
                        Environmental Services Division
                        Environmental Services Division
                              Air Quality Bureau
                              Air Quality Bureau
                                       
                                       
                                       
                                       
                                       
                                       
                    Construction Permit Application Review
                            Engineering Evaluation 
                                      for
                       Issuance of Construction Permits 
                                       
                                       
                                 July 3, 2018
                                       
                                       
          MidAmerican Energy Company  -  Riverside Generating Station
                               6001 State Street
                            Bettendorf, Iowa 52722
                                       
                                       
                                       
                                       
                            Plant Number: 82-02-006
                                       
                            Project Number: 18-194 
                                       


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                               Table of Contents

Section 1	6
Purpose of this Document	6
Description of Applicant's Request	6
Department's Determination on Applicant's Request	7
Project Contact Information	8

Section 2	9
  Processes Description	8
 Natural Gas Combustion	9
 Electric Power Plants	11
  Facility's Description	12
 MidAmerican Energy Company	12
       Facility's SIC Code	13
       Facility's NAICS Code	13
       Facility's Location	13
  Facility's Compliance Status	14

Section 3	15
Construction Permit and Stack Testing History	15

Section 4	17
Applicability Review	17
 Potential to Emit (PTE)	17
 Title V Operating Program	18
 Prevention of Significant Deterioration (PSD)	19
 National Ambient Air Quality Standards (NAAQS)	23
 New Source Performance Standard (NSPS)	24
 National Emission Standards for Hazardous Air Pollutants (NESHAP)	26
 Iowa Administrative Code (IAC)	27

Section 5	29
Emission Limits: Direct and Indirect	29
Compliance Demonstration	31
Confidentiality	31
Comments on Draft Permits	31

Section 6	32
Project Air Emissions Calculations	32
Facility-Wide Air Emissions	39
Indicator Opacity	40
Stack Test Run Time	41



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Section 1

Purpose of this Document

      This document has been prepared to provide staff members of the Iowa Department of Natural Resources (Department) and the public a summary of the decisions made during the review of this project; the rationale behind these decisions; and an explanation of the requirements in the construction permit(s) issued.  


Description of Applicant's Request
   
      On May 14, 2018, Plant Number 82-02-006 (currently known as MidAmerican Energy Company  -  Riverside Generating Station) submitted a construction permit application requesting a restriction in natural gas usage for Boiler #9 (EU-1) so that the facility may become an area source for NESHAP purposes.  The Department assigned Project Number 18-194 to this application.  
      
      This application was later modified on June 22, 2018 to request that reference to NESHAP Subpart DDDDD be removed from the permits issued to the LNG Vaporizers (EU-70 and EU-71) and Auxiliary Boilers (EU-87 and EU-88). 
      
      The equipment evaluated under this project includes:
      
             Boiler #9 (EP-1 / EU-1). This boiler has a maximum heat input capacity of 1,202 million Btu per hour and it uses a low-NOx burner and over-fire air to control nitrogen oxides emissions.  It only combusts natural gas.
            
             LNG Vaporizer #1 (EP-70 / EU-70).  The maximum heat input capacity for this LNG vaporizer is 23.196 million Btu per hour and it only combusts natural gas.

             LNG Vaporizer #2 (EP-71 / EU-71).  The maximum heat input capacity for this LNG vaporizer is 23.196 million Btu per hour and it only combusts natural gas.
      
             Auxiliary Boiler #1 (EP-87 / EU-87).  The maximum heat input capacity for this boiler is 26 million Btu per hour and it only combusts natural gas.
      
             Auxiliary Boiler #2 (EP-88 / EU-88).  The maximum heat input capacity for this boiler is 26 million Btu per hour and it only combusts natural gas.
      

Department's Determination on Applicant's Request

      Sections 2 through 6 of this document describe the Department's detailed evaluation of Project Number 18-194.  Based on this evaluation, the Department has determined the following:
      
 MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is one of the 28 Prevention of Significant Deterioration (PSD) listed stationary source categories and potential emissions for each of several NSR pollutants are greater than 100 tons per year.  Therefore, this facility is considered a "major stationary source" for purposes of the PSD program.
            
 MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is a "major stationary source" for purposes of the Title V program, because potential emissions for each of several criteria pollutants are above 100 tons per year.  
            
 MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is now considered a "synthetic minor source" for NESHAP purposes, because restrictions have been imposed on the operation of this facility to reduce emissions below NESHAP major sources.  

 Boiler # 9 (EU-1) is of the source category affected by NSPS Subparts D (Standards of Performance for Fossil-Fuel-Fired Steam Generators) and Da (Standards of Performance for Electric Utility Steam Generating Units). However, this unit is not subject to either of this subparts, because its construction date was prior to the applicability date for each of these federal rules and the unit has not been modified since its construction date.
            
 The LNG Vaporizers (EU-70 and EU-71) and the Auxiliary Boilers (EU-87 and EU-88) are subject to NSPS Subparts A (General Provisions) and Dc (Standards of Performance for Small Industrial-Commercial Institutional Steam Generating Units).

 Boiler #9 (EU-1) is not an affected emission unit under NESHAP, because there are no applicable categories at this time.

 The LNG Vaporizers (EU-70 and EU-71) and the Auxiliary Boilers (EU-87 and EU-88) are of the source category, but not subject to NESHAP Subpart JJJJJJ (Industrial, Commercial, and Institutional Boilers Area Sources), because each of these units meets the definition of "gas-fired boiler" in §63.11237 of Subpart JJJJJJ.
            
 The need to conduct modeling analysis was not evaluated under this project, because there are no increases in emissions as a result of this project.

 The revised construction application submitted on June 22, 2018 by MidAmerican Energy Company has met all the requirements under 567 IAC 22.3 for issuance of air quality construction permits.
      
      
      
      
      
      
      Therefore, the Department has finalized Project Number 18-194 as follows:  
      
 Issued Permit No. 93-A-339-S3 for Boiler #9 (EP-1 / EU-1).
            
 Issued a Collection of Air Permits for the LNG vaporizers including the following permits:
 Permit No. 06-A-027-S2 for LNG Vaporizer #1 (EP-70 / EU-70)
                  
 Permit No. 06-A-028-S2 for LNG Vaporizer #2 (EP-71 / EU-71)
              
 Issued a Collection of Air Permits for the auxiliary boilers including the following permits:
 Permit No. 13-A-008-S3 for Auxiliary Boiler #1 (EP-87 / EU-87)
                  
 Permit No. 13-A-009-S3 for Auxiliary Boiler #2 (EP-88 / EU-88)
            
 Used the Department's most recent permit templates at the time that this permit was issued.
   

   Project Contact Information
   
         Contact information for both MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) and the Department concerning this project can be found below in Table 1.  
   
                         Table 1  -  Contact Information
   
Responsible Party
Company Contact
Air Quality Contact
Douglas Haiston
Unit Manager

6001 State Street
Bettendorf, IA 52722
Phone: (563) 333-8503
DHHaiston@midamerican.com 
Douglas Haiston
Unit Manager

6001 State Street
Bettendorf, IA 52722
Phone: (563) 333-8503
DHHaiston@midamerican.com
Rachel Quill
Environmental Engineer
Wallace Building
502 E 9[th] Street
Des Moines, IA 50319
Phone: (515) 725-9556
Fax: (515) 725-9501
Rachel.Quill@dnr.iowa.gov 
   


                                   Section 2

Processes Description

 Natural Gas Combustion

            MidAmerican Energy Company owns and operates several natural gas boilers at its Riverside Generating Station (Plant No. 82-02-006).  The facility's request to impose natural gas usage limits on its Boiler #9 (EU-1)will bring the facility-wide hexane potential emissions (highest Single HAP at this facility) below the NESHAP major threshold of 10 tons per year.  Facility-wide Total HAP potential emissions are well below the NESHAP major threshold of 25 tons per year.  This request is evaluated under this project (18-194).
            
            Natural gas is one of the major combustion fuels used throughout the country.  It is mainly used to generate industrial and utility electric power, produce industrial process steam and heat, and heat residential and commercial space.  Natural gas consists of a high percentage of methane (generally above 85 percent) and varying amounts of ethane, propane, butane, and inerts (typically nitrogen, carbon dioxide, and helium).  The average gross heating value of natural gas is approximately 1,020 British thermal units per standard cubic foot (Btu/scf).
            
            There are three major types of boilers used for natural gas combustion in commercial, industrial, and utility applications:  watertube, fireture, and cast iron.  
            
            Watertube boilers are designed to pass water through the inside of heat transfer tubes while the outside of the tubes is heated by direct contact with the hot combustion gases and through radiant heat transfer.  The watertube design is the most common in utility and large industrial boilers.  Watertube boilers are used for a variety of applications, ranging from providing large amounts of process steam, to providing hot water or steam for space heating, to generating high-temperature, high-pressure steam for producing electricity.  Furthermore, watertube boilers can be distinguished either as field erected units or packaged units.
            
