Climate Action 

Reserve, 2009). 
13 

Other Greenhouse Gas Emissions

Nitric acid plants may also indirectly have emissions of carbon dioxide (CO2)and CH4 by 

consuming steam or electricity produced through the combustion of fossil fuels during startup. 

This is common for plants with steam powered compressors that require the use of natural gas at 

startup. Once the plant begins operating normally, the plant will generate enough steam to 

power the compressor. Also, the plant will also be able to export additional steam to the rest of 

the facility which offsets steam production that could be produced by burning fossil fuels. 

During this limited time period, carbon dioxide is produced. 

Also, CO2 and methane (in small amounts) can be emitted by nitric acid plants controlled 

by nonselective catalytic reduction (NSCR) and other catalytic reduction technologies. 

Estimates of these emissions were shown in Table 2. Methane is often the fuel. Combustion of 

methane or other organic fuels produces carbon dioxide. As far as CO2 (equivalent) is 

concerned, the CO2 emissions result in a less than a 2% increase in GHG compared to the 80% 

reduction in GHG obtained from controlling N2O emissions using NSCR. This less than 2% 

increase is also lowered when considering that much of the heat produced in NSCR is recovered 

in the expander which is then used to power the compressor which in turn powers the nitric acid 

plant. This reduces the amount of power needed from either a steam turbine or electric motor. 

5.0 Energy Efficiency Improvements to Reduce other GHG Emissions (RTI, 2009) 

Energy Recovery 

 Nitric acid production is a net exporter of energy. Therefore, energy recovery is a 

valuable resource for these facilities. External sources of fuel can be minimized through 

recovery of energy from the production process. 

 There are two exothermic reactions, oxidation and absorption, that produce more energy 

than the total production process consumes. Single and dual-pressure plants are used within the 

US. For new plants, dual-pressure is the most predominant design. However, there is not a 

substantial difference in the total energy required or recovered from the two designs. 

 The energy requirements of controls should also be considered. As far as NOx controls, 

SCR units require less energy than NSCR units because they operate at lower temperatures. As 

shown earlier NSCR has the additional benefit of controlling N2O. The overall energy recovery 

is dependent on the design of the facility. Approximately 1,660 Btu/lb of 100% nitric acid 

(Btu/lb) is produced from the catalytic reactor. The absorption tower produces approximately 

370 Btu/lb. All of this energy is potentially available for recovery. Additionally, the expansion 

unit has the potential to recover 80 percent of the mechanical energy used, or approximately 325 

Btu/lb. This provides for an overall amount of energy available for recovery of approximately 

1,955 Btu/lb. The potential CO2 equivalent emissions that are avoided by this level of steam 

energy recovery are 0.26 tonnes CO2e per ton of 100% nitric acid. An additional 0.77 tonnes 

CO2e per ton 100% nitric acid is avoided through electric energy production. However, the 

actual levels of energy recovery, due to economic and practical considerations, are around 50-65 

percent of the theoretical values. Therefore, between 969 and 1,217 Btu/lb is available for 

recovery. This equates to an offset of 0.12 to 0.5 tonnes CO2e/ton HNO3. 
14 

 Steam production is the most common form of energy recovery for process lines in nitric 

acid production. Heat from the process is typically recovered and used to generate a large 

portion of the steam needed elsewhere in the plant. During startup, natural gas is used to 

augment this steam when nitric acid production is at levels below those needed to recover 

enough steam for the rest of the facility. Although not widely practiced currently at nitric acid 

production facilities, bottoming cycle combined heat and power (CHP) could also be used for 

energy recovery at nitric acid plants. With this type of CHP system, steam would be generated 

from heat recovery at a higher pressure than is needed in the other processes and run through a 

steam turbine generator before being sent to the processes at the required pressure. The power 

generated could be used within the plant, offsetting power purchases from the grid. This would 

not result in direct CO2 reductions at the facility from the power produced, but indirect 

reductions from displacing grid power. The level of reduction is a function of the CO2 intensity 

of the displaced external power production. 

Energy Efficiency 

There are energy efficiency measures that can be implemented at nitric acid plants. 

