AIR EMISSION PERMIT NO. 05301050-021 [AMENDMENT TO AIR

AIR EMISSION PERMIT NO. 05301050-021

[AMENDMENT TO AIR EMISSION PERMIT NO. 05301050-011]

IS ISSUED TO

THE UNIVERSITY OF MINNESOTA AND

FOSTER WHEELER TWIN CITIES, INC.

FOR THE UNIVERSITY OF MINNESOTA TWIN CITIES

SOUTHEAST STEAM PLANT 600 Main Street Southeast

Minneapolis, Hennepin County, MN 55455 The emission units, control equipment and emission stacks at the stationary source authorized in this permit are as described in the following permit application(s): Permit Type Initial Application Date Permit Issuance Date Installation and Operation Permit* 8/1/94 10/28/96 Modification and Operation Permit 3/17/97 1/25/99 Major Permit Amendment 4/8/04 See below * superseded by Air Emission Permit No. 05301050-011 issued on 1/25/99 This permit authorizes the Permittee to modify and operate the stationary source at the address listed above unless otherwise noted in Table A. The Permittee must comply with all the conditions of the permit. Any changes or modifications to the stationary source must be performed in compliance with Minn. R. 7007.1150 to 7007.1500. Terms used in the permit are as defined in the state air pollution control rules unless the term is explicitly defined in the permit.

Permit Type: State (Part 70 permit pending)/Limits to avoid NSR

Issue Date: February 14, 2006

Expiration: Upon issuance of the Part 70 permit All Title I Conditions do not expire Richard J. Sandberg, Manager Air Quality Permits Section Industrial Division for Sheryl A. Corrigan

Commissioner Minnesota Pollution Control Agency

TABLE OF CONTENTS

Overview Notice to the Permittee Permit Shield Facility Description Table A: Limits and Other Requirements (amended pages only) Table B: Submittals (amended pages only)

OVERVIEW: This permit action (Air Emission Permit No. 05301050-021) is an amendment to the existing modification and operation permit (Air Emission Permit No. 05301050-011) issued on January 25, 1999, for the Southeast Steam Plant and St. Paul Steam Plant at the University of Minnesota Twin Cities. This permit action only affects operations at the Southeast Steam Plant and will remain in effect until the Part 70 permit for the University of Minnesota Twin Cities is issued. NOTICE TO THE PERMITTEE: Your stationary source may be subject to the requirements of the Minnesota Pollution Control Agency’s (MPCA) solid waste, hazardous waste, and water quality programs. If you wish to obtain information on these programs, including information on obtaining any required permits, please contact the MPCA general information number at: Metro Area (651) 296-6300 Outside Metro Area 1-800-657-3864 TTY (651) 282-5332 The rules governing these programs are contained in Minn. R. chs. 7000-7105. Written questions may be sent to: Minnesota Pollution Control Agency, 520 Lafayette Road North, St. Paul, Minnesota 55155-4194. Questions about this air emission permit or about air quality requirements can also be directed to the telephone numbers and address listed above. PERMIT SHIELD: Subject to the limitations in Minn. R. 7007.1800, compliance with the conditions of this permit shall be deemed compliance with the specific provision of the applicable requirement identified in the permit as the basis of each condition. Subject to the limitations of Minn. R. 7007.1800 and 7017.0100, subp. 2, notwithstanding the conditions of this permit specifying compliance practices for applicable requirements, any person (including the Permittee) may also use other credible evidence to establish compliance or noncompliance with applicable requirements.

FACILITY DESCRIPTION: The University of Minnesota Twin Cities owns two facilities for generating steam and electricity that are operated by Foster Wheeler Twin Cities, Inc. - the Southeast Steam Plant and the St. Paul Steam Plant. This permit action only affects the Southeast Steam Plant. The primary source of air emissions at the Southeast Steam Plant is five boilers – a circulating fluidized bed (CFB) boiler (EU 001) burning coal, wood, natural gas, and oil; two package boilers (EU 002 and EU 003) burning oil and natural gas; and two coal-fired boilers (EU 004 and EU 005) burning coal and oil. Air emissions are also generated with the handling of fuels and other materials (i.e., limestone, lime, sand, and ash) at the plant. Air emissions from the boilers are a result of fuel combustion and include particulate matter (PM and PM10), nitrogen oxides (NOx), sulfur dioxide (SO2), carbon monoxide (CO), and volatile organic compounds (VOC). PM/PM10 emissions are controlled with baghouse fabric filters at the CFB boiler and coal-fired boilers. SO2 emissions are controlled with limestone in the combustion chamber of the CFB boiler, with fuel oil sulfur content limits on the package boilers, and with lime injection (i.e., dry scrubbers) at the coal-fired boilers. PM/PM10 emissions from the fuel and material handling are controlled with enclosures and fabric filters. DESCRIPTION OF CHANGES (05301050-021): The Southeast Steam Plant and the St. Paul Steam plant currently operate under Air Emission Permit No. 05301050-011, issued on January 25, 1999. Two amendments to the permit in 2003 authorized the University of Minnesota to conduct limited test burns of oat hulls in the CFB boiler to determine the technical feasibility of handling, storing, and burning the fuel on a permanent basis and to measure the resulting air emissions. As a result of the testing, the University of Minnesota has concluded that oat hulls are a viable fuel and submitted a major permit amendment application on April 8, 2004, to make changes to Air Emission Permit No. 05301050-011. This permit action:

1) authorizes the handling of oat hulls in the existing coal handling equipment and the burning of oat hulls in EU 001 and EU 005;

2) authorizes a new biomass truck unloading station, silo, and handling system;

3) requires performance testing of EU 001 with the new fuel handling system;

4) requires performance testing of EU 005 within 60 days of firing oat hulls in the unit;

5) authorizes limited performance test burns of new biomass fuels in EU 001 and EU 005;

6) adds oat hulls and other biomass that may be approved in the future to the list of fuels that may satisfy the existing 70 percent total heat input requirement on steam generators; and

7) allows the use of an emission factor for calculating actual hydrogen chloride (HCl) emissions from EU001.

Permit No. 05301050-021 Amendment to Permit No. 05301050-011

Page 9a of 77 Subject Item: Total Facility General Requirements applicable to all facilities

What to do Why to do it

Comply with Fugitive Emission Control Plan: The Permittee shall follow the actions and recordkeeping specified in the control plan received by the Commissioner on December 23, 1996 and amended by Permit Application Form GI-05D Fugitive Emission Source Information received by the Commissioner on April 8, 2004. The plan may be amended by the Permittee with the Commissioner’s approval. If the Commissioner determines that the Permittee is out of compliance with Minn. R. 7011.0150 or the fugitive control plan, the Permittee may be required to amend the control plan and/or install and operate particulate matter ambient monitors as requested by the Commissioner.

Minn. Stat. § 116.07, subd. 4a; Minn. R. 7007.0800, subp. 2

The Permittee shall monitor the actual emissions of any regulated NSR pollutant that could increase as a result of a project that was analyzed using the baseline actual to projected actual emissions test, and the potential emissions of any regulated NSR pollutant that could increase as a result of the project and that was analyzed using potential emissions. The Permittee shall calculate and maintain a record of the sum of the actual and potential (if used in the analysis) emissions of the regulated pollutant, in tons per year on a calendar year basis, for a period of 5 years following resumption of regular operations after the change, or for a period of 10 years following resumption of regular operations after the change if the project increases the design capacity of or potential to emit of any unit associated with the project.