            Field erected boilers are boilers that are constructed on site and comprise the larger sized watertube boilers.  Generally, boilers with heat input levels greater than 100 MMBtu/hour, are field erected.  Field erected units usually have multiple burners and, given the customized nature of their construction, also have greater operational flexibility and NOx control options.  Field erected units can also be further categorized as wall-fired or tangential-fired.  Wall-fired units are characterized by multiple individual burners located on a single wall or on opposing walls of the furnace, while tangential units have several rows of air and fuel nozzles located in each of the four corners of the boiler.
            
            
            
            
            
            Packaged units are constructed off-site and shipped to the location where they are needed.  While the heat input levels of packaged units may range up to 250 MMBtu/hour, the physical size of these units is constrained by shipping considerations and they generally have heat input levels less than 100 MMBtu/hour.  Packaged units are always wall-fired units with one or more individual burners.  Given the size limitations imposed on packaged boilers, they have limited operational flexibility and cannot feasibly incorporate some NOx control options.
            
            Firetube boilers are designed such that the hot combustion gases flow through tubes, which heat the water circulating outside of the tubes.  These boilers are used primarily for space heating systems, industrial process steam, and portable power boilers.  Firetube boilers are almost exclusively packaged units.
            
            In cast iron boilers, as in firetube boilers, the hot gases are contained inside the tubes and the water being heated circulates outside the tubes.  However, the units are constructed of cast iron rather than steel.  Virtually all cast iron boilers are constructed as package boilers.  These boilers are used to produce either low-pressure steam or hot water and are most commonly used in small commercial applications.
            
            The emissions from natural gas-fired boilers and furnaces include nitrogen oxides, carbon monoxide, carbon dioxide, methane, volatile organic compounds, trace amounts of sulfur dioxide, and particulate matter.
            
            Currently, the two most prevalent combustion control techniques used to reduce NOx emissions from natural gas-fired boilers are flue gas recirculation (FGR) and low NOx burners.
            
            In an FGR system, a portion of the flue gas is recycled from the stack to the burner windbox.  Upon entering the windbox, the recirculated gas is mixed with combustion air prior to being fed to the burner.  The recycled flue gas consists of combustion products that act as inerts during combustion of the fuel/air mixture.  The FGR system reduces NOx emissions by two mechanisms.  Primarily, the recirculated gas acts as a diluent to reduce combustion temperatures, thus suppressing the thermal NOx mechanism.  To a lesser extent, FGR also reduces NOx formation by lowering the oxygen concentration in the primary flame zone.  The amount of recirculated flue gas is a key operating parameter influencing NOx emission rates for these systems.  An FGR system is normally used in combination with specially designed low NOx burners capable of sustaining a stable flame with the increased inert gas flow resulting from the use of FGR.  When low NOx burners and FGR are used in combination, these techniques are capable of reducing NOx emissions by 60 to 90 percent.
            
            Low NOx burners reduce NOx by accomplishing the combustion process in stages.  Staging partially delays the combustion process, resulting in a cooler flame that suppresses thermal NOx formation.  The two most common types of low NOx burners being applied to natural gas-fired boilers are staged air burners and staged fuel burners.  NOx emission reductions of 40 to 85 percent (relative to uncontrolled emission levels) have been observed with low NOx burners.
            
              

 Electric Power Plants

            Electric power plants have a number of components in common (see Figure 1) and are an interesting study in the various forms and changes of energy necessary to produce electricity.

                  
                                       
                        Figure 1: Electric Power Plant
		
            Boiler Unit: Almost all of power plants operate by heating water in a boiler unit into superheated steam at very high pressures.  The source of heat from combustion reactions may vary in fossil fuel plants from the source of fuels such as coal, oil, or natural gas.  Biomass or waste plant parts may also be used as a source of fuel.  In some areas solid waste incinerators area also used as a source of heat.  All of these sources of fuels result in varying amounts of air pollution.
            
            In a nuclear power plant, the fission chain reaction of splitting nuclei provides the source of heat.
            
            Turbine-Generator: The superheated steam is used to spin the blades of a turbine, which in turn is used in the generator to turn a coil of wires within a circular arrangements of magnets.  The rotating coil of wire in the magnets results in the generation of electricity.
            
            Cooling Water: After the steam travels through the turbine, it must be cooled and condensed back into liquid water to start the cycle over again.  Cooling water can be obtained from a nearby river or lake.  The water is returned to the body of water 10 to 20 degrees higher in temperature than the intake water.  Alternate method is to use a very tall cooling tower, where the evaporation of water falling through the tower provides the cooling effect.
            
            
            



Facility's Description

 MidAmerican Energy Company 

            MidAmerican Energy Company provides service to 770,000 electric customers and 751,000 natural gas customers in a 10,600-square mile are in Iowa, Illinois, South Dakota, and Nebraska.  MidAmerican Energy Company is a subsidiary of Berkshire Hathaway Energy.
            
                     
                                             
                 Figure 2: MidAmerican Energy Riverside Generating Station
            
            Electricity is produced at an electric power plant, such as MidAmerican's Riverside Generating Station in Bettendorf, Iowa (see Figure 2).  The facility uses natural gas in its boilers to produce heat, which in turn creates steam.  MidAmerican's Riverside Generating Station includes the following natural gas-firing equipment:
            
 Boiler #9 (EU-1) with a maximum heat input capacity of 1,202 million Btu per hour; Permit No. 93-A-339-S2.
 Process Heater #1 (EU-70) with a maximum heat input capacity of 23.196 million Btu per hour; Permit No. 06-A-027-S1.
 Process Heater #2 (EU-71) with a maximum heat input capacity of 23.196 million Btu per hour; Permit No. 06-A-028-S1.
 LNG Emergency Generator (EU-77) with a maximum rated capacity of 133 horsepower.  This unit is grandfathered; therefore, no construction permit has been issued to this unit.
 BSC Emergency Generator (EU-78) with a maximum rated capacity of 31 horsepower.  This unit is grandfathered; therefore, no construction permit has been issued to this unit.
 Natural Gas Boiler (EU-087) with a maximum heat input capacity of 26 million Btu per hour; Permit No. 13-A-008-S2.
 Natural Gas Boiler (EU-088) with a maximum heat input capacity of 26 million Btu per hour; Permit No. 13-A-009-S2.
         
         
 Facility's Standard Industrial Classification Code
            
            The primary SIC code for MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is 4911 (Electric Services).  This code describes establishments primarily engaged in the generation, transmission, and/or distribution of electric energy for sale.
            
 Electric power generation, transmission, or distribution
                   
            
 Facility's North American Industrial Classification System Code
            
            The primary NAICS code for MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is 221112 (Fossil Fuel Electric Power Generation).  This U.S. industry comprises establishments primarily engaged in operating fossil fuel powered electric power generation facilities.  These facilities use fossil fuels, such as coal, oil, or gas, in internal combustion or combustion turbine conventional steam process to produce electric energy.  The electric energy produced in these establishments is provided to electric power transmission systems or to electric power distribution systems.
         
         
 Facility's Location
            
            MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is located on 6001 State Street, in Bettendorf, Iowa.  Bettendorf is part of Scott County.  The Department's local representative for this county is listed below.
   
            Washington Field Office #6
            Iowa Department of Natural Resources
            1023 West Madison Street
            Washington, IA 52353
            Telephone: (319) 653-2135
            Fax: (319) 653-2856
                              
                              




Facility's Compliance Status 

      Air Quality Bureau (AQB) Compliance Database 

            There are 5 entries in the AQB Compliance Database for MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) and they all have been cleared; therefore the facility is cleared for the issuance of permits.
            
      
      Field Office (FO) Compliance Database 
            
            According to the FO Compliance Database, MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) was inspected by Field Office 6 on February 16, 2017.  The inspection report, dated February 27, 2017, indicates that there were no air quality permitting or recordkeeping violations.
   

                                   Section 3

Construction Permit and Stack Testing History

 Boiler #9 (EP-1) 

 Boiler #9 (EP-1 / EU-1) was first permitted under Project Number 93-118 and Original Permit No. 93-A-339 was issued on May 18, 1993.  This permit has been modified several times.  The most recent modification prior to Project Number 18-194 was approved by the Department on 10/13/2015 and Permit No. 93-A-339-S2 was issued under Project Number 15-266.
         
 There is no stack testing history associated with Boiler #9, because the Department has not required that stack testing be conducted on Boiler #9.

 LNG Vaporizer #1 (EP-70) 

 LNG Vaporizer #1 (EP-70 / EU-70) was first permitted under Project Number 06-005 and Original Permit No. 06-A-027 was issued on January 20, 2006.  This permit modified once prior to Project Number 18-194 and Permit No. 06-A-027-S1 was issued on 06/29/2006, under Project Number 06-353.
         
