Draft Technical Support Document For Air Emission Permit No

Transcription

1 Draft Technical Support Document For Air Emission Permit No This technical support document (TSD) is intended for all parties interested in the draft permit and to meet the requirements that have been set forth by the federal and state regulations (40 CFR 70.7(a)(5) and Minn. R , subp. 1). The purpose of this document is to provide the legal and factual justification for each applicable requirement or policy decision considered in the preliminary determination to issue the draft permit. 1. General information 1.1. Applicant and stationary source location Table 1. Applicant and source address Applicant/Address City of Virginia 618 2nd St S Virginia, MN Contact: Jeff Minter Phone: Stationary source/address (SIC Code: Electric Services) Virginia Department of Public Utilities 618 2nd St S Virginia, MN Facility description Virginia Department of Public Utilities is a citizen-owned utility that provides steam to the heating distribution system for local businesses and residents of the Virginia, Minnesota area. In addition, the cogeneration facility also operates and maintains a 26 megawatt-maximum electrical distribution system, a natural gas distribution system, and a water treatment plant that supplies drinking water to the citizens of Virginia. The facility has the potential to operate four boilers, each burning specific fuel types: Boiler #7 (EQUI 2) and Boiler #9 (EQUI 3) each burn coal, Boiler #10 (EQUI 4) fires natural gas, and Boiler #11 (EQUI 16) burns wood co-fired with natural gas, each used for district heating and electricity generation. There is an additional boiler, Boiler #8, located at the facility that is not physically connected to the utility system and is not permitted for operation; therefore, it is not inventoried as an emission unit. Other emission sources at the facility include a makeup air heater, wood storage and handling systems for fuel delivery to EQUI 16, and fugitive dust emissions from truck traffic and ash handling. Major pollutants emitted include nitrogen oxides (NOx), sulfur dioxides (SO 2), particulate matter (PM), particulate matter with an aerodynamic diameter less than 10 microns (PM 10), particulate matter with an aerodynamic diameter less than 2.5 microns (PM 2.5), hydrogen chloride (HCl), and carbon monoxide (CO). Add-on pollution control equipment includes bag houses, cyclones, electrostatic precipitators (ESP), and selective non-catalytic reduction (SNCR), in combination with good combustion practices. Pollution controls intrinsic to the design of EQUI 4 (not add-on controls) include low-excess firing, flue gas recirculation, and oxygen trim/modified burner design Description of the activities allowed by this permit action Part 70 Reissuance (2016) This permit action is a Part 70 Reissuance that incorporates several permit actions as described below. The Minnesota Pollution Control Agency (MPCA) has a combined operating and construction-permitting program under Minnesota Rules Chapter 7007, and under Minn. R Under that authority, this permit action authorizes construction described elsewhere in this permit. Technical Support Document, Permit Number: Page 1 of 26

2 Major Amendment (2017) This major amendment was submitted to lower the allowable SO 2 emissions on EQUI 2 and EQUI 3. Additionally, the facility seeks to raise the stack height on EQUI 3 (STRU 5) consistent with the stack parameters used in the 2017 dispersion model. The facility proposed lower SO 2 limits with a longer averaging period (30 days) and submitted modeling, including the assumed stack extension, to demonstrate compliance with the National and Minnesota Ambient Air Quality Standards (NAAQS/MAAQS). This permit restricts simultaneous operation of EQUI 2 and EQUI 3 to startup and shut down periods only. See Section 3.2 for further discussion Major Amendment (2015) This major amendment application was submitted to re-incorporate applicable requirements from 40 CFR pt. 63, subp. DDDDD, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. These requirements were previously removed as a result of the standard being vacated by the United States Court of Appeals. Since the facility is a major source of HAPs, EQUI 2, EQUI 3, and EQUI 16 are subject to the standards in this rule depending upon boiler design, capacity, and fuel(s) burned. EQUI 4 is exempt because it is defined as an electric utility steam-generating unit (EGU) under 40 CFR pt. 63, subp. UUUUU as described in Section 2.4. This action does not authorize emissions increases Administrative Amendment and Permit Reopening (2015) The administrative amendment application was submitted to extend a NOx stack test deadline for EQUI 3 by 60 days. This was required because EQUI 3 has required NOx testing every 24 months but the boiler was down due to an unexpected extended repair. That same year, a Notice of Compliance (NOC) for EQUI 16 performance test results and EQUI 4 continuous emissions monitoring systems (CEMS) recertification were issued and needed to be incorporated into the permit through a permit re-opening Other changes This Part 70 reissuance will include limits to avoid the requirement to submit a mercury emissions reduction plan for affected units specified under Minn. R The facility submitted a Mercury Reduction Plan Submittal as required by Permit No on June 24, The Permittee will accept limits on mercury-emitting units, defined as fossil fuel-burning units that emit three pounds per year or more of mercury, in lieu of submitting and following a mercury reduction plan. A copy of the submittal may be found in Attachment 5 to this TSD Description of notifications and applications included in this action Table 2. Notifications and applications included in this action Date received Application/Notification type and description 03/09/2017 Major Amendment (IND ) 07/15/2016 Part 70 Reissuance (IND ) 08/27/2015 Permit Re-opening (IND ) 07/30/2015 Major Amendment (IND ) 06/15/2015 Administrative Amendment (IND ) Technical Support Document, Permit Number: Page 2 of 26

