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 destructi on 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 gu idance 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 1.0i Table of Contents

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

2.0 PROJECT DESCRI PTION ............................................................................................... 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 Pl ant ....................................................................................... 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 To wer ...................................................................................... 2-11 2.2.8 Firewater Pu mp .................................................................................... 2-11 2.2.9 Flare .................................................................................................... 2-12 2.3 Project Emis sions ............................................................................................ 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 Requir ements ............................................................................ 3-2 3.2.2 Control Technolo gy 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 Engineer ing Practice Stack Height ..................... 3-7 3.2.6 Additional Impact Analysis ...................................................................... 3-8 3.3 Nonattainment Rules ......................................................................................... 3-8 3.4 Emission Stan dards ........................................................................................... 3-8 3.4.1 New Source Performance St andards — 40 CF R 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 Requirem ents ........................................................................................ 3-10 3.5.1 Title V Prog ram .................................................................................... 3-10 3.5.2 Risk Management Progra m ................................................................... 3-10 3.5.3 General Duty Clause ............................................................................. 3-11

4.0 BEST AVAILABLE CONTROL TE CHNOLOGY ANALYSIS .................................................... 4-1 4.1 Point Source Em issions ...................................................................................... 4-3 4.1.1 Ammonia Plant — Trai ns 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 Pu mp .................................................................................... 4-13 4.1.5 Flare .................................................................................................... 4-14 4.2 Greenhouse Gases (CO 2 e) ................................................................................ 4-15 4.2.1 Dilute GHG Emissions Result ing From Comb ustion .................................. 4-16 4.2.2 Concentrated CO 2 Emissions from the Ammonia Plant CO 2 Vents ............. 4-18 4.2.3 N 2 O Emissions from the Ni tric Acid Plant ................................................ 4-22

5.0 AIR QUALITY AN ALYSIS ............................................................................................... 5-1ii 6.0 ADDITIONAL IMPACT ANALYSIS ................................................................................... 6-1 6.1 Growth Anal ysis ................................................................................................ 6-1 6.2 Soils Analys is .................................................................................................... 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 Compar ed to Potential Emission s ............................. 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 Pr oposed US Nitrogen Site ................................... 3-6 Table 4-1 US Nitrogen Potential Em issions of GHGs ............................................................ 4-3 Table 4-2 US Nitrogen Emission Point Sources an d Respective Potent ial Emissi ons ............... 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 NO X Reduction Options ........ 4-7 Table 4-5 Financial Comparison of US Ni trogen Nitric Acid Plant NO X Reduction Options ..... 4-10 Table 4-6 Financial Comparison of US Nitrogen Boiler NO X Reduction Options .................... 4-13 Table 4-7 Financial Comparison of Nitric Acid Plant N 2 O Reduction Options ........................ 4-26 Table 6-1 Injury Threshold Concentrations for NO X ............................................................. 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 WorksheetsPSD 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 manufact ure nitric acid, ammonia (NH 3 ), and liquid ammonium nitrate solution (ANSOL). The facility will be located on appr oximately 400 acres at 471 Pottertown Road, Midway, Greene County, Tennessee, near the intersec tion of US Highway 11E (Andrew Johnson Highway) and I-81. The approximate Univer sal Transverse Mercator (UTM) coordinates of the facility are 319,733 meters east and 4,006,685 mete rs 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 a ttainment or unclassified area fo r all National Ambient Air Quality Standards (NAAQS). The federal and state Preven tion 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 rule s as one of 28 source categories that have lower thresholds for re quiring a PSD construction permit. Because

the threshold amounts will be exceed ed 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 (NO X ) 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 propos ed project and identifi es 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 (CO 2 e 1 ) 75,000 197,598 112,188 Yes Particulate Matter (PM) 25 22.63 23.22 No PM 10

15 10.65 11.11 No PM 2.5

10 8.15 8.61 No Sulfur Dioxide (SO 2 ) 40 0.50 0.50 No Nitrogen Oxides (NO X ) 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. CO 2 e = Carbon dioxide equivalents

This application will provide information to suppo rt a construction permit approval based on the following demonstrations and analyses of the project:

 Neither PSD ambient air incremen ts nor NAAQS will be violated.

 Emissions resulting from operation of the prop osed 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 vege tation will not be subjected to signifcant adverse impact.

The remainder of the air permit application pres ents the demonstrations and analyses mentioned above. Section 2 contains a description of the pr oposed project operations while Section 3 contains an analysis of the applicable regulations. Se ction 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 applic ation forms, emissions calcul ations, BACT RACT/BACT/LAER Clearinghouse (RBLC) search results, air qualit y modeling protocol, outputs from air dispersionPSD 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 wi th the Federal Land Managers, and documentation of Austin Powder’s cost of capital are included in the appendices.

With this application, US Nitrog en provides a detailed demonstratio n of compliance wi th all federal and State of Tennessee requirements for air quality protection prior to construction of the proposed new production facility. A construction permit a pplication 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, NH 3 , and ANSOL production facility at this location for the purpose of ve rtical supply chain integration wi th other Austin Powder locations throughout the United States. US Nitrogen’s parent company, Austin Powder, operates similar facilities throughout the world, meeting recogniz ed environmental, safety, and pollution control requirements. The ANSOL prod uced 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 fac ility will be constructed on appr oximately 400-acr e 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) an d 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 fac ility, 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 standar d best practices commonly found in facilities producing nitric acid, NH 3 , and ANSOL primarily using natural gas cracking and steam. Facility processes and equi pment are described in the following sections.

2.2.1 Steam Generating Boiler US Nitrogen proposes to install a natural gas-fi red 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 Br itish Thermal Units per hour (MMBtu/hr) and will use only natural gas as fuel.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-2PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-3PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-4 DWAYPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-5Figure 4 Emission Point LocationsPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-6 2.2.2 Ammonia Plant

The NH 3 plant will consist of two trains, capable of producing a total of 200 tons of synthetic NH 3 per day, or 68,000 tons per year. Synthetic ammonia refers to NH 3 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 nitrog en, 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 mo lecules to carbon and hydrogen is called

the catalytic steam reforming method . Six steps are required to produce synthetic NH 3 using

this method:

(1) Natural gas desulfurization (2) Catalytic steam reforming (3) CO shift (4) Carbon Dioxide (CO 2 ) removal (5) Methanation (6) NH 3 synthesis

The first, third, fourth, and fifth steps remove impurities such as sulfur, CO, CO 2 , and water from the feedstock, hydrogen, and sy nthesis gas streams. In the second step, hydrogen is manufactured and nitrogen (air) is introduced. The sixth step produces anhydrous NH 3 from the synthetic gas.

2.2.2.1 Natural Gas Desulfurization In this step of the NH 3 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 fe ed 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 proc ess stream passes downward through the catalyst filled tubes in the reforming furnace, pr oducing a gas containing hydrogen, CO, CO 2 , 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 withPSD 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 CO 2 ).

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 sy nthesis gas stream are converted to CO 2 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 CO 2 is removed from the process gas by cooling the gas and sending it through the CO 2 Absorber, an absorption tower. There, the CO 2 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 CO 2 Absorber in a continuous cycle. Initially,

the CO 2 gas (approximately 91% pure) will be captured and vented to the atmosphere. At a later date, efforts will be made to capture this CO 2 for commercial use at another facility.

2.2.2.5 Methanation Upon leaving the CO 2 absorber, the synthesis gas consists primarily of uncombined hydrogen and nitrogen with residual amounts of CO 2 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 nitr ogen-rich synthesis gas is converted to NH 3 . The process is not 100% efficient, and some of the unconverte d synthesis gas leaving this step is mixed with incoming raw synthesis gas and recy cled back through the process.

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

NH 3 synthesis gas, NH 3 recycle gas, process air, and refrigeration NH 3 . 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-8 After methanation, the sy nthesis gas is compressed and joined by the recycled synthesis gas and passed through the Gas Filter to remove entrained compressor oil and water. Any NH 3 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 NH 3 present in the gas. Cooling takes place by evaporation of refrigerant NH 3 in a closed-system.

The NH 3 -synthesis gas mixture flows to the Secondary Ammonia Separator, where the liquid NH 3 is separated before the gas passes through the tube side of the Loop Heat Exchanger. The unconverted synthesis gas flows to the A mmonia 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 NH 3 .

NH 3 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 NH 3 . From the Primary Ammonia Condenser, the NH 3 -synthesis gas mixture flows to the Primary Ammonia Separator where the liquid NH 3 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 NH 3 -rich flashed vapor then undergoes pressure reduction

to be condensed in a ch iller, where anhydrous NH 3 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 prod uce 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 ut ilize a high-temperature catalyti c oxidation process using the NH 3 produced in the process describe d previously in Section 2.2.2. This process will consist of three steps:

(1) NH 3 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 NH 3 is mixed with ambient air, heated, and then passed over a platinum catalyst, where the NH 3 is oxidized to nitric acid. The raw materials required for production of nitric acid are atmospheric air and NH 3 . These raw materials are combined at elevated temperature and pressure and passed over a platinum-containing catalyst, where the NH 3 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 NH 3 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 cont act 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

NO X 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 NO X content to approximately 1,000 parts per million (ppm) by vo lume, 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 af ter being fed to the stea m superheater. Tail gas from the hot gas expander then flows to the NO X 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 NO X 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 th e capacity to pr oduce 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 NH 3 . 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 th e neutralizer by the reaction between NH 3 vapor and

nitric acid. The NH 3 required for the reaction is provided by vaporizing liquid NH 3 . Nitric acid is supplied from the battery limits to the neutralizer. The NH 3 is mixed with the nitric acid by a sparger system in the bottom of the neutralizer. The NH 3 flow to the neutralizer is flow

ratio-controlled to the nitric acid flow to obtain the proper reaction. A sm aller amount of acid is added to the neutralizer based on the pH of the ne utralizer 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 neutrali zer boils off steam, which passes overhead into the ammonium nitrate scrubber along with a small amount of unreacted NH 3 . The steam is used to vaporize the NH 3 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 NH 3 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 concentr ation control and neutra lizes the unreacted NH 3 in the gas stream. A small amount of nitric acid is added to the ammonium nitrate scrubber to

maintain the acid-rich conditions necessa ry for neutralization of the unreacted NH 3 . Dilute