Title I Condition: 40 CFR § 52.21(r)(6) and Minn. R. 7007.3000; Minn. R. 7007.0800, subp. 4 & 5

The Permittee must submit a report to the Agency if the annual summed (actual plus potential, if applicable) emissions differ from the preconstruction projection and exceed the baseline actual emissions by a significant amount as listed at 40 CFR § 52.21(b)(23). Such report shall be submitted to the Agency within 60 days after the end of the year in which the exceedances occur. The report shall contain: a. The name and ID number of the facility, and the name and telephone number of the facility contact person b. The annual emissions (actual plus potential, if any part of the project was analyzed using potential emissions) for each pollutant for which the preconstruction projection and significant emissions increase are exceeded. c. Any other information, such as an explanation as to why the summed emissions differ from the preconstruction projection.

Title I Condition: 40 CFR § 52.21(r)(6) and Minn. R. 7007.3000; Minn. R. 7007.0800, subp. 4 & 5


Page 10a of 77

What to do Why to do it Inapplicable Requirement: Standards of Performance for Commercial and Industrial Solid Waste Incineration (CISWI) Units applies to CISWI Units which are defined as any combustion device that combusts commercial and industrial waste. Commercial and industrial waste is further defined as solid waste combusted without energy recovery. Since all combustion devices at the facility (i.e., boilers) include energy recovery, this subpart does not apply.

Minn. R. 7007.1800, subp. (A)(2); 40 CFR pt. 60, subp. CCCC

Inapplicable Requirement: Standards of Performance for Waste Combustors does not apply because oat hulls and the other types of biomass for which the facility may conduct test burns are not “solid waste” under Minn. Stat. §116.06, subd. 22.

Minn. R. 7007.1800, subp. (A)(2); Minn. R. 7007.1201


Page 12a of 77

Subject Item: Control Equipment

Low-temperature fabric filters

Associated Items:

Coal handling and miscellaneous material handling operations

What to do Why to do it Total Particulate Matter: greater than or equal to 99% control efficiency. The Permittee shall operate and maintain the control equipment such that it achieves an overall control efficiency for PM of 99%. This limit applies to each unit individually.

Title I Condition: to avoid classification as a major modification under 40 CFR § 52.21; Minn. R. 7007.3000

Particulate Matter < 10 micron: greater than or equal to 99% control efficiency. The Permittee shall operate and maintain the control equipment such that it achieves an overall control efficiency for PM10 of 99%. This limit applies to each unit individually.


Pressure Drop: greater than or equal to 2 inches of water column and less than or equal to 6 inches of water column , unless a new range is set pursuant to Minn. R. 7017.2025, subp. 3, based on the values recorded during the most recent MPCA approved performance test where compliance was demonstrated.


Visible Emissions: The Permittee shall check the associated fabric filter stacks for any visible emissions once each day of operation during daylight hours. During inclement weather, the Permittee shall read and record the pressure drop across the fabric filter, once each day of operation.

Title I Condition: Monitoring for Limit taken to avoid classification as a major modification under 40 CFR § 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subp. 4 and 5

Recordkeeping of Visible Emissions and Pressure Drop. The Permittee shall record the time and date of each visible emission inspection and pressure drop reading, and whether or not any visible emissions were observed, and whether or not the observed pressure drop was within the range specified in this permit.

Title I Condition: Monitoring for Limit taken to avoid classification as a major modification under 40 CFR § 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subp. 4 and 5

The Permittee shall operate and maintain the fabric filter at all times that any emission unit controlled by the fabric filter is in operation. The Permittee shall document periods of non-operation of the control equipment.

Title I Condition: Limit taken to avoid classification as a major modification under 40 CFR § 52.21; Minn. R. 7007.3000; Minn. R. 7007.0800, subp. 2 and 14


Page 12b of 77

Corrective Actions: The Permittee shall take corrective action as soon as possible if any of the following occur: - visible emissions are observed; - the recorded pressure drop is outside the required operating range; or - the fabric filter or any of its components are found during the inspections to need repair. Corrective actions shall return the pressure drop to within the permitted range, eliminate visible emissions, and/or include completion of necessary repairs identified during the inspection, as applicable. Corrective actions include, but are not limited to, those outlined in the O & M Plan for the fabric filter. The Permittee shall keep a record of the type and date of any corrective action taken for each filter.

Minn. R. 7007.0800, subp. 4, 5, and 14

Periodic Inspections: At least once per calendar quarter, or more frequently as required by the manufacturing specifications, the Permittee shall inspect the control equipment components. The Permittee shall maintain a written record of these inspections.

Minn. R. 7007.0800, subp. 4, 5 and 14

The Permittee shall operate and maintain the fabric filter in accordance with the Operation and Maintenance (O & M) Plan. The Permittee shall keep copies of the O & M Plan available onsite for use by staff and MPCA staff.

Minn. R. 7007.0800, subp. 14


Page 17 or 77 Subject Item: EU001 Circulating Fluidized Bed (CFB) boiler (Db boiler)

265.32 MMBtu/hr for bituminous coal, subbituminous coal, wood mixed with coal, and natural gas, approved biomass, approved biomass mixed with coal, approved biomass mixed with natural gas; 40 MMBtu/hr on No. 2 fuel oil for startup

Associated Items:

Control Equipment SV001

Baghouse fabric filter


Record keeping: Maintain records of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the facility; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative

40 CFR § 60.7(b)

Record Keeping: maintain records of the type and amount of each fuel combusted each day; calculate the annual capacity factor for each fuel for each calendar quarter. Annual capacity factor is calculated on a 12-month rolling average basis at the end of each calendar month

40 CFR § 60.49b(d)

Approved biomass includes wood (as limited below) and oat hulls. Alternative biomass may be fired during test burns in compliance with all permit conditions.

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

Treated wood and wood waste materials prohibited as fuel: No wood or wood waste which meets the definition of hazardous waste may be used as fuel.

Minn. R. 7007.0800, subp. 2

Total PM: less than or equal to 0.1. lb/MMBtu for all fuels and fuel combinations

40 CFR § 60.43b(a)(2)

Annual Capacity Factor for Fuels Other Than Coal: greater than 10%. Annual Capacity Factor shall be calculated as defined in 40 CFR pt. 60, subp. Db

40 CFR § 60.43b(a)(2) 40 CFR § 60.41b

Opacity: less than or equal to 20% opacity as a 6-minute average except for one 6-minute period per house of not more than 27% opacity

40 CFR § 60.43b(f)

Opacity CEMS: The owner or operator shall install, calibrate, maintain and operate a continuous opacity monitoring system (COMS)

40 CFR § 60.48b(a)

The PM and opacity standards apply at all time, except during periods of startup, shutdown or malfunctions.

40 CFR § 60.43b(g)

Initial Performance Test: due 180 days after initial start-up with testing to be completed within 60 days after achieving the maximum production rate at which the affected facility will be operated to measure PM and opacity emissions in accordance with the procedures in 40 CFR § 60.46b(d)

40 CFR 60.8(a)

Performance Test Pre-test Meeting: due 7 days before Initial Performance Test

Minn. R. 7017.2030, subp. 4


Page 17a or 77

What to do Why to do it Oat Hull Performance Test: due 60 days after achieving the maximum oat hull firing rate, but no later than 180 days after initial startup of the biomass truck unloading station, biomass storage silo, and biomass transfer system to measure CO, PM, PM10, VOC, HCl, and hexane emissions, to monitor NOx and SO2 emissions, and to determine fuel chlorine content for calculating HCl control efficiency.

Minn. R. 7017.2020, subp. 1

Oat Hull Performance Test Notification and Submittals; Performance Test Notification (written): due 30 days before Performance Test Performance Test Plan: due 30 days before Performance Test Performance Test Pre-Test Meeting: due 7 day before Performance Test Performance Test Report: due 45 days after Performance Test Performance Test Report - Microfiche Copy or CD: due 105 days after Performance Test. The Notification, Test Plan, and Test Report may be submitted in alternative format as allowed by Minn. R. 7017.2018.

