For DRAFT Air Emission Permit No. 01500010 101

Technical Support Document, Permit Number: 01500010-101 of 10

Technical Support Document For

DRAFT Air Emission Permit No. 01500010‐101 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. 7007.0850, 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 Stationary source/address

(SIC Code: 4931) City of New Ulm 310 First North Street New Ulm, MN 56073

New Ulm Public Utilities ‐ Municipal Power 310 First North Street New Ulm, MN 526073 Brown County

Contact: Gary Domeier Phone: 507‐359‐8240

1.2 Facility description

New Ulm Public Utilities is a municipal utility that provides electricity and steam to the city of New Ulm. The Facility operates three boilers: EQUI 010 and EQUI 012 are natural gas‐fired and EQUI 013 is natural gas‐ and has the ability to become coal‐fired after further permitting; and two simple cycle distillate oil‐fired combustion turbine generators: EQUI 011 and EQUI 002. Total generating capacity is 76.2 megawatts. The facility is an existing major source under the Part 70 and Prevention of Significant Deterioration regulations. The facility is an area source under 40 CFR pt. 63. Under 40 CFR Section 72.6(b)(1) and (2), the electric generating equipment is not subject to Title IV (Acid Rain requirements) because all units commenced operation before November 15, 1990. The facility has two multiclones that control particulate matter from EQUI 012 and EQUI 013. Currently, the Permittee is not authorized to burn coal in EQUI 013 until the Permittee installs a fabric filter or electrostatic precipitator and applies for and obtains an amendment to incorporate the appropriate applicable requirements related to coal combustion. Therefore, coal storage, coal handling, and ash handling are insignificant activities as defined in Minn. R. 7007.1300. See Appendix A of the permit for all listed insignificant activities.

1.3 Description of the activities allowed by this permit action This permit action is a major amendment. The MPCA has a combined operating and construction permitting program under Minn. R. ch. 7007 and under Minn. R. 7007.0800. Under that authority, this permit action authorizes construction. Permit action 01500010‐008 authorized the changeout of three existing burners with one single burner on utility Boiler No. 2 (EQUI 012). The boiler was derated in 2006. When the boiler was derated, two of the existing


burners were disconnected from fuel lines and not used. A new single burner was proposed to restore the boiler to 99 MMbtu/hr heat input. The new burner would be a larger burner than the three smaller existing burners. Since the issuance of permit 01500010‐008 in November 2012, New Ulm has received advice from its consultants recommending against the installation of one large burner due to potential damage to the boiler’s superheater. As such, New Ulm has requested a change in the language of the construction authorization to allow for flexibility in the number of burners installed as long as the total burner capacity is at or below 99 MMBtu/hr. The original permit language stated: “The Permittee is authorized to modify EU 002 by replacing the existing natural gas burners with a single natural gas burner not to exceed 99 million Btu/hr capacity”. The permit language now reads: “The Permittee is authorized to modify EQUI 012 (Boiler #2) by replacing the existing natural gas burners with new natural gas burner(s) not to exceed 99 million Btu/hr in total capacity”. The change in number of replacement burners has no effect on the applicability of regulations or on the emissions calculations.

1.4 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 08/17/2015 Major Amendment

1.5 Facility emissions:

Table 3. Title I emissions summary * Pollutant Emissions

Increase from the

Modification

(tpy)

Limited Emissions Increase from the

Modification (tpy)

Net Emissions Increase (tpy)

NSR significant thresholds for major sources (tpy)

NSR review

required? (Yes/No)

PM 0.64 0.64 0.64 25 No PM10 1.28 1.28 1.28 15 No PM2.5 1.28 1.28 1.28 10 No NOx 42.2 39.0 39.0 40 No SO2 0.25 0.25 0.25 40 No CO 35.4 35.4 35.4 100 No

Ozone (VOC)

2.32 2.32 2.32 40 No

Lead 2.11E‐04 2.11E‐04 2.11E‐04 0.6 No CO2e** 50,600 50,600 50,600 75,000 No

*Although EQUI 012 is an existing unit subject to the applicability procedures under 40 CFR Section 52.21(a)(2)(iv)(c), the emissions increase was calculated in a more conservative and simple manner as the future potential emissions of EQUI 012. **Carbon dioxide equivalents as defined in Minn. R. 7007.0100.

Table 4. Total facility potential to emit summary


PM tpy

PM10 tpy

PM2.5 tpy

SO2 tpy

NOx tpy

CO Tpy

CO2e Tpy

VOC tpy

Single HAP tpy

All HAPs tpy

Total Facility Limited Potential Emissions 25 27 27 819 1561 156 486,000 200 3.20 5.52 Total Facility Actual Emissions (2014) 0.07 0.07 0.07 0.11 28.7 0.52 * 0.80 *

* Not reported in MN emission inventory.

Table 5. Facility classification

Classification Major Synthetic minor/area Minor/area PSD X Part 70 Permit Program X Part 63 NESHAP X

1.6 Changes to permit

Under the authority of the combined operating permit program the following changes were also made to the permit through this permit action ‐ Changes to requirements related to coal usage (see Section 3.2 for further information) ‐ Addition of requirements of Cross State Air Pollution Rule (CSAPR) requirement to EQUI 002 (see Section 2.6

for further information) ‐ Updated citations for modeling‐based limits based on standard guidance. However, Minn. R. 7007.0100, subp.

7(L) was not included in the citation because a review of the permitting record shows that the modeling was only completed for the Minnesota Ambient Air Quality SO2 Standard and not the National Ambient Air Quality Standard.

‐ Updated former references to “EUs”, “CEs”, and “SVs” to “EQUI”, “TREA”, and “STRU” respectively (new Tempo references).

‐ Miscellaneous changes to help with clarity ‐ Updated requirements to current standard MPCA language.

2. Regulatory and/or statutory basis

2.1 New source review (NSR)

The facility is an existing major source under New Source Review regulations. Permit action 01500010‐008 incorporated limits on NOx emissions from Boiler No. 2 (EQUI 012) to ensure that the increase in emissions due to the modification is below the significant emission rate for all pollutants. No changes to that limit are authorized by this permit action

2.2 Part 70 permit program

The facility is a major source under the Part 70 permit program.