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

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

to the vent scrubber for remo val of remaining traces of NH 3 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 inPSD Permit Application 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 NO X emission control system at the nitric acid plant under vacuum. Approximately every 90 days the NO X emission control system will be shut down for approximately 24 hours. During that time, the ANSOL produc tion process will continue running, which will pull

nitric acid from the tank , while no additional nitr ic 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 thro ughout the plant for pr ocess 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 seri es 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 th e 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 co ncentrate dissolved solid s (within set design parameters), this entrained water becomes a source of particulate matter (PM) emissions. The cooling tower will have three cells and serv e 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 emerge ncy firewater pump to provide fire-fighting capability. The diesel engine, which will be rate d at approximately 400 horsepower (hp), will be routinely tested, as required by Federal, stat e, and local fire codes. The engine will bePSD 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 NH 3 unit startup and to combust vent gas during safety relief. Normal em issions 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

2-13Table 2-1Projected Annual Emissions (TPY)Source Description PM PM10PM2.5SO2NOXVOC CO CO2CH4N2O CO2e NH3Cooling 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 0.000 24 —Boiler 3.19 3.19 3.19 0.25 4.282.31 17.14 50,061 0.944 0.094 50,110 —Flare 0.00 0.00 0.00 0.01 2.320.47 2.71 2,848 0.053 0.006 2,851 —Plant Road17.97 2.12 0.23 — — — — — — — — —Nitric Acid Plant — — — — 54.80 — — —— 29.100 9,021 144.5ANSOL 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 0.042 22,402 1.75Ammonia Train 1 — CO2Vent — — — — — — 4.54 45,394 — — 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 0.042 22,402 1.75Ammonia Train 2 — CO2Vent — — — — — — 4.54 45,394 — — 45,394 —Total US Nitrogen Emissions: 22.63 10.65 8.15 0.50 76.43 4.93 90.36 188,481 1.842 29.284 197,598 148Emissions from Potential Commercial FacilityNon-Condensable Gas Vent — — — — — — 6.12 5,305 3.440 — 5,378 —Cooling Tower 0.59 0.46 0.46 — — — — — — — — —Total Project EmissionsIncluding Potential Facility2:23.22 11.11 8.61 0.50 76.43 4.93 87.40 102,998 5.282 29.284 112,188 148

Note:1. Emissions include truck traffic from proposed commercial facility, which would share the same entrance road.2. The US Nitrogen ammonia plant CO2vents would be routed to the proposed commercial facility, therefore, Total Project Emissions = Total US Nitrogen Emissions– Ammonia Train CO2Vents + Emissions from Potential Commercial Facility.3. CO2e = Carbon dioxide equivalentsPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-1 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 th at 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 fa cility 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 sp ecific 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 (PM 10

) and less than or equal to 2.5 microns in size (PM 2.5

),

SO 2 , CO, ozone (O 3 ), NO 2 , 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 an y 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 loca ted in or near these areas may be subject to more stringent air permitting requirements. The existing applicable NAAQS are presented in

Table 3-1.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-2 Table 3-1 NAAQS and PSD Increments and Significance Levels (μg/m 3 , unless otherwise noted) [1,2]

Pollutant and Time Period NAAQS PSD

Primary Secondary Class I Increment Class II Increment Significance Levels
PM 10 Annual Arithmetic Mean — — 4 17 1 24-Hour Average 150 150 8 30 5 PM 2.5 Annual Arithmetic Mean 15.0 15.0 1 4 0.30 24-Hour, 98 th Percentile 35 35 2 9 1.2 SO 2 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 NO 2 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 O 3 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/m 3 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), whic h 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 na med source categories that have the potential to emit 100 tons per year (TPY) or more or any othe r stationary facility that ha s the potential to emit 250 TPY or more of any pollutant regulated und er the CAA. “Potential to emit” meansPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-3 the capability, at maximum design capacity, to emit a pollutant afte r the application of control equipment.

A “major modification” is defined under PSD regula tions as a change at an existing major facility that increases emissions by greater than significan t 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/m 3 ) [2] Averaging Time
PM 25 10 24-Hour PM 10

15 10 24-Hour PM 2.5

10 — — SO 2 40 13 24-Hour NO X 40 14 Annual CO 100 575 8-Hour Ozone (VOCs or NO X ) 40 — — Pb 0.6 0.1 3-Month Fluorides 3 0.25 24-Hour Sulfuric Acid Mist 7 — — Hydrogen Sulfide (H 2 S) 10 0.2 1-Hour Total Reduced Sulfur (including H 2 S) 10 10 1-Hour Reduced Sulfur Compounds (including H 2 S) 10 10 1-Hour Greenhouse Gases (CO 2 e) [3] 75,000 —

—

Notes: 1. Source: 40 CFR 52.21 2. μg/m 3 = microgram per cubic meter 3. CO 2 e = Carbon dioxide equivalents

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

concentrations for NO 2 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 NO 2 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 signif icant air quality deterioration will result from the new or modified facility. Federal PSD requirements ar e contained in 40 CFR 52.21, Prevention of Significant Dete rioration of Air Quality. The State of Tennessee has adoptedPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-4 PSD regulations in TAPCR 1200-03-09-.01(4). Major ne w facilities and major modifications are required to undergo the following analysis related to PSD for each pollutan t 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 facilit y must also be reviewed with respect to Good Engineering Practice (GEP) stack height re gulations. Discussion s concerning each of these requirements are presen ted in the following sections.

The projected emissions from this proposed pr oject 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 a pplied 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 so urce that qualifies as a major PSD source, or to all regulated pollutants for which the increase in em issions 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 fe asible by the permitting authority, taking into consideration environmental, ener gy, and economic impacts.

The requirement for BACT was contained in the PSD requirements prescribed by the CAA Amendments of 1977. The premise behi nd 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 si gnificantly degrading air quality. Guidelines for

the evaluation of BACT can be found in EPA’s Gu idelines for Determining Best Available Control Technology (EPA, 1978) and th e 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 inPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-5 another area. According to EPA (1980), “BACT anal yses 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 fo und in Section 4.

3.2.3 Source Impact Analysis All PSD applicants must conduct air quality analys es to assess the ambient impacts associated with construction and operation of the facility. A separate air qua lity analysis must be submitted for each regulated pollutant for whic h the applicant proposes to emit in a significant amount from a new or modified major source. The main purp ose of the analysis is to demonstrate that

the new emissions from the source , in conjunction with related emi ssions 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 qual ity levels, and determining compliance with NAAQS and allowable PSD increments. Designated EPA mo dels 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 a ddress compliance with the NAAQS and PSD i ncrements 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 prop osed 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 Ni trogen facility and their relative distances from the proposed facility location.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-6 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. Ther e 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 thes e receptors. The Class I analysis documented in Section 5 and Append ix C demonstrate impacts less than the Class I significant impact levels and no adverse effects on visibility.

3.2.4 Air Quality Moni toring 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 amount s. For a major modification, the pollutants are those for which the new emissions increase exceeds the significan t 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 be low 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 mini mum 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).PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-7 As described in the air modeling report in Appendix C, NO 2 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 oper ations at the new US Nitrogen Fa cility 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 th at 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:

H g = H + 1.5L

Where H g

is the GEP stack height, H is the height of the structure or nearby structure, and L is the lesser dimension (heigh t 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 modelin g 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-8 3.2.6 Additional Impact Analysis In addition to air quality impact analyses, fede ral 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 co mmercial, residential, indu strial, and other growth

associated with the source also mu st 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 equipm ent have the potential to emit 100 TPY or more of the nonattainment pollutan t. 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 modifi cation 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 fo r all criteria pollutants. Theref ore, 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 re duction 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 noti fication, 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 an d operators of stat ionary compression ignition (CI) internal combustion engines (ICE) th at commence construction after July 11, 2005.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-9 The proposed firewater pump engi ne 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 reco nstruction 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 NO X emission limitation and continuous emissions monitoring requirements.

3.4.2 National Emission Standards for Haza rdous Air Pollutants (MACT) — 40 CFR 63 The EPA has promulgated emissions standards fo r 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 fr om the applicable regu latory 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 noti fication, 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-10 40 CFR 63, Subpart JJJJJJ — National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Inst itutional 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 Perm itting 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 appr ovals for air pollution sources include NSR for nonattainment areas, PSD, NSPS, NESHAP, cons truction permits, and operating permits. The requirements for construction permits ar e 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 fede rally-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 spec ify that all affected sources have a Title V permit to operate. The pr ojected emissions from this proposed project are

estimated to exceed the thresh olds 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 fac ility'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 applie s to all stationa ry sources that have a regulated substance present in a process in more than the listed threshold quantity. If the threshold quantity for a regulated substanc e is exceeded, then the facility would need to develop a risk management plan. The NH 3 to be used at this facilit y will be anhydrous (100%) NH 3 which is above the regulated NH 3 solution level of 20 percent aqueous NH 3 solution. Thus, the facility is required to prepare a risk management plan.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

3-11 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 operat ors of stationary source s to identify hazards that may result from accidental releases, to desi gn 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 ha zardous substance" that are not limited to the list of regulated substances under Section 112(r) or under Occupational Safety and Health Administration’s regulations.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-1 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 regu lations 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, taki ng into account techni cal 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 numer ical 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 ma jor stationary source. The pollu tants 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 an alysis. The “top-down” BACT approach requires that a source not only consider the most stringen t 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 Cleari nghouse (RBLC), Federal /State/Local new source review permits, technical journals and report s, and other sources (S ee Appendix E for RBLC searches). If the proposed BACT is equivalent to the most stringent em ission limit, no further analysis is necessary. However, if the most stringent emission lim it is not selected, additional analyses are required.