Minn. R. 7017.2030, subp. 1-4; Minn. R. 7017.2018 and Minn. R. 7017.2035, subp. 1-2

Revised PSD Analysis based on Oat Hull Performance Test: Within 60 days of submitting the Oat Hull Performance Test Report, the Permittee shall perform a revised PSD analysis based on the results of the performance test. If the results of the analysis continue to demonstrate that projected actual emission do not exceed baseline actual emissions for any regulated NSR pollutant by a significant amount, the Permittee may burn oat hulls up to the tested rate and shall maintain records of the revised PSD analysis. If the results of the analysis demonstrate that a significant emissions increase would occur, the Permittee may not operate the biomass truck unloading station, biomass storage silo, and biomass transfer system without obtaining a permit amendment in compliance with Minn. R. 7007.1150 through Minn. R. 7007.1500.

Title I Condition: Limit to avoid major modification under 40 CFR § 52.21; Minn. R. 7007.1150 through Minn. R. 7007.1500

Alternative Biomass Fuel Testing Authorization: The Permittee is authorized to conduct test burns of the following alternative biomass fuels: agricultural crops; herbs, nuts, by-products or waste; vegetable oils, by-products or waste; crop field residue or field processing by-products; shells, husks, seed, dust, screenings and other agricultural by-products; cultivated grasses or grass by-products; wood, wood waste including wood processing by-products; and leaves. Acceptable biomass fuels do not include peat, wood that has been painted, stained or pressure treated, waste oil, farm chemicals, pesticide containers, demolition waste except for wood, waste from farms from an open dump, tire derived fuels, non-agricultural industrial process wastes, animal manures and wastes, or any material meeting the definition of a hazardous waste.

Minn R. 7007.0800, subp. 2


Page 17b of 77 Alternative Biomass Fuel Testing Restrictions: Test burns for any potential biomass fuel shall be limited to 4,000 tons, no more than 45 days of operation using the fuel, and a test period not to exceed 180 days.

Minn R. 7007.0800, subp. 2

Alternative Biomass Fuel Testing Requirements: Test burns shall be conducted to measure CO, PM, PM10, VOC, HCl, and hexane emissions, to monitor NOx and SO2 emissions, and to determine fuel chlorine content for calculating HCl control efficiency.

Minn R. 7007.0800, subp. 2

Alternative Biomass Fuel Testing Submittals: 30 days prior to testing of a biomass fuel, the Permittee shall submit a written performance test notification and test plan. The test plan shall meet the requirements of Minn. R. 7017.2030 and shall also include the type(s) and estimated amount of biomass to be tested, 2) operating parameters and anticipated fuel mixes during testing for the boiler to be tested, 3) air pollutants that will be monitored and measured during testing, and 4) a testing schedule.

Minn. R. 7017.2030, subp. 1-4; Minn. R. 7017.2018

Alternative Biomass Fuel Testing Notification and Submittals; Pre-Test Meeting: due 7 day before Performance Test Test Report: due 45 days after Performance Test Test Report - Microfiche Copy or CD: due 105 days after Performance Test. The Notification, Test Plan, and Test Report may be submitted in alternative format as allowed by Minn. R. 7017.2018.



Page 19 of 77 Nitrogen Oxides expressed as NO2: less than or equal to 0.200 lb/MMBtu (which is equivalent to 53.06 lb/hr at manufacture’s rated capacity) when combusting only natural gas or only fuel oil as determined by a CEMS as a 30-day rolling average.

40 CFR § 60.44b(a)(1) 40 CFR § 60.44b(a)(2) 40 CFR §60.46b(e)(3)

Nitrogen Oxides: Emission rate shall be determined by the NOx CEMS as a 30-day rolling average

40 CFR § 60.44b(i)

Nitrogen Oxides: less than or equal to the amount allowed by the following formula when the facility simultaneously combusts coal, oil and/or natural gas or if the facility simultaneously combusts coal or oil, or a mixture of these fuels, with natural gas, and wood approved biomass: En = [(ELgo x Hgo)+(Elc x Hc)] / (Hgo+Hc) Where: ] En = the NOx emission limit in lb/MMBtu Elgo = the emission limit for natural gas or fuel oil in lb/MMBtu Hgo = the total heat input from natural gas or fuel oil, MMbtu/hr ELc = the emission limit for coal in lb/MMBtu Hc = the total heat input from coal, MMBtu/hr

40 CFR § 60.44b(b) 40 CFR § 60.44b(c)

Initial Performance Test for Nitrogen Oxides: due 180 days after initial start-up with testing to completed within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not to exceed 180 days from initial start-up to determine the Nitrogen Oxides (expressed as NOx) emission rate in accordance with the procedures in 40 CFR § 60.46b(e)

40 CFR § 60.8

Performance Test Pre-Test Meeting: due 7 days before Initial Performance Test.

Minn. R. 7017.2030, subp. 4

Nitrogen Oxides CEMS: the owner or operator shall install, calibrate, maintain, and operate a continuous monitoring system for measuring NOx

40 CFR § 60.48b(b)


Page 23 of 77 Subject Item: EU005 SE No. 4 spreader stoker boiler 187 MMBtu/hr on

all fuels subbituminous coal, No. 2 fuel oil, and approved biomass mixed with coal

Associated Items: Control Equipment

SV004 Dry scrubber and baghouse


Approved biomass includes oat hulls. Alternative biomass may be fired during test burns in compliance with all permit conditions

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

Combustion of EDTA-type boiler cleaning agents is authorized provided the cleaning agents are generated on-site and provide less than 5% of heat input to the emission unit per hour.

Minn. Stat. § 116.07, subp. 4a; Minn. R. 7007.0800, subp. 2

Total PM: less than or equal to 0.1 lb/MMBtu Minn. R. 7007.0800, subp. 2

Opacity: less than or equal to 20 % opacity, except for one 6-minute period per hour of not ore than 33%

Minn. R. 7007.0800, subp. 2

Opacity CEMS: Maintain and operate a COMS Minn. R. 7017.1000, subp. 1

Sulfur Dioxide: less than or equal to the amount allowed by the following formula when the facility simultaneously combusts coal and/or oil with or without approved biomass: Es = [Elo x Ho)+(Elc x Hc)] / (Ho+Hc) Where: Es = the SO2 emission limit in Lb/MMBtu ELo = the emission limit for fuel oil Ho = the total heat input from fuel oil, MMBtu/hr ELc = the emission limit for coal Hc = the total heat input from coal

Minn. R. 7011.0505, subp. 3


Page 23a of 77 Oat Hull Performance Test: due 60 days after achieving the maximum oat hull firing rate, but no later than 180 days after initial firing of oat hulls to measure CO, NOx, PM, PM10, VOC, HCl, and hexane emissions, to monitor SO2 emissions, and to determine fuel chlorine content for calculating HCl control efficiency

Minn. R. 7017.2020, subp. 1

Oat Hull Performance Test Notification and Submittals; Performance Test Notification (written): due 30 days before Performance Test Performance Test Plan: due 30 days before Performance Test Performance Test Pre-Test Meeting: due 7 day before Performance Test Performance Test Report: due 45 days after Performance Test Performance Test Report - Microfiche Copy or CD: due 105 days after Performance Test. The Notification, Test Plan, and Test Report may be submitted in alternative format as allowed by Minn. R. 7017.2018.


Revised PSD Analysis based on Oat Hull Performance Test: Within 60 days of submitting the Oat Hull Performance Test Report, the Permittee shall perform a revised PSD analysis based on the results of the performance test. If the results of the analysis continue to demonstrate that projected actual emission do not exceed baseline actual emissions for any regulated NSR pollutant by a significant amount, the Permittee may burn oat hulls up to the tested rate and shall maintain records of the revised PSD analysis. If the results of the analysis demonstrate that a significant emissions increase would occur, the Permittee may not fire oat hulls in EU005 without obtaining a permit amendment in compliance with Minn. R. 7007.1150 through Minn. R. 7007.1500.