2.3 New source performance standards (NSPS) The EQUI 012 burner replacement qualifies as a modification under 40 CFR Section 60.14 because there is an increase in hourly potential emissions. As a result of the modification the boiler will become subject to NSPS Subpart Dc – Standards of Performance for Small Industrial‐Commercial‐Institutional Steam Generating Units. The boiler is subject to this subpart because it is a steam generating unit with a maximum design heat input capacity greater than 10 MMBtu/hr but less than 100 MMBtu/hr (Boiler No. 2 capacity = 99 MMbtu/hr). The boiler will be subject to the requirements for natural gas burning units.


The requirements of this NSPS subpart were incorporated into the permit through permit action 01500010‐008 and become effective upon startup of the boiler following the burner modification.

2.4 National emission standards for hazardous air pollutants (NESHAP) The facility is an area source under 40 CFR pt. 63. Thus, no major source NESHAPs apply. Because the Permittee is not currently authorized to burn coal in EQUI 013, this permit action did not include coal burning emissions in the PTE calculations for the facility and the action removed the limit on coal usage that the Permittee accepted to keep the source an area source under 40 CFR pt. 63. Without the potential emissions from coal combustion, the facility is a natural area source under 40 CFR pt. 63. In addition, the Permittee has stated that no area source NESHAPs apply to the facility; however, if the facility resumes the burning of coal they would become subject to 40 CFR pt. 63, subp. JJJJJJ for Industrial, Commercial, and Institutional Boilers at Area Sources.

2.5 Acid Rain Program The utility units are not subject to the Acid Rain Program because they are not affected units under 40 CFR § 72.6(b)(1) and (2). EQUI 010, 011, 012, and 013 are not subject because they commenced commercial operation before November 15, 1990 and do not serve a generator with a nameplate capacity of greater than 25MWe. EQUI 002 (gas turbine #7) does serve a generator with a nameplate capacity greater than 25MWe, but it is not an affected unit because it is a simple combustion turbine that commenced commercial operation before November 15, 1990.

2.6 Cross‐State Air Pollution Rule (CSAPR) The facility is subject to CSAPR (also known as the Transport Rule or TR) because it has a stationary fossil‐fuel‐fired combustion turbine (EQUI 002, Gas Turbine #7) that serves, on or after January 1, 2005, a generator with a nameplate capacity of more than 25 MWe producing electricity for sale (EQUI 002 serves a 26 MW generator). Specifically, the facility is subject to the requirements of the TR NOx Annual Program (40 CFR pt. 97 subp. AAAAA) and the TR SO2 Group 2 Trading Program (40 CFR pt. 97, subp. DDDDD) because Minnesota is subject to the TR NOx Annual Trading Program pursuant to 40 CFR Section 52.38(a)(2) and Minnesota is subject to the requirements of the TR SO2 Group 2 Trading program pursuant to 40 CFR Section 52.39(c). EQUI 002 is eligible to comply using a low mass emission excepted monitoring methodology described under 40 CFR Section 75.19 because EQUI 002 is an oil‐fired unit that emits NOx less than the thresholds in 40 CFR Section 75.19(a)()1)(i)(A). As such, the Permittee can satisfy the requirements of the Transport Rule by monitoring fuel flow and using and emission factor to calculate emissions rather than installing continuous emissions monitors. This permit incorporates the requirements of 40 CFR pt. 97 subps. AAAAA and DDDDD into the permit. EPA issued a memorandum on May 13, 2015 to provide guidance to the regions and the states on incorporating CSAPR requirements into Title V permits. The guidance includes a template to be used in permits. All CSAPR requirements incorporated into this permit adhere to EPA’s guidance and template, with one exception. The permit does not include the requirements from 40 CFR Section 97.406(d) and 40 CFR Section 97.706(d) which address Title V permit revision requirements. These requirements were not included in the permit because they refer to the permit modifications procedures under Part 70 that a Permittee may use to make changes to the monitoring provisions table in the permit. However, under Minnesota rules, in order to make changes to the monitoring provisions table in the permit the Permittee must follow Minn. R. 7007.1150‐1500.

2.7 Compliance assurance monitoring (CAM) This permit action removes CAM requirements from TREA 002, the multiclone that controls emissions from EQUI 013 (boiler No. 4). EQUI 013 was only subject to CAM due to coal emissions (control from the multiclone was needed in order for EUQI 013 to meet the indirect heating rule while burning coal). The Permittee is not authorized to combust coal in EQUI 013, therefore the CAM requirements were removed from TREA 002. TREA


002 is not needed to meet any applicable requirements; however, if the Permittee wishes to take credit for control provided by TREA 002 for the purposes of reporting actual emissions for emissions inventory, the Permittee must comply with the requirements at TREA 002 level of the permit. CAM will apply to EQUI 013 (Boiler 4) when and if the Permittee begins burning coal in EQUI 013.

2.8 Minnesota state rules There are no changes to the applicable Minnesota rules through this permit action. Portions of the facility are subject to the following Minnesota Standards of Performance:

Minn. R. 7011.0510 Standards of Performance for Existing Indirect Heating Equipment

Minn. R. 7011.2300 Standards of Performance for Stationary Internal Combustion Engines

Table 6. Regulatory overview of units affected by the modification/permit amendment

Subject item* Applicable regulations Rationale

EQUI 002 (Gas Turbine #7 (simple cycle))

40 CFR pt. 60, subp. GG

Standards of Performance for Stationary Gas Turbines: The facility is subject to this standard because it owns and operates a stationary gas turbine with a heat input at peak load equal to or greater than 10 MMBtu/hr that commenced construction, reconstruction, or modification after October 3, 1977 but before February 18, 2005. EQUI 002 was built in 1979 and refurbished in 2001. No changes to these requirements through this permit action.

Title I Condition to avoid major modification under 40 CFR § 52.21

Prevention of Significant Deterioration (PSD): The Permittee remains below the NOx limit established by NSPS subp. GG in order to maintain NOx emissions below the PSD major modification threshold. The Permittee has also accepted a limit on sulfur content of fuel to remain below the SO2 major modification threshold. No changes to these requirements through this permit action.

Minn. R. 7017.2025

Minnesota Rule for Performance Tests: EQUI 002 is subject to an operational restriction as a result of a performance test. No changes to these requirements through this permit action.