Once the most stringent emission limit has been identified, its techni cal 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 consider ed available if it has reachedPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-2 the licensing and commercial sale s 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 tech nically 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. Th e process continues until an emission level cannot

be eliminated.

Impact Analysis of Control Alternatives When the most stringent technically feasible em ission 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. Th e 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 co nsidered because of the po ssibility of a change in availability in subsequent years.

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

consideration to the cost effectiv eness (dollars per ton of polluta nt removed) for each option. The analysis generally includes an estimate of ca pital annualized costs for each alternative based on vendor quotes and established EPA cost-e stimating procedures. For the purposes of these economic impact analyses, a capital recove ry 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 wit h 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 emi ssion unit subject to BACT and the emission limit must be federally enforceable. Th at is, the emission limit must be short-term and specific such that regulatory agency personnel can determine compliance at any time.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-3 GHG BACT Analysis As of January 2, 2011, new EPA rules regulating GHG emissions from larg e 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 po llutants other than GHGs also will be subject to PSD requirements, including BACT, for GHGs if the new or modified source increases emissions by more t han 75,000 TPY of CO 2 e. A summary of GHG pollutants for US Nitrogen is given in Table 4-1. Total GHG pote ntial emissions exceed 75,000 TPY.

Table 4-1 US Nitrogen Potential Emissions of GHGs (TPY) Pollutant Emissions (TPY) CO 2 e (TPY) CO 2 188,481.6 188,481.6 CH 4 1.84 38.7 N 2 O 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 NO X and

GHG’s were considered in the BACT analysis. For simplicity and clarity, all GHG’s are considered together in this BACT analysis an d are handled separately from the NO X 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, Se ction 2.2 provides a detailed descri ption of all facility processes.

Table 4-2 US Nitrogen Emission Point Sources an d Respective Potential Emissions (TPY)

Source Description NO X CO 2 CH 4 N 2 O Ammonia Plant Train 1 — Fl ue Gas 7.5 22,380.0 0.422 0.042 Ammonia Plant Train 1 — CO 2 Vent — 45,394.3 — — Ammonia Plant Train 2 — Fl ue Gas 7.5 22,380.0 0.422 0.042 Ammonia Plant Train 2 — CO 2 Vent — 45,394.3 — — Nitric Acid Plant 54.8 — — 29.1 Steam-Generating Boil er 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 NO X and GHG point source is shown in Table 4-3.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-4Table 4-3Summary of Proposed BACT for Each US Nitrogen Emission SourcePollutant Emission SourceControl Technologies ConsideredIn Descending Order of ReductionLowest RBLCEmission RateControl TechnologyAssociated WithLowest RBLC RateEmission RateProposed As BACTControl TechnologyProposed As BACT CommentsNOXAmmonia Plant FlueSCR0.41 lbs NOX/T NH3LNB 0.41 lbs NOX/T NH3SCRSCR and LNB are technically feasible. Chose lowest RBLC rate using SCR.Estimated cost $4,546/T NOXremoved.LNBSNCRNitric Acid PlantSCR0.524 lbs NOX/T HNO3SCR 0.6 lbs NOX/T HNO3Extended absorption plus SCRAll technologies are technically feasible. Chose combination of extendedabsorption and SCR to achieve a 99%reduction. Estimated cost $231/TNOXremoved.NSCRExtended absorptionSteam BoilerSCR plus LNB plus FGR0.01 lbs/MMBtu LNB 0.01 lbs/MMBtu UNLB plus FGRAll technologies are technically feasible. Chose lowest RBLC rate usingULNB plus FGR. Estimated cost $2,649/T NOXremoved.ULNB plus FGRLNB and FGRFirewater PumpDiesel engine design in accordance with40 CFR 60, Subpart IIII3.2 g/kWh None 3.0 g/hp-hComply with 40 CFR 60, SubpartIIIIChose compliance with 40 CFR 60, Subpart IIII as BACTFlareMaintain high combustion efficiency bycomplying with 40 CFR 60.181.1 lbs/hr None3.1 lbs/hr during SU,0.49 lbs/hr during NOComply with 40 CFR 60.18Rates based on AP-42 factors for combustion of flare gas (SU) andnatural gas (NO). Chose compliance with 40 CFR 60.18 as BACT.GHG FromCombustionSourcesAll Combustion SourcesCCSNA NA Various Energy and process efficiencyCCS not commercially available for these sources. Chose energy andprocess efficiencies as BACT.Energy and process efficiencyConcentratedCO2Ammonia Plant CO2ventCCSNA NA 90,788.6 TPY CO2e Process efficiencyCCS transport costs for geologic sequestration alone estimated to be$115/T CO2. Terrestrial sequestration not commercially available.Chose process efficiencies as BACT.Process efficiencyN2ONitric Acid PlantTertiary controls —Catalytic DecompositionNA NA29.1 TPY N2O9021 TPY CO2ePrimary plus tertiary control(catalytic decomposition)Chose primary plus tertiary (catalytic decomposition) controls as BACT.Estimated cost $1.18/T CO2e.Tertiary controls — NSCRPrimary controlsPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-5 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

NH 3 per day (100 tons per train), or 68,000 tons per year. Synthetic NH 3 refers to NH 3 that has been synthesized from natural gas. The natural gas molecules are reduced to carbon and hydrogen. The hydrogen is then purified and reac ted 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 mo lecules to carbon and hydrogen is called

the catalytic steam reforming method . Six steps are required to produce synthetic NH 3 using

this method:

(1) Natural gas desulfurization (2) Catalytic steam reforming (3) CO shift (4) CO 2 removal (5) Methanation (6) NH 3 synthesis

The first, third, fourth, and fifth steps remove impurities such as sulfur, CO, CO 2 , and water from the feedstock, hydrogen, and sy nthesis gas streams. In the second step, hydrogen is manufactured and nitrogen (air) is introduced. The sixth step produces anhydrous NH 3 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 ga s leaving the primary refo rmer is controlled at approximately 1950°F. It is cooled in an air pr eheater coil, waste heat boiler and the economizer before being exhausted to the atmosphere at 425°F.

4.1.1.2.1 Flue Gas NO X Emissions There are three control technologies/m ethods available for reducing the NO X content of flue gas

emissions from ammonia plants. These include, in descending order of removal efficiency, (1) Selective Catalytic Reduction (SCR), (2) low-NO X burners (LNB), and (3) Selective Non-catalytic Reduction (SNCR).PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-6 LNB’s minimize the formation of NO X by controlling the quantities an d 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 NH 3 -containing reagent to react with

the NO X produced in the reformer to convert the NO X 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 NH 3 and NO X . SCR technology is capable of achi eving much larger reductions in NO X 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 NO X 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 NH 3 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 tech nically 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 NH 3 reformers was 11.93 lbs/hr for a 700 ton per day (TPD) plant, or 0.41 lbs NO X /ton

of NH 3 (T NH3 ). The control method specified for this so urce 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 NO X emissions was evaluated by determining the cost per ton of NO X 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 Gree ne 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-7 Table 4-4 Financial Comparison of US Nitrogen Ammonia Plant NO X Reduction Options 1,2
LNB SCR Inlet NO X(TPY) 52.3 52.3 Outlet NO X(TPY) 19.7 7.5 Reduction Efficiency (%) 62 86 NO XReduced (TPY) 32.6 44.8 Total Capital Investment ($) $5,759,100 3 $538,403 Capital Recovery Cost ($/yr) $920,082 3 $86,016 O&M Annual Expense ($/y) $172,773 $117,627 Total Annual Cost ($) $1,092,855 $203,643 Cost Of NO XRemoved ($/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 NO X removed, and all emissi ons are per Ammonia Plant train, therefore each must be multiplied times two for the entire Ammonia Plant. 3. Reflects the cost to rebuild the primar y 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 NH 3 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 NH 3 and unreacted NH 3 will be emitted to the atmosphere (NH 3 slip). NH 3 is a precursor to the formation of PM 10

and PM 2.5 in the atmosphere. LNBs do not result in the direct emission of additional air pollutants and result in very minor indirect emissi ons. LNB’s require no reagents like NH 3 .

4.1.1.2.1.4 Pr oposed 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 NO X /T NH3 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 prod uce 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 ut ilize a high-temperature catalyti c oxidation process using the NH 3 produced in the process descri bed previously. This proce ss will consist of three steps:PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-8 (1) Ammonia oxidation, (2) Nitric oxide oxidation, and (3) Absorption.

4.1.2.1.1 Ammonia Oxidation In this process, the NH 3 is mixed with ambient air, heated, and then passed over a platinum cataly st, where the NH 3 is oxidized to nitric acid. The raw materials required for production of nitric acid are atmospheric air and NH 3 . These raw materials are combined at elevated temperature and pressure and passed over a platinum-containing catalyst, where the NH 3 reacts with oxygen in the air. The resultant process gas is passed through the heat exchanger train where the major portion of this reac tion 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 NH 3 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

NO X 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 NO X Emissions There are three control technologies/methods available for reducing the NO X 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-9 Extended absorption reduces NO X 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, NH 3 , hydrogen, propane, butane, or naphtha) and passed over a catalyst bed. In the presence of the catalyst, the fuels are oxidized and the NO X 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 elimin ated by adding a fuel (u sually natural gas) and, after completing this step, to provide for the reaction with the NO X , in the presence of a catalyst, to produce a tail gas with a reduced NO X concentration. The catalysts used in NSCR usually contain platinum or palladium. These noble metals are de posited on either alumina pellets or honeycomb type of substrate.

With NSCR systems, most of the hydrocarbo ns from the natural gas are converted to CO 2 and CO, resulting in additional emissions of 6,000-7,000 ppm CO 2 and 300-400 ppm of CO, as well as some unburned hydrocarbons.

With SCR systems, oxygen is not consumed before the NO X is reduced, and the NO X 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 NH 3 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 NO X is reduced to nitrogen. The tail gas leaves the reactor with a reduced NO X concentration of 33-150 ppm, depending on the NO X concentration at the inlet to the SCR, the amount of catalyst, and

the reaction time. For nitr ic acid plants the inlet NO X concentration can range from 1,000-3,000 ppm depending on the extent to which NO X is reduced in the absorption tower.