Title I Condition: Limit to avoid major modification under 40 CFR § 52.21; Minn. R. 7007.1150 through Minn. R. 7007.1500

Alternative Biomass Fuel Testing Authorization: Permittee is authorized to conduct test burns of the following alternative biomass fuels: agricultural crops; herbs, nuts, by-products or waste; vegetable oils, by-products or waste; crop field residue or field processing by-products; shells, husks, seed, dust, screenings and other agricultural by-products; cultivated grasses or grass by-products; wood, wood waste including wood processing by-products; and leaves. Acceptable biomass fuels do not include peat, wood that has been painted, stained or pressure treated, waste oil, farm chemicals, pesticide containers, demolition waste except for wood, waste from farms from an open dump, tire derived fuels, non-agricultural industrial process wastes, animal manures and wastes, or any material meeting the definition of a hazardous waste.

Minn R. 7007.0800, subp. 2


Page 23b of 77 Alternative Biomass Fuel Testing Restrictions: Test burns for any potential biomass fuel shall be limited to 4,000 tons, no more than 45 days of operation using the fuel, and a test period not to exceed 180 days.

Minn R. 7007.0800, subp. 2

Alternative Biomass Fuel Testing Requirements: Test burns shall be conducted to measure CO, NOx, PM, PM10, VOC, HCl, and hexane emissions, to monitor SO2 emissions, and to determine fuel chlorine content for determining HCl control efficiency.

Minn R. 7007.0800, subp. 2

Alternative Biomass Fuel Testing Submittals: 30 days prior to testing of a biomass fuel, the Permittee shall submit a written performance test notification and test plan. The test plan shall meet the requirements of Minn. R. 701.2030 and shall also include 1) the type(s) and estimated amount of biomass to be tested, 2) operating parameters and anticipated fuel mixes during testing for the boiler to be tested, 3) air pollutants that will be monitored and measured during testing, and 4) a testing schedule.

Minn. R. 7017.2030, subp. 1-4; Minn. R. 7017.2018

Alternative Biomass Fuel Testing Notification and Submittals; Pre-Test Meeting: due 7 day before Performance Test Test Report: due 45 days after Performance Test Test Report - Microfiche Copy or CD: due 105 days after Performance Test. The Notification, Test Plan, and Test Report may be submitted in alternative format as allowed by Minn. R. 7017.2018.



Page 38 of 77 Subject Item: Emission Unit Minneapolis, Southeast coal and biomass

conveyor from stockpile and inside bunkers Associated Items: Control Equipment

(VSE1, VSE2)


Total PM: less than or equal to 0.020 grain/dry standard cubic foot Minn. R. 7011.1105, subp. G (1)

Opacity: less than or equal to 20% opacity Minn. R. 7011.1105, subp. G(2)

Subject Item: Emission Unit CFB coal and biomass bins Associated Items: Control Equipment

(VSE3, VSE4)


Total PM: less than or equal to 0.020 grain/dry standard cubic foot Minn. R. 7011.1105, subp. G (1)

Opacity: less than or equal to 20% opacity Minn. R. 7011.1105, subp. G(2)


Page 38a of 77 Subject Item: Emission Unit Minneapolis, Southeast biomass truck

unloading Associated Items: Control Equipment

Fabric Filter (VSE12)


Notification of Commence Construction Date and Initial Startup Date: due 30 days after initial startup. The Permittee shall submit the following information with the notification: stack/vent, control equipment, and emissions unit information using the latest MPCA application forms.

Minn. R. 7007.0800, subp. 2

The Permittee shall clean up commodities (i.e., biomass) spilled on the driveway and other facility property as required to minimize fugitive emissions to a level consistent with RACT (reasonably available control technology).

Minn. R. 7011.1005, subp. 1(A)

Opacity: less than or equal to 10% opacity discharged from control equipment.

Minn. R. 7011.1005, subp. 3(D)

Total Particulate Matter: greater than or equal to 80% collection efficiency

Minn. R. 7011.1005, subp. 3(E)

Opacity: less than or equal to 5% opacity from truck unloading stations, railcar unloading stations, railcar loading stations, and handling operation fugitive emissions.

Minn. R. 7011.1005, subp. 3(A)

Visible Emissions: The Permittee shall check the fabric filter for any visible emissions once each day of operation during daylight hours. During inclement weather, the Permittee shall read and record the pressure drop across the fabric filter, once each day of operation.

Minn. R. 7007.0800, subp. 4 and 5

Recordkeeping of Visible Emissions and Pressure Drop. The Permittee shall record the time and date of each visible emission inspection and pressure drop reading, and whether or not any visible emissions were observed.

Minn. R. 7007.0800, subp. 4 and 5


Minn. R. 7007.0800, subp. 2 and 14


Minn. R. 7007.0800, subp. 4, 5 and 14


Page 38b of 77 Subject Item: Emission Unit Minneapolis, Southeast biomass silo and

biomass transfer to CFB Associated Items: Control Equipment

Fabric Filter (VSE13)


Notification of Commence Construction Date and Initial Startup Date: due 30 days after initial startup. The Permittee shall submit the following information with the notification: stack/vent, control equipment, and emissions unit information using the latest MPCA application forms.

Minn. R. 7007.0800, subp. 2

The Permittee shall clean up commodities (i.e., biomass) spilled on the driveway and other facility property as required to minimize fugitive emissions to a level consistent with RACT (reasonably available control technology).

Minn. R. 7011.1005, subp. 1(A)

Opacity: less than or equal to 10% opacity discharged from control equipment.

Minn. R. 7011.1005, subp. 3(D)

Total Particulate Matter: greater than or equal to 80% collection efficiency

Minn. R. 7011.1005, subp. 3(E)

Opacity: less than or equal to 5% opacity from truck unloading stations, railcar unloading stations, railcar loading stations, and handling operation fugitive emissions.

Minn. R. 7011.1005, subp. 3(A)

Visible Emissions: The Permittee shall check the fabric filter for any visible emissions once each day of operation during daylight hours. During inclement weather, the Permittee shall read and record the pressure drop across the fabric filter, once each day of operation.

Minn. R. 7007.0800, subp. 4 and 5

Recordkeeping of Visible Emissions and Pressure Drop. The Permittee shall record the time and date of each visible emission inspection and pressure drop reading, and whether or not any visible emissions were observed.

Minn. R. 7007.0800, subp. 4 and 5


Minn. R. 7007.0800, subp. 2 and 14


Minn. R. 7007.0800, subp. 4, 5 and 14


Page 45 of 77 Subject Item: Fugitive

Source Minneapolis Main ash truck loading and handling

Associated Items:

What to do Why to do it Fugitive PM: greater than or equal to 20% by weight water content of ash loaded into trucks, added in ash conditioner.

Minn. R. 7011.0150

Fugitive PM: Cover ash haul trucks leaving the facility; control fugitive dust during unloading and loading ash trucks at the Main Steam Service Facility ash storage building

Minn. R. 7011.0150

Subject Item: Fugitive

Source Minneapolis, Southeast coal and biomass stockpile

Associated Items:

What to do Why to do it Fugitive PM: Maintain shape of coal pile and apply water to minimize fugitive dust.

Minn. R. 7011.1105, subp. C and F

Fugitive PM: less than or equal to 13000 tons coal and biomass stored on site

Minn. R. 7011.1105, subp. F

Subject Item: Fugitive

Source Minneapolis Southeast Boilers 3 and 4 ash truck loading and handling

Associated Items:

What to do Why to do it Fugitive PM: greater than or equal to 20% by weight water content of ash loaded into trucks, added in ash conditioner

Minn. R. 7011.0150

Fugitive PM: Cover ash haul trucks leaving the facility; control fugitive dust during unloading and loading ash trucks at the Main Steam Service Facility ash storage building.