40 CFR pt. 97, subp. AAAAA and DDDDD

Cross‐State Air Pollution Rule (CSAPR): EQUI 002 is subject to this requirement because it is a stationary fossil‐fuel‐fired combustion turbine that serves, on or after January 1, 2005, a generator with a nameplate capacity of more than 25 MWe producing electricity for sale (EQUI 002 serves a 26 MW generator). The Permittee is subject to the requirements of the TR NOx Annual Trading Program and the TR SO2 Group 2 Trading Program. These requirements are added through this permit action.

EQUI 012 (Boiler #2)

Title I Condition to avoid major modification under 40 CFR § 52.21

PSD. The permit authorizes the replacement of the burners on EQUI 002. The authorization limits the new burners to a combined capacity of 99 MMBtu/hr to limit the emissions increase from the change to below major modification thresholds under PSD. This requirement was modified through this permit action to allow the existing burners to be replaced with any number of new burners as long as the combined capacity is less than or equal to 99 MMBtu/hr. The permit also contains an explicit limit on NOx emissions to avoid major modification thresholds. This limit takes effect after the replacement of the new burners.


Subject item* Applicable regulations Rationale

40 CFR pt 60 subp. Dc

New Source Performance Standards for Small Industrial‐Commercial‐Institutional Steam Generating Units: The burner replacement qualifies as a modification under 40 CFR Section 60.14 because there is an increase in hourly potential emissions. The boiler is subject to this subpart because it is a steam generating unit with a maximum design heat input capacity greater than 10 MMBtu/hr but less 100 MMBtu/hr (Boiler No. 2 capacity = 99 MMbtu/hr). The boiler will be subject to the requirements for natural gas burning units.

Minn. R. 7019.3020(G)

Minnesota Rules on calculation of actual emission for emission inventory: The Permittee is not required to vent emissions from EQUI 012 to control equipment in order to meet any applicable requirements; however, the Permittee may take credit for operation of TREA 001 during times that EQUI 012 is vented to TREA 001. No changes were made to the content of this requirement through this permitting action, but the citation was amended. The permit previously cited Minn. Stat. 116.07, subd. 4a. The statute citation is not a citation that would typically be cited in this situation, and the permitting record does not indicate why this citation was used, so it was removed.

*Location of the requirement in the permit (e.g., EQUI 001, STRU 002,etc.).

3. Technical information 3.1 Emissions increase analysis

Attachment 1 to this TSD contains a summary of the PTE of the Facility, and detailed spreadsheets and supporting information prepared by the MPCA and the Permittee.

The original emissions increases analysis associated with the EQUI 012 modification authorized by permit action 01500010‐008 was completed by calculating (1) the post‐modification potential to emit (future potential emissions) of the boiler, including the annual limit proposed by the permittee, and (2) the pre‐modification actual emissions of the boiler (baseline actual emissions). Future potential emissions were calculated using the modified boiler capacity and emission factors published in AP‐42 for natural gas combustion. Baseline actual emissions were calculated using the natural gas usage as reported in the annual emission inventory and emission factors published in AP‐42. The selected baseline period was calendar years 2010 and 2011. The emissions increase for purposes of determining NSR applicability is the (future potential emissions) minus the (baseline actual emissions).

The AP‐42 emission factors used are for uncontrolled emissions; the factor for NOX emissions (the only one used for compliance demonstration in the permit) is rated “B” meaning it is “above average.” It is developed from A‐ or B‐rated test data from a "reasonable number" of facilities, meaning that the source category population is sufficiently specific to minimize variability. However, the permit still requires a test to demonstrate the NOX emission rate to be used in the compliance calculations; the AP‐42 factor is to be used prior to test data being obtained.

Under 40 CFR Section 52.21(b)(48) for an existing electric utility steam generating unit baseline actual emissions shall be calculated based on any consecutive 24‐month period within the 5‐year period immediately preceding when the owner or operator begins actual construction of the project. Because the Permittee has not yet began actual construction on the burner replacement, the baseline period of 2010‐2011 used in the original analysis of no longer valid.

However, because the future potential for all regulated pollutants is below the significant emissions rate prior to subtracting out the baseline actual emissions, no revisions were required to the emissions increase analysis, and the emission increase is equal to the future potential emissions.

3.2 Coal Usage Requirements


Permit 0150010‐009 contained limits and monitoring requirements associated with the combustion of coal in boiler No. 4 (EQUI 013); however, the Permittee was not authorized to combust coal. The facility ceased burning coal in EQUI 013 in 1997. In 2009 the MPCA submitted an applicability determination to EPA Region V requesting concurrence that resuming coal combustion in EQUI 013 would constitute a change in method of operation that could be subject to PSD review if it resulted in a significant net emission increase. EPA agreed that the fuel switch qualified as a change in method of operation because the source was not continuously capable of accommodating the alternative fuel because, among other things, the coal bucket elevator had been removed. The determination letter is Attachment 3 to this TSD. The limits and monitoring requirements contained in permit 01500010‐009 were not in effect if and until the Permittee began combusting coal in boiler No. 4. However, the EPA determination made it clear that the Permittee could not resume combustion of coal without a major amendment and a PSD applicability analysis. Additionally, notwithstanding any PSD requirements, or limits to avoid PSD, permit 0150010‐009 did not contain all applicable requirements for the combustion of coal in boiler No. 4 (e.g. the permit did not contain 40 CFR pt. 63, subp. JJJJJJ requirements nor did it contain the appropriate monitoring or recordkeeping requirements for control equipment associated with the boiler.) Because the facility is not currently authorized to burn coal and would not be authorized if and until a major amendment was issued and a PSD analysis was completed and because any limits and monitoring requirements would undoubtedly be substantially changed it does not make sense to retain the requirements in the permit related to coal combustion. Therefore, the following requirements have been removed or changed:

COMs – the Permittee was only required to operate COMs if coal was combusted in boiler No. 4; therefore, all COMs requirements have been removed

Fugitive Dust Control Plan – The fugitive dust control plan only applied if coal was combusted in boiler No. 4. The fugitive control dust plan that was contained in Appendix C of permit 01500010‐009 and has been removed from this permit.