SCR systems are easier to operate than NSCR systems and they begin reducing NO X during plant startup much earlier than NSCR. Although there are some additional emissions of NH 3 (known as slip) with SCR operation, there are no increases in emissions of CO 2 , 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 emi ssion limit identified in the RBLC was 0.524 lbs

NO X /ton of 100% acid produced (T 100% Acid ). The control method specified is SCR.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-10 A review of the permit for the facility for which th is 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 th e permit. The limit of 0.524 lbs NO X /T 100% Acid was set for Plant 7

while a limit of 0.6 lbs NO X /T 100% 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 NO X /T 100% 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 NO X /T 100% 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 NO X 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 NO X removed for each. Detailed Fina ncial Analysis Worksheets are included in Appendix G, while Table 4-5 summarizes the results of the analysis. Note that because

NSCR reduces both NO X and N 2 O, for the purposes of the financial analysis, the costs of the NSCR have been split 80% for NO X reductions and 20% for N 2 O reductions. This split is based on the fact that incoming NO X concentrations to the NSCR would be approximately 2,000 ppm while incoming

N 2 O concentrations would be approximately 500 ppm.

Table 4-5 Financial Comparison of US Nitrogen Nitric Acid Plant NO X Reduction Options 1
NSCR 2 SCR
Inlet NO X ( T PY ) 1

, 643.9 1

, 842.9 Outlet NO X(TPY) 82.6 54.8 Reduction Efficiency (%) 95 97 NO XReduced (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 $414,029 Cost Of NO XRemoved ($/T) $586 $232

Notes: 1. See Appendix G, Tables G-3 and G-4 for de tailed financial analysis worksheets. 2. Applied 80% of NSCR costs to the reduction of NO Xand 20% to the reduction of N 2 O.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-11 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 a ddition, 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 — NH 3 or natural gas. With an SCR unreacted NH 3 would be emitted to the atmosphere (NH 3 slip). NH 3 is a precursor to the formation of PM 10

and

PM 2.5 in the atmosphere. The additional electrical usage of both NSCR and SCR will result in

the indirect emission of NO X , SO 2 , and CO 2 from the generation of electricity. As stated earlier, with the NSCR system, most of the hydrocarbons from the natural gas are converted to CO 2 and CO, resulting in additional emissions of 6,000-7,000 ppm CO 2 and 300-400 ppm of CO, as well as some= unburned hydrocarbons. As no ted earlier, NSCR reduces both NO X and N 2 O.

4.1.1.2.2.4 Pr oposed BACT As stated earlier, the US Nitrogen facility will make use of existing ammoni a and nitric acid plant equipment which are being re-located to the Greene Co unty facility. The existing nitric acid plant absorption tower is designed to reduce NO X 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 NO X control purposes. Therefore, extended absorption, at

no additional cost to the fa cility, will initially reduce NO X emissions by about 50%.

Based on this analysis an emission limit of 12.5 lb/hr or 0.6 lbs NO X /T 100% Acid using a combination of extended absorption and SCR is proposed as BA CT. The extended absorption will reduce the NO X 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 NO X reduction of approximately 99%.

4.1.3 Steam-Generating Boiler 4.1.3.1 Process Description US Nitrogen proposes to install a natural gas-fi red 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-12 4.1.3.2 Boiler NO X Emissions There are three possible control technologies for reducing NO X emissions from natural gas-fired boilers in the 100–200 MMBtu/hr range. These incl ude, in descending order of removal efficiency, (1) SCR with LNB and flue gas recirculation (FGR), (2) ultra-low-NO X 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 NO X 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 NH 3 is mixed with the boiler exhaust gas in a static mixer prior to being fed over the catalyst. In the reactor, the NH 3 /exhaust gas mixture flows through the catalyst

where NO X is reduced to nitrogen.

The results of a RBLC search for 100-200 MMB tu/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 “Pre liminary Determination Summary” for the permit

associated with this emission limit indicates the applicant proposed to use LNB to meet the emission limitation. Further investigation re vealed that the 1.8 lbs/hr emission limit is equivalent, in that case, to 0.01 lb/MMBtu or 9 ppmv NO X , dry, corrected to 3% oxygen, averaged over three hours, which was designed to be consistent wi th 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 NO X emissions was evaluated by determining the cost per ton of NO X removed for each technology. Detailed Financial Analysis Worksheet s are included in Appendix G, while Table 4-6 summarizes the results of the analysis.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-13 Table 4-6 Financial Comparison of US Nitrogen Boiler NO X Reduction Options 1
LNB + FGR ULNB + FGR SCR+LNB+FGR
Inlet NO X (TPY) 47.8 47.8 47.8 Outlet NO X(TPY) 14.3 4.3 1.4 Reduction Efficiency (%) 70 91 97 NO X 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 $395,934 Cost Of NO XRemoved ($/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 NH 3 . With an SCR, un-reacted NH 3 would be emitted to the atmosphere (NH 3 slip).

NH 3 is a precursor to the formation of PM 10

and PM 2.5 in the atmosphere. The additional electrical usage will result in the indirect emission of NO X , SO 2 , and CO 2 from the generation of electricity.

4.1.3.2.4 Proposed BACT Based on this analysis, a NO X 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 NO X reduction (2.9 T/yr) is unreasonably high, there is additional consumption of resources (NH 3 ) and electrical energy, there are both direct (NH 3 ) and indirect (NO X , SO 2 , and CO 2 ) emission of additional air pollutants, and the ULNB plus FGR option can achi eve 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 emerge ncy 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 code s. 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-14 4.1.4.2 Pump NO X Emissions As mentioned above, the firewater diesel engine will be subject to 40 CFR 60 Subpart IIII (NSPS).

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

Emission Standards for Stat ionary 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 de tails 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 maxi mum of three times per year for 36 hours per event. The emissions from the vents last approx imately 12 hours per event. During startup, the maximum heat input, including the heat valu e 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 NO X Emissions The only control technology/meth od available for the control NO X 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-15 The EPA AP-42 NO X emission factor for flares is 0.068 lb/MMBtu and the AP-42 NO X emission factor

for uncontrolled combustion of natural gas is 100 lbs/10 6 standard cubic feet (scf) of natural gas. Based on the maximum heat input during startup of 45.6 MMBtu/hr, the proposed NO X 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 Propos ed BACT Operating the flare in compliance with 40 CFR 60.18 with an em ission 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 (CO 2 e)

Table 4-1 summarizes the GHG emissions from the US Nitrogen facility while Table 4-2 provides

the details of the emissions for each emissi on source. These GHG emissions fall into three categories, and for simplicity, were addresse d in this analysis in those three categories. The three categories are:

 Relatively dilute GHG emissions resulting from combustion

 Concentrated CO 2 emissions (greater than 90% CO 2 ) from the ammonia plant CO 2 vents

 N 2 O 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 Emissi ons from the Nitric Acid Production Industry

, USEPA, Research Triangle Park, December 2010.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-16 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 e fficiency 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, Tr ains 1 and 2 Flue Gas The flue gas streams from each train are the same. As discussed in Sectio n 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 CO 2 being formed during combustion. The natural gas combustion process will be optimized for maximum fuel efficiency to th e 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.):

 CO 2 22,380.0 TPY

 CH 4 0.422 TPY

 N 2 O 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 boil er 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 CO 2 emission rate, and be designed with ULNB plus FGR for NO X control (See Section 4.1.3.), the latest instrumentation and controls for controlling efficiency , and insulation to minimize en ergy leakage. The boiler will be operated with a thermal efficiency of 81% or greater.

The proposed GHG BACT emission limits are as fo llows (See Appendix B fo r a detailed description of the basis for these limits.):

 CO 2 50,061.1 TPY

 CH 4 0.944 TPYPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-17  N 2 O 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 de signed for energy ef ficient operation.

The proposed GHG BACT emission limits are as fo llows (See Appendix B fo r a detailed description of the basis for these limits.):

 CO 2 23.9 TPY

 CH 4 0.001 TPY

 N 2 O 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 NH 3 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 emissi ons). 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 an d 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, NH 3 , and other components in the gases flowing to the flare. Maximizing the combustion efficiency of the

flare maximizes the amount of CO 2 and other GHG’s produced by the flare. During normal operations, only natural gas, the fuel option with the lowest CO 2 emission rate, will be combusted. BACT is proposed to be energy efficient co mbustion 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.):PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-18 Normal Operations

 CO 2 2,559.8 TPY

 CH 4 0.048 TPY

 N 2 O 0.005 TPY

Startup

 CO 2 287.8 TPY

 CH 4 0.005 TPY

 N 2 O 0.001 TPY

4.2.2 Concentrated CO 2 Emissions from the Ammonia Plant CO 2 Vents

The concentrated CO 2 emissions are emitted from the CO 2 vents at the Ammonia Plant —

Trains 1 and 2. CO 2 emissions result from NH 3 synthesis after the CO shift. The CO 2 is removed from the process gas by cooling the gas and sending it through the CO 2 Absorber, an absorption tower. There, the CO 2 is removed from the gas by absorpti on in MDEA solution. The MDEA solution is regenerated in the Amine Regenerator and re-circulated through the CO 2 Absorber in a continuous cycle. Initially, the CO 2 gas will be captured and vented to the atmosphere . At a later date, efforts will be made to capture this CO 2 for commercial use at another facility.

The concentration of CO 2 in this gas stream is approximately 91 percent.

There are two control technologies/methods available for reducing the content of GHG’s in the CO 2 vents. They are, in descending order of removal efficiency, (1) CCS and (2) energy/process efficiency methods. The fact that the CO 2 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, CO 2 , are also considered technically feasible.