 The Department required carbon monoxide (CO) stack testing on LNG Vaporizer #1.  The most recent CO testing was conducted on January 29, 2009.  The results demonstrated compliance with the limit of 400 ppmv.
      
 LNG Vaporizer #2 (EP-71) 

 LNG Vaporizer #2 (EP-71 / EU-71) was first permitted under Project Number 06-005 and Original Permit No. 06-A-028 was issued on January 20, 2006.  This permit modified once prior to Project Number 18-194 and Permit No. 06-A-028-S1 was issued on 06/29/2006, under Project Number 06-353.
         
 The Department required carbon monoxide (CO) stack testing on LNG Vaporizer #2.  The most recent CO testing was conducted on January 29, 2009.  The results demonstrated compliance with the limit of 400 ppmv.

 Auxiliary Boiler #1 (EP-87) 

 Auxiliary Boiler #1 (EP-87 / EU-87) was first permitted under Project Number 13-009 and Original Permit No. 13-A-008 was issued on January 18, 2013.  This permit modified twice prior to Project Number 18-194.  The most recent modification was approved by the Department on 10/31/2013 and Permit No. 13-A-008-S2 was issued under Project Number 13-357.
         
 The Department originally required stack testing on Auxiliary Boiler #1, but it was removed on 08/13/2013 under Project Number 13-244.  



 Auxiliary Boiler #2 (EP-88) 

 Auxiliary Boiler #2 (EP-88 / EU-88) was first permitted under Project Number 13-009 and Original Permit No. 13-A-009 was issued on January 18, 2013.  This permit modified twice prior to Project Number 18-194.  The most recent modification was approved by the Department on 10/31/2013 and Permit No. 13-A-009-S2 was issued under Project Number 13-357.
         
 The Department originally required stack testing on Auxiliary Boiler #2, but it was removed on 08/13/2013 under Project Number 13-244.  

















                                   Section 4
   
Applicability Review

    Potential to Emit (PTE) 

   Per 567 IAC 20.2  -  Definitions, Potential to emit means the maximum capacity of a stationary source to emit any air pollutant under its physical and operational design.  Any physical or operational limitation on the capacity of a source to emit an air pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed shall be treated as part of its design if the limitation is enforceable by the administrator.
   
   For any limit or condition to be a legitimate restriction on potential to emit, that limit or condition must be federally- enforceable, which in turn requires practical enforceability.  Practical enforceability means the source and/or enforcement authority must be able to show continual compliance (or noncompliance) with each limitation requirement.  In other words, adequate testing, monitoring, and record-keeping procedures must be included either in an applicable federally issued permit or in the applicable federally approved State Implementation Plant (SIP) or the permit issued under the same.
   
   Federally-enforceable permit conditions that may be used to limit potential to emit can be expressed in a variety of terms and usually include a combination of two or more of the following four requirements in conjunction with appropriate record-keeping requirements for verification of compliance:
   
 Installation and continuous operation and maintenance of air pollution controls, usually expressed as both a required abatement efficiency of the maximum uncontrolled emission rate and a maximum outlet concentration or hourly emission rate (flow rate x concentration);
         
 Capacity limitations;
         
 Restrictions on hours of operation, including seasonal operation; and
         
 Limitations on raw materials used (including fuel combusted) and stored.
   
   
   
   
   
   
   
   
   
   
   
   
   
   
   
   Potential to Emit for MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006)
   
      Table 2 lists potential emissions for criteria pollutants and for hazardous air pollutants for Plant No. 82-02-006 and includes emissions from the equipment evaluated under this project (18-194).  Emissions calculations for Project Number 18-194 are included in Section 6 of this document.
   
            Table 2  -  Potential Emissions for Plant No. 82-02-006

Pollutant
                           Potential Emissions (tpy)
PM
                                   2,311.89
PM10
                                   2,311.89
PM2.5
                                   2,311.89
SO2
                                     3.11
NOx
                                    860.58
VOC
                                     30.83
CO
                                    164.35
Single HAP (hexane)
                                     9.33
Total HAP
                                     9.75
      

    Title V Operating Program 
      
   Operating permits are legally enforceable documents that permitting authorities issue to air pollution sources after the facility has begun to operate.  The Operating Permit program is often referred to as "Title V" since the authority comes from Title V of the Clean Air Act Amendments (CAAA) of 1990.  
   
   The Title V program mostly affects the largest emitters, but it also impacts some smaller sources of air pollution.  567 IAC 22.101(1) defines the types of sources that need to obtain a Title V permit.  Some of these include:
   
       "Affected Sources" under the Acid Rain rules (Title IV of the CAA) regardless of size
      
 Any source with a major source permit under New Source Review (NSR)

 Any source (including non-major sources) subject to a requirement under Section 111 (New Source Performance Standards) of the CAA
 Any "major stationary source" as defined under the Title V program.  For sources in attainment areas, major source status is defined as:
   
               A potential-to-emit (PTE) equal to or greater than 100 tons/year of any criteria pollutant,
              
               A PTE equal to or greater than 10 tons/year of any individual "hazardous air pollutant (HAP)" listed in Section 112 of the Act, or
              
               A PTE greater than or equal to 25 tons/year of total HAP emissions
      
   Title V Applicability for MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006)
      
      MidAmerican Energy Company (Plant No. 82-02-006) is classified as a "major stationary source" for purposes of the Title V program, because potential emissions for applicable pollutants are above the Title V threshold levels. This facility has applied for and obtained a Title V operating permit.  Operating Permit No. 98-TV-004R2-M002, issued on February 17, 2017, is currently under Department review.
            
            
    Prevention of Significant Deterioration (PSD)  
   
      Major stationary sources of air pollution and major modifications to major stationary sources are required by the CAA to obtain an air pollution permit before commencing construction.  
      
      A "major stationary source" for PSD purposes is defined in Section 169 of the CAA as:
      
         "Any one of 28 types of sources with the potential-to-emit 100 tons per year or more of any pollutant regulated in the CAA or any other type of source with the potential to emit regulated pollutants in amounts equal to or greater than 250 tons per year."
      
      A "major modification" for PSD purposes is defined in 567 IAC 33.3(1) as:
      
         "Any physical change in or change in the method of operation of a major stationary source that would result in a significant emissions increase of a regulated NSR pollutant and a significant net emissions increase of that pollutant from the major stationary source."
      
      The term "significant" refers to the thresholds assigned to each criteria pollutant and certain non-criteria pollutants.  For example, the significant threshold for NOx is 40 tons per year and 15 tons per year for PM10.
      
      The process of applying and obtaining an air pollution permit before commencing construction is called "New Source Review" (NSR) and it is required whether the major source or modification is planned for an area where the National Ambient Air Quality Standards (NAAQS) are exceeded (nonattainment), or an area where the NAAQS are not exceeded (attainment), or an area that cannot be classified on the basis of available information as meeting or not meeting the NAAQS (unclassifiable). 
      
      Part C of the CAA establishes guidelines to prevent the significant deterioration of the air quality in areas that do not exceed the NAAQS or are unclassifiable.  These guidelines are compiled under the "Prevention of Significant Deterioration" (PSD) NSR Program.  In accordance with Section 160 of Part C of the CAA, the purposes for the PSD program are: 
      
             To protect public health and welfare from any actual or potential adverse effect which in the Administrator's judgment may reasonably be anticipated to occur from air pollution, even though air pollution concentrations are below the NAAQS; 
            
             To preserve, protect, and enhance the air quality in areas of special natural recreational, scenic, or historic value, such as national parks and wilderness areas;
            
             To insure that economic growth will occur in a manner consistent with the prevention of existing clean air resources;
            
             To assure that emissions from any source in any State will not interfere with any portion of the applicable implementation plan to prevent significant deterioration of air quality for any other State; and
            
             To assure that any decision to permit increased air pollution in any attainment area is made only after careful evaluation of all the consequences of such a decision and after adequate procedural opportunities for informed public participation in the decision making process.
      
      Title 40 of the Code of Federal Regulations (CFR) Section 51.166 specifies the minimum requirements that a PSD air quality program under Part C of the Act must contain in order to warrant approval by EPA as a revision to a State Implementation Plant (SIP).  In addition, 40 CFR §52.21 delineates the federal PSD permit program, which currently applies as part of the SIP.  40 CFR §52.833(b) states: "Regulations for preventing significant deterioration of air quality.  The provisions of §52.21 except paragraph (a)(1) are hereby incorporated and made a part of the applicable State plan for the State of Iowa."  PSD regulations may be found in 567 IAC Chapter 33.
      