These areas include building lighting and HVAC, motors, compressed air and pumps. Energy 

Star has not prepared an Energy Guide specific to nitric acid plants. A general guide “Managing 

Your Energy”, EPA Document #LBNL-3714E is available.
15 

EPA Contacts 

Bill Neuffer 

U.S. EPA 

OAQPS/SPPD/MMG 

Mail Code D243-02 

Research Triangle Park, NC 27711 

Phone: 919-541-5435 

neuffer.bill@epa.gov

Nathan Frank 

U.S. EPA 

Region 5 

77 W. Jackson Blvd 

Chicago, IL 60604 

Phone: 312-886-3850 

frank.nathan@epa.gov

Mausami Desai 

U.S. EPA 

OAR/OAP/CCD 

Washington, DC 20460 

Phone: 202-343-9381 

desai.mausami@epa.gov
16 

References 

Climate Action Reserve, October 1, 2010. List of GHG Projects . 

https://thereserve1.apx.com/myModule/rpt/myrpt.asp?r=111 

Climate Action Reserve, December 2, 2009. Nitric Acid Production Project Protocol – 

Reducing Nitrous Oxide from Process Gas Emissions. 

http://www.climateactionreserve.org/wpcontent/uploads/2009/12/Nitric_Acid_Production_Project_Protocol_Version_1.0.pdf

CRI Catalysts Company (CRI), 2009. “N2O Decomposition,” October 2009. 

http://www.cricatalyst.com/products/environmental/n2o_Decomposition.aspx

Durilla, Mike, 2009. “NOx and N2O Control in Nitric Acid Plants,” Environment 

Management. Air and Waste Management Association. November 2009 

European Commission. August 2007. Integrated Pollution Prevention and Control. 

Reference Document on Best Available Techniques for the Manufacture of Large 

volume Inorganic Chemicals – Ammonia, Acids and Fertilisers. 

fttp://ftp.jrc.es/pub/eippcb/doc/lvic_bref_0907.pdf 

European Commission. February 2008. Support for the Development and Adoption of 

Monitoring and Reporting Guidelines and Harmonised Benchmarks for N2O 

Activities for Unilateral Inclusion for the EU ETS for 2008-12. 

http://ec.europa.eu/environment/climat/emission/pdf/benchmarking/entec_study_2008

.pdf 

Fraunhofer Institute. Methodology for the free allocation of emission allowances in 

the EU ETS post 2012. Sector Report for the Chemical Industry. November 2009. 

http://ec.europa.eu/environment/climat/emission/pdf/bm/BM%20study%20-

%20Chemicals.pdf

Institute of Clean Air Companies (ICAC), 2009. “NOx and N2O Reductions in Nitric 

Acid Plants,” PowerPoint Presentation, August 12, 2009. 

Industrial GHG, 6/17/2010. http://www.industrialghg.com/articleprint.jsp?article_id=6323

Perez-Ramirez, J., F Kapteijn, K. Schoffel, and J. A. Moulijn. “Formation and Control of N2O in 

nitric acid production: Where do we stand today?”. Applied Catalysis B: Environmental 44 

(2003) pp 117-151. 

“Product Benchmark – State of Play”. Presented at Ad-hoc ECCP Stakeholder meeting on 

benchmarking. Brussels. July 1, 2010. 
17 

RTI International (RTI), 2009. “Greenhouse Gas Industry Profile for the Nitric Acid 

Production Industry – Draft Final Report,” January 15, 2009, Research Triangle Park, 

NC. 

Slaughter, Carolyn. (cslaughter@icac.com), 13 August 2009. ICAC Nitric Acid Plant 

Presentation- Follow-up. E-mail to Bill Neuffer, (Neuffer.Bill@epa.gov). 

Süd-Chemie, n.d. “Catalytic Emission Control for Nitric Acid Plants,” Bruckmühl, 

Germany. http://www.sudchemie.com/scmcms/web/binary.jsp?nodeId=7106&binaryId=8671&preview=&dispo

sition=inline&lang=en

The Fertilizer Institute. List of Active Nitric Acid Facilities. September 9, 2009. 

Thyssen Krupp, 2005. “Uhde EnviNOx

® Process for the Combined Reduction of N2O 

and NOx emissions from Nitric Acid Plants,” Techforum, pp. 66-71, July 2005, 

Düsseldorf, Germany. 

http://www.thyssenkrupp.com/documents/Publikationen/Techforum/forum_07_05_en.

pdf

Uhde, 2005. “Nitric Acid,” Uhde and ThyssenKrupp, June 2005, Dortmund, 

Germany. http://www.uhde.eu/cgibin/byteserver.pl/pdf/broschueren/Duengemittel/Nitric_acid.pdf

U.S.EPA. AP-42, Background Report. Nitric Acid, Fifth Edition, Section 8.8. 

Research Triangle Park, NC. January 1996. 

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Manufacturing Plants. EPA-450/3-91-026. Research Triangle Park, NC. December 

1991. 

U.S. EPA. Compilation of Air Pollutant Emission Factors, Volume 1: Stationary 

Point and Area Sources, AP-42, Fifth Edition, Chapter 8.8. Research Triangle Park, 

NC. January 1996. 