Control Equipment 003 (Fabric Filter) – The permit required the Permittee to install either a fabric filter (formerly CE 003) or an ESP and route emissions from boiler No. 4 to one of these pieces of control equipment prior to commencing combustion of coal. Neither piece of equipment has been installed. The fabric filter was removed from the permit (the ESP was never listed in the permit).

MN Standards of Performance Limits – Any limits, monitoring, recordkeeping, or reporting associated with coal combustion were removed

Coal usage limit to avoid major source status under 40 CFR pt. 63, subp. 63 – This limit and associated monitoring, recordkeeping and reporting was removed because it is not needed since the Permittee is not authorized to burn coal. The facility is a true area source under 40 CFR pt. 63, subp. 63 without authorization to burn coal.

CAM requirements – CAM applied to EQUI 013 only based on coal combustion. All CAM requirements were removed from TREA 002.

This permit requires that if the Permittee resumes combustion of coal the Permittee must first apply for and obtain a permit that requires operation of a continuous opacity monitor to monitor opacity from EQUI 013 and installation of either a fabric filter or ESP to control emissions from EQUI 013. These two requirements were included in the original Title V permit in response to opacity violations that occurred prior to 1997 when the facility was combusting coal. If the Permittee were to resume coal combustion in EQUI 013, a typical analysis of the applicable requirements for coal combustion would not necessarily result in the requirement to operate COMs and fabric filter/ESP. As such, these requirements are retained in the permit.

3.3 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.


For CAM, the Permittee submitted a CAM proposal as required by 40 CFR § 64.3. It can be found in Attachment 3 to this TSD. Further discussion of decisions about CAM can be found in Table 7. 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.

The kind of monitoring found on similar units elsewhere.

The table below summarizes the monitoring requirements associated with this amendment.

Table 7. Monitoring associated with units affected by the modification/permit amendment

Subject item*

Requirement (rule basis) Monitoring Discussion

EQUI 002 (Gas Turbine #7 (simple cycle))

SO2 ≤ 0.015 % by vol. @ 15 % O2 on a dry basis (NSPS subp. GG)

Fuel sulfur monitoring and recordkeeping

Monitoring associated with the NSPS standard is sufficient to ensure compliance with the limits.

NOx ≤75 ppm @ 15% O2 on a dry basis (NSPA subp. GG)

Continuous monitoring and recordkeeping of ratio of water to fuel fired, O&M plan, performance testing

Monitoring associated with the NSPS standard is sufficient to ensure compliance with the limits.

Fuel limited to distillate fuel oil (Minn. R. 7007.0800, subp. 2) Daily fuel records

On each day of operation, records are kept of the fuel type fired in the turbine

Fuel Usage ≤ 1.625648 mil gallons/yr (Title I Condition to avoid major modification)

Daily fuel usage records, monthly 12‐month rolling sum calculations

On each day of operation, the Permittee maintains records of the amount of fuel fired in the turbine using a fuel meter.

Power Production ≤ 28200 kW (8‐hr average) (Minn. R. 7017.2025, subp. 3)

Daily records of total kilowatts power produced during each 8‐hr period, daily records of operating time, daily calculations

On each day of operation, the Permittee maintains records of operating time and power production. On a daily basis, for each 8‐hr block period, the Permittee calculates the average hourly power production.

Requirement to hold allowances ≥ total NOx and total SO2 emissions for each control period (40 CFR pt. 97, supbs. AAAAA & DDDDD)

Hourly records of fuel type, heat input, and operation; calculations of SO2 and NOx emission; monitoring plan

Monitoring required by the Transport Rule is sufficient to ensure and demonstrate compliance with the requirements of the Transport Rule.


Subject item*

Requirement (rule basis) Monitoring Discussion

EQUI 012 (Boiler #2)

PM ≤ 0.60 lb/MMBtu Opacity ≤ 20% (Minn. R. 7011.0510) Fuel records

This unit only burns natural gas; therefore, the likelihood of violating either of the emission limits is very small. The Permittee can demonstrate that these units will continue to operate such that emissions are well below the emission limits by only burning natural gas. Since this is a permit condition, the semi‐annual deviations report will document any deviations from this condition. Design based PTE for each unit, using AP‐42, is 0.0072 compared to the rule limit of 0.60 lb/MMBtu.

NOx ≤ 39.0 tons/y (Title I Condition to avoid major modification)

Daily fuel records, monthly 12‐month rolling sum calcluations, performance tests

The Permittee is required to maintain daily records of fuel usage and to complete monthly calculations. After burner replacement, the calculation will be based on a site‐specific emission factor derived from performance testing. Performance tests are required every 60 months to verify the emission factor.

*Location of the requirement in the permit (e.g., EQUI, STRU, etc.).

3.4 Insignificant activities

New Ulm Public Utilities ‐ Municipal Power has several operations which are classified as insignificant activities under the MPCA’s permitting rules. These are listed in Appendix A to the permit. There are no changes to the insignificant activities as a result of this amendment.

3.5 Permit organization In general, the permit meets the MPCA Tempo Guidance for ordering and grouping of requirements. One area where this permit deviates slightly from Tempo guidance is in the use of appendices. While appendices are fully enforceable parts of the permit, in general, any requirement that the MPCA thinks should be electronically tracked (e.g., limits, submittals, etc.), should be in the Requirements table in Tempo. The main reason is that the appendices are word processing sections and are not part of the electronic tracking system. Violation of the appendices can be enforced, but the computer system will not automatically generate the necessary enforcement notices or documents. Staff must generate these. This permit uses an appendix to list the applicable monitoring scheme the Permittee uses under the Transport Rule. This appendix is a template provided by EPA that EPA has encouraged states to use in incorporating the Transport Rule requirements into Part 70 permits. Tempo cannot accommodate this template, and therefore it is attached to the permit as an appendix.

3.6 Comments received To be filled out upon the completion of the public comment period and the EPA review period. Public Notice Period: [start date] – [end date] EPA Review Period: [start date] – [end date]

3.7 Two‐Stage Issuance This permit will follow the 2‐stage issuance procedures. Under Minnesota’s air quality permitting program, construction permitting requirements and operating permitting requirements are both drafted during one permitting effort. Minnesota’s permitting rule allows the MPCA to separate the issuance of the construction provisions from the operation provisions under Minn. R. 7007.0750, subp. 7. In the two‐stage issuance process, Stage 1 refers to the issuance of the portions of the permit that relate to construction activities, including emission limits, restrictions on operations and the recordkeeping associated with that restriction, and requirements to demonstrate initial compliance. These conditions are marked with “[Stage 1]” in the permit. Stage 1 conditions are issued after the conclusion of the 30‐day public comments period and responding to and resolving any public comments. Stage 2, the remainder of the permit conditions, can be issued after EPA’s 45‐day review period and any comments from EPA are resolved.