      Before a new major stationary source is constructed or an existing major stationary source makes a major modification in an attainment area, the source is required to obtain a PSD permit.  A PSD permit is a legal document that limits the amount of air pollution that may be released by the source.  The permit also specifies things such as the construction that is allowed, all emission limits (both state and federal), compliance testing requirements, operating monitoring, recordkeeping, and the type of pollution controls.
      
      PSD rules apply to criteria pollutants and other pollutants that do not have a NAAQS.  These non-criteria pollutants are listed in the regulations and they include total particulate matter, fluorides, sulfuric acid mist, total reduced sulfur, and certain contaminants from municipal solid waste plants.
      
      The new source review is pollutant specific.  For example, a facility may emit many air regulated NSR pollutants, however, depending on the magnitude of the emissions of each regulated NSR pollutant, only one or a few may be subject to the new source review.  
      
      Per 567 IAC 33.3(1), a regulated NSR pollutant is defined as:
   
             Any pollutant for which a national ambient air quality standard has been promulgated and any constituents or precursors for such pollutants identified by the Administrator (e.g., volatile organic compounds and NOx are precursors for ozone);
            
             Any pollutant that is subject to any standard promulgated under Section 111 of the Act;
            
             Any Class I or Class II substance subject to a standard promulgated under or established by Title VI of the Act; or
             Any pollutant that otherwise is subject to regulation under the Act; except that any or all hazardous air pollutants either listed in Section 112 of the Act or added to the list pursuant to Section 112(b)(2) of the Act, which have not been delisted pursuant to Section 112(b)(3) of the Act, are not regulated NSR pollutants unless the listed hazardous air pollutant is also regulated as a constituent or precursor of a general pollutant listed under Section 108 of the Act.
      
      According to 567 IAC 33.3(2), the PSD program requirements apply to the construction of any new "major stationary source" or the major modification of any existing major stationary source.  If a source or modification thus qualifies as major, its prospective location or existing location must also qualify as a PSD area, in order for PSD review to apply.  No source or modification subject to PSD review may be constructed without a permit.  To obtain a PSD permit, an applicant must:
      
 Apply the best available control technology (BACT).  A BACT analysis is done on a case-by-case basis and considers energy, environmental, and economic impacts in determining the maximum degree of reduction achievable for the proposed source modification.  
            
 Conduct an ambient air quality analysis.  The applicant must conduct this analysis to demonstrate that its new pollutant emission would not violate either the applicable NAAQS or the applicable PSD increment.
            
 Analyze impacts to soils, vegetation, and visibility.  The applicant is required to analyze whether its proposed emissions increases would impair visibility, or impact on soils or vegetation.  Not only must the applicant look at the direct effect of source emission on these resources, but it also must consider the impacts from general commercial, residential, industrial, and other growth associated with the proposed source or modification.
            
 Not adversely impact a Class I area.  
            
 Undergo adequate public participation by applicant.  Specific public notice requirements and a public comment period are required before the PSD review agency takes final action on a PSD application.
      
   
   PSD Applicability for MidAmerican Energy Company (Plant No. 82-02-006) and Project No. 18-194
   
      A PSD applicability review is the process of determining whether a pre-construction review should be conducted by and a permit issued to a proposed new source or a modification of an existing source by the reviewing authority, pursuant to PSD requirements.  There are several criteria in determining PSD applicability.
      
      The first criterion is whether the source is located in a PSD area.  As indicated in Section 2, MidAmerican's Riverside Generating Station (Plant No. 82-02-006) is located in Bettendorf (Scott County), Iowa.  Bettendorf is an area that has been determined to be in attainment with the National Ambient Air Quality Standards.  As a result, PSD regulations apply to this area.
      
      The second criterion is whether the source meets the definition of a stationary source under PSD regulations.  For the purposes of PSD a "stationary source" is any building, structure, facility, or installation which emits or may emit any air pollutant subject to regulation under the Clean Air Act (the Act).  Furthermore, "building, structure, facility, or installation" means all the pollutant-emitting activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties and are under common ownership or control.  An "emissions unit" is any part of a stationary source that emits or has the potential to emit any pollutant subject to regulation under the Act.
      
      The term "same industrial grouping" refers to the "major groups" identified by two-digit codes in the Standard Industrial Classification (SIC) Manual.  As indicated in Section 2, MidAmerican's Riverside Generating Station (Plant No. 82-02-006) has a two (2) digit SIC code of 49 and it is classified as an "electric, gas, and sanitary services" facility.
      
      The third criterion is whether the source is a "major stationary source" or a "major emitting facility" for PSD purposes.  
      
      A source is considered a "major stationary source" or a "major emitting facility" for PSD purposes, if one of the following applies:
            
 It is one of the PSD 28 listed stationary source categories and potential emissions (including fugitive emissions) for any of the NSR pollutants are at least 100 tons per year.
            
 It is not one of the PSD 28 listed stationary source categories, but non-fugitive potential emissions for any of the NSR pollutants are a least 250 tons per year.
      
      As stated above, MidAmerican's Riverside Generating Station (Plant No. 82-02-006) is a "fossil fuel-fired steam electric plant of more than 250 million British thermal units per hour heat input," and, as result, it is one of the 28 PSD listed stationary source categories.  Since potential emissions for PM, PM10, PM2.5, and NOx are greater than 100 tons/year, each, MidAmerican's Riverside Generating Station (Plant No. 82-02-006) is classified as a "major stationary source" for the purposes of PSD.
      
      The fourth criterion is whether the pollutant or pollutants under review are regulated NSR pollutants.  A "regulated NSR pollutant" means:
            
 Any pollutant for which a national ambient air quality standard has been promulgated and any constituents or precursors for such pollutants identified by the Administrator;
            
 Any pollutant that is subject to any standard promulgated under Section 111 of the Act;
            
 Any Class I or Class II substance subject to a standard promulgated under or established by Title VI of the Act; or
            
 Any pollutant that otherwise is subject to regulation under the Act as defined in 567 IAC 33.3(1), definition of "subject to regulation."

      The pollutants under review in this project (18-027) are PM, PM10, and PM2.5, SO2, NO2, VOC, CO, and CO2e, which, per 567 IAC Chapter 33, are all deemed "regulated NSR pollutants." Therefore, any emissions change for any of these pollutants as a result of this project (18-194) must be considered in this PSD applicability determination.
      The fifth criterion is whether the construction is a new major stationary source or a major modification of an existing major stationary source. 
      
 Does the applicant's request meet the definition of "construction"?

 Per 567 IAC 33.3(1), construction means any physical change or change in the method of operation, including fabrication, erection, installation, demolition, or modification of an emissions unit, that would result in a change in emissions.
                     
 As described in the application, Plant Number 82-02-006 has requested the following:
                           
 Restriction on the natural gas usage for Boiler #9 (EP-1 / EU-1) to reduce emissions below the NESHAP major source threshold for hexane (highest HAP at the facility). 
                           
 Removal of the reference to NESHAP Subpart DDDDD from all permits associated with this facility.  
                     
         The requested changes do not meet the definition of "construction," therefore, a PSD applicability review is not required as this project (18-194) is deemed a "minor modification to a major source." 
         
         
    National Ambient Air Quality Standards (NAAQS) 

   The NAAQS are maximum concentration "ceilings" measured in terms of the total concentration of a pollutant in the atmosphere.  They are health and welfare based standards established by EPA.  For a new project, compliance with any NAAQS is based upon the total estimated air quality.  This is the sum of the ambient estimates resulting from existing sources of air pollution (modeled source impacts plus measured background concentrations) and the modeled ambient impact caused by the proposed project and its associated growth.
   
   
Modeling Analysis for Project Number 18-194
   
   MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) is considered a major source for PSD purposes; therefore, prior to evaluate the need for modeling analysis, it is necessary to determine if the net increase in emissions for any of the applicable pollutants affected by this project (18-194) is subject to PSD review.  
   
   The PSD applicability conducted for this project indicates that this project is minor for the purposes of PSD and it is not subject to PSD review (see Item C in Section 4 of this document). As a result, the modeling guidelines for non-PSD projects apply to Project No. 18-194. 
   
   A modeling analysis determination looks at the total net change in hourly emissions from the project and at the air resource currently being used in the area where the facility is located.   Since no increases in air emissions will occur as a result of this project, a modeling analysis determination is not required for Project Number 18-194.
   
   
   
    New Source Performance Standards (NSPS)  

   Section 111 of the Clean Air Act, "Standards of Performance of New Stationary Sources," requires EPA to establish federal emission standards for source categories that cause or contribute significantly to air pollution.  
   
   These standards are intended to promote use of the best air pollution control technologies, taking into account the cost of such technologies and any other non-air quality, health, and environmental impact and energy requirements.
   
   Furthermore, these standards apply to sources with have been constructed or modified since the proposal of the standard.