Minn. R. 7011.0150


Page 49 of 77 Record keeping: Maintain a record of the daily emissions of each pollutant and a 12-month rolling sum of emissions for each pollutant as calculated above.

Title I Condition: limitation on emissions to avoid classification as a major modification under 40 CFR § 52.21 and 40 CFR pt. 51 Appendix S

Calculation of emissions: The following equation shall be used for this calculation: F = ΣiΣj [Efij x FCij] Where F = the total emission in tons of a specific pollutant Σ = sum over all values of I or j I = a number from 1 to 7 identifying each emission unit in the group J – identifies the type of fuel combusted EFij = emission factor as listed below or as determined by performance testing for emission unit i when combusting fuel j, or for pollutants monitored by a CMES in lb/MMBtu, the average value for each day FCij = fuel consumption for fuel of type j in emission unit i, or for pollutants monitored by a CEMS in lb/MMBtu, the total heat input to the emission unit in a day in MMBtu


Emission factor for total PM, lb/MMBtu: EU001 – all fuels, 0.018 EU002 – fuel oil, 0.036; natural gas, 0.005 EU003 – fuel oil, 0.036; natural gas, 0.005 EU004 – coal, 0.034; fuel oil, 0.014 EU005 – coal and approved biomass, 0.038; fuel oil, 0.014 EU006 – fuel oil, 0.036; natural gas, 0.005


Emission factor for PM < 10 micron, lb/MMBtu: EU001 - all fuels, 0.033 EU002 – fuel oil, 0.056; natural gas, 0.020 EU003 – fuel oil, 0.056 natural gas, 0.020 EU004 – coal, 0.106; fuel oil, 0.029 EU005 – coal and approved biomass,0.084; fuel oil, 0.029 EU006 – fuel oil, 0.056; natural gas, 0.020


Emission factor for SO2, lb/MMBtu: EU001 – coal, fuel oil, and approved biomass, CEMS data; natural gas, 0.0006 EU002 – fuel oil, fuel oil receipts; natural gas, 0.0006 EU003 – fuel oil, fuel oil receipts; natural gas, 0.0006 EU004 – coal, CEMS data; fuel oil, CEMS data EU005 – coal and approved biomass, CEMS data; fuel oil, CEMS data EU006 – fuel oil, fuel oil receipts; natural gas, 0.0006



Page 50 of 77 Emission factor for Nitrogen Oxides, lb/MMBtu: EU001 – all fuels, CEMS data EU002 – all fuels, CEMS data EU003 – all fuels, CEMS data EU004 – coal, 1.18 fuel oil, 0.200 EU005 – coal and approved biomass, 0.783; fuel oil, 0.200 EU006 – CEMS data


Emission factors for carbon monoxide, lb/MMBtu EU001 – coal, 0.100; fuel oil, 0.200; natural gas, 0.200; wood approved biomass, 0.267 when operating at Maximum Continuous Rating (MCR). Emission of CO is not expected to exceed 30 lb/hr at 50% or more of MCR when firing coal only and will be verified during startup performance tests. EU002 – all fuels, 0.040 EU003 – all fuels, 0.040 EU004 – coal, 0.034; fuel oil, 0.036 EU005 – coal and approved biomass, 0.280; fuel oil, 0.036 EU006 – all fuels, 0.040


Emission factors for volatile organic compounds, lb/MMBtu EU001 – coal, 0.015; fuel oil, 0.015; natural gas, 0.001; wood approved biomass, 0.036 EU002 – all fuels, 0.040 EU003 – all fuels, 0.040 EU004 – coal, 0.003; fuel oil, 0.001 EU005 – coal, 0.003; fuel oil, 0.001, and approved biomass, 0.036 EU006 – all fuels, 0.004



Page 52 of 77 Subject Item: GP002 All steam service facilities steam boilers other than

Minneapolis Main 1-6 and St. Paul 3 and 4 Associated Items: EU001

EU002 EU003 EU004 EU005 EU006 EU007 EU008 EU009 EU010 EU011


Natural gas and wood approved biomass: greater than or equal to 70% of total fuel heat input to steam generators in Group GP002 after startup of EU001, EU002, EU003, EU004, EU005 and EU006. Natural gas and wood approved biomass heat input shall be determined as a 12-month rolling average starting with the 13th month after startup. Combustion of fuels during the Initial Performance Tests required by 40 CFR pt. 60 are not included in the calculation of the 12 month rolling sum.

Minn. Stat. § 116.07, subd. 4a;

Record keeping: For EU001, EU002, EU003, EU004, EU005, and EU006, maintain records of type and quantity of fuel used as specified in GP001 including clear indication of the type and quantity of any alternative biomass fired during a test burn.

Minn. R. 7007.0800, subp. 4 and 5

Record keeping: For EU007, EU008, EU009, EU0010, and EU0011 maintain records of the type and amount of fuels combusted each day.

Minn. R. 7007.0800, subp. 4 and 5

Subject Item: GP003 Associated Items: EU006, EU011 St. Paul package boiler and St. Paul Boiler No. 7

What to do Why to do it Distillate Fuel Oil Usage: less than or equal to 45,200 gallons/day. Minn. R. 7009.0020 Record keeping: maintain a daily record of the fuel oil combusted in these emission units and the sum of the amount used in each unit.

Minn. R. 7009.0020


Page 53 of 77 Subject Item: GP004

Associated Items: EU001, EU002, EU003, EU004, EU005, EU006, EU007, EU008, EU009, EU010, EU011


Hydrogen Chloride Emission from GP004: less than or equal to 7 tons per year as a 12-month rolling sum

Limitation on hydrogen chloride emissions to avoid classification as a major source under 40 CFR pt. 63

Hydrogen Chloride Monitoring: Determine hydrogen chloride emissions by collecting coal and/or biomass samples in an as-fired condition at the inlet to the steam generating units in GP004, combine the samples into a monthly composite, and analyzing the monthly composite for chlorine content, and by collecting a fuel oil sample from the fuel oil storage tank after each delivery of fuel oil and analyzing for chlorine and heat content. Instead of by fuel analyses, the Permittee may determine hydrogen chloride emissions from solid fuels at EU001 with an emission factor of 0.054 lb HCl/ton fuel (the emission factor shall be adjusted if testing of any solid fuel indicates a fuel chlorine content greater than 1900 mg/kg or an overall HCl control efficiency less than 99%). The Permittee may propose HCl emission factors based on performance test results for other emission units.


Record Keeping: maintain records of the sampling and analysis of coal and fuel oil for chlorine content; calculate and maintain records of monthly and 12-month hydrogen chloride emissions


Subject Item: GP005 Minneapolis Main Boiler 1, 2, and 3

Associated Items:

What to do Why to do it Total Steam Output: less than or equal to 140,000 lbs/hr as a three-hour average when burning coal

Minn. R. 7007.0800, subp. 2

Record Keeping: maintain records of the total steam production of Minneapolis Main boilers 1, 2, and 3 as a three-hour average

Minn. R. 7007.0800, subp. 5


Page 55 of 77 Sulfur Dioxide: less than or equal to 10% of the potential SO2 emission rate and less than or equal to the amount allowed by the following formula, as a 1 hours average, when the facility simultaneously combusts coal and/or oil with or without any other fuel Es = (Ka x Ha + Kb x Hb) / (Ha + Hb) Where: Es = the SO2 emission limit in lb/MMBtu Ka = 0.38 lb/MMBtu Kb = .0515 lb/MMBtu Ha = the heat input from the combustion of coal Hb = the heat input from the combustion of oil This is a state-only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act.

Minn. R. 7009-0020; most stringent, meets limits set by 40 CFR § 60.42b(a)

Nitrogen Oxides: less than or equal to 0.222 lb/MMBtu and less than or equal to 58.96 lb/hr as determined by a CEMS as a 30-day rolling average. This is a state-only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act.