3 1.5. Facility emissions Table 3. Total facility potential to emit summary PM tpy PM10 tpy PM2.5 tpy SO2 tpy Technical Support Document, Permit Number: Page 3 of 26 NOx tpy CO tpy CO2e tpy VOC tpy Single Total facility limited potential emissions , Total facility actual emissions (2016) * * PM = Particulate Matter (PM) PM10 = Particulate Matter with an aerodynamic diameter less than 10 micrometers PM2.5 = Particulate Matter with an aerodynamic diameter less than 2.5 micrometers SO2 = Sulfur Dioxide NOx = Nitrogen Oxides Table 4. Facility classification HAP tpy All HAPs tpy CO = Carbon Monoxide CO2e = Carbon Dioxide Equivalent defined under Minn. R VOC = Volatile Organic Compounds Single HAP = Largest Single Hazardous Air Pollutant All HAPs = Total Hazardous Air Pollutants *Not reported in Minnesota emission inventory. Classification Major Synthetic minor/area Minor/Area New Source Review X Part 70 X Part 63 X 1.6. Changes to permit The MPCA has a combined operating and construction-permitting program under Minnesota Rules Chapter 7007, and under Minn. R , the MPCA has authority to include additional requirements in a permit. Under that authority, the following changes to the permit are made through this permit action: The permit has been updated to reflect current MPCA templates and standard citation formatting; One-time testing requirements, initial compliance requirements, and other requirements that have been completed or no longer apply have been deleted; Some requirements have been reordered to help with clarity (i.e. groups that do not share a common limit were disbanded). Allowable SO 2 emissions from EQUI 2 and EQUI 3 were lowered to lb/mmbtu and lb/mmbtu, respectively, each with a 30-day averaging period; Steam production limits, monitoring, and recordkeeping were specified under EQUI 3; Additional mercury limits were placed on EQUI 3 in order to avoid requirements to submit mercury emissions reduction plans under Minn. R ; Applicable unit-specific requirements (limits, submittal/actions, etc.) from 40 CFR pt. 60, subp. Da and 40 CFR pt. 63, subp. DDDDD were incorporated under each affected boiler. The citations of generally applicable requirements in the standard were listed in a text requirement that refers to a copy of the standard in an appendix. See Section 3.6 for further discussion; Oily, cellulose-based sorbents (oily rags) were removed as allowable fuels for EQUI 3 due to being defined as solid waste under 40 CFR pt. 241; The opacity and PM limits on EQUI 4 required by 40 CFR pt. 60, subp. Da were removed because they do not apply to boilers limited to burning natural gas according to 60.42Da(b)(2) and 60.42Da(f)(1); Fuel type requirement under EQUI 4 was added to limit permitted fuels to natural gas only; Wood pellets were removed as an allowable fuel for EQUI 3; Performance testing due dates were updated to reflect future dates; Stack extension construction authorization and notification requirements were added under STRU 5;

4 GP001 (Boilers 7 and 9 SO 2 Limits) was deleted because the boilers will not be permitted to operate simultaneously, making the group redundant; GP003 (Material Handling Baghouses), GP004 (NSPS CEMS), GP005 (Opacity Monitors), and GP006 (non- NSPS CEMS) were all disbanded because the groups contained limits that did not apply to all members; GP007 (Enclosed Wood Unloading System), GP008 (Wood Conveying Systems), and GP009 (Wood Transfer/Metering Bin System) were disbanded and their requirements placed under each respective stack/vent; and GP010 (Ash Loadout) was disbanded and its requirements placed under each fugitive subject item. 2. Regulatory and/or statutory basis 2.1 New Source Review (NSR) The facility is an existing major source under New Source Review regulations. Limits have been carried forward such that the facility avoids major modifications under NSR. No emissions increases are authorized by this permit. 2.2 Part 70 permit program The facility is a major source under the Part 70 permit program. This permit is a reissuance under the authority of the Part 70 permit program. 2.3 New Source Performance Standards (NSPS) The Permittee has stated that New Source Performance Standards apply to the operations at this facility, including 40 CFR pt. 60, subp. Da, Standards of Performance for Electric Utility Steam Generating Units, and 40 CFR pt. 60, subp. Db, Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units. These have been carried forward from the previous permit. Applicable continuing compliance, monitoring, recordkeeping, and reporting required under 40 CFR pt. 60, subp. Da were added to EQUI 4 unit requirements because only emission limits required under the standard were previously in the permit. While the facility has fossil-fuel-fired steam generators with a rated capacity of 250 MMBtu/hr or more, no operations at the facility are subject to 40 CFR pt. 60, subp. D, Standards of Performance for Fossil-Fuel-Fired Steam Generators. EQUI 4 is subject to 40 CFR pt. 60, subp. Da, making Subpart D inapplicable per 40 CFR 60.40(e). EQUI 16 is subject to 40 CFR pt. 60, subp. Db due to its capacity and construction date. 2.4 National Emission Standards for Hazardous Air Pollutants (NESHAP) The facility is an existing major source of HAPs and, therefore, EQUI 2, EQUI 3, and EQUI 16 are subject to 40 CFR pt. 63, subp. DDDDD, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. EQUI 4 is not subject to MACT DDDDD because it is an electric utility steam-generating unit as defined under 40 CFR pt. 63, subp. UUUUU. The coal-fired boilers located at the facility are not subject to the requirements of MACT UUUUU due to the following: None of the turbines/steam generators have a rated output of 25 megawatts (MW) or greater; and The coal boilers by themselves are not capable of producing the amount and quality of steam required to produce 25 MW of electricity for sale to a utility distribution system under either cogeneration or non-cogeneration mode of operation. See Attachment 4 to this TSD for additional information regarding MACT UUUUU applicability. 2.5 Acid rain program The facility does not have units that are subject to the Acid Rain Program under 40 CFR 70.2 even though existing boilers burn fuels that have characteristically-high sulfur content (coal). The facility operates as a cogeneration facility and defined as such under the rule because the steam generated is used for heating as Technical Support Document, Permit Number: Page 4 of 26