NSPS Applicability for Project Number 18-194
   
 Boiler #9 (EP-1) 
            
          The provisions in 40 CFR Part 60, Subpart D (Standards of Performance for Fossil-Fuel-Fired Steam Generators) apply to each fossil-fuel-fired steam generating unit for which construction, modification, or reconstruction is commenced after August 17, 1971, and that has a maximum design heat input capacity of greater than 250 MMBtu/hr.
                
                 Boiler #9 was constructed in June 1961, as a result, it is not subject to the requirements in NSPS Subpart D, because it was constructed prior to the applicability date of August 17, 1971.
         
          The provisions in 40 CFR Part 60, Subpart Da (Standards of Performance for Electric Utility Steam Generating Units) apply to each electric utility steam generating unit for which construction, modification, or reconstruction is commenced after September 18, 1978 and that has a maximum design heat input capacity of greater than 250 MMBtu/hr.
                
                 Boiler #9 was constructed in June 1961, as a result, it is not subject to the requirements in NSPS Subpart Da, because it was constructed prior to the applicability date of September 18, 1978.
                
         
         
         
         
         
         
         
         
         
         
         
         
         
 LNG Vaporizer #1 (EP-70)
            
               The provisions in 40 CFR Part 60, Subpart Dc (Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units) apply to each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 100 million Btu per hour or less, but greater than 10 MMBtu/hr.
                      
                       LNG Vaporizer #1 (EU-70) was constructed in April 2006 and it has a maximum design heat input capacity of 23.196 million Btu per hour; therefore, it is subject to NSPS Subparts A (General Provisions) and Dc.

 LNG Vaporizer #2 (EP-71)
            
                The provisions in 40 CFR Part 60, Subpart Dc (Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units) apply to each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 100 million Btu per hour or less, but greater than 10 MMBtu/hr.
               
 LNG Vaporizer #2 (EU-71) was constructed in April 2006 and it has a maximum design heat input capacity of 23.196 million Btu per hour; therefore, it is subject to NSPS Subparts A (General Provisions) and Dc.

 Auxiliary Boiler #1 (EP-87)
            
                 The provisions in 40 CFR Part 60, Subpart Dc (Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units) apply to each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 100 million Btu per hour or less, but greater than 10 MMBtu/hr.
                    
 Auxiliary Boiler #1 (EU-87) was constructed in September 2013 and it has a maximum design heat input capacity of 26 million Btu per hour; therefore, it is subject to NSPS Subparts A (General Provisions) and Dc.









 Auxiliary Boiler #2 (EP-88)
            
 The provisions in 40 CFR Part 60, Subpart Dc (Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units) apply to each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 100 million Btu per hour or less, but greater than 10 MMBtu/hr.
                    
                     Auxiliary Boiler #2 (EU-88) was constructed in September 2013 and it has a maximum design heat input capacity of 26 million Btu per hour; therefore, it is subject to NSPS Subparts A (General Provisions) and Dc.

      
    National Emission Standards for Hazardous Air Pollutants (NESHAP)  

   These are the standards for those pollutants that are known or suspected to cause cancer or other serious health effects or adverse environmental effects.
   

NESHAP Applicability for Project Number 18-194
   
 Boiler #9 (EP-1) 
            
The only two NESHAP standards that might apply to this unit are Subpart UUUUU (NESHAP: Coal- and Oil-Fired Electric Utility Steam Generating Units) and Subpart JJJJJJ (NESHAP for Industrial, Commercial, and Institutional Boilers Area Sources).
                
 Subpart UUUUUU applies to both major and area sources of HAP, as long as the electric utility steam generating unit burns coal or oil.  Boiler #9 only burns natural gas, as a result, it is not an affected source under NESHAP Subpart UUUUU. 
            
 Subpart JJJJJJ only applies to industrial, commercial, and institutional boilers located at NESHAP area sources.  Boiler #9 is not an affected emission unit under Subpart JJJJJJ, because it does not meet the definition of "industrial boiler," or "commercial boiler," or "institutional boiler," as it is an electric utility steam generating unit (EUG).

Therefore, the following statement applies to Boiler #9:
      
      "Boiler #9 (EU-1) is not an affected emission unit under the federal standards for emission of hazardous air pollutants for sources categories, as defined in 40 CFR Part 63, because there are no applicable categories at this time."
      
      
      
      
      
      
 LNG Vaporizer #1 (EP-70)
            
 The LNG Vaporizer #1 (EU-70) is of the source category, but not subject to 40 CFR Part 63, Subpart JJJJJJ (NESHAP for Industrial, Commercial, and Institutional Boilers Area Sources), because it meets the definition of "gas-fired boiler" in §63.11237 of Subpart JJJJJJ. 

 LNG Vaporizer #2 (EP-71)
            
 The LNG Vaporizer #2 (EU-71) is of the source category, but not subject to 40 CFR Part 63, Subpart JJJJJJ (NESHAP for Industrial, Commercial, and Institutional Boilers Area Sources), because it meets the definition of "gas-fired boiler" in §63.11237 of Subpart JJJJJJ. 
      
 Auxiliary Boiler #1 (EP-87)
            
 Auxiliary Boiler #1 (EU-87) is of the source category, but not subject to 40 CFR Part 63, Subpart JJJJJJ (NESHAP for Industrial, Commercial, and Institutional Boilers Area Sources), because it meets the definition of "gas-fired boiler" in §63.11237 of Subpart JJJJJJ. 
      
 Auxiliary Boiler #2 (EP-88)
            
 Auxiliary Boiler #2 (EU-88) is of the source category, but not subject to 40 CFR Part 63, Subpart JJJJJJ (NESHAP for Industrial, Commercial, and Institutional Boilers Area Sources), because it meets the definition of "gas-fired boiler" in §63.11237 of Subpart JJJJJJ. 
      
    
    Iowa Administrative Code (IAC)  
      
   The Iowa Administrative Procedures Act (IAPA), Iowa Code Chapter 17A, and an agency's enabling legislation work together to guide an agency's adoption and implementation of administrative rules. Administrative rules implement or interpret law, prescribe policy, or describe the organization, procedure, or practice requirements of an executive branch agency. 
   
   The IAPA establishes specific procedures, which must be followed by state agencies adopting administrative rules.  The IAPA is a "minimum procedural code."  This means that the IAPA is concerned with how an agency creates its policy through rule-making rather than the specific policy implemented through adopting administrative rules.  The rule-making process in Iowa takes at least 108 days.
   
   In addition, an environmental protection commission (EPC) was created under Iowa Code Chapter 455A to provide policy oversight over Iowa's environmental protection efforts.  The EPC is a panel of nine citizens, who are appointed by the Governor and confirmed by vote of the senate for four year terms.
   
   The Iowa Administrative Code (IAC) contains the adopted administrative rules of state agencies.  Chapter 567 of the IAC contains the composite of all administrative rules adopted by the EPC.
   The following sections of the IAC are applicable to this project:
          567 IAC 22.1(1):  Permit required.  Unless exempted in subrule 22.1(2), no person shall construct, install, reconstruct, or alter any equipment, control equipment, or anaerobic lagoon without first obtaining a construction permit.
         
          567 IAC 22.3(1):  Issuing permits for stationary sources.  In no case shall a construction permit, which results in an increase in emissions be issued to any facility, which is in violation of any condition found in a permit involving PSD, NSPS, NESHAP, or a provision of the Iowa state implementation plan.  If the facility is in compliance with a schedule for correcting the violation and that schedule is contained in an order or permit condition, the Department may consider issuance of a construction permit.

          567 IAC 23.1(2):  New source performance standards. 

          567 IAC 23.1(2)"lll":  New source performance standards. Small industrial-commercial-institutional steam generating units. Each steam generating unit for which construction, reconstruction, or modification commenced after June 9, 1989, and which has a maximum design heat input capacity of 100 million Btu/hour or less, but more than 10 million Btu per hour.

          567 IAC 23.3(2)"b": Particulate matter.  Combustion for indirect heating.  Emissions of particulate matter from the combustion of fuel for indirect heating or for power generation shall be limited by the ASME Standard APS-1.

          567 IAC 23.3(2)"b"(3): Particulate matter.  Combustion for indirect heating.  For a new fossil fuel-fired steam generating unit of less than 150 million Btu per hour heat input, the maximum allowable emissions from such new unit shall be 0.6 pounds of particulates per million Btu input.  NOTE: This standard applies to Emission Units 70, 71, 87, and 88, because they were installed after January 13, 1976.

          567 IAC 23.3(2)"d": Particulate matter.  Visible emissions.  No person shall allow, cause or permit the emission of visible air contaminants into the atmosphere from any equipment, internal combustion engine, premise fire, open fire or stack, equal to or in excess of 40 percent opacity.

          567 IAC 23.3(3)"e": Other processes capable of emitting sulfur dioxide.  After January 1, 1974, no person shall allow, cause, or permit the emission of sulfur dioxide from any process, other than sulfuric acid manufacture, in excess of 500 parts per million, based on volume.
         