Minn. R. 7009.0020; most stringent, meets limit set by 40 CFR § 60.44b(a)(3)(ii) and 40 CFR § 60.44b(d); 40 CFR § 60.46b(e)(2)

Nitrogen Oxides: The nitrogen oxides standards apply at all times including periods of startup, shutdown and malfunction

40 CFR § 60.46b(h)

Carbon Monoxide: less than or equal to 0.267 lb/MMBtu and less than or equal to 70.75 lb/hr. This is a state-only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act.

Minn. R. 7009-0020

Initial Performance Test: due 180 days after initial start-up of EU001 with testing to be completed within 60 days after achieving the maximum production rate at which the affected facility will be operated to measure CO emissions

Minn. R. 7017.2020, subp. 1

Performance Test Pre-test Meeting: due 7 days before Initial Performance Test

Minn. R. 7017.2030, subp. 4

Testing Frequency Plan: due 60 days after Initial Performance Test for CO emissions. The plan shall specify a testing frequency using the test data based on MPCA guidance. Future performance tests based on year (12 month), 36 month, 60 month intervals, or as applicable, shall be required on written approval of MPCA per Minn. R. 7017.2020, subp. 1

Minn. R. 7017.2020, subp. 1

Initial Performance Test: due 180 days after initial start-up of EU001 with testing to be completed within 60 days after achieving the maximum production rate at which the affected facility will be operated to verify the VOC emission factor to be used to determined GP001 VOC emission

Minn. R. 7017.2020, supb. 1

Performance Test Pre-test Meeting: due 7 days before Initial Performance Test.

Minn. R. 7017.2030, supb. 4


Page 60 of 77

Subject Item: SV004 Associated Items: EU005

Control Equipment SE No. 4 spreader stoker coal and biomass boiler, 187 MMBtu/hr

Initial Performance Test: due 180 days after initial start-up of EU004 with testing to be completed within 60 days after achieving the maximum production rate at which the affected facility will be operated to determine PM10 emissions.

Minn. R. 7017.2020, subp. 1

Ambient Air Impact Analysis based on Initial Performance Test: If the Initial Performance Test demonstrates an emission rate greater than either 0.084 lb/MMBtu or 15.71 lb/hr PM10 the Permittees shall submit a protocol for an ambient air impact dispersion model using the measured emission rate. The protocol shall be submitted by 60 days after written notice from the MPCA that the last of the initial performance test reports for SV001, SV002, SV003, SV004, SV005, SV006, and SV007 have been received and accepted by the MPCA. The results of the dispersion model using the measured emission rate shall be submitted as specified in the protocol as approved by the MPCA. This is a state-only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act.

Minn. R. 7009.0020

Performance Test Pre-test Meeting: Due 7 days before Initial Performance Test.

Minn. R. 7017.2030, subp. 4

Testing Frequency Plan: due 60 days after Initial Performance Test for PM10 emissions and for total PM emissions. The plan shall specify a testing frequency using the test data based on MPCA guidance. Future performance tests based on year (12 month), 36 month, or 60 month intervals, or as applicable, shall be required on written approval of MPCA per Minn. R. 7017.2020, subp. 1

Minn. R. 7017.2020, subp. 1

Sulfur Dioxide: less than or equal to 0.34 lb/MMBtu and less than or equal to 62.83 lb/hr, as a 1 hour average, when combusting coal or No. 2 fuel oil or both with or without approved biomass as determined by CEMS. This is a state-only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act.

Minn. R. 7009.0020; most stringent, meets limits set by Minn. R. 7011.0510, subp. 1

Sulfur Dioxide CEMS: Maintain and operate CMES for SO2 and diluent oxygen after the dry scrubber

Minn. R. 7017.1000, subp. 1

Nitrogen Oxides: 0.78 lb/MMBtu and less than or equal to 146.61 lb/hr. This is a state only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act.

Minn. R. 7009.0020


Page 70 of 77 TABLE B: ONE TIME SUBMITTALS OR NOTIFICATIONS

When to Send What to Send Portion of Facility Affected Due 15 days after equipment is rendered inoperable

Notification of the date of Equipment Inoperability

Any emission unit removed or dismantled

Due 30 days after start of construction or reconstruction

Notification of date that construction or reconstruction began under 40 CFR § 60.7(a)(1) and Minn. R. 7019.0100, subp. 1

EU001, EU002, EU003. EU006

Due 30 days before anticipated date of initial startup

Notification of the anticipated date of initial startup under 40 CFR § 60.7(a)(2) and Minn. R. 7019.0100, subp. 1

EU001, EU002, EU003. EU006

Due 15 days after initial startup

Notification of the actual date of initial startup 40 CFR § 60.7(a)(3), Minn. R. 7019.0100, subp. 1 and Minn. R. 70190100, subp. 2(A)

EU001, EU002, EU003. EU006

Due 30 days after initial startup

Notification of commence construction date and initial startup date

Minneapolis Southeast biomass truck unloading, Minneapolis Southeast silo and biomass transfer to CFB

Due 60 days (or as soon as practical) before the change is commenced

Notification of any physical or operational change which increases emission rate under 40 CFR § 60.7(a)(4)

Any emission unit in a category regulated by a standard under 40 CFR pt. 60 but not subject to such standard due to the date of construction

Due 30 days before CEMS/COMS Certification Test

Notification of planned date for conducting CEMS/COMS certification under 40 CFR § 60.7(a)(5)

CEMS/COMS for EU001, EU002, EU003, EU006, SV006


CEMS/COMS Certification Test Plan



CEMS/COMS Certification Test Report



CEMS.COMS Certification Test Report Microfiche Copy


Due 30 days prior to observation date

Notification of anticipated date for conducting opacity observations under 40 CFR § 60.7(a)(6)

Eu001, EU002, EU003, EU006, EU007, EU008, EU009, EU010

Technical Support Document, Air Emission Permit No. 05301050-021 Page 1 of 12 Date: 02/09/2006

TECHNICAL SUPPORT DOCUMENT FOR

AIR EMISSION PERMIT NO. 05301050-021

This technical support document is intended for all parties interested in the 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 permit.

1. General Information

1.1 Applicant and Stationary Source Location:

Applicant/Address Stationary Source/Address (SIC Code: 8221)

University of Minnesota and Foster Wheeler Twin Cities, Inc.

202 Morrill Hall – Office of the President 100 Church Street SE

Minneapolis, MN 55455

Southeast Steam Plant 600 Main Street SE

Minneapolis Hennepin County

Contact: Craig Moody Phone: (612) 626-4399

1.2 Description of the Facility

The University of Minnesota Twin Cities owns two facilities for generating steam and electricity that are operated by Foster Wheeler Twin Cities, Inc. - the Southeast Steam Plant and the St. Paul Steam Plant. The primary source of air emissions at the Southeast Steam Plant is five boilers – a circulating fluidized bed (CFB) boiler (EU 001) burning coal, wood, natural gas, and oil; two package boilers (EU 002 and EU 003) burning oil and natural gas; and two coal-fired boilers (EU 004 and EU 005) burning coal and oil. Air emissions are also generated with the handling of fuels and other materials (i.e., limestone, lime, sand, and ash) at the plant.

Air emissions from the boilers are a result of fuel combustion and include particulate matter (PM and PM10), nitrogen oxides (NOx), sulfur dioxide (SO2), carbon monoxide (CO), and volatile organic compounds (VOC). PM/PM10 emissions are controlled with baghouse fabric filters at the CFB boiler and coal-fired boilers. SO2 emissions are controlled with limestone in the combustion chamber of the CFB boiler, with fuel oil sulfur content limits with the package boilers, and with lime injection (i.e., dry scrubbers) at the coal-fired boilers. PM/PM10 emissions from the fuel and material handling are controlled with enclosures and fabric filters.