4. Permit fee assessment

Attachment 4 to this TSD contains the MPCA’s assessment of Application and Additional Points used to determine the permit application fee for this permit action as required by Minn. R. 7002.0019. The permit action includes on permit application received after the effective date of the rule (July 1, 2009). The action does not include any changes or analysis subject to additional points fees.

5. Conclusion Based on the information provided by New Ulm Public Utilities ‐ Municipal Power the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 01500010‐101 and this TSD, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules.

Staff Members on Permit Team: Kelsey Suddard (permit engineer)

Cory Boeck (compliance) Sarah Sevcik (peer reviewer) Becki Olson (permit writing assistant) Laurie O’Brien (administrative support)

Attachments: 1. Calculations spreadsheets

2. Points calculator 3. EPA Applicability Determination on Coal Use at New Ulm Public Utilities

Attachment 1: Calculation Spreadsheets EU001

EU001, EQUI 010 Boiler #1

96 MMBtu/hour 96 MMBtu/hr (total) Fuels: Natural Gas 1028 MMBtu/mmcf as per 40 CFR Part 98, Table C-1

Fuel Consumption: Natural Gas 0.093385 mmcf/hour ((MMBtu/hr)/(MMBtu/mmcf))

CO2

N2O

CH4

Emission Factors 53.02 1.00E-04 1.00E-03 kg/mmBtu

PM PM10 PM2.5 SO2 NOX CO VOC Lead CO2 N2O CH4 CO2e Gas - AP42 1.4 7.6 7.6 7.6 0.6 100 84 5.5 0.0005 119,910 2.26E-01 2.26E+00 120,028 lb/mmcf 40 CFR Part 98 for GHG

Potential Emissions - Natural Gas Sample calculations for both Sample: 7.6 lb PM/mmcf x 0.093385 mmcf/hour = 0.71 lb PM/hour

criteria and HAP pollutants Sample: 0.71 lb PM/hour * 8760 hours/year /2000 lb/ton = 3.11 tons per year

PM 0.71

PM10

0.71 PM2.5

0.71 SO2

0.06 NOX

9.34 CO 7.84

VOC 0.51

Lead 0.00

CO2

11,198 N2O 0.02

CH4

0.21 CO2e

11,209

lb/hour 3.11 3.11 3.11 0.25 40.90 34.36 2.25 0.00 49,046 0.09 0.93 49,095 tpy

HAP Emissions

Emission Factors Gas (lb/mmcf)

Emissions

(lb/hr) Gas

tpy

Lim. Tpy 2-Methylnaphthalene Arsenic Benzene Cadmium Chromium Dichlorobenzene Fluoranthene Fluorene Formaldehyde Hexane Manganese Mercury Naphthalene Nickel Phenanathrene Pyrene Selenium Toluene

2.40E-05 2.00E-04 2.13E-03 1.10E-03 1.40E-03 1.20E-03 3.00E-06 2.80E-06 7.50E-02 1.80E+00 3.80E-04 2.60E-04 6.10E-04 2.10E-03 1.70E-05 5.00E-06 2.40E-05 3.40E-03

2.24E-06 1.87E-05 1.99E-04 1.03E-04 1.31E-04 1.12E-04 2.80E-07 2.61E-07 7.00E-03 1.68E-01 3.55E-05 2.43E-05 5.70E-05 1.96E-04 1.59E-06 4.67E-07 2.24E-06 3.18E-04



Total = 1.76E-01 7.72E-01 7.72E-01

EU002

EU002, EQUI 012 Boiler #2

99 mmBtu/hr

Fuels: Natural Gas Control: Cyclone 80% PM 60% PM10/PM2.5

1028 MMBtu/mmcf (40 CFR Part 98, Table C1) Fuel Consumption: Natural Gas 0.096304 mmcf/hour ((MMBtu/hr)/(MMBtu/mmcf))

843.6187 mmcf/yr unlimited CO2 N2O CH4

Emission Factors 53.02 1.00E-04 1.00E-03 kg/mmBtu

PM PM10 PM2.5 SO2 NOX CO VOC Lead CO2 N2O CH4 CO2e

Gas - AP42 1.4 7.6 7.6 7.6 0.6 100 84 5.5 0.0005 119,910 2.26E-01 2.26E+00 120,028 lb/mmcf 40 CFR Part 98 for GHG

Potential Emissions - Natural Gas Sample calculations for both Sample: 7.6 lb PM/mmcf x 0.103113 mmcf/hour = 0.78 lb PM/hour lb/hour

criteria and HAP pollutants Sample: 0.78 lb PM/hour * 8760 hours/year /2000 lb/ton = 3.43 tons/year


0.73 0.73 0.73 0.06 9.63 8.09 0.53 4.82E-05 11,548 0 0 11,559 lb/hour - uncontrolled 0.15 0.29 0.29 0.06 9.63 8.09 0.53 4.82E-05 11,548 0.02 0.22 11,559 lb/hr - controlled

0.10 0.10 0.02 3.21 2.70 0.18 0.00 3849.25 0.01 0.07 3,853 lb/hr - only one burner working NSPS Increase 0.20 0.20 0.04 6.42 lb/hr

3.21 3.21 3.21 0.25 42.18 35.43 2.32 2.11E-04 50,579 0.10 0.95 50,629 tpy - uncontrolled 1.07 1.07 1.07 0.08 14.06 11.81 0.77 0.00 16859.72 0.03 0.32 16,876 tpy -one existing burner working 0.64 1.28 1.28 0.25 42.18 35.43 2.32 2.11E-04 50,579 0.10 0.95 50,629 tpy - controlled

Limited PTE 0.59 1.19 1.19 0.23 39.00 32.76 2.15 1.95E-04 46764.91 0.09 0.88 46,811 tpy - with synthetic minor limits