          567 IAC 25.1(7): Tests by owner.  The owner of new or existing equipment or the owner's authorized agent shall conduct emission tests to determine compliance with applicable rules.  For new equipment: Unless otherwise specified by the Department, all new equipment shall be tested by the owner or the owner's authorized agent to determine compliance with applicable emission limits.  For existing equipment: The director may require the owner or the owner's authorized agent to conduct an emission test on any equipment if the director has reason to believe that the equipment does not comply with applicable requirements.


                                   Section 5


Emission Limits: Direct and Indirect
   
      Emission limits are restrictions over a given period of time on the amount of pollutant which may be emitted by a source.  An emission limitation by itself limits the potential-to-emit when it reflects the absolute maximum that the unit could emit without controls or other operational restrictions. Therefore, in order for any limit or condition to be a legitimate restriction in a construction permit, that limit or condition must be federally enforceable, which in turn requires practical enforceability.  
      
      There are two types of emission limits: direct and indirect.
      
 Direct limits are those on the amount of emissions and are also called "numeric emission limits." 
          
 Indirect limits are also called "operating limits" and restrict emissions by setting operational limits such as:
                
 Amount of final product which may be manufacture or otherwise produced at the facility
 Hours of operation
 Amount of raw material consumed
 Type and amount of fuel combusted
 Installation and maintenance of add-on controls that operate at a specified rate or efficiency
      
            Indirect limits are necessary if the emission limits do not represent the maximum emissions of the unit (i.e., not operating at full design capacity and/or without pollution control equipment). In other words, if the emission limit could be achieved only if the emission unit operated at less than full design capacity or if pollution control equipment is required to meet the emission limit, then both a production and operational limit are required in the permit in addition to an emission limit.
   
   
   
   
   
   
   
   
   
   
   
   
   

   Limits for Project Number 18-194 
      
          Boiler #9 (EP-1 / EU-1)
             
              A PM limit of 0.39 lb/MMBtu (468.78 lb/hr) was imposed on this unit under Project Number 04-596, per facility's request to limit potential-to-emit and address PM10 NAAQS issues as this limit also applies to PM10 and PM2.5.
             
              Boiler #9 shall only combust natural gas.
             
              Boiler #9 shall combust no more than 9,500 million cubic feet of natural gas per 12-month rolling period.
         
          LNG Vaporizer #1 (EP-70 / EU-70)
             
              PM is limited to 0.6 lb/MMBtu (13.92 lb/hr) and it also applies to PM10 and PM2.5.
             
              LNG Vaporizer #1 shall only combust natural gas.

          LNG Vaporizer #2 (EP-71 / EU-71)
             
              PM is limited to 0.6 lb/MMBtu (13.92 lb/hr) and it also applies to PM10 and PM2.5.
             
              LNG Vaporizer #2 shall only combust natural gas.

          Auxiliary Boiler #1 (EP-87 / EU-87)
             
              PM is limited to 0.6 lb/MMBtu (15.60 lb/hr) and it also applies to PM10 and PM2.5.
             
              Auxiliary Boiler #1 shall only combust natural gas.

          Auxiliary Boiler #2 (EP-88 / EU-88)
             
              PM is limited to 0.6 lb/MMBtu (15.60 lb/hr) and it also applies to PM10 and PM2.5.
             
              Auxiliary Boiler #2 shall only combust natural gas.



Compliance Demonstration
   
      In order to make an emission limit enforceable as a practical matter, a compliance demonstration is necessary as indicated in EPA's "Guidance on Limiting Potential to Emit in New Source Permitting."  This compliance demonstration usually is for both initial compliance and continuous or periodic compliance.
      
      Compliance can be demonstrated several ways.  It can be done through emission stack testing, continuous emission monitoring systems (CEMS), and continuous opacity monitoring systems (COMS), or monitoring & recordkeeping.  CEMS/COMS typically provide the best measure of emissions.  
      
 Stack Testing
               
 Stack testing is not required under this project as there are no emissions increases or any changes in the method of operation for any of the equipment evaluated under Project Number 18-194.
            
 Monitoring & Recordkeeping

 Boiler #9 (EP-1 /EU-1) has been limited to burning no more than 9,500 million cubic feet of natural gas per 12-month rolling period.  As a result, the owner or operator is required to keep track of the amount of natural gas burned on a monthly basis and on a 12-month rolling basis.

      
Confidentiality

      MidAmerican Energy Company  -  Riverside Generating Station (Plant No. 82-02-006) did not request confidentiality on any part of the project/application.


Comments on Draft Permits

      Facility review started on 06/25/2018, and ended on 07/03/2018.  Comments are enclosed as Appendix A.
      

                                   Section 6
   
Project Air Emissions Calculations

Air emissions are commonly calculated using emission factors.  An emission factor is a representative value that attempts to relate the quantity of a pollutant released to the atmosphere with an activity associated with the release of that pollutant.  

Emission factors are usually expressed as the weight of the pollutant divided by the unit weight, volume, distance, or duration of the activity that emits the pollutant.

 Federal Allowable Emissions 
   
 Boiler #9 (EP-1 / EU-1)
   
             NSPS  -  Not applicable as this unit was constructed prior to the applicability dates for Subparts D and Da.

             NESHAP - Not applicable as this emission unit is not subject to any National Emissions Standards for Hazardous Air Pollutants.
            
 LNG Vaporizer #1 (EP-70 / EU-70)
   
             NSPS  -  Subject to NSPS Subpart Dc.  -  There are no emission standards for natural gas fired boilers

             NESHAP - Not applicable as this emission unit burns natural gas and, as a result, is not subject to NESHAP Subpart JJJJJJ.
            
 LNG Vaporizer #2 (EP-71 / EU-71)
   
             NSPS  -  Subject to NSPS Subpart Dc.  -  There are no emission standards for natural gas fired boilers

             NESHAP - Not applicable as this emission unit burns natural gas and, as a result, is not subject to NESHAP Subpart JJJJJJ.

 Auxiliary Boiler #1 (EP-87/ EU-87)
   
             NSPS  -  Subject to NSPS Subpart Dc.  -  There are no emission standards for natural gas fired boilers

             NESHAP - Not applicable as this emission unit burns natural gas and, as a result, is not subject to NESHAP Subpart JJJJJJ.
      
 Auxiliary Boiler #2 (EP-88/ EU-88)
   
             NSPS  -  Subject to NSPS Subpart Dc.  -  There are no emission standards for natural gas fired boilers

             NESHAP - Not applicable as this emission unit burns natural gas and, as a result, is not subject to NESHAP Subpart JJJJJJ.
      
 Iowa Allowable Emissions 
   
 Boiler #9 (EP-1 / EU-1)
   
 PM: 567 IAC 23.3(2)"b": ASME Standard APS-1. Facility requested a limit of  0.39 lb/MMBtu
 PM = 0.39 lb PM/MMBtu * 1,202 MMBtu/hr = 468.78 lb/hr
            
 Visible emissions: 567 IAC 23.3(2)"d"; 40% opacity
            
 SO2: 567 IAC 23.3(3)"e"; 500 ppmv

 LNG Vaporizer #1 (EP-70 / EU-70)
   
 PM: 567 IAC 23.3(2)"b"(3): 0.6 lb/MMBtu
 PM = 0.6 lb PM/MMBtu * 23.196 MMBtu/hr = 13.92 lb/hr
            
 Visible emissions: 567 IAC 23.3(2)"d"; 40% opacity
            
 SO2: 567 IAC 23.3(3)"e"; 500 ppmv
   
 LNG Vaporizer #2 (EP-71 / EU-71)
   
 PM: 567 IAC 23.3(2)"b"(3): 0.6 lb/MMBtu
 PM = 0.6 lb PM/MMBtu * 23.196 MMBtu/hr = 13.92 lb/hr
            
 Visible emissions: 567 IAC 23.3(2)"d"; 40% opacity
            
 SO2: 567 IAC 23.3(3)"e"; 500 ppmv
   
 Auxiliary Boiler #1 (EP-87 / EU-87)
   
 PM: 567 IAC 23.3(2)"b"(3): 0.6 lb/MMBtu
 PM = 0.6 lb PM/MMBtu * 26 MMBtu/hr = 15.60 lb/hr
            
 Visible emissions: 567 IAC 23.3(2)"d"; 40% opacity
            
 SO2: 567 IAC 23.3(3)"e"; 500 ppmv
   
 Auxiliary Boiler #2 (EP-88 / EU-88)
   
 PM: 567 IAC 23.3(2)"b"(3): 0.6 lb/MMBtu
 PM = 0.6 lb PM/MMBtu * 26 MMBtu/hr = 15.60 lb/hr
            
 Visible emissions: 567 IAC 23.3(2)"d"; 40% opacity
            
 SO2: 567 IAC 23.3(3)"e"; 500 ppmv
   
   
   
   
   
   
   
   
   
 Potential to Emit (PTE) 
   
 Boiler #9 (EP-1 / EU-1)
   
The potential-to-emit for this unit takes into consideration the following:
            
 Boiler #9 (EU-1) is restricted to burning no more than 9,500 million cubic feet of natural gas per 12-month rolling period.