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Washington, DC. June 2006. 

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430-R-10-006. Washington, DC. April 15, 2010. 

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Proposed Rule for Mandatory Reporting of Greenhouse Gases, January 22, 2009. 
18 

APPENDIX A 

SOUTHEAST IDAHO ENERGY, LLC 

POWER COUNTY ADVANCED ENERGY CENTER 

MERICAN FALLS, IDAHO 

http://www.deq.idaho.gov/Applications/NewsApp/showNews.cfm?news_id=2848&CFID=217875&CFTOK

EN=16675422

 The following is a summary from the press release (link) provided above, the Statement 

of Basis and the Permit to Construct (PTC). The facility will produce fertilizer products through 

the gasification of coal and petcoke. A pure H2 stream is used to manufacture ammonia which is 

used to produce nitrogen-based fertilizers. The nitric acid produced will be approximately 57% 

concentration at a rate of 575 TPD of 100% acid. 

 A final PTC was issued on 11/30/09 for this plant. As far as the nitric acid facility at this 

plant is concerned, the installation of an extended absorption tower and SCR is required for NOx 

control. Catalytic decomposition is required for N2O control. There are NOx, NH3 and N2O and 

emission limits for the plant. These limits are: 

• For NOx, reduce NOx emissions by 4.2 tpy from the Nitric Acid Plant. The NOx

emission limits are 50 ppmv, 0.60 lb/T, 14.4 lb/hr, and 63.0 TPY. There is an 

ammonia slip limit of 10 ppmv (dry) converted to 15 % oxygen. 

• For N2O, reduce the N2O emissions by 90% by volume from 3000 ppmv to 300 

ppmv. 

• The N2O emission limit was based on a performance guarantee by the technology 

provider. 
19 

APPENDIX B – US Nitric Acid Plants 

Company Parent Co City State

Apache Nitrogen Benson AZ 

El Dorado Nitrogen El Dorado AR 

Cherokee Nitrogen El Dorado Cherokee AL 

Agrium West Sacramento CA 

J R Simplot Helm CA 

PCS Nitrogen Fertlizer Potash Corp Augusta GA 

Rentech East Dubuque IL 

Koch Nitrogen Fort dodge IA 

Coffeyville Resource Coffeyville KS 

Koch Nitrogen Dodge KS 

Angus Chemical Sterlington LA 

Lyondell Chemical Lake Charles LA 

PCS Nitrogen Fertilizer Potash Corp Geismar LA 

Rubicon Geismar LA 

First Chemical Pascagoula MS 

Dyno Nobel Louisiana MO 

Agrium Beatrice NE 

Koch Chemical Beatrice NE 

Dyno Nobel Battle Mountain NV 

N-Ren Corp Carlsbad NM 

Agrium Cincinnati OH 

PCS Nitrogen Fertilizer Potash Corp Lima OH 

Koch Nitrogen Enid OK 

Dyno Nobel St Helens OR 

Dyno Nobel Donora PA 

Air Products Pasadena TX 

Dupont Beaumont TX 

El Dorado Nitrogen LSB Industries Baytown TX 

Goodpasture Dimmitt TX 

Invista Victoria TX 

Invista Orange TX 

Geneva Nitrogen Orica USA Geneva UT 

Agrium Kennewick WA 

Dyno Nobel Cheyenne WY 
20 

APPENDIX C - Summary of CDM Monitoring Reports – from 

http://cdm.unfccc.int/Issuance/index.html 

 

Plant Location Control Test Dates Uncontrolled 

(lb/ton) 

Controlled 

(lb/ton) 