5 well as electricity generation. According to 40 CFR 70.6(b)(4)(i) and (ii), the following types of units are not affected units subject to the requirements of the acid rain program: (4) A cogeneration facility which: (i) For a unit that commenced construction on or prior to November 15, 1990, was constructed for the purpose of supplying equal to or less than one-third its potential electrical output capacity or equal to or less than 219,000 MWh actual electric output on an annual basis to any utility power distribution system for sale (on a gross basis). If the purpose of construction is not known, the Administrator will presume that actual operation from 1985 through 1987 is consistent with such purpose. However, if in any three calendar year period after November 15, 1990, such unit sells to a utility power distribution system an annual average of more than one-third of its potential electrical output capacity and more than 219,000 MWh actual electric output (on a gross basis), that unit shall be an affected unit, subject to the requirements of the Acid Rain Program; or (ii) For units which commenced construction after November 15, 1990, supplies equal to or less than onethird its potential electrical output capacity or equal to or less than 219,000 MWh actual electric output on an annual basis to any utility power distribution system for sale (on a gross basis). However, if in any three calendar year period after November 15, 1990, such unit sells to a utility power distribution system an annual average of more than one-third of its potential electrical output capacity and more than 219,000 MWh actual electric output (on a gross basis), that unit shall be an affected unit, subject to the requirements of the Acid Rain Program. EQUI 2, EQUI 3, and EQUI 4 meet the exemption stipulated in 70.6(b)(4)(i) because no individual unit can achieve 219,000 MWh on an annual basis. EQUI 16 meets the exemption under 70.6(b)(4)(ii) because it was installed after November 15, 1990 and it can only produce 131,400 MWh on an annual basis. 2.6 Compliance assurance monitoring (CAM) The table below lists the sources subject to CAM, control equipment associated with the source, whether the source is a large or other pollutant specific emission unit (PSEU), and the pollutants that trigger CAM. Table 5. CAM summary Unit Control CAM applicability Pollutant EQUI 2 TREA 4 ESP Other PM/PM10 EQUI 3 TREA 1 ESP Other PM/PM10 EQUI 16 TREA 5 SNCR Large NOx See Attachment 3 to this TSD for the CAM Plan submitted by the applicant, which has been carried over from the previous permit. 2.7 Minnesota State Rules Portions of the facility are subject to the following Minnesota Standards of Performance: Minn. R Standards of Performance for Existing Indirect Heating Equipment; Minn. R Electric Utility Steam Generating Units: Incorporation of New Source Performance Standards by Reference; Minn. R Industrial-Commercial-Institutional Steam Generating Units: Incorporation of New Source Performance Standards by Reference; Minn. R Standards of Performance for Post-1969 Industrial Process Equipment; and Minn. R Emission Standards for Hazardous Air Pollutants: Industrial, Commercial, and Institutional Boilers and Process Heaters; Major Sources. Technical Support Document, Permit Number: Page 5 of 26

6 2.8 Regulatory Overview Table 6. Regulatory overview of facility Subject item* Applicable regulations Rationale TFAC 2 Total Facility Requirements Minn. R Mercury Emissions Reduction Plan. This rule applies because the facility has boilers that are existing sources of mercury emissions and actual mercury emissions from the units exceed five pounds per year. This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act. COMG 2 - Boilers #7, #9, and #10 and Makeup Air Heater NOx Cap 40 CFR 52.21(b)(2) Prevention of Significant Deterioration: Limits to avoid a major modification. Limits set on combined NOx emissions, including recordkeeping, and reporting requirements to avoid a major modification under PSD. EQUI 2 Boiler #7 40 CFR 52.21(b)(2) and (k) Prevention of Significant Deterioration: Limits to avoid a major modification and modeling. Recordkeeping and reporting requirements on fuel use. Fuel records and NOx emission factors derived from performance tests shall be used to calculate NOx emissions to avoid major modifications under PSD. Requirements specifying emissions are to be vented to control equipment at all times to meet modeling limits. 40 CFR pt. 63, subp. DDDDD National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. EQUI 2 is subject to emission limitations and operating requirements specified under the standard because the boiler is described as follows: It is located at a major source of HAPs; It is a stoker boiler designed to burn coal/solid fossil fuels; and It is an existing affected source under the standard because it was constructed/reconstructed prior to June 4, Minn. R , subps. 7A, 7L, & 7M Minn. R Modeling Limit: EQUI 2 is subject to a SO2 emission limit resulting from a Title V modeling demonstration. Compliance with this limit is required to demonstrate continuing compliance with NAAQS/MAAQS. Standards of Performance for Existing Indirect Heating Equipment. The boiler is existing indirect heating equipment because it was constructed prior to 1/31/1977. The standard places limits on SO2, PM, and opacity. EQUI 3 Boiler #9 40 CFR 52.21(b)(2) and (k) Prevention of Significant Deterioration: Limits to avoid a major modification and modeling. Recordkeeping and reporting requirements on fuel use. Fuel records and NOx emission factors derived from performance tests shall be used to calculate NOx emissions to avoid major modifications under PSD. Requirements specifying emissions are to be vented to control equipment at all times to meet modeling limits. Technical Support Document, Permit Number: Page 6 of 26