 Maximum Design Heat Input Capacity: 1,202 MMBtu/hr.

 Assuming a high heating value of 1,000 Btu/scf, the maximum natural gas consumption rate is 1.202 MMcf/hr

 A PM limit of 0.39 lb/MMBtu was requested by the facility under Project No. 04-596 to address NAAQS issues and to satisfy 567 IAC 23.3(2)"b" requirements.  This represents 

C.1 AP-42 Emission Factors for SCC 10100604 (External Combustion Boilers, Electric Generation, and Natural Gas) 

	C.1.1 Maximum Hourly Emissions 

 PM (permit limit) = 0.39 lb/MMBtu * 1,202 MMBtu/hr = 468.78 lb/hr
 PM10 = PM = 468.78 lb/hr
 PM2.5 = PM2.5 = 468.78 lb/hr
 SO2 = 0.6 lb/MMcf * 1.202 MMcf/hr = 0.72 lb/hr
 NOx = 170 lb/MMcf * 1.202 MMcf/hr = 204.34 lb/hr
 VOC = 5.5 lb/MMcf * 1.202 MMcf/hr = 6.61 lb/hr
 CO = 24 lb/MMcf * 1.202 MMcf/hr = 28.85 lb/hr
 Hexane = 1.80 lb/MMcf * 1.202 MMcf/hr = 2.16 lb/hr
 Total HAP = 1.881 lb/MMcf * 1.202 MMcf/hr = 2.26 lb/hr

	C.1.2 Annual Potential Emissions 

 PM = 468.78 lb/hr * 8,760 hours/year = 4,106,512.8 lb/yr
 PM10 = PM = 4,106,512.8 lb/yr
 PM2.5 = PM10 = 4,106,512.8 lb/yr
 SO2 = 0.6 lb/MMcf * 9,500 MMcf/yr = 5,700 lb/yr
 NOx = 170 lb/MMcf * 9,500 MMcf/yr = 1,615,000 lb/yr
 VOC = 5.5 lb/MMcf * 9,500 MMcf/yr = 52,250 lb/yr
 CO = 24 lb/MMcf * 9,500 MMcf/yr = 228,000 lb/yr
 Hexane = 1.80 lb/MMcf * 9,500 MMcf/yr = 17,100 lb/yr
 Total HAP = 1.881 lb/MMcf * 9,500 MMcf/yr = 17,869.5 lb/yr







 LNG Vaporizer #1 (EP-70 / EU-70)
   
The potential-to-emit for this unit takes into consideration the following:
            
 LNG Vaporizer #1 (EU-70) has a maximum design heat input capacity of 23.196 MMBtu/hr.

 Assuming a high heating value of 1,000 Btu/scf, the maximum natural gas consumption rate is 0.023196 MMcf/hr

 The PM allowable emission rate for this unit is 13.92 lb/hour.  

 An emission rate limit of 2.0 lb of NOx per hour was imposed under Project Number 06-005 to demonstrate this project was not a significant emissions increase for PSD purposes.

C.2 AP-42 Emission Factors for SCC 10200602 (External Combustion Boilers, Industrial, Natural Gas, and 10 to 100 MMBtu/hr) and Manufacturer's worst-case, i.e., higher than AP-42

	C.2.1 Maximum Hourly Emissions 

 PM (allowable) = 13.92 lb/hr
 PM10 = PM = 13.92 lb/hr
 PM2.5 = PM10 = 13.92 lb/hr
 SO2 (AP-42) = 0.6 lb/MMcf * 0.023196 MMcf/hr = 0.014 lb/hr
 NOx (permit limit) = 2.0 lb/hr
 VOC (Manufacturer) = 0.016 lb/MMBtu * 23.196 MMBtu/hr = 0.37 lb/hr
 CO (Manufacturer) = 0.15 lb/MMBtu * 23.196 MMBtu/hr = 3.48 lb/hr
 Hexane = 1.80 lb/MMcf * 0.023196 MMcf/hr = 0.042 lb/hr
 Total HAP = 1.881 lb/MMcf * 0.023196 MMcf/hr = 0.044 lb/hr

	C.2.2 Annual Potential Emissions 

 PM = 13.92 lb/hr * 8,760 hours/year = 121,939.20 lb/yr
 PM10 = PM = 121,939.20 lb/yr
 PM2.5 = PM10 = 121,939.20 lb/yr
 SO2 = 0.014 lb/hr * 8,760 hours/year = 122.64 lb/yr
 NOx = 2.0 lb/hr * 8,760 hours/year = 17,520 lb/yr
 VOC = 0.37 lb/hr * 8,760 hours/year = 3,241 lb/yr
 CO = 3.48 lb/hr * 8,760 hours/year = 30,484.8 lb/yr
 Hexane = 0.042 lb/hr * 8,760 hours/year = 367.92 lb/yr
 Total HAP = 0.044 lb/hr* 8,760 hours/year = 385.44 lb/yr








 LNG Vaporizer #2 (EP-71 / EU-71)
   
The potential-to-emit for this unit takes into consideration the following:
            
 LNG Vaporizer #2 (EU-71) has a maximum design heat input capacity of 23.196 MMBtu/hr.

 Assuming a high heating value of 1,000 Btu/scf, the maximum natural gas consumption rate is 0.023196 MMcf/hr

 The PM allowable emission rate for this unit is 13.92 lb/hour.  

 An emission rate limit of 2.0 lb of NOx per hour was imposed under Project Number 06-005 to demonstrate this project was not a significant emissions increase for PSD purposes.

C.3 AP-42 Emission Factors for SCC 10200602 (External Combustion Boilers, Industrial, Natural Gas, and 10 to 100 MMBtu/hr) and Manufacturer's worst-case, i.e., higher than AP-42

	C.3.1 Maximum Hourly Emissions 

 PM (allowable) = 13.92 lb/hr
 PM10 = PM = 13.92 lb/hr
 PM2.5 = PM10 = 13.92 lb/hr
 SO2 (AP-42) = 0.6 lb/MMcf * 0.023196 MMcf/hr = 0.014 lb/hr
 NOx (permit limit) = 2.0 lb/hr
 VOC (Manufacturer) = 0.016 lb/MMBtu * 23.196 MMBtu/hr = 0.37 lb/hr
 CO (Manufacturer) = 0.15 lb/MMBtu * 23.196 MMBtu/hr = 3.48 lb/hr
 Hexane = 1.80 lb/MMcf * 0.023196 MMcf/hr = 0.042 lb/hr
 Total HAP = 1.881 lb/MMcf * 0.023196 MMcf/hr = 0.044 lb/hr

	C.3.2 Annual Potential Emissions 

 PM = 13.92 lb/hr * 8,760 hours/year = 121,939.20 lb/yr
 PM10 = PM = 121,939.20 lb/yr
 PM2.5 = PM10 = 121,939.20 lb/yr
 SO2 = 0.014 lb/hr * 8,760 hours/year = 122.64 lb/yr
 NOx = 2.0 lb/hr * 8,760 hours/year = 17,520 lb/yr
 VOC = 0.37 lb/hr * 8,760 hours/year = 3,241 lb/yr
 CO = 3.48 lb/hr * 8,760 hours/year = 30,484.8 lb/yr
 Hexane = 0.042 lb/hr * 8,760 hours/year = 367.92 lb/yr
 Total HAP = 0.044 lb/hr* 8,760 hours/year = 385.44 lb/yr








 Auxiliary Boiler #1 (EP-87 / EU-87)
   
The potential-to-emit for this unit takes into consideration the following:
            
 Auxiliary Boiler #2 (EU-87) has a maximum design heat input capacity of 26 MMBtu/hr.

 Assuming a high heating value of 1,000 Btu/scf, the maximum natural gas consumption rate is 0.026 MMcf/hr

 The PM allowable emission rate for this unit is 15.60 lb/hour.  

 An emission rate limit of 4.0 lb of NOx per hour was imposed under Project Number 13-009 to demonstrate this project was not a significant emissions increase for PSD purposes.