Emission Factors Gas Emissions Gas (lb/mmcf) (lb/hr) tpy synthetic minor limits

2-Methylnaphthalene 2.40E-05 2.31E-06 1.01E-05 9.36E-06 Arsenic 2.00E-04 1.93E-05 8.44E-05 7.80E-05 Benzene 2.13E-03 2.05E-04 8.98E-04 8.31E-04 Cadmium 1.10E-03 1.06E-04 4.64E-04 4.29E-04 Chromium 1.40E-03 1.35E-04 5.91E-04 5.46E-04 Dichlorobenzene 1.20E-03 1.16E-04 5.06E-04 4.68E-04 Fluoranthene 3.00E-06 2.89E-07 1.27E-06 1.17E-06 Fluorene 2.80E-06 2.70E-07 1.18E-06 1.09E-06 Formaldehyde 7.50E-02 7.22E-03 3.16E-02 2.93E-02 Hexane 1.80E+00 1.73E-01 7.59E-01 7.02E-01 Manganese 3.80E-04 3.66E-05 1.60E-04 1.48E-04 Mercury 2.60E-04 2.50E-05 1.10E-04 1.01E-04 2.03E-01 lb/year Naphthalene 6.10E-04 5.87E-05 2.57E-04 2.38E-04 Nickel 2.10E-03 2.02E-04 8.86E-04 8.19E-04 Phenanathrene 1.70E-05 1.64E-06 7.17E-06 6.63E-06 Pyrene 5.00E-06 4.82E-07 2.11E-06 1.95E-06 Selenium 2.40E-05 2.31E-06 1.01E-05 9.36E-06 Toluene 3.40E-03

Total =

3.27E-04

1.82E-01

1.43E-03

7.96E-01

1.33E-03

7.36E-01

Calculation of Flue Gas Flow Rate

F Factor 10,610 wcfm/mmBtu Heat Input 99 mmBtu/hr Excess Air 20% Exhaust Temperature 320 F

Exhaust Flow 31,512 acfm

EU 003

EU 003, EQUI 013 Boiler #3

234 MMBtu/hour 234 MMBtu/hr (total) 2049840

Fuels: Natural Gas 1028 MMBtu/mmcf as per 40 CFR Part 98, Table C-1

Used Oil 138.00 MMBtu/mgal per 40 CFR pt. 98

Fuel Consumption:

828 MMBtu/yr Emission Factors

PM

PM10

PM2.5

SO2

NOX

CO

VOC

Lead

53.02 CO2

1.00E-04 N2O

1.00E-03 CH4

kg/mmBtu CO2e

Gas - AP42 1.4 7.6 7.6 7.6 0.6 100 84 5.5 0.0005 119,910 2.26E-01 2.26 120,028 lb/mmcf 40 CFR Part 98 for GHG 7.39E-03 7.39E-03 7.39E-03 5.84E-04 9.73E-02 8.17E-02 5.35E-03 4.86E-07 116.644 2.20E-04 2.20E-03 116.76 lb/MMBtu

Used Oil AP42 1.3 3.3 2.3 1.55 71 24 5 0.2 lb/mgal 1.63E+02 1.32E-03 0.01 163 lb/MMBtu

2.39E-02 1.67E-02 1.12E-02 5.14E-01 1.74E-01 3.62E-02 1.45E-03 lb/MMBtu

Control Cyclone 80% PM 60% PM10/2.5

Potential Emissions - Natural Gas Sample calculations for both Sample: 7.6 lb PM/mmcf x 0.227626 mmcf/hour = 1.73 lb PM/hour

criteria and HAP pollutants Sample: 1.73 lb PM/hour * 8760 hours/year /2000 lb/ton = 7.58 tons per year

PM PM10 PM2.5 SO2 NOX CO VOC Lead CO2 N2O CH4 CO2e 1.73 1.73 1.73 0.14 22.76 19.12 1.25 1.14E-04 27,295 0.05 0.51 27,321 lb/hour 7.58 7.58 7.58 0.60 99.70 83.75 5.48 4.99E-04 119,551 0.23 2.25 119,668 tpy 0.35 0.69 0.69 0.14 22.76 19.12 1.25 1.14E-04 27294.70 0.05 0.51 27321.47 lb/hour controlled 1.52 3.03 3.03 0.60 99.70 83.75 5.48 4.99E-04 119551 0.23 2.25 119668 tpy controlled

Potential Emissions - Waste Oil

PM

PM10

PM2.5

SO2

NOX

CO

VOC

Lead

CO2

N2O

CH4

CO2e

0.28 0.20 0.13 6.02 2.03 0.42 0.02 1903.73 0.02 0.08 1910.26 lb/hour

1.23 0.85 0.58 26.37 8.91 1.86 0.07 8338.34 0.07 0.34 8366.95 tpy

0.06 0.08 0.05 6.02 2.03 0.42 0.02 1903.73 0.02 0.08 1910.26 lb/hour controlled

0.00 0.00 0.00 0.21 0.07 0.02 0.00 67.36 5.46E-04 2.73E-03 67.59 tpy limited and controlled

Worst Case PM PM10 PM2.5 SO2 NOX CO VOC Lead CO2 N2O CH4 CO2e

0.38 0.74 0.71 6.15 23.66 19.12 1.25 4.99E-04 27833.69 0.06 0.57 27865.66 lb/hr controlled

1.52 3.03 3.03 0.81 99.73 83.75 5.48 4.99E-04 119569.84 0.23 2.26 119687.28 tpy limited and controlled

Natural Gas 0.227626 mmcf/hour ((MMBtu/hr)/(MMBtu/mmcf)) Maximum Used Oil 11.7 MMBtu/hr (5% of heat input)

0.084783 mgal/hr 6 mgal/yr CO2 N2O CH4

EU 003

HAP Emissions Emission Factors

Gas Emissions

Gas

(lb/mmcf) (lb/hr) tpy Lim. Tpy 2-Methylnaphthalene 2.40E-05 5.46E-06 2.39E-05 2.39E-05 Arsenic Benzene