7 Subject item* Applicable regulations Rationale EQUI 3 Boiler #9 40 CFR pt. 63, subp. DDDDD National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. EQUI 3 is subject to emission limitations and operating requirements specified under the standard because the boiler is described as follows: It is located at a major source of HAPs; It is a stoker boiler designed to burn coal/solid fossil fuels; and It is an existing affected source under the standard because it was constructed/reconstructed prior to June 4, Minn. R , subps. 7A, 7L, & 7M, Minn. R , subps. 1, 2, & 4 Minn. R Minn. R Modeling Limit: EQUI 3 is subject to a SO2 emission limit resulting from a Title V modeling demonstration. Compliance with this limit is required to demonstrate continuing compliance with NAAQS/MAAQS. Mercury Emissions Reduction Plan. The rule applies because the unit is an existing source of mercury emissions as defined under Minn. R , subp. 23b and has emitted over five pounds per year of mercury since This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (USEPA) Administrator and citizens under the Clean Air Act. Standards of Performance for Existing Indirect Heating Equipment. The boiler is existing indirect heating equipment because it was constructed prior to 1/31/1977. The standard places limits on SO2, PM, and opacity. EQUI 4 Boiler #10 40 CFR 52.21(b)(2) Prevention of Significant Deterioration: Limits to avoid a major modification. Recordkeeping and reporting requirements on fuel use. CEMS, fuel records, and NOx emission factors derived from performance tests (during malfunction) shall be used to calculate NOx emissions to avoid major modifications under PSD. 40 CFR pt. 60, subp. Da Standards of Performance for Electric Utility Steam Generating Units. This standard applies because the following: The unit has the capability to combust 250 MMBtu/hr heat input of fossil fuel; and It was constructed after September 18, The standard sets emission limits, monitoring, and operation requirements, including CEMS. EQUI 9 - Makeup Air Heater EQUI 16 Boiler #11 Minn. R Standards of Performance for Fossil-Fuel-Burning Direct Heating Equipment. The standard applies because the unit fires natural gas, and a standard of performance has not been promulgated under any other rule. Standards include limits on PM emissions and opacity (no SO2 standard for gaseous fuels). 40 CFR 52.21(b)(2) and (j) Prevention of Significant Deterioration: Limits to avoid a major modification and BACT. BACT analyses set limits on CO, NOx, PM, and PM10 and requires the use of control equipment, performance testing, and monitors (CEMS). Limits set on PM10, PM2.5, NOx, and CO to avoid a major modification under PSD. Technical Support Document, Permit Number: Page 7 of 26

8 Subject item* Applicable regulations Rationale EQUI 16 Boiler #11 STRU 4 Enclosed Wood Unloading Area Stack/Vent STRU 7 Wood Conveyor Stack/Vent STRU 8 Wood Transfer Metering Bin Stack/Vent TREA 1 - Electrostatic Precipitator (Boiler #9) TREA 4 - Electrostatic Precipitator (Boiler #7) TREA 3 Centrifugal Collector (Boiler #7) TREA 5 Selective Non-Catalytic Reduction (Boiler #11) TREA 7 Fabric Filter (Enclosed Wood Unloading Area Stack/Vent) 40 CFR pt. 60, subp. Db Standards of Performance for Industrial-Commercial- Institutional Steam Generating Units. This standard applies because the following: The boiler has a rated heat input capacity greater than 100 MMBtu/hr; and The boiler does not meet the applicability requirements under 40 CFR pt. 60, subp. Da. 40 CFR pt. 63, subp. DDDDD National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters. EQUI 16 is subject to emission limitations and operating requirements specified under the standard because the boiler is described as follows: It is located at a major source of HAPs; It is a sloped-grate boiler designed to burn wet biomass; and It is an existing affected source under the standard because it was constructed/reconstructed prior to June 4, CFR 52.21(j); Prevention of Significant Deterioration: BACT. Analysis set Minn. R limits on PM, PM10, and opacity. Industrial Process Equipment Rule. Applies to industrial process equipment that emits particulate matter for which a standard of performance has not been promulgated in a specific rule. 40 CFR 52.21(k); 40 CFR pt. 64 Prevention of Significant Deterioration: Modeling. Incorporated assumed minimum total power input and minimum control efficiency from dispersion modeling inputs as permit limits. Recordkeeping requirements included to ensure enforceability. Compliance Assurance Monitoring. EQUI 2 and EQUI 3 are subject to CAM as other pollutant-specific emission units (PSEUs) because uncontrolled PM/PM10 emissions are greater than 100 percent of Part 70 thresholds but controlled emissions are less than those thresholds. 40 CFR 52.21(k) Prevention of Significant Deterioration: Modeling. Operation of collector required due to its operation during dispersion modeling. Aids in removal of gross particulates before exhaust gas enters the ESP. 40 CFR 52.21(j) Prevention of Significant Deterioration: BACT. Analysis 40 CFR pt. 64 required under PSD specifies minimum injection temperature and reducing agent (urea) feed rate. Recordkeeping requirements included to ensure enforceability. Compliance Assurance Monitoring. EQUI 16 is subject to CAM as a large PSEU because uncontrolled and controlled NOx emissions are greater than 100 percent of Part 70 thresholds. 40 CFR 52.21(j) Prevention of Significant Deterioration: BACT. Minimum control efficiency specified to ensure compliance with PM/PM10 BACT limits. The MPCA assumes compliance with the efficiency limits with demonstrated compliance with emission Technical Support Document, Permit Number: Page 8 of 26