C.4 AP-42 Emission Factors for SCC 10200602 (External Combustion Boilers, Industrial, Natural Gas, and 10 to 100 MMBtu/hr) 

	C.4.1 Maximum Hourly Emissions 

 PM (allowable) = 15.60 lb/hr
 PM10 = PM = 15.60 lb/hr
 PM2.5 = PM10 = 15.60 lb/hr
 SO2 = 0.6 lb/MMcf * 0.026 MMcf/hr = 0.016 lb/hr
 NOx (permit limit) = 4.0 lb/hr
 VOC = 5.5 lb/MMcf * 0.026 MMcf/hr = 0.14 lb/hr
 CO = 84 lb/MMcf * 0.026 MMcf/hr = 2.18 lb/hr
 Hexane = 1.80 lb/MMcf * 0.026 MMcf/hr = 0.0468 lb/hr
 Total HAP = 1.881 lb/MMcf * 0.026 MMcf/hr = 0.0489 lb/hr

	C.4.2 Annual Potential Emissions 

 PM = 15.60 * 8,760 hours/year = 136,656 lb/yr
 PM10 = PM = 136,656 lb/yr
 PM2.5 = PM10 = 136,656 lb/yr
 SO2 = 0.016 lb/hr * 8,760 hours/year = 140.16 lb/yr
 NOx = 4.0 lb/hr * 8,760 hours/year = 35,040 lb/yr
 VOC = 0.14 lb/hr * 8,760 hours/year = 1,252.68 lb/yr
 CO = 2.18 lb/hr * 8,760 hours/year = 19,131.84 lb/yr
 Hexane = 0.0468 lb/hr * 8,760 hours/year = 409.97 lb/yr
 Total HAP = 0.0489 lb/hr* 8,760 hours/year = 428.42 lb/yr









 Auxiliary Boiler #2 (EP-88 / EU-88)
   
The potential-to-emit for this unit takes into consideration the following:
            
 Auxiliary Boiler #2 (EU-88) has a maximum design heat input capacity of 26 MMBtu/hr.

 Assuming a high heating value of 1,000 Btu/scf, the maximum natural gas consumption rate is 0.026 MMcf/hr

 The PM allowable emission rate for this unit is 15.60 lb/hour.  

 An emission rate limit of 4.0 lb of NOx per hour was imposed under Project Number 13-009 to demonstrate this project was not a significant emissions increase for PSD purposes.

C.5 AP-42 Emission Factors for SCC 10200602 (External Combustion Boilers, Industrial, Natural Gas, and 10 to 100 MMBtu/hr) 

	C.5.1 Maximum Hourly Emissions 

 PM (allowable) = 15.60 lb/hr
 PM10 = PM = 15.60 lb/hr
 PM2.5 = PM10 = 15.60 lb/hr
 SO2 = 0.6 lb/MMcf * 0.026 MMcf/hr = 0.016 lb/hr
 NOx (permit limit) = 4.0 lb/hr
 VOC = 5.5 lb/MMcf * 0.026 MMcf/hr = 0.14 lb/hr
 CO = 84 lb/MMcf * 0.026 MMcf/hr = 2.18 lb/hr
 Hexane = 1.80 lb/MMcf * 0.026 MMcf/hr = 0.0468 lb/hr
 Total HAP = 1.881 lb/MMcf * 0.026 MMcf/hr = 0.0489 lb/hr

	C.5.2 Annual Potential Emissions 

 PM = 15.60 * 8,760 hours/year = 136,656 lb/yr
 PM10 = PM = 136,656 lb/yr
 PM2.5 = PM10 = 136,656 lb/yr
 SO2 = 0.016 lb/hr * 8,760 hours/year = 140.16 lb/yr
 NOx = 4.0 lb/hr * 8,760 hours/year = 35,040 lb/yr
 VOC = 0.14 lb/hr * 8,760 hours/year = 1,252.68 lb/yr
 CO = 2.18 lb/hr * 8,760 hours/year = 19,131.84 lb/yr
 Hexane = 0.0468 lb/hr * 8,760 hours/year = 409.97 lb/yr
 Total HAP = 0.0489 lb/hr* 8,760 hours/year = 428.42 lb/yr








 Project Potential Emissions

                    Project Totals  -  Potential Emissions
Pollutant
                                    lb/year
                                    lb/hour
                                   tons/year
PM
                                  4,623,703.2
                                    527.82
                                   2,311.85
PM10
                                  4,623,703.2
                                    527.82
                                   2,311.85
PM2.5
                                  4,623,703.2
                                    527.82
                                   2,311.85
SO2
                                   6,225.60
                                     0.71
                                     3.11
NOx
                                   1,720,120
                                    196.36
                                    860.06
VOC
                                   61,237.36
                                     6.99
                                     30.62
CO
                                  327,233.28
                                     37.36
                                    163.62
Single HAP (Hexane)
                                   18,655.78
                                     2.13
                                     9.33
Total HAP
                                   19,497.22
                                     2.23
                                     9.75
	


Facility-Wide Air Emissions

 Potential to Emit from Other Sources at Plant Number 82-02-006 
   
 LNG Emergency Generator (EP-77 / EU-77) - Grandfathered

A.1. Annual Potential Emissions  -  SCC 20100202 (Internal Combustion Engine, Electric Generation, and Natural Gas)

            PM = 0.03 tons/year
            PM10 = PM = 0.03 tons/year
            PM2.5 = PM10 = 0.03 tons/year
            SO2 = 0.0 tons/year
            NOx = 0.42 tons/year
            VOC = 0.17 tons/year
            CO = 0.59 tons/year

 Service Center Emergency Generator (EP-78 / EU-78) - Grandfathered

A.2. Annual Potential Emissions  -  SCC 20100202 (Internal Combustion Engine, Electric Generation, and Natural Gas)

            PM = 0.01 tons/year
            PM10 = PM = 0.01 tons/year
            PM2.5 = PM10 = 0.01 tons/year
            SO2 = 0.0 tons/year
            NOx = 0.10 tons/year
            VOC = 0.04 tons/year
            CO = 0.14 tons/year





 Sum of Potential Air Emissions from Project 18-194 and all other Sources  

                                       
                               Facility-Wide PTE
Pollutant
                                   tons/year
PM
                                   2,311.89
PM10
                                   2,311.89
PM2.5
                                   2,311.89
SO2
                                     3.11
NOx
                                    860.58
VOC
                                     30.83
CO
                                    164.35
Single HAP (Hexane)
                                     9.33
Total HAP
                                     9.75

   NOTE:  Based on the information in previous and current applications, without restrictions, potential emissions for Single HAP (hexane) would be above the NESHAP major source thresholds. Since operating limits restrictions are now imposed under this project (18-194), this facility has become a NESHAP area source.  In addition, this facility is a major source for purposes of Title V and PSD. 


Indicator Opacity for Project Number 18-194

      The indicator opacity depends on the grain loading of the smallest particle size as can be seen by the table below:

Grain Loading (gr/scf)
Indicator Opacity (%)
                                   < 0.01
                         No Visible Emissions (No VE)
                                 0.01  -  0.06
                                      10
                                0.061  -  0.08
                                      20
                                 0.081  -  0.1
                                      25
                  
                  
                Emission Point 1 (Boiler #9)
                      At PM10 = 468.78 lb/hr (natural gas):
                            The grain loading at 320,785 scfm is 0.1705 gr/dscf; therefore, the Indicator Opacity is 25%
                           
                Emission Point 70 (LNG Vaporizer #1)
                      At PM10 = 13.92 lb/hr (natural gas):
                            The grain loading at 4,800 scfm is 0.3383 gr/dscf; therefore, the Indicator Opacity is 25%
                           
                Emission Point 71 (LNG Vaporizer #2)
                      At PM10 = 13.92 lb/hr (natural gas):
                            The grain loading at 4,800 scfm is 0.3383 gr/dscf; therefore, the Indicator Opacity is 25%
                           
                           
                           
                Emission Point 87 (Auxiliary Boiler #1)
                      At PM10 = 15.60 lb/hr (natural gas):
                            The grain loading at 5,000 scfm is 0.3640 gr/dscf; therefore, the Indicator Opacity is 25%
                           
                Emission Point 88 (Auxiliary Boiler #2)
                      At PM10 = 15.60 lb/hr (natural gas):
                            The grain loading at 5,000 scfm is 0.3640 gr/dscf; therefore, the Indicator Opacity is 25%
                           

Stack Test Run Time for Project Number 18-194

 Emission Point 1 (Boiler #9)
 PMState: 1 hour
 PM10: 1 hour
 PM2.5: 1 hour
      
 Emission Point 70 (LNG Vaporizer #1)
 PMState: 1 hour
 PM10: 1 hour
 PM2.5: 1 hour
      
 Emission Point 71 (LNG Vaporizer #2)
 PMState: 1 hour
 PM10: 1 hour
 PM2.5: 1 hour
      
 Emission Point 87 (Auxiliary Boiler #1)
 PMState: 1 hour
 PM10: 1 hour
 PM2.5: 1 hour
      
 Emission Point 88 (Auxiliary Boiler #2)
 PMState: 1 hour
 PM10: 1 hour
 PM2.5: 1 hour
      