2.00E-04 2.13E-03

4.55E-05 4.85E-04

1.99E-04 2.12E-03

1.99E-04 2.12E-03

Cadmium 1.10E-03 2.50E-04 1.10E-03 1.10E-03 Chromium 1.40E-03 3.19E-04 1.40E-03 1.40E-03 Dichlorobenzene 1.20E-03 2.73E-04 1.20E-03 1.20E-03 Fluoranthene 3.00E-06 6.83E-07 2.99E-06 2.99E-06 Fluorene 2.80E-06 6.37E-07 2.79E-06 2.79E-06 Formaldehyde 7.50E-02 1.71E-02 7.48E-02 7.48E-02 Hexane 1.80E+00 4.10E-01 1.79E+00 1.79E+00 Manganese 3.80E-04 8.65E-05 3.79E-04 3.79E-04 Mercury 2.60E-04 5.92E-05 2.59E-04 2.59E-04 Naphthalene 6.10E-04 1.39E-04 6.08E-04 6.08E-04 Nickel 2.10E-03 4.78E-04 2.09E-03 2.09E-03 Phenanathrene 1.70E-05 3.87E-06 1.69E-05 1.69E-05 Pyrene 5.00E-06 1.14E-06 4.99E-06 4.99E-06 Selenium 2.40E-05 5.46E-06 2.39E-05 2.39E-05 Toluene 3.40E-03 7.74E-04 3.39E-03 3.39E-03

Total = 4.30E-01 1.88E+00 1.88E+00

EU004

EU004, EQUI 011 Turbine #5 25 MW

352 MMBtu/hour Fuels: Distillate Oil Emission Factors

CO2

73.96 N2O

6.00E-04 CH4

3.00E-03 CO2e

74

kg/mmBtu

PM PM10 PM2.5 SO2 NOX CO VOC Lead CO2 N2O CH4 CO2e 0.012 0.012 0.012 0.505 0.88 0.0033 0.00041 1.40E-05 163 0.00132 0.0066 163 lb/MMBtu

Potential Emissions - Distillate Oil

Sample: 0.12 lb PM/MMBtu x 352 MMBtu/hour = 4.22 lb PM/hour Sample: 4.22 lb PM/hour x 8760 (hr/yr) x (ton/2000 lb) = 18.50 tons per year

PM PM10 PM2.5 SO2 NOX CO VOC Lead CO2 N2O CH4 CO2e 4.22 4.22 4.22 177.76 309.76 1.16 0.14 0 57,275 5.E-01 2.E+00 57,467 lb/hour 18.50 18.50 18.50 778.59 1356.75 5.09 0.63 0 250,863 2.E+00 1.E+01 251,707 tpy

HAP Emissions Sample: 5.5E-5 Benz/MMBtu x 352 MMBtu/hour = 1.94E-2 lb Benz./hour

Sample: 1.94E-2 Benz./hour x 8760 (hr/yr) x (ton/2000 lb) = 8.48E-2 tons per year Emission Factors Oil Emissions Oil (lb/MMBtu) (lb/hr) tpy Lim. Tpy Benzene 5.50E-05 1.94E-02 8.48E-02 8.48E-02 Formaldehyde 2.80E-04 9.86E-02 4.32E-01 4.32E-01 Napthalene 3.50E-05 1.23E-02 5.40E-02 5.40E-02 PAH 4.00E-05 1.41E-02 6.17E-02 6.17E-02 1,3-Butadiene 1.60E-05 5.63E-03 2.47E-02 2.47E-02 Arsenic 1.10E-05 3.87E-03 1.70E-02 1.70E-02 Beryllium 3.10E-07 1.09E-04 4.78E-04 4.78E-04 Cadmium 4.80E-06 1.69E-03 7.40E-03 7.40E-03 Chromium 1.10E-05 3.87E-03 1.70E-02 1.70E-02 Lead 1.40E-05 4.93E-03 2.16E-02 2.16E-02 Manganese 7.90E-04 2.78E-01 1.22E+00 1.22E+00 Mercury 1.20E-06 4.22E-04 1.85E-03 1.85E-03 Nickel 4.60E-06 1.62E-03 7.09E-03 7.09E-03 Selenium Total HAPS

2.50E-05 8.80E-03

4.53E-01

3.85E-02 1.99E+00

3.85E-02 1.99E+00

43.1 ppm @ 16.2 O2 - July 17, 2013 NOx test 1.19E-07 Conversion Factor of ppm Nox to lb/scf

9,190 dscf/10^6 Btu (Part 60 Appendices F Factor) 32,554 dscf/10^6 Btu @ 15% O2

2.10E-01 lb/mmBtu 54.10 ppm @ 15%02 15.00 %O2 3.54 flow rate percent of stoichiometric

EU005

EU005, EQUI 002 Turbine #7 26 MW

350 MMBtu/hour

Fuels: Distillate Oil

140 MMBtu/1000 gal (40 CFR Part 98, Table C-1)

2.5 mgal

1,625,648 gal/yr permit limited oil usage

1,625.65 1000 gallons/yr

227,590.72 MMBtu/yr

Emission Factors

CO2

73.96 N2O

6.00E-04 CH4

3.00E-03 CO2e

74

kg/mmBtu


0.012 0.012 0.012 0.3434 0.22 0.0033 0.00041 1.40E-05 163 0.00132 0.0066 163 lb/MMBtu

Calculation of Nox Emission Factor from test results

Potential Emissions - Distillate Oil Sample: 0.12 lb PM/MMBtu x 352 MMBtu/hour = 4.20 lb PM/hour Sample: 4.20 lb PM/hour x 8760 (hr/yr) x (ton/2000 lb) = 18.40 tons per year Sample: 0.12 lb PM/mmBtu x limited mmBtu/year x (ton/2000 lb) = 1.35 tons per year


4.20 4.20 4.20 120.19 77.00 1.16 0.14 0.00 56,949 0.4620 2.3100 57,141 lb/hour 18.40 18.40 18.40 526.43 337.26 5.06 0.63 0.02 249,437 2.0236 10.1178 250,277 tpy - unlimited 1.37 1.37 1.37 39.08 25.03 0.38 0.05 0.00 18,516 0.1502 0.7510 18,578 tpy - limited

HAP Emissions Sample: 5.5E-5 Benz/MMBtu x 350 MMBtu/hour = 1.93E-2 lb Benz./hour

Sample: 1.93E-2 Benz./hour x 8760 (hr/yr) x (ton/2000 lb) = 8.43E-2 tons per year Sample: 5.5E-5 Benz./mmBtu x 224,339 mmBtu/yr x (ton/2000 lb) = 6.169E-3 tpy