9 Subject item* Applicable regulations Rationale TREA 10 Fabric Filter (Wood Conveyor Stack/Vent) TREA 11 Fabric Filter (Wood Transfer Metering Bin Stack/Vent) TREA 16 Multiple Cyclone w/o Fly Ash Reinjection (Boiler #11) TREA 17 - Electrostatic Precipitator (Boiler #11) limits. Pressure drop ranges are also specified to ensure proper operation of fabric filter. 40 CFR 52.21(j) Prevention of Significant Deterioration: BACT. Operation required by BACT. Aids in removal of gross particulates before exhaust gas enters the ESP. 40 CFR 52.21(j) Prevention of Significant Deterioration: BACT. Incorporated minimum total power input and minimum control efficiency from BACT analysis as limits. Recordkeeping requirements included to ensure enforceability. *Location of the requirement in the permit (e.g., EQUI 1, STRU 2, etc.). The language 'This is a state-only requirement and is not enforceable by the U.S. Environmental Protection Agency (EPA) Administrator and citizens under the Clean Air Act' refers to permit requirements that are established only under state law and are not established under or required by the federal Clean Air Act. The language is to clarify the distinction between permit conditions that are required by federal law and those that are required only under state law. State law-only requirements are not enforceable by the EPA or by citizens under the federal Clean Air Act, but are fully enforceable by the MPCA and citizens under provisions of state law. 3. Technical information In the past, facilities were permitted to burn various materials in their boilers other than traditional fuels. In the case of VPU, EQUI 3 had been permitted to burn a limited quantity of oily, cellulose-based sorbents, including oily rags. Due to court challenges, the United States Environmental Protection Agency (USEPA) now specifies which materials, known as non-hazardous secondary materials (NHSM), are permitted to be burned in boilers that are not waste incinerators defined under 40 CFR pt. 241, subp. B. If the material is not listed under 40 CFR 241.4(a), the facility may determine that the materials are NHSM and must consistently demonstrate that the materials meet that definition. Since oily, cellulose-based sorbents are not listed in this subpart as a NHSM, and the Permittee does not wish self-determine these materials meet NHSM criteria, these materials will no longer be permitted fuels to be burned in EQUI Calculations of potential to emit (PTE) Boilers The facility burns a variety of fuels in its boilers and therefore requires a variety of sources to calculate PTE. Emission factors for spreader stoker-fired boilers are based on USEPA AP-42, Chapter 1.1, Bituminous and Subbituminous Coal Combustion, Tables 1.1-3, 9, 12, 13, 14, 15, 18 & 19 (September 1998). Emission factors for greenhouse gas (GHG) emissions were taken from 40 CFR pt. 98, subp. C, Table C-1 and C-2, and 40 CFR pt. 98, subp. A, Table A-1 (November 29, 2013). Controlled emissions from these units include the use of add-on control equipment. EQUI 2 and EQUI 3 each have ESPs that lower PM and PM 10 emissions by 95 percent, and PM 2.5 by 90 percent (EQUI 2 also has a centrifugal collector whose control efficiency is not taken into account). This control equipment is required to meet permitted NESHAP and modeling limits on PM and PM 10. Technical Support Document, Permit Number: Page 9 of 26

10 EQUI 4 is fired by natural gas only. Emission factors are based on controlled large boilers (>100 MMBtu/hr), USEPA AP-42, Chapter 1.4 Natural Gas Combustion, Tables 1.4-1, 1.4-2, 1.4-3, and (July 1998). Emission factors for greenhouse gas (GHG) emissions were taken from 40 CFR pt. 98, subp. C, Table C-1 and C-2, and 40 CFR pt. 98, subp. A, Table A-1 (November 29, 2013). Although EQUI 4 does not have add-on control equipment, it does have design mechanisms that reduce NOx emissions, including flue gas recirculation, low excess-air firing, and modified furnace design. These reductions are reflected in the AP-42 emission factor listed for NOx. EQUI 16 is a co-fired boiler in which wet biomass and natural gas are used as fuel. Due to numerous excursions of the CO limit, a natural gas burner was installed as part of Permit No to stabilize the burn and maintain consistently lower CO emissions. Emission factors are based on bark/bark and wet wood fuel, USEPA AP-42, Chapter 1.6 Wood Residue Combustion in Boilers, Tables 1.6-1, 1.6-2, 1.6-3, & (September 2003). Natural gas emission factors are based on uncontrolled small boilers (<100 MMBtu/hr), USEPA AP-42, Chapter 1.4 Natural Gas Combustion, Tables 1.4-1, 1.4-2, 1.4-3, & (July 1998). As shown in the calculations, wood provides higher pollutant emissions and is therefore considered the worst-case fuel for the purposes of PTE. EQUI 16 has a multiple cyclone (MC) and an ESP to control PM/PM 10/PM 2.5 emissions. The MC and ESP are required to meet the BACT emission limits on particulate matter (MC control efficiency is not taken into account). The boiler also uses SNCR as required by BACT to reduce NOx emissions Wood handling Unloading, transport, and storage systems for wood is a source of PM/PM 10/PM 2.5 emissions at the facility. A series of elevators, screws, and conveyors are used to move the biomass fuel from the receiving dock to the metering bin. Particulate emissions result from each drop/transfer point in the transport process of the wood chips, in which emissions are collected by baghouses with a 99.7 percent control efficiency for inlet loads greater than one grain per cubic foot, as reported by the manufacturer. The manufacturer cannot guarantee control efficiencies due to load variability and other factors. Therefore, the Permittee assumed the filter control efficiency for PM is equal to PM 10 for a conservative assumption (99 percent) and PM 2.5 collection efficiency of 93 percent for the purposes of PTE calculations and program applicability. The MPCA assumes the facility is in compliance with the minimum control efficiencies specified in the permit when compliance with the BACT emission limits on PM/PM 10 is demonstrated through stack testing. No limits on PM 2.5 currently apply to these units. The following is an excerpt from VPU major amendment application for Permit No explaining the derivation of the emission factor for wood bark dust from transfer operations: Emission factors for potential emissions from these operations were derived from analysis done by the Oregon Department of Environmental Quality (DEQ) that were used to support calculations in a Title V permit issued by them. A sieve analysis completed to support permitting for Frank Lumber Company in Mill City, Oregon (Permit No ) indicated that only percent of the bark dust was smaller than 125 microns. The Oregon DEQ accepted use of a one percent by weight for an estimation of fugitive dust from bark as a conservative assumption. This one percent factor has been used to determine potential emissions from wet wood chip handling. The resulting emission factor applied is 0.01 pounds PM/PM 10/PM 2.5 per ton of wood chips. Attachment 1 to this TSD contains Form GI-07, which summarizes the PTE of the Facility, including detailed spreadsheets and supporting information prepared by the MPCA and the Permittee Dispersion modeling hour SO2 NAAQS modeling demonstration VPU submitted a major amendment application on March 12, 2017 requesting that the MPCA lower their permitted emission limits on SO 2 from EQUI 2 and EQUI 3 due to meeting the 1-hr SO 2 NAAQS Technical Support Document, Permit Number: Page 10 of 26