1.3 Description of the Activities Allowed by this Permit Action The Southeast Steam Plant and the St. Paul Steam plant currently operate under Air Emission Permit No. 05301050-011 issued on January 25, 1999. Two amendments to the permit in 2003 authorized the University of Minnesota (U of M or facility) to conduct limited test burns of oat hulls in the CFB boiler to determine the technical feasibility of handling, storing, and burning the fuel on a permanent basis and to measure the resulting air emissions. As a result of the testing, the U of M has concluded that oat hulls are a viable fuel and submitted a major permit amendment application on April 8, 2004, to make various changes to Air Emission Permit No. 05301050-011. This permit action includes the following changes to the operations of the Southeast Steam Plant: 1) Authorizes the handling of oat hulls in the existing coal handling equipment and the burning

of oat hulls in EU 001 and EU 005 - With the existing coal handling equipment, the test burns demonstrated that acceptable handling of oat hulls requires that they be blended with coal. During the test burns, the maximum amount of oat hulls that was achieved in this mixture was 34.4%.

2) Authorizes a new biomass truck unloading station, silo, and handling system that would allow the facility to handle and burn oat hulls in EU 001 without coal blending - The associated pollution control equipment for this new equipment includes two baghouse filters. EU 005 would not be connected to this new fuel handling system and oat hull firing would be limited to the existing coal handling equipment.

3) Requires performance testing of EU 001 with the new fuel handling system since the system would allow the firing of oat hulls at a higher rate than previously tested - If the resulting emissions meet specific permit requirements, the facility may utilize the new equipment without the need for an additional permit amendment. If the specified conditions are not met, a permit amendment would be required to operate the equipment.

4) Requires performance testing of EU 005 within 60 days of firing oat hulls in the unit - If the resulting emissions meet specific permit requirements, oat hulls may continue to be burned in EU 005 without an additional permit amendment. If the specified conditions are not met, a permit amendment would be required to burn oat hulls in EU 005.

5) Authorizes performance test burns of alternative biomass fuels in EU 001 and EU 005 without the need to obtain a permit amendment - A list of biomass fuels that may and may not be tested is added for clarification. Test burns may only be conducted after a performance test plan is submitted by the U of M and is approved by the Minnesota Pollution Control Agency (MPCA). After performance testing is completed, the new biomass fuel may be burned only if the U of M applies for and receives a major permit amendment.

6) Adds oat hulls and other biomass that may be approved in the future to the list of fuels that may satisfy the existing 70% total heat input requirement on steam generators - In the current permit, natural gas and wood are the only fuels that may be used to meet this requirement.

7) Allows the use of an emission factor for calculating actual hydrogen chloride (HCl) emissions from EU 001 - This factor applies to coal, oil, and biomass. The permit currently requires HCl emissions from coal and oil to be determined by analyses of the chlorine content of the fuels. Fuel analyses would continue to apply to all other boilers.


1.4 Facility Emissions: The main air pollutants of concern with this project are dust (i.e., PM/PM10) from handling biomass and combustion products from burning biomass (i.e., PM/PM10, NOx, SO2, CO, and VOC).

Table 1. Facility Classification

Classification Major/Affected Source

Synthetic Minor Minor

PSD X Part 70 Permit Program X Part 63 NESHAP X

Table 2. Title I Emissions Increase Summary

Pollutant Fuel Combustion

Baseline Actual

Emissions (tpy1)

Fuel Combustion

Projected Actual

Emissions (tpy)

Fuel and Material Handling Baseline Actual

Emissions (tpy)

Fuel and Material Handling Projected

Actual Emissions

(tpy)

Total Projected Emissions Increase

(tpy)

PSD Major Modification Thresholds for Existing

Major Sources

(tpy)

PM 10.26 16.25 0.89 1.78 6.88 25 PM10 9.76 16.84 0.22 0.72 7.58 15 NOx 136.69 168.52 NA NA 31.83 40 SO2 26.64 31.14 NA NA 4.50 40 CO 66.07 60.64 NA NA -5.43 100 VOC 5.34 5.83 NA NA 0.49 40 1tons per year 2. Regulatory and/or Statutory Basis New Source Review/ Prevention of Significant Deterioration (PSD)

The facility is an existing major source under PSD regulations as indicated in Table 1. The projected actual emissions increases due to the changes authorized by this permit are below the thresholds for a PSD major modification (see Table 2); therefore, PSD does not apply (see Attachment 1 and Section 3.1 Emissions Increase Analysis for more detailed information).

The existing permit contains emission rate limits (lb/hr and lb/MMBtu fuel) and annual emission limits that were established based on air quality modeling when the steam plant renovation project was originally permitted. None of these allowable emission limits are being changed with this permit amendment.


Part 70 Permit Program

The facility remains a major source under the Part 70 permit program as indicated in Table 1. The changes authorized by this permit will be incorporated into the facility’s Part 70 permit when the Part 70 permit is issued.

New Source Performance Standards (NSPS)

40 CFR pt. 60, subp. Db Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units continues to apply to EU001. The changes authorized by this permit do not change the applicability of these NSPS requirements to any emission units at this facility.

The facility is not subject to 40 CFR pt. 60, subp. DD Standards of Performance for Grain Elevators.

The facility is not subject to 40 CFR pt. 60, subp. CCCC Standards of Performance for Commercial and Industrial Solid Waste Incineration Units.

National Emission Standards for Hazardous Air Pollutants (NESHAP)

As indicated in Table 1, the facility remains subject to a limit on HCl emissions such that it is not a major source under 40 CFR pt. 63. Thus, no NESHAPs apply to the facility.

Minnesota State Rules The requirements of Minn. R. 7011.0510 Standards of Performance for Existing Indirect Heating Equipment continue to apply to EU005 and do not change as a result of this permit amendment.

Minn. R. 7011.1105 Standards of Performance for Certain Coal Handling Facilities will continue to apply to the coal handling units that will be authorized to handle biomass as a result of this permit amendment.

Minn. R. 7011.1005 Standards of Performance for Dry Bulk Agricultural Commodity Facilities applies to the new biomass truck unloading, silo, and transfer equipment.

Minn. R. 7011.1201 Waste Combustors does not apply to this permit amendment.

Table 3. Regulatory Overview of Units Affected by the Modification/Permit Amendment

EU, GP, or SV Applicable Regulations Comments: EU 005 – Southeast No. 4 spreader stoker boiler

40 CFR pt. 60, subp. Db If the required performance test for EU 005 confirms that the permit limits will be met while burning oat hulls, then the burning of oat hulls will not be considered an NSPS modification triggering NSPS subpart Db for this unit. If the performance test indicates that the permit limits would not be met with the burning of oat hulls, a major permit amendment would be required which would include an analysis of possible subpart Db applicability.


EU, GP, or SV Applicable Regulations Comments: GP 002 – EU001, 002, 003, 004, 005, 006, 007, 008, 009, 010, 011

40 CFR pt. 60, subp. CCCC

Standards of Performance for Commercial and Industrial Solid Waste Incineration (CISWI) Units. The subpart applies to CISWI Units which are defined as any combustion device that combusts commercial and industrial waste. Commercial and industrial waste is further defined as solid waste combusted without energy recovery. Since all combustion devices at the facility (i.e., boilers) include energy recovery, this subpart does not apply.

GP 002– EU001, 002, 003, 004, 005, 006, 007, 008, 009, 010, 011

Minn. R. 7007.1201 Standards of Performance for Waste Combustors. This standard does not apply because oat hulls and the other types of biomass for which the facility may conduct test burns are not “solid waste” under Minn. Stat. §116.06, subd. 22.