Emission Factors Oil Emissions

(lb/MMBtu) (lb/hr) tpy Lim. tpy Benzene 5.50E-05 1.93E-02 8.43E-02 0.006259 Formaldehyde 2.80E-04 9.80E-02 4.29E-01 0.031863 Napthalene 3.50E-05 1.23E-02 5.37E-02 0.003983 PAH 4.00E-05 1.40E-02 6.13E-02 0.004552 1,3-Butadiene 1.60E-05 5.60E-03 2.45E-02 0.001821 Arsenic 1.10E-05 3.85E-03 1.69E-02 0.001252 Beryllium 3.10E-07 1.09E-04 4.75E-04 3.53E-05 Cadmium 4.80E-06 1.68E-03 7.36E-03 0.000546 Chromium 1.10E-05 3.85E-03 1.69E-02 0.001252 Lead 1.40E-05 4.90E-03 2.15E-02 0.001593 Manganese 7.90E-04 2.77E-01 1.21E+00 0.089898 Mercury 1.20E-06 4.20E-04 1.84E-03 0.000137 Nickel 4.60E-06 1.61E-03 7.05E-03 0.000523 Selenium 2.50E-05 8.75E-03 3.83E-02 0.002845

Total HAPS 4.51E-01 1.97E+00 1.47E-01

EU005

Past CO2e Emissions - SO2 Emissions - Nox Emissions

CO2 Emission Factor = Distillate HHV = CH4 Emission Factor N2O Emission Factor

73.96 kg CO2/mmBtu 0.140 mmBtu/gal

3.00E-03 kg CH4/mmBtu 6.00E-04 kg N2O/mmBtu

40 CFR Part 98, Table C-1




2003 Heat Input = 2004 Heat Input = 2005 Heat Input = 2006 Heat Input = 2007 Heat Input = 2008 Heat Input = 2009 Heat Input = 2010 Heat Input = 2011 Heat Input = 2012 Heat Input = 2013 Heat Input = 2014 Heat Input =

15,795 mmBtu/yr 9,198 mmBtu/yr 2,260 mmBtu/yr 4,679 mmBtu/yr 2,637 mmBtu/yr

932 mmBtu/yr 699 mmBtu/yr

2,915 mmBtu/yr 1,226 mmBtu/yr 1,264 mmBtu/yr 9,148 mmBtu/yr 1,190 mmBtu/yr

2007 SO2 Emission = 2008 SO2 Emissions = 2009 SO2 Emissions = 2010 SO2 Emissions =

0.453 tons SO2 0.160 tons SO2 0.120 tons SO2 0.501 tons SO2

2011 SO2 Emissions = 2012 SO2 Emission = 2013 SO2 Emissions = 2014 SO2 Emissions =

0.211 tons SO2 0.217 tons SO2 1.571 tons SO2 0.204 tons SO2

2007 Nox Emissions = 2008 Nox Emissions = 2009 Nox Emissions 2010 Nox Emissions =

0.277 tons NOx 0.098 tons NOx 0.073 tons NOx 0.307 tons NOx

2011 Nox Emissions = 2012 Nox Emissions = 2013 Nox Emissions = 2014 Nox Emissions =

0.129 tons NOx 0.133 tons NOx 0.962 tons NOx 0.125 tons NOx

2015 First Quarter Fuel Flow

2003 Oil Use 112,820 gallons NOC SO2 2004 Oil Use = 65,701 gallons 2015 Qtr 1 Time start Time end Hour of the quarter Op Time mmBtu Emissions Emissions 2005 Oil Use = 16,141 gallons 1/26/2015 206 gal 10 11 610 0.088874286 31.106 0.018664 0.005288 2006 Oil Use = 33,423 gallons 3/26/2015 522 gal 10 11 2026 0.225205714 78.822 0.047293 0.0134 2007 Oil Use = 18,838 gallons A = 35 x 14 490

2008 Oil Use = 6,655 gallons 0.31408 2009 Oil Use = 4,992 gallons 2010 Oil Use = 20,824 gallons 2011 Oil Use = 8,760 gallons 2012 Oil Use = 9,028 gallons 2013 Oil Use = 65,340 gallons 2014 Oil Use = 8,500 gallons Turbine #7 Only

Attachment 2: Points Calculator

1) AI ID No.: 1865 Total Points 252) Facility Name: New Ulm Public Utilities - Municipal Power3) Small business? y/n? N 4) Air Project Tracking Numbers 5337 5) Date of each Application Received: 08/17/20156) Final Permit No. 01500010-1017) Permit Staff Kelsey Suddard

Total TotalApplication Type Air Project Tracking No. Tempo Activity ID Qty. Points Points Additionl Cost DetailsAdministrative Amendment 1 0 -$ M inor Amendment 4 0 -$ Applicability Request 10 0 -$ Moderate Amendment 15 0 -$ Major Amendment 5337 IND20150001 1 25 25 7,125.00$ Individual State Permit (not reissuance) 50 0 -$ Individual Part 70 Permit (not reissuance) 75 0 -$

Additional PointsModeling Review 15 0 -$

BACT Review 15 0 -$ LAER Review 15 0 -$ CAIR/Part 75 CEM analysis 10 0 -$ NSPS Review 10 0 -$ NESHAP Review 10 0 -$ Case-by-case MACT Review 20 0 -$ Netting 10 0 -$ Limits to remain below threshold 10 0 -$ Plantwide Applicability Limit (PAL) 20 0 -$ AERA review 15 0 -$ Variance request under 7000.7000 35 0 -$ Confidentiality request under 7000.1300 2 0 -$ EAW reviewPart 4410.4300, subparts 18, item A; and 29 15 0 -$ Part 4410.4300, subparts 8, items A & B; 10,

items A to C; 16, items A & D; 17, items A to C

& E to G; and 18, items B & C

35 0 -$

Part 4410.4300, subparts 4; 5 items A & B;

13; 15; 16, items B & C; and 17 item D

70 0 -$

Add'l Points 0

NOTES:

Attachment 3: EPA Applicability Determination on Coal Use at New Ulm Public Utilities

For DRAFT Air Emission Permit No. 01500010 101

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