4.2.2.1 Carbon Capture and Sequestration CCS involves capturing CO 2 , 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 CO 2 is technically feasible since the existing gas stream has a CO 2 concentration of 91%. Some additional concentration of the CO 2 , as well as the removal of water, will be required, which is also technically feasible.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-19 4.2.2.1.2 Transportation Long-term carbon storage is possible only in a ve ry limited number of site s in the southeastern US and the US Nitrogen site is not a suitable storage location. Accordingly, the captured CO 2 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 CO 2 over long distances. Approximately 3,600 miles of CO 2 pipeline operate today in the United States. These pipelines generally carry CO 2 from naturally-occurring underground reservoirs, natural gas processing facilities, NH 3 manufacturing plants, and large coal gasification projects to oil fields. Pipeline transportation of CO 2 is typically accomplished with CO 2 that is compressed to pressures of 1,200 to 2,000 pounds per square inch. This co mpression requires high levels of energy consumption. In addition, water must be eliminated from CO 2 pipeline systems, as the presence of water results in formation of carbonic acid, whic h is extremely corrosive to carbon steel pipe. The primary compressor stations are located at the CO 2 source and at the storage site with booster compressors located as needed along the pipeline. In overall construction, CO 2 pipelines are similar to natural gas pipelines, requiring the same at tention to design, monitoring for leaks, and protection against overpressure, especially in popula ted areas. All of these technical issues can be addressed through modern pipeline construction and maintenance practices; therefore, transporting

the CO 2 from the CO 2 vents at the US Nitrogen facility is considered technically feasible.

4.2.2.1.3 Storage There are several options for permanent storage of CO 2 . They include gaseous storage in various geological formations (including saline formatio ns, 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 Ni trogen facility location is at least 300 miles from

the ocean.

4.2.2.1.3.1 Geologic Formations The geologic formations considered appropriate for CO 2 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 ro ck and pressurized CO 2 is injected into it. Under high pressure, CO 2 turns to liquid and can move through a formation as a fluid. Once injected, the liquid CO 2 tends to be buoyant and will flow up ward until it encounters a barrier of non-porous rock, which can trap the CO 2 and prevent further upward migration.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-20 The degree to which a specific underground formation is amenable to CO 2 storage can be difficult

to determine. Research is be ing performed today which is aimed at developing the ability to

characterize a formation before CO 2 injection in order to predict its CO 2 storage capacity.

Discussed below are the geologic formations th at have some potentia l 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 la yer of non-porous rock which forms a dome. This dome offers great potential to trap CO 2 and makes these formations excellent storage opportunities. As a value-added benefit, CO 2 injected into a depletin g oil reservoir can enable recovery of additional oil and gas, because when it is injected into a deplet ed oil bearing formation,

the CO 2 dissolves in the trapped oil and reduces its vi scosity. This improves the ability of oil to move through the pores in the rock and flow with a pressure differential to ward 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 CO 2 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. Alth ough 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-Min eable 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 CH 4 adsorbed onto pore surfaces, and wells can be drilled into

un-mineable coal beds to recover this coal bed CH 4 (“CBM”). Initial CB M recovery methods, dewatering and depressurization, leave an appreciable amount of CBM in the reservoir. Additional CBM recovery can be achieved by sweep ing the coal bed with nitrogen or CO 2 , which preferentially adsorbs onto the surface of the coal, releasing the CH 4 . It is estimated that 150 to 200 billion

metric tons of CO 2 sequestration potential exists in un-mineab le coal seams identified by the RCSPs. According to SERCSP, none of these seams are in th e vicinity of the US Nitr ogen facility, but there may be some potential storage capacity in un-mineable seams of the central Appalachian coal basin of southwestern Virginia, approx imately 100 miles from the facility. Although no extensivePSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-21 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 bearin g rock, and represent an enormous potential for

CO 2 storage capacity. The RCSPs estimate a rang e of 3,300 to 12,000 billion metric tons of sequestration potential in saline formations. Howe ver, 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 wit h their ability to store CO 2 . Saline formations contain minerals that could react with injected CO 2 to form solid carbonates. The carbonat e 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 injectio n 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 exte nsive 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 CO 2 from the CO 2 vents at the US Nitrogen facility would have to be transp orted 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 Tenne ssee 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 whic h is equal to an annualized cost of approximately $10,225,000. At this annual cost, the cost per ton of CO 2 transported would be about $115. For this reason, transport of the CO 2 from the US Nitrogen CO 2 vents to a geologic

formation was determined to be economically infeasible and no further analysis of storage in geologic formations was conducted.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-22 4.2.2.1.3.1.4 Terrestrial Ecosystems Terrestrial sequestration is the enhancement of CO 2 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 prov ides an opportunity for relatively low-cost CO 2 emissions offsets. Examples in clude tree-plantings, no-till farm ing, and forest preservation.

To date, there are no actual commercial applications of terrestrial sequestration of a CO 2 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 CO 2 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 N 2 O Emissions from the Nitric Acid Plant

N 2 O is an unwanted by-product of the manufacture of nitric acid. It is formed alongside the main, desired product during the catalytic oxidation of NH 3 in air over noble metal gauzes. N 2 O 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. NH 3 combustion to form NO:

NH 3 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 th e following equation:

4 NH 3 +5 O 2 → 4 NO +6 H 2 O

Simultaneously, N 2 O, nitrogen and water are formed as well, in accordance with the following equations:

4 NH 3 +3 O 2 → 2 N 2 +6 H 2 O

4 NH 3 +4 O

2 → 2 N 2 O +6 H 2 OPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-23 NO yield depends mainly on pressure and temperature in the NH 3 oxidation process and usually is in a range of 95% to 97%.

2. NO is oxidized to nitrogen dioxide (NO 2 ):

2 NO + O 2 → 2 NO 2

3. Absorption of NO 2 in water to form nitric acid (HNO 3 ):

3 NO 2 + H 2 O → 2 HNO 3 + NO

Based on similar nitric acid plant designs where the N 2 O has been measured with no reduction systems installed, it is estimated that the N 2 O formation across the NH 3 oxidation catalyst at the US Nitrogen plant will be on the order of 1,500- 1,800 ppm. Therefore, th is is the concentration used in this analysis as the uncontrolled concentration.

4.2.3.1 N 2 O Reduction Methods There are three categories of control technologies/methods available for reducing

the N 2 O 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 N 2 O by installing a catalytic reactor either upstream or downstream of the tail gas expansion unit following NH 3 oxidation. Tert iary processes can

be further broken down into two technolo gies/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, N 2 O and NO 2 ), while catalytic decomposition uses a specially formulated catalyst to chemica lly decompose the N 2 O to nitrogen and oxygen.

 Secondary controls/methods reduce N 2 O immediately after it is formed in the NH 3 oxidation step. This control/method em ploys a specially formulated catalyst to decompose the N 2 O to nitrogen and oxygen.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-24  Primary controls/methods reduce the amount of N 2 O formed in the NH 3 oxidation step. This is accomplished by modifying the cataly st 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 NH 3 oxidation reactor, some of the N 2 O 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 NH 3 oxidation catalyst.

This takes place in all nitric acid plants and can be enhanced by providing residence time at elevated temperatures above 800 o C. For the US Nitrogen nitric acid plant, this reduction method

can reduce the N 2 O from 1,500-1,800 ppm to approximately 500 ppm. It has been assumed that once the reactant gas is lowered to less than 500 o C, all N 2 O reduction ceases and the N 2 O 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 te chnically feasible for the US Nitrogen nitric acid plant.

4.2.3.1.2 Secondary Controls/Methods Secondary N 2 O reduction is classified as a reducing step that takes place directly underneath

the NH 3 oxidation catalyst. This secondary reduction takes plac e across a catalyst that is specially formulated to selectively reduce N 2 O and to not affect the NO that is produced in

the NH 3 oxidation reactor.

With this secondary reduction process, the re actor design must take into account design parameters that limit catalyst loss and hold NH 3 bypassing to a minimum. Also, with secondary reduction, the NH 3 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 NH 3 oxidation reactor.

Higher pressure drop across the reactor lowers the usable life of the reactor and causes bypassing of NH 3 around the platinum catalyst. NH 3 bypassing occurs when the clearances in the reactor catalyst hold-d own system become distorted beyo nd the ability of gasketing. NH 3 will bypass the platinum catalyst and the secondary reaction of NH 3 to nitrogen and waterPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-25 will take precedence over formation of NO. This bypassing leads to adverse reactions that lower

the NH 3 conversion efficiency.

As mentioned earlier, the US Nitr ogen facility will make use of exis ting nitric acid plant equipment which is being re-located to the Greene County facility. It is not pr actical to incorporate the changes to the plant design that would be required for secondary control, therefore, secondary control is not considered technically fe asible for the US Nitrog en nitric acid plant.

4.2.3.1.3 Tertiary Reduction Tertiary reduction of N 2 O occurs in the tail gas stream prior to the tail gas entering the hot gas expander. The tail gas, containing approximately 500 ppm of N 2 O, 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 NO X .

With NSCR, a reagent fuel, such as natu ral gas, is used to reduce both NO X and N 2 O over a catalyst to produce N 2 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 NO X and N 2 O 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 pe r 1% of oxygen destroyed. The US Nitrogen nitric acid plant will have an inlet tail gas free oxyg en concentration of 2.9%, the reduction of which would add about 855°F to the gas stream. Since th is 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 N 2 O reduction efficiency of 80-95%.

With NSCR systems, most of the hydrocarbo ns from the natural gas are converted to CO 2 and CO, resulting in additional emissions of 6,000-7,000 ppm CO 2 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 CO 2 , CO, or unburned hydrocarbons are emitted. The basis of decomposition technology is to decompose the N 2 O to form N 2 and O 2 . A catalyst is used to drive the decomposition. This catalyst is stable in the presence of NO X and NH 3 , allowing placement either upstream or downstream of an SCR used to reduce NO X . Catalytic decomposition is alsoPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-26 easier to operate than NSCR and begins reducing N 2 O 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 te chnically feasible options for control of N 2 O emissions from the US Nitrogen facility, a financial compar ison of the options was conducted. Detailed financial analysis worksheets are included in Appe ndix G, while Table 4-7 summarizes the results of the analysis.