11 compliance demonstration. Because the methodology provided in EPA s April 23, 2014 Guidance for 1- Hour SO 2 Nonattainment SIP Submissions memorandum can be used in areas with poor air quality, the MPCA believes it can also be used to protect the NAAQS in the area surrounding the Virginia Public Utilities facility. The facility modeled SO 2 emissions from sources using two scenarios, each of which are detailed below. National Ambient Air Quality Standard modeling results for 1-hour SO 2 were evaluated based on two operating scenarios: the first includes the operation of Boilers #7, #10, and #11, and the second includes the operation of Boilers #9, #10, and #11 (i.e., Boilers #7 and #9 do not operate simultaneously). While the modeling results added to ambient background concentrations show that the plant is above the 1- hour ambient standard (see Attachment 7), the Permittee assessed culpability of sources contributing to the 1-hour SO 2 NAAQS exceedance. When culpability is properly assessed, the facility falls below the 1- hour SO 2 NAAQS as shown in Table 7 below. Table 7. SO 2 dispersion modeling results Pollutant SO2 Averaging Time 1-hour SO2 = Sulfur Dioxide Percent of standard (%) Operating Scenario NAAQS standard (µg/m 3 ) MAAQS standard (µg/m 3 ) Total modeled concentration NAAQS MAAQS In addition, per MPCA practice, a table of the modeled parameters has been added to the permit as an appendix. Other than specific operating restrictions mentioned above, the parameters listed in Appendix B of the permit describe the operation of the facility at maximum capacity. Flow rates and temperatures listed in Appendix B represent the minimum parameters at the maximum emission rates. The MPCA does not require any specific compliance demonstration with these parameters because they are worse case conditions. The purpose of listing the parameters in the permit appendix is to provide a benchmark for determining if and when additional modeling is required Construction of stack extension The dispersion modeling described above assumes the post-construction stack height on EQUI 3 (STRU 5) of 195 feet. The construction of this stack extension is described in the 2017 major amendment application that includes the SO 2 dispersion model. Since the EQUI 3 stack height is assumed to be 195 feet in the dispersion model (currently 150 feet), and assuming this stack height is required for EQUI 3 to meet its SO 2 limit, the MPCA expects VPU to begin construction of this stack extension within 18 months after issuance of Permit No Operation of EQUI 3 is not authorized 18 months after permit issuance without completion of the stack height increase (i.e. the facility may not share a stack/vent with another emission unit or otherwise vent emissions elsewhere) Wood Boiler BACT Analysis Authorization to construct and operate EQUI 16 and wood handling systems in 2005 was contingent upon completion of a BACT analysis (Permit No ). The analysis resulted in emission limits on various pollutants, including requiring the installation and operation of appropriate pollution control equipment in order to meet those limits (BACT controls). Further discussion may be found in Section 3.6. No changes to these BACT requirements are authorized by this permit action and all requirements from the BACT analysis have been carried forward. See Permit No for a copy and further discussion of the BACT analysis. Technical Support Document, Permit Number: Page 11 of 26

12 3.4. Mercury emissions reduction plan The facility owns and operates coal-fired boilers, one of which meets the definition of an existing mercury emission source. The following is an excerpt from Minn. R , subp. 2, showing the definition applies to VPU: Subp. 2. Applicability. The owners or operators of an existing mercury emission source must comply with this part. For the purposes of this part, "existing mercury emission source" means that the owners or operators have been issued an air emission permit by the agency as of September 29, For initial applicability, owners or operators must calculate emissions following methods in part for the calendar year If, after 2014, the actual mercury emissions from the existing mercury emission source are below the threshold of three pounds per year or more for three consecutive years, then the stationary source is no longer considered a mercury emission source and is not subject to this part. The owner or operator must: A. retain records of the actual mercury emissions for the qualifying three years on site for five years from the date the determination was made; B. make the records available for inspection and submit the records, within specified timelines, upon request of the commissioner; and C. immediately resume compliance with applicable requirements for mercury emission sources if a physical or operational change causes the stationary source to again become a mercury emission source. Owners or operators must resubmit a mercury emissions reduction plan under subpart 3 within 12 months of again becoming a mercury emission source. As described above, EQUI 3 currently emits greater than three pounds per year of mercury and, therefore, meets the definition as a mercury emission source as defined under Minn. R , subp. 23b. In addition, EQUI 3 has actual mercury emissions for the past three years greater than five pounds per year, making it subject to the mercury emissions reduction plan rule. The Permittee has accepted limits to reduce mercury emissions from EQUI 3 to less than five pounds per year in order to avoid being required to submit and follow a mercury reduction plan under Minn. R To demonstrate compliance, the Permittee shall calculate monthly mercury emissions based on the emission factor from the Notice of Compliance certifying the most recent stack test (lb mercury/mmbtu heat input) and the total amount of fuel combusted in EQUI 3 that month (MMBtu heat input/month). The total amount of fuel combusted shall be calculated using shipment receipts and the heating value of coal from required monthly fuel analyses. Compliance with the limit is based upon a 12-month rolling sum of the calculated monthly mercury emissions as defined in Minn. R , subp. 21b in order to obtain a calendar year total. The Permittee may not use an emission factor from a stack test until it is certified in a Notice of Compliance issued by MPCA Historical testing summary The table below summarizes the most recent performance testing done by the Permittee, which justifies the current testing frequency required by the facility as stated in the permit. Testing for pollutants of interest and associated limits depends upon standards to which each emission unit/source is subject. Technical Support Document, Permit Number: Page 12 of 26