Efficiency 

Rhodia Brazil 2 9/15/08 - 

5/11/09 

9.90 0.15 98% 

Haifa Chemicals – 

N2 

Israel 2 5/20/09 - 

3/24/09 

23.30 0.52 98% 

African 

Explosives 

South Africa 2 ended 

9/25/2007 

8.10 0.81 90% 

ONPI Philippines 2 ended 

2/22/2010 

8.90 0.89 90% 

Fosfertil 

Piacaguera NAP2 

Brazil 2 3/21/09 -

7/28/09 

9.60 1.30 86% 

Fertilizers & 

Chemicals 

Israel 2 06/07 -- 13.46 1.35 90% 

Deepak Fertilisers 

WNA III 

India 2 02/08 -- 

03/16/10 

10.22 1.53 85% 

Shijazhuang Jinshi China 2 6/27/08-

3/13/09 

12.20 1.54 87% 

Sasoi -Sasolburg South Africa 2 12/11/08-

8/3/09 

19.30 1.60 92% 

Jinxiang – Line 1 China 2 3/2/08 - 

5/15/08 

14.60 1.70 88% 

Rhodia Brazil 2 ended 

1/23/2007 

11.80 1.98 83% 

Haifa Chemicals – 

N2 

Israel 2 1/08 -- 13.34 2.00 85% 

Abonos 

ColombianosNAN1 

Colombia 2 10/07 -- 13.74 2.06 85% 

Yunnan Jiehua China 2 ended 

11/1/2007 

10.80 2.20 80% 

Shijazhuang Jinshi China 2 3/14/09 -

9/8/09 

13.10 2.30 82% 

Rashtriya 

Chemical 

India 2 ended 

7/21/2009 

23.80 2.40 90% 

Abonos 

ColombianosNAN2 

Colombia 2 10/07 -- 16.12 2.42 85% 

Deepak Fertilisers 

WNA I 

India 2 11/09 -- 3/10 17.20 2.60 85% 
21 

Plant Location Control Test Dates Uncontrolled 

(lb/ton) 

Controlled 

(lb/ton) 

Efficiency 

Rashtriya 

Chemical 

India 2 3/14/08-

7/21/09 

25.00 2.60 90% 

Haifa Chemicals – 

N4 

Israel 2 18.20 2.73 85% 

Anhui HuainanLine4 China 2 April 2009 -- 15.04 3.16 79% 

Haifa Chemicals – 

N1 

Israel 2 5/20/09 - 

3/24/09 

23.30 3.40 85% 

Haifa Chemicals – 

N1 

Israel 2 1/08 -- 23.72 3.56 85% 

Gujarat Narmada 

Valley 

India 2 10/29/09 - 

1/15/10 

12.50 3.60 71% 

Dongbu Hannong 

Chemicals 

Korea 2 01/27/07 -- 

03/30/10 

21.56 4.31 80% 

Sasoi - Sasolburg South Africa 2 8/10/08 - 

12/7/08 

19.30 4.90 75% 

Donghu Hannong 

Chemicals 

Korea 2 1/8/09 - 

10/15/09 

21.40 5.90 72% 

Haifa - N3 Israel 2 5/25/08 - 

2/4/09 

15.70 6.00 62% 

Haifa Chemicals – 

N3 plant 

Israel 2 5/25/08 - 

2/4/09 

15.70 6.00 62% 

Sasoi-Secunda South Africa 2 5/2/09-

1/31/10 

9.10 6.40 30% 

Wuiashan Line 2 China 2 6/27/08 - 

12/29/09 

13.40 6.70 50% 

Chuanhua China 2 06/25/07 -- 38.00 7.90 79% 

Sasoi -Secunda South Africa 2 8/31/08-

4/26/09 

9.00 8.20 9% 

Chongqing Fuyan China 2 10/20/08-

4/1810 

28.20 8.50 70% 

Donghu Hannong 

Chemicals 

Korea 2 1/4/08 - 

5/15/08 

21.40 8.60 60% 

Tianji Line 1 China 2 12/18/08 -

7/27/08 

22.20 10.90 51% 

Tianji Line 2 China 2 9/21/08 -

5/3/09 

29.00 11.30 61% 
22 

Plant Location Control Test Dates Uncontrolled 

(lb/ton) 

Controlled 

(lb/ton) 

Efficiency 

Tianji Line 3 China 2 12/31/08 - 

8/17/09 

20.30 11.60 43% 

 AVERAGE 17.14 4.10 76% 

Hu-Chems - 4 Korea 3 3/1/09 -

6/30/09 

13.70 0.41 97% 

Hu-Chems - 3 Korea 3 3/1/09 - 

6/30/09 

24.60 0.42 98% 

Omnia Fertilizer South Africa 3 2/1/09 - 

5/31/09 

12.40 0.48 96% 

PANNA 3 – 

Enaex 

Chile 3 7/1/09 - 

9/30/09 

16.60 0.65 96% 

Hu-Chems - 2 Korea 3 3/1/09 - 

6/30/09 

26.00 0.68 97% 

PANNA 3 – 

Enaex 

Chile 3 4/1/09 - 

6/30/09 

18.40 0.79 96% 

Abu Qir Fertilizer Egypt 3 3/10/09 - 

6/30/09 

14.10 0.97 93% 

PANNA 3 – 

Enaex 

Chile 3 9/1/07 -- 18.57 1.17 94% 

Pakarab Fertilizer Pakistan 3 6/1/09 - 

8/31/09 

22.80 2.20 90% 

Hanwha Corp Korea 3 1/7/07 - 21.17 2.46 88% 

Kaifeng Jinkai China 3 1/7/2007 - 31.43 3.22 90% 

 AVERAGE 19.98 1.22 94%