Table 4-7 Financial Comparison of Nitric Acid Plant N 2 O Reduction Options 1 Primary Reduction Tertiary Reduction Using NSCR Tertiary Reduction Using Catalytic Decomposition Inlet N 2 O (TPY) 2,047.0 581.4 581.4 Outlet N 2 O (TPY) 581.4 24.1 29.1 Reduction Efficiency (%) 72 96 95 N 2 O Removed (TPY) 1,465.6 557.3 552.3 N 2 O Removed (TPY CO 2 e) 454,336 165,922 2 171,232 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 $630,983 Cost of CO 2 e Removed ($/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 CO 2 is produced. Therefore, the net CO 2 e removed is 172,763 TPY N 2 O as CO 2 e minus 6,841 TPY CO 2 produced.

As can be seen from Table 4-7, primary controls have the lowest cost per ton CO 2 e 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

N 2 O reduction is estimated to be 7.5 MWh/yr, while the additional natural gas consumed that is

attributable to N 2 O reduction is estimated to be 23 MMscf/yr (23,460 MMBtu/yr). Catalytic decomposition requir es an additional 385 MWh/yr in electrical usage.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

4-27 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 NO X , SO 2 , and CO 2 from the generation of electricity. As stated earlier, with the NSCR syst em, most of the hydrocarbons from the natural gas

are converted to CO 2 and CO, resulting in additional emissions of 6,000-7,000 ppm CO 2 and 300-400 ppm of CO, as well as some unburned hydr ocarbons. However, as noted earlier, NSCR

reduces both N 2 O and NO X .

4.2.3.5 Propos ed 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 CO 2 e 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 CO 2 e. This average price was based primarily on trades of offsets such as agricultural CH 4 offsets, agricultural soil offsets, coal mine CH 4 offsets, forestry offsets, fuel switching offsets, landfill CH 4 offsets, organic waste disposal CH 4 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 CO 2 e.

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 CO 2 e currently being traded in the voluntary US market. Although the cost per ton to reduce N 2 O using NSCR is lower than the cost of making an equal reduction using catalyti c 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, CO 2 , and unburned hydrocarbons), and are much quicker and easier to operate during startup and shutdown. Consequently, a N 2 O emission limit of 29.1 TPY (9,021 TPY CO 2 e) using a combination of the primary controls de scribed above and catalytic decomposition is proposed as BACT. This approach will result in about a 98% reduction in N 2 O emissions from the nitric acid plant.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

5-1 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 demonstrat ion that the project will no t 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, NO X emissions will be emitted in signific ant quantities and were therefore evaluated in the modeling analysis.

Only the emissions from the prop osed new facility were initially evaluated in the Source Impact Analysis of 40 CFR 52.21(k) and Air Quality An alysis of 40 CFR 52.21(m) for determining if the project significantly impacted local air qualit y. 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 Wilderne ss 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 eval uation 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 resu lt, these receptors were modeled to determine if there would be any NO 2 or plume impacts at this park.

The results of this significant impacts analysis de monstrate that the proposed project will result in ambient impacts of NO X in excess of Class II significance le vels. Therefore, a refined air quality analysis to calculate concentrations for comparis on to the NAAQS and increments was required for this pollutant. NAAQS and increment impact s were determined to be acceptable. NO 2 Class I impacts were determined to be less than significant. In addition, the near-field visibility analysisPSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

5-2 results demonstrate that visibility is will not be affected. Furtherm ore, the preconstruction ambient monitoring exemption levels were determined not to be exceeded.

A more detailed description of the modeling proced ures and results is presented in Appendix C.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

6-1 6.0 ADDITIONAL IMPACT ANALYSIS PSD regulations require an additional impacts an alysis of each pollutant emitted by a source, including the analysis of the effects on local soils and vege tation. 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 pollu tant 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 sign ificance 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 insignif icant. Greene Country experienced a 9.4% growth in population during th e 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 ho useholds 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 fr om associated growth in the local area.

6.2 Soils Analysis Because most air pollutants are ultimately deposite d primarily upon soil, the potential impact of these pollutants on terrestrial ecosystems is impo rtant. Pollutant emissi ons 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 depo sition) or contribute to nutritional imbalances in plant communities (e.g., excessive nitrogen deposition). The NO X emissions from the facility are not expected to have any significant impact on so ils 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.PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

6-2 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 woul d 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 ex pected to approach threshold levels for pollutant damage to vegetation in the area. The potential impacted vegetation is mostly residential and forest vegetation. The NO X maximum modeled 1- hr impact of 56.7 μg/m 3 is 6% of the maximum hourly screening concentration of 940 μg/m 3 . The screening concentration level for NO X is 3,760 μg/m 3 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 insignifican t 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 demons trated to cause plant growth ef fects are not anticipated to be approached as a result of facility emissions. Furt hermore, chronic pollution effects, either direct effects or possible effects from se condary 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 characteri zes injury threshold concentrations for NO X for plants

native to the Southeastern United States:PSD Permit Application US Nitrogen Midway, Tennessee August 2011, Revision 1.0

6-3 Table 6-1 Injury Threshold Concentrations for NO X Common Name Scientific Name NO X 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/m 3 , US Nitrogen will not surpass even the lowest threshold of impact – 65 μg/m 3 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 FormsAppendix B

Emission CalculationsAppendix C Air Dispersion Modeling and Class II Visibility AnalysisAppendix D Correspondence with Federal Land ManagersAppendix E RBLC Search Summary TablesAppendix F Austin Powder Cost of CapitalAppendix G BACT Financial Analysis WorksheetsOffice of Air and Radiation October 2010



## AVAILABLE AND EMERGING TECHNOLOGIES FOR

REDUCING GREENHOUSE GAS EMISSIONS FROM THE NITRIC ACID PR ODUCTION 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 N 2 

## O 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.211 

### A 

## bbreviations 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 CO 2 

### Carbon dioxide CO 2 

### e Carbon dioxide equivalent EU European Union GHG Greenhouse Gases H 2 

### Hydrogen IPCC Intergovernmental Panel on Climate Change IPPC Industrial Pollution Prevention and Control JI Joint Implementation kg N 2 

### O/tonne kilograms of N 2 

### O per tonne of 100% nitric acid kg CO 2 

### e/tonne kilograms of CO 2 

### e per tonne of 100% nitric acid lb N 2 

### O/ton pounds of N 2 

### O per ton of 100% nitric acid MTPD Million tons per day N 2 

### Nitrogen NH 3 

### Ammonia NO Nitric oxide NO 2 

### Nitrogen dioxide NO x 

### Nitrogen oxides NSCR Nonselective Catalytic Reduction N 2 

### O 4 

### Nitrogen tetraoxide N 2 

### O Nitrous oxide O 2 

### Oxygen PSD Prevention of Significant Deterioration SCR Selective Catalytic Reduction TPD Tons per day2 

### I. Introduction

This document is one of several white papers that summarize readily available information on control technique s and measures to mitigate greenhouse gas (GHG) emissions from specific industrial sectors. These white papers are sole ly intended to provide basic information on GHG control technologies and reduc tion measures in order to assist States and local air pollution control agencies, tribal aut horities, and regulated entities in implementing technologies or measures to reduce GHGs under th e Clean Air Act, particularly in permitting under the prevention of significan t deterioration (PSD) program and the assessment of best available control technology (B ACT). These white papers do not set policy, standards or otherwise establish any binding re quirements; such requirements ar e contained in the applicable EPA regulations and approved state implementation plans.

II. Purpose of this Document

This document provides information on c ontrol techniques and measures that are available to mitigate greenhouse ga s (GHG) emissions from the nitr ic acid production industry at this time. Because the primary GHG emitted by th e nitric acid production industry is nitrous oxide (N 2 

### O), the control technologies and measures pr esented in this document focus on this pollutant. While a large number of available technologies are disc ussed here, this paper does not necessarily represent all potenti ally available technologies or measures that that may be considered for any given source for the purposes of reducing its GHG emissions. N 2 

### O has a global warming potential that is 310 times that of CO 2 

### 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 s hould 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 th e Southeast Idaho Ener gy, LLC plant Advanced Energy Center in American Falls, Idaho. More details on this determin ation 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, conde nsation, and absorption to produce nitric acid at concentrations between 30 and 70 percent ni tric acid. High-strength acid (90 percent or greater nitric acid) can be produced from de hydrating, bleaching, condensing, and absorption of the weak nitric acid. The basic process tec hnology has not changed over time. Most US plants were built between 1960 and 2000. There are pres ently 39 active weak n itric acid production plants and one high-strength nitric acid production plant. These pl ants 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 diag ram 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) a nd 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 pressure s result in the production of more nitrogen (N 2 

### ) and N 2 

### O. 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 a ddition 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/c ondenser to form nitrogen dioxide (NO 2 

### ) and nitrogen tetroxide (N 2 

### O 4 

### ), a liquid dimer. This process step is temperature and pressure dependant. Low temperatures and high pressure s result in better oxidation.

The final step for the production of w eak nitric acid is absorption. The NO 2 

### 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. Dei onized process water is ad ded at the top of the absorption tower. The water flows countercurrently through the NO 2 

### /dimer mixture and absorption occurs on bubble cap or sieve trays. Any residual NO 2 

### is removed by a secondary air

stream.