13 Table 8. Summary of most-recent performance tests as of Permit No issuance Pollutant Front-Half Particulate Matter Total Particulate Matter Particulate Matter less than 10 Microns Particulate Matter less than 2.5 Microns Emission Unit/Source Tested Most Recent Test Date Permit Limit Regulatory Basis Result EQUI 2 03/06/ lb/mmbtu 40 CFR pt. 63, subp lb/mmbtu EQUI 3 08/15/2017 DDDDD lb/mmbtu EQUI 16 02/28/ lb/mmbtu EQUI 2 10/07/ lb/mmbtu Minn. R , lb/mmbtu EQUI 3 07/07/2015 subp lb/mmbtu EQUI 4 07/27/ lb/mmbtu 40 CFR pt. 60, subp. Da lb/mmbtu EQUI 16 07/13/ lb/mmbtu 40 CFR 52.21(j) lb/mmbtu STRU 4 09/26/ gr/dscf 40 CFR 52.21(j) gr/dscf STRU 7 09/26/ CFR 52.21(j) gr/dscf STRU 8 09/27/ CFR 52.21(j) gr/dscf EQUI 2 10/07/ lb/mmbtu 40 CFR 52.21(k) lb/mmbtu EQUI 3 07/07/ CFR 52.21(k) lb/mmbtu EQUI 16 07/13/ / CFR 52.21(j) lb/mmbtu lb/mmbtu EQUI 16 08/15/ lb/mmbtu 40 CFR 52.21(b)(2) lb/mmbtu Opacity STRU 4 09/26/2017 0% 40 CFR pt. 63, subp. 0% STRU 7 09/26/2017 DDDDD 0% STRU 8 09/27/2017 0% Nitrogen EQUI 2 03/06/2018 Emission Factor 40 CFR 52.21(b)(2) lb/mmbtu Oxides EQUI 3 07/19/2017 Determination lb/mmbtu EQUI 4 12/09/ / CFR 52.21(b)(2)/ lb/mmbtu lb/mmbtu CFR pt. 60, subp. Da EQUI 16 10/01-30/ lb/mmbtu 40 CFR 52.21(j) lb/mmbtu (30-day test) Mercury EQUI 2 03/06/ E CFR pt. 63, subp. 1.59E-06 lb/mmbtu EQUI 3 02/27/2018 lb/mmbtu DDDDD 6.30E-06 lb/mmbtu EQUI 16 02/28/ E-07 lb/mmbtu Ammonia EQUI 16 07/13/ ppm Minn. R , subp ppm 3.6. Pollution control equipment not needed to meet emission limits The facility currently operates a medium-efficiency centrifugal collector (TREA 3) and a multiple cyclone without fly ash reinjection (TREA 16) on EQUI 2 and EQUI 16, respectively. Their purpose is to condition exhaust gas by removing large particles emitted from the boilers that would otherwise foul the ESPs. The Permittee has not taken credit for the emissions limited by these units based on the control efficiency reported for each pollutant and do not use their efficiency in reporting emissions to Air Emissions Inventory. These are also not required to meet any emission limit; however, TREA 3 was included as assumed control equipment for PM 10 in the PSD dispersion modeling conducted in Therefore, TREA 3 is required to be in the permit (and operated) regardless if credit is taken for its control efficiency. Similarly, TREA 16 was identified as a BACT control in the analysis discussed in Section 3.3 above. Therefore, its presence in the permit and continued operation is required unless a revised BACT analysis is conducted showing TREA 16 is not required to meet the BACT limit. Similarly, the Permittee must show that TREA 3 is not required to meet the PM 10 modeling limit through stack testing if they wish to remove it from the permit. Technical Support Document, Permit Number: Page 13 of 26