Biomass truck unloading, Biomass silo and transfer to CFB

40 CFR pt. 60, subp. DD

Standards of Performance for Grain Elevators. This subpart applies to certain grain but not grain by-product operations. Since oat hulls are considered a grain by-product, this standard does not apply.

Biomass truck unloading, Biomass silo and transfer to CFB

Minn. R. 7011.1005 Standards of Performance for Dry Bulk Agriculture Commodity Facilities. This standard applies to grain by-products. In addition, the facility is located in the Minneapolis-St. Paul Air Quality Control Region for which control is required.

The language 'This is a state-only requirement and is not enforceable by the EPA Administrator and citizens under the Clean Air Act' refers to permit requirements that are mandated by state law rather than 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 by state law. State law requirements are not enforceable by U.S. 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

3.1 Emissions Increase Analysis The University of Minnesota determined whether the changes authorized by this permit amendment constitute a major modification under PSD by determining the total increase in emissions consistent with the requirements of 40 CFR § 52.21. For existing emission units, the increase in emissions was determined by comparing the baseline actual emissions of the units before the proposed changes to the projected actual emissions after the changes. For new emission units, the increase in emissions is equal to the potential to emit of the units. The detailed emissions increase calculations are included in Attachment 1 and demonstrate that the modification will remain below the major modification thresholds under PSD; therefore, PSD


does not apply to this permit amendment. A discussion of certain aspects of this determination is provided below. Baseline actual emissions For this facility, baseline actual emissions are defined as the average annual emissions that were actually emitted during any consecutive 24-month period within the last ten years. The U of M selected the calendar years of 2002 and 2003 for the 24-month period for all pollutants and provided usage data for all fuels fired at all emission units at the facility during this baseline period. Rather than being based on material throughput, lime, limestone, sand, and ash handling emissions are assumed to have occurred at the maximum hourly rate for the same number of hours as coal handling (coal handling hours are based on actual coal throughput and maximum hourly handling rates). Emission factors for each material and emission unit are based on performance test results, continuous emission monitor data, or AP-42 emission factors. The one exception is for ash unloading where emission factors are from Air Pollution Engineering Manual, Second Edition (Wayne T. Davis, 2000). Projected Actual Emissions Since the addition of oat hulls does not increase the design capacity or potential to emit of any existing emission units, projected actual emissions are defined as the maximum annual emissions that the emission units are projected to emit within five years after the change. In determining projected actual emissions, all relevant information such as historical operational data and the facility’s expected business activity must be considered. Additionally, any emissions following the project that could have been accommodated by the emission unit during the baseline period and that are unrelated to the project, including emission increases due to demand growth, are excluded from projected actual emissions. The U of M submitted a report titled Renewable Biofuels and Fuel Flexibility: Permitting Oat Hulls and other Biofuels as Part of the University of Minnesota Energy Efficiency and Fossil Fuel Use Reduction Program, dated January 26, 2004 (Attachment 2). The report includes historical data (1988 – 2003) which shows that the U of M has reduced campus steam requirements by about 23 percent even though total building space has increased by 18 percent over the same time period. Based on this trend, ongoing conservation and energy efficiency efforts, and the fact that no significant capital projects that would affect steam demand have been funded, the U of M has projected fuel usage after the project to be equal to the usage during the 2002 – 2003 baseline period. While future fuel usage may exceed this projected usage due to extreme weather conditions or major capital projects that are not currently planned or funded, the higher emissions that would result from such conditions would be unrelated to the oat hulls project, could have been accommodated during the baseline period, and would not have been counted toward projected actual emissions. Projected actual emissions for this project are based on an oat hulls usage of 25,000 tons per year. The U of M is planning to burn oat hulls primarily in the CFB boiler except during periods


of low steam demand in May and October when the CFB boiler is not utilized. During these times, oat hulls will continue to be received and will be burned in EU 005 due to limited storage capacity. With the existing coal handling equipment, the test burns demonstrated that acceptable handling of oat hulls requires that they be blended with coal. During testing, oat hulls were blended with coal at percentages of 9 percent and 34.4 percent. With installation of the new biomass equipment, oat hulls may be fired in the CFB boiler without blending. In determining projected actual emission for the CFB boiler, the higher emission factor from the two oat hull performance tests is assumed for each pollutant. To verify this assumption and ensure that this project will not result in a significant emissions increase, the permit requires performance testing of the CFB boiler and a revised PSD analysis based on the performance test after the new biomass equipment is installed. Likewise, the permit requires performance testing of EU 005 along with a revised PSD analysis to confirm emission factor assumptions and the analysis that a significant emissions increase will not occur. For the purpose of calculating projected actual emissions, emission factors for the burning of oat hulls in EU 005 have been conservatively assumed to be equal to coal. The unloading and handling of oat hulls may be accomplished under a number of different scenarios. The scenario with the highest emissions is where oat hulls are delivered by rail and are transferred to the boilers by the existing coal handling equipment. Projected actual emissions from oat hulls handling assumes this worst-case scenario rather than delivery of oat hulls to the new biomass truck unloading station which would result in lower emissions. As a result, the potential emissions from the new biomass emission units have been calculated but are not included in the calculation of the emissions increase from this project since the higher emissions from handling oat hulls at the existing coal handling emission units are included instead. Source Obligation If there is reasonable possibility that a project may result in a significant emissions increase even though one has not been projected, the facility is subject to additional monitoring and reporting requirements to determine whether a significant emissions increase occurs. The MPCA believes that there is a reasonable possibility that this project may result in a significant emissions increase; therefore, the permit includes the additional monitoring and reporting requirements of 40 CFR § 52.21(r)(6).

3.2 Biomass Testing and Approval The U of M’s 1996 permit authorizing the installation and operation of the CFB boiler (EU001) and modification of the stoker fired boiler (EU005) involved a netting analysis demonstrating that the project did not constitute a major modification triggering PSD review. The fuels considered in the analysis included coal, natural gas, wood, and fuel oil for EU001 and coal and oil for EU005. The authorization to burn these specific fuels is considered a Title I condition, even though there is no corresponding underlying applicable requirement, because the condition is necessary for the facility to avoid being subject to PSD (Minn. R. 7007.0100, Subp. 25(C)). In


other words, without such a restriction the facility would not be explicitly prohibited from burning a new fuel that would/could trigger PSD. Modifying such a condition by adding a new fuel such as oat hulls or any other fuel requires a major permit amendment (Minn. R. 7007.1500, Subp. 1(C)) including public notice (Minn. R. 7007.0850). Based on oat hulls performance testing data and an analysis of projected changes in actual emissions, the U of M has demonstrated that the addition of oat hulls would not trigger PSD review. As a result, this permit amendment adds oats hulls (along with wood for EU 001) as “approved biomass” that may be used as a fuel. Since the emissions data and analysis provided by the U of M were limited to oat hulls, the MPCA cannot approve the use of any other biomass fuels at this time. The future addition of alternative biomass fuels would require a major permit amendment pursuant to Minn. R. 7007.1500, Subp. 1(C). This permit amendment provides authorization to perform test burns with limited quantities of alternative biomass fuels for limited periods of time in EU 001 and EU 005. The permit identifies the types of biomass fuels that may be tested along with materials that may not be. The purpose of such testing would be for the facility to gather information to determine the technical and regulatory feasibility of adding a new biomass fuel. All permit conditions, including emission limits, would continue to apply during any test burn. In addition, any test burn must be accompanied by performance testing to characterize the air emissions from burning the potential biomass fuel. Upon completion of a test burn, the facility must submit a performance test report and, as discussed above, the facility would need to obtain a major permit amendment to continue burning the tested fuel.

3.3 Hydrogen Chloride (HCl) Emission Factor The current permit includes an HCl limit on GP 004. The current permit further requires coal and oil sampling and analysis for chlorine. For demonstrating compliance with the HCl limit, the presumption of the existing permit is that all