Weak nitric acid production ut ilizes either a single- or dua l-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 th is single pressure is used in both the ammonia oxidation and nitrogen oxides absorp tion phases. Medium pressure pl ants 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 becau se NO conversion is favored under lower pressures while NO 2 

### and nitric acid formation are favored at higher pressures during the final reaction by combining low pressure ammonia oxidati on with high pressure absorption. Ammonia oxidation is usually carri ed out at slightly negative pr essure to about 4 atm. The reaction heat is recovered by a waste heat boile r, which supplies steam for the turbine driven compressor. After passing thru the cooler/conde nser, 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 se nt 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 ha ve the advantage of superior ammonia conversion4 

### 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 plan ts is their substantially higher capital cost for construction and installation versus si ngle 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 fr om the weak nitric aci d. Figure 2 presents a process flow diagram of the high-strength ni tric acid production process. The secondary production of high strength acid from weak acid is not known to result in additional N 2 

### O emissions. Sulfuric acid is fed with weak n itric 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.

N 2 

### O emissions and Nitric Acid Production Process

N 2 

### O emissions from nitric acid are a byproduc t of the process st ream and therefore characterized as “industrial process” emissions . Ammonia oxidation is the main source of N 2 

### O emissions from nitric acid pr oduction. The amount of N 2 

### O 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 N 2 

### O/ton for low pressure processes, 17 lb N 2 

### O/ton for medium pressure processes, and 21.9 lb N 2 

### O/ton for high pressure processes. More details on N 2 

### O formation are contained in Pe rez-Ramirez, J. et al, 2003.

In the US, N 2 

### O emissions contributed approximate ly 4.6% of total GHG emissions in 2008 in terms of CO 2 

### equivalents. The nitric acid producti on process is the th ird largest source of N 2 

### O emissions in the US, comprising 6% of total N 2 

### O emissions or 19 million metric tons (tonnes) of CO 2 

### equivalents (EPA 2010 Inventory).6 

### II. Summary of Control Measures

Table 1 summarizes the GHG control measur es 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 ($/ton CO 2 e) Operating Costs ($/ton CO 2 e) Demonstrated in Practice?

N 2 O Primary 30 - 85 None Unknown Unknown Yes

N 2 O Secondary 70 -90 None Unknown 0.12 – 0.97 Yes

N 2 O NSCR > 80 None 6.27 0.14 – 0.22 Yes

N 2 O Other Tertiary Controls >80 None 2.18 – 3.55 0.14 – 1.91 Yes



### Source: EPA 2006; Eur opean Commission August 2007

Three types of controls exist for N 2 

### O at nitric acid plants based on the location of the control within the nitric acid produc tion process: (Durilla, 2009)

• Primary – reduces the amount of N 2 

### O 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 N 2 

### O immediately after it is form ed in the ammonia oxidation step.

• Tertiary – reduces N 2 

### O by installing a catalytic re actor either upstream or downstream of the tailgas expans ion unit following ammonia oxidation.

The most common applied controls are second ary and tertiary cont rols. These control technologies employ abatement or decomposition control techniques. These technologies are capable of and typically achieve gr eater than 80 per cent reduction of N 2 

### O emissions. A 2006 EPA economic report constructed marginal abatement curves to be used for modeling the cost of emissions reductions of non-CO 2 

### greenhouse gases globally in the 2010 to 2020 timeframe (EPA, June 2006). In the nitric ac id sector, the report utilized e ngineering reports to characterize catalytic reduction methods developed by severa l companies. The capital costs for control technology ranged from $2 to $6 per ton of carbon equivalent rem oved. Operating costs ranged from $0.14 to $1.91 per ton carbon equivalent removed (US EPA; June 2006).

Most of the technologies discussed here we re first developed in Europe to support national commitments or emissions targets esta blished under the Kyoto Protocol. Under the recently updated European Union Industrial Pollu tion Prevention and Control (IPPC) Directive, member countries are required to set permit limits for N 2 

### O emissions based on the best available technologies. Controls have also been evalua ted in the context of offsets programs such as7 

### Climate Action Reserve (CAR), Clean De velopment Mechanism (CDM), and Joint Implementation (JI) under the Kyoto Protocol. Detailed descriptions on the monitoring of emissions with application of th ese controls at plants located world-wide are found at the United Nations Framework Convention on Climate Change website: http://unfccc.int . Information on N 2 

### O controls and related projects is available on CAR’s website at http://www.climateactionreserve.org/how/protoco ls/adopted/nap/current-nitric-acid-productionproject-protocol/ . Detailed descriptions on monitoring of emissions with the application of these controls at plants located wo rld-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 li sted in the CDM shows 66 n itric acid lines using N 2 

### O controls at nitric acid plants outside the US. Fifty three lines use secondary contro ls and 13 use tertiary controls ( http://cdm.unfccc.int/Projects/projsearch.html ). These numbers do not include the use of nonselective catalytic reduction (N SCR) which is used in 14 process trains in the US. Also, there are at least another 10 Eur opean lines using secondary cont rols 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 CO 2 

### e/tonne or 1.1 kg N 2 

### O/tonne or 2.2 lb N 2 

### O/ton. Units using NSCR were excluded in this ca lculation as units are not required to monitor other GHG (methane, CO 2 

### ) that are emitted from NSCR un its. (Product Benchmark, 2010).

Primary Control – Suppression of N 2 

### O formation

One primary control is the extension of the NH 3 

### 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 ar e estimated to be 70% to 85% (4 to 6 lb N 2 

### O/ton 100% acid or about 400 ppm). This technique is applicable to ne w plants with low additional investments. For existing plants, costs are mu ch higher as a new reactor may be required along with other plant modifications. (E uropean Commission, August 2007).

Another primary control is modifying the am monia oxidation gauzes. These catalysts can be improved platinum catalysts. A few pl ants 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 show ed a range of 3.6 –9.7 kg N 2 

### O/tonne (7.2 – 19.4 lb N 2 

### O/ton). The average was 6.2 kg N 2 

### O/tonne (12.4 lb N 2 

### O/ton). (European Commission, February 2008).8 

### Secondary Control - Catalytic N 2 

### O decomposition in the Oxidation Reactor

For this control, a catalyst is located immediately downstream of the NH 3 

### oxidation step. Using this catalyst, N 2 

### O is decomposed to N 2 

### and O 2 

### almost instantly as shown in Equation 1. Four compani es (Yara, BASF, Johnson Matthey, and He reaus) have developed selective catalysts for the removal of N 2 

### O. The catalyst is c ontained in the ammonia burner and is termed “selective” as it promotes the reactio n (1) below the decomposition of N 2 

### O to N 2 

### and O 2 

### . No major modification of the ammoni a oxidation reactor is typically required and the installation of this catalyst has shown no effect on ammonia c onversion. The placement of the catalyst in the ammonia burner allows for reduction of N 2 

### O emissions by increasing th e 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 N 2 

### O 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 N 2 

### O - Æ 2N 2 

### + O 2 

### (1)

One reference states this control has the lowe st capital cost as minimal modifications are required to the reactor for the ammonia oxidati on catalyst. There are no additional operating costs. A total of 63 process lin es at nitric acid plants worldwide have implemented this technology. As drafts of this repor t were being prepared, no US n itric acid facility was known to have installed or applied seconda ry controls in the U.S. (Dur illa, 2009). However, a recent article discusses a secondary catalyst being in stalled 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 em ission credits under the Climate Action Reserve program. Also, Terra Industries ha s installed secondary catalysts in Yazoo City, Mississippi and Claremore, Oklahoma.

Emission test results for secondary contro l were obtained from 2 sources – European Commission (February 2008) and monitoring report s from CDM projects (Appendix C). These results are summarized in Table 2. The CDM in cludes 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. N 2 

### O Emission Test Results- Secondary Controls (lb N 2 

### O/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 catalyst9 

### Figure 3 – Yara Secondary N 2 

### O Control from Nitric Acid Production Source: ICAC, 2009.



### Tertiary Controls –Catalytic Reduction

Nonselective Catalytic Reducti on (NSCR) is a common contro l technology utilized at nitric acid production facilities to reduce NO x 

### emissions where a reagent fuel, such as natural gas, propane, butane, or amm onia plant purge gas (mainly H 2 

### ) is used as a reagent to reduce NO x 

### , and N 2 

### O over a catalyst to produce N 2 

### and water. Similar to a three-way catalytic converter, reductions of NO x 

### and N 2 

### O occur while other emissions are oxidized. Catalysts for NSCR are usually based on platinum, vanadium pe ntoxide, iron oxide or titanium. Catalyst supports are typically made of alumina pellets or a ceramic honeycomb substrate. NSCR has a N 2 

### O reduction efficiency of 80-95 percent (Eur opean Commission, August 2007). As far as selection of a NO x 

### control, NSCR is typically used at plan ts that have the capability to preheat tailgas to 200 - 450o C and requi res a greater reagent input than SCR (RTI, 2009). As stated earlier, 14 process trains in the US use NSCR. Th ese facilities have installed NSCR to control NO x 

### emissions and as an additional benefit NSCR reduces N 2 

### O emissions. The emissions from one US plant with NSCR were 0.43 lb N 2 

### O/ton. In numerous nitric acid plants outside of the US, NSCR/catalytic reduction is used in conjunction with SCR.

A European report (Fraunhofer, 2009) estimate s that the average emissions from NSCR are 2.0 lb N 2 

### O/ton when the additional CO 2 

### and methane emitted from operation of the NSCR are included. Average emissions from NSCR, ac cording to this report, are shown in Table 3.10 

### Table 3. Emissions from NSCR

Pollutant Concentration (ppm) Emissions (lb N 2 O/ton) N 2 O 50 0.66 Methane 4,500 1.5 CO 2 1,000 0.04 NO x 150 NH 3 100



### Uhde has developed a pro cess referred to as EnviNO x ® 

### . More details are shown in Figures 4 and 5. There are two variants of the EnviNO x ® 

### process depending on the tail gas temperature. Variant 1 is discussed under the ne xt section – catalytic de composition. Variant 2 is suitable for lower tail gas temp eratures ranging from 300 to 520 C.

The low temperature variant utili zes hydrocarbons, such as natura l gas, to drive catalytic reduction. The reaction vessel is positioned upstr eam of the tailgas expander (turbine). Ammonia is mixed with the ta ilgas that contains both N 2 

### O and NO x 

### . 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 CO 2 

### emissions when compared to the reduction of N 2 

### O in the unit (Uhde, 2005). This pr ocess utilizes a tailgas reactor positioned directly upstream of the tailgas expander (turbine).