14 While not specifically listed in Table 9 of this TSD due to no operating limits on these controls, TREA 3 and TREA 16 will be subject to monitoring, recordkeeping, and corrective actions as described in the permit. The MPCA agrees that minimum monitoring and recordkeeping requirements will be sufficient considering they are not required to meet emission limits. The Permittee shall submit the appropriate permit amendment should they elect to show a control is not required to meet the associated emission limit Monitoring In accordance with the Clean Air Act, it is the responsibility of the owner or operator of a facility to have sufficient knowledge of the facility to certify that the facility is in compliance with all applicable requirements. The Permittee submitted a CAM plan as required by 40 CFR 64.3 for Permit No Since no changes have been proposed, the CAM plan has been carried forward unchanged and can be found in Attachment 3 to this TSD. A summary of units subject to CAM and pollutants of interest can be found in Table 5 of Section 2.6 above. In evaluating the monitoring included in the permit, the MPCA considered the following: the likelihood of the facility violating the applicable requirements; whether add-on controls are necessary to meet the emission limits; the variability of emissions over time; the type of monitoring, process, maintenance, or control equipment data already available for the emission unit; the technical and economic feasibility of possible periodic monitoring methods; and the kind of monitoring found on similar units elsewhere. Table 9 summarizes the monitoring requirements. Table 9. Monitoring Subject Item* COMG 2 - Boilers #7, #9, and #10 and Makeup Air Heater NOx Cap Requirement (basis) Nitrogen Oxides < tons per month. [Title I Condition: Avoid major modification under 40 CFR 52.21(b)(2) and Minn. R. What is the monitoring? Monthly recordkeeping and reporting; Performance testbased emission factor revision. Why is this monitoring adequate? The following is required to be recorded on a monthly basis which ensures compliance with the limit: Total quantity of coal burned in EQUI 2 during the previous month, in tons; Total quantity of coal burned in EQUI 3 during the previous month, in tons; Total monthly NOx emissions from EQUI 4 and EQUI 9 as measured by NOx CEMS, in tons; Quantity of natural gas combusted in EQUI 4 and EQUI 9 during times of NOx CEMS malfunction; and 12-month rolling average of NOx emission rate. emissions monitoring documents SO2 emissions, including limit excursions. Proper CEMS operation, including coal combustion monitoring during start-up and shut down, ensures compliance with the limit. EQUI 2 Boiler #7 Sulfur Dioxide <= pounds per MMBtu 30-day rolling average. [Minn. R , subps. 1,2, & 4, Minn. R , Minn. R , subp. 1, Minn. Stat , subd. 4a & 9] Coal combustion monitoring; CEMS. Technical Support Document, Permit Number: Page 14 of 26

15 Subject Item* Requirement (basis) What is the monitoring? Why is this monitoring adequate? EQUI 2 Boiler #7 Sulfur Dioxide <= 4.0 pounds per million Btu heat input. [Minn. R , subp. 1] Opacity <= 10 percent opacity. [40 CFR (a)(2), 40 CFR pt. 63, subp. DDDDD, Table 4, Minn. monitoring (COMS). Monitoring COMS and maintaining records ensures compliance with the limit. Opacity <= 20 percent opacity. [Minn. R , subp. 2] Front-half Particulate Matter <= pounds per million Btu heat input. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. Performance testing; COMS. Performance testing will determine whether the unit is in compliance with the limit. COMS will show potential excursions as opacity and PM emissions are related. PM <= 0.60 pounds per million Btu heat input. [Minn. R , subp. 1] PM < 10 micron <= 0.30 pounds per million Btu heat input (k)(Modeling) & Minn. R. Carbon Monoxide <= 340 parts per million. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. Recordkeeping; CEMS. Maintaining records, results of CO CEMS performance audits, dates and duration of periods when the CO CEMS is out of control, and completion of the corrective actions necessary to return the CO CEMS to operation consistent with the Site-Specific Monitoring Plan will ensure compliance. Mercury <= pounds per million Btu heat input. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. Performance testing; Fuel analysis. Establishing maximum pollutant content in fuel and performance testing will ensure compliance with the limit. Hydrogen Chloride <= pounds per million Btu heat input. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. Steam Flow <= 79,530 pounds per hour. [Minn. R , subp. 3, Minn. R , subp. 3a] Daily recordkeeping and calculations. Calculating and recording three, 8-hour block average steam flow values each day will ensure compliance with the limit. Technical Support Document, Permit Number: Page 15 of 26

16 Subject Item* Requirement (basis) What is the monitoring? Coal combustion monitoring; CEMS. Why is this monitoring adequate? emissions monitoring documents SO2 emissions, including potential excursions. Proper CEMS operation, including coal combustion monitoring during start-up and shut down, ensures compliance with the limit. EQUI 3 Boiler #9 Sulfur Dioxide <= pounds per MMBtu 30-day rolling average. [Minn. R , subps. 1, 2, & 4, Minn. R , subps. 7A, 7L, &7M, Minn. R , Minn. R , subp. 1, Minn. Stat , subd. 4a & 9] Sulfur Dioxide <= 4.0 pounds per million Btu heat input. [Minn. R , subp. 1] Opacity <= 10 percent opacity. [40 CFR (a)(2), 40 CFR pt. 63, subp. DDDDD, Table 4, Minn. Opacity <= 20 percent opacity. [Minn. R , subp. 2] Front-half Particulate Matter <= pounds per million Btu heat input. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. PM <= 0.60 pounds per million Btu heat input. [Minn. R , subp. 1] monitoring (COMS). Monitoring COMS and maintaining records ensures compliance with the limit. Performance testing; COMS. Performance testing will determine whether the unit is in compliance with the limit. COMS will show potential excursions as opacity and PM emissions are related. PM < 10 micron <= 0.30 pounds per million Btu heat input (k)(Modeling) & Minn. R. Carbon Monoxide <= 340 parts per million. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. Recordkeeping; CEMS. Maintaining records, results of CO CEMS performance audits, dates and duration of periods when the CO CEMS is out of control, and completion of the corrective actions necessary to return the CO CEMS to operation consistent with the Site-Specific Monitoring Plan will ensure compliance. Establishing maximum pollutant content in fuel and conducting performance testing will ensure compliance with the limit. Mercury <= pounds per million Btu heat input. [40 CFR (a)(1), 40 CFR pt. 63, subp. DDDDD, Table 2, Minn. Performance testing; Fuel analysis. Technical Support Document, Permit Number: Page 16 of 26