Figure 4 – Uhde Combination N 2 

### O and NO X 

### Control for Nitric Acid Production Plants Source: ICAC, 2009.11 

### Figure 5 – Uhde EnviNO x ® 

### Reactor in Linz, Austria

Source: ICAC, 2009.



### Süd-Chemie has developed an NSCR process for removal of N 2 

### O from tailgas streams. The EnviCat ® 

### N 2 

### O is designed for tailgas temperatures less than 400°C. This system was developed in cooperation with Uhde. A vana dium-free catalyst is used to convert N 2 

### O and NO x 

### to nitrogen, oxygen, and water. This particular catalyst also removes the ammonia that was added to drive the reaction between the catalyst and N 2 

### O, thus preventing ammonia leakage. Conversion rates greater than 98 percent have been achieved with the EnviCat ® 

### N 2 

### O system right below the platinum gauze (Süd-Chemie, n.d.).

Süd-Chemie has another NS CR unit designed to reduce N 2 

### O and NO x 

### emissions. The EnviCat ® 

### unit works best for tailgas temperatures greater than 400°C. Th is unit is a direct disintegration process with the ca talyst positioned close to the reactor. Residual hydrocarbons are required in the tailgas stream to provide efficient control. Both N 2 

### O and NO x 

### react with the hydrocarbons to break down the compounds to n itrogen and oxygen. In some cases, additional methane or hydrogen is necessary if the residual amount of hydroc arbons is too low for effective control (Süd-Chemie, n.d.).12 

### Tertiary Controls – Catalytic Decomposition

Decomposition technology, which can be high te mperature or low temperature, does not require any additional reducing ag ents or additives, and no unde sirable byproducts are formed from the reaction. The basis of decompos ition technology is to simply decompose N 2 

### O to form nitrogen and oxygen (ICAC, 2009). A catalyst is used to drive the decomposition. This catalyst is stable in the presence of NO x 

### and ammonia, allowing placement either upstream or downstream of the SCR used to reduce NO x 

### (ICAC, 2009). Decomposition can remove up to 99 percent of the N 2 

### O in the process stream.

Uhde has developed a process referred to as EnviNO x ® 

### . More details are shown in Figures 4 and 5. There are two variants of the EnviNO x ® 

### 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, EnviNO x ® 

### is a two stage process. In the first stage, N 2 

### O is decomposed to oxygen and nitrogen in a catalyst bed. The resulting tailgas is then mixed with ammonia and en ters a second catalyst bed where NO x 

### is reduced to water vapor and nitrogen. The N 2 

### O is further removed in this catalyst bed. (Uhde, 2005 and ThyssenKrupp, 2005).

Another decomposition technology is the CRI N 2 

### O 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 N 2 

### O is typically within the ra nge of 70-95 percent (CRI, 2009).

Shell has a similar C-NAT system that operate s at temperatures as low as 300°C. Like the other direct decomposition systems, no add itional reducing agents are required. The Shell CNAT system achieves greater th an 98 percent reduction of N 2 

### O (ICAC, 2009).

Emission test results for tertiary controls were obtained from 2 sources – European Commission (February 2008) and monitoring repo rts from CDM projects (Appendix B). These results are summarized in Table 4.

Table 4. N 2 

### O Emission Test Results- Tertiary Controls (lb N 2 

### O/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 N 2 

### O emissions (Perez-Ram irez et al 2003). The CAR’s Nitric Acid Production Project Protocol elaborates th at SCRs can have at least a slight unintentional impact on N 2 

### O 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 (CO 2 

### )and CH 4 

### by consuming steam or electricity produced through the combustion of fossil fuels during startup. This is common for plants with steam powered comp ressors that require the use of natural gas at startup. Once the plant begins operating nor mally, the plant will generate enough steam to power the compressor. Also, the pl ant 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 peri od, carbon dioxide is produced.

Also, CO 2 

### and methane (in small amounts) can be em itted by nitric acid plants controlled by nonselective catalytic reduction (NSCR) a nd other catalytic reduction technologies. Estimates of these emissions were shown in Tabl e 2. Methane is often th e fuel. Combustion of methane or other organic fuels prod uces carbon dioxide. As far as CO 2 

### (equivalent) is concerned, the CO 2 

### emissions result in a less than a 2% increase in GHG compared to the 80% reduction in GHG obtained from controlling N 2 

### O emissions using NSCR. This less than 2% increase is also lowered when considering that much of the h eat produced in NSCR is recovered in the expander which is then used to power th e compressor which in turn powers the nitric acid plant. This reduces the amount of power needed fr om either a steam turbine or electric motor.

5.0 Energy Efficiency Improvement s 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 faci lities. External sources of fuel can be minimized through recovery of energy from the production process.

There are two exothermic reactions, oxidati on and absorption, that produce more energy than the total production process co nsumes. 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 re quired 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 becau se they operate at lower temperatures. As shown earlier NSCR has the addi tional benefit of controlling N 2 

### O. 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 availabl e for recovery. Addi tionally, the expansion unit has the potential to recove r 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 CO 2 

### equivalent emissions that are avoided by this level of steam energy recovery are 0.26 tonnes CO 2 

### e per ton of 100% nitric acid. An additional 0.77 tonnes CO 2 

### e per ton 100% nitric acid is avoided through electric energy production. However, the actual levels of energy recover y, due to economic and practical considerations, are around 50-65 percent of the theoretical values. Therefor e, between 969 and 1,217 Btu/lb is available for recovery. This equates to an offset of 0.12 to 0.5 tonnes CO 2 

### e/ton HNO 3


### .14 

### Steam production is the most common form of energy recovery for proc ess lines in nitric acid production. Heat from the pr ocess is typically recovered a nd used to generate a large portion of the steam needed elsewhere in the pl ant. 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 f acility. Although not widely practi ced currently at nitric acid production facilities, bottoming cycle combined h eat and power (CHP) could also be used for energy recovery at nitric acid pl ants. With this type of CHP sy stem, steam would be generated from heat recovery at a higher pressure than is needed in the other pr ocesses and run through a steam turbine generator before being sent to th e processes at the required pressure. The power generated could be used within the plant, offse tting power purchases from the grid. This would not result in direct CO 2 

### reductions at the facility from the power produced, but indirect reductions from displacing grid power. The le vel of reduction is a function of the CO 2 

### intensity of the displaced extern al power production.

Energy Efficiency

There are energy efficiency measures that ca n be implemented at nitric acid plants. These areas include building lig hting 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.gov16 

## References

Climate Action Reserve, Octobe r 1, 2010. List of GHG Projects . https://thereserve1.apx.com/my Module/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. “N 2 

### O Decomposition,” October 2009. http://www.cricatalyst.com/products /environmental/n2o_Decomposition.aspx

Durilla, Mike, 2009. “NO x 

### and N 2 

### O Control in Nitric Acid Plants,” Environment Management. Air and Waste Manage ment Association. November 2009

European Commission. August 2007. Integrat ed Pollution Prevention and Control. Reference Document on Best Available T echniques for the Manufacture of Large volume Inorganic Chemicals – Amm onia, Acids and Fertilisers. fttp://ftp.jrc.es/pub/ei ppcb/doc/lvic_bref_0907.pdf

European Commission. February 2008. Suppor t for the Development and Adoption of Monitoring and Reporting Guidelines and Harmonised Benchmarks for N 2 

### O Activities for Unilate ral Inclusion for the EU ETS for 2008-12. http://ec.europa.eu/environment/clima t/emission/pdf/benchmarking/entec_study_2008 .pdf

Fraunhofer Institute. Methodology for the fr ee allocation of emission allowances in the EU ETS post 2012. Sector Report fo r the Chemical Industry. November 2009. http://ec.europa.eu/environment/c limat/emission/pdf/bm/BM%20study%20- %20Chemicals.pdf

Institute of Clean Air Companies (ICAC), 2009. “NO x 

### and N 2 

### O 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, a nd J. A. Moulijn. “Formation and Control of N 2 

### O in nitric acid production: Where do we stand today?”. Applied Catalysis B: Environmental 44 (2003) pp 117-151.

“Product Benchmark – State of Play”. Presen ted 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 Contro l for Nitric Acid Plants,” Bruckmühl, Germany. http://www.sudchemie.com/scmcms/web/binary.jsp?node Id=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 EnviNO x ® 

### Process for the Combined Reduction of N 2 

### O and NO x 

### 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 a nd 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. Nitr ic Acid, Fifth Edition, Section 8.8. Research Triangle Park, NC. January 1996.

U. S. EPA. Alternative C ontrol Techniques Document – Nitric and Adipic Acid Manufacturing Plants. EPA-450/3-91-026. Re search Triangle Park, NC. December 1991.

U.S. EPA. Compilation of Air Pollutant Em ission Factors, Volume 1: Stationary Point and Area Sources, AP-42, Fifth Editi on, Chapter 8.8. Research Triangle Park, NC. January 1996.

U.S. EPA. Global Mitigation of Non-CO 2 

### Greenhouse Gases. EPA 430-R-06-005. Washington, DC. June 2006.

U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2008. EPA 430-R-10-006. Washingt on, DC. April 15, 2010.

U. S. EPA. Technical Support Document for the Nitric Acid Production Sector: 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/sh owNews.cfm?news_id=2848&CFID=217875&CFTOK EN=16675422



### The following is a summary from the press re lease (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 H 2 

### 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 absorpti on tower and SCR is required for NO x 

### control. Catalytic decomposition is required for N 2 

### O control. There are NO x 

### , NH 3 

### and N 2 

### O and emission limits for the plant. These limits are:

• For NO x 

### , reduce NO x 

### emissions by 4.2 tpy from the Nitric Acid Plant. The NO x 

### 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 N 2 

### O, reduce the N 2 

### O emissions by 90% by volume from 3000 ppmv to 300
ppmv.

• The N 2 

### O 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 WY20 

### 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%

AbonosColombianosNAN1 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%

AbonosColombianosNAN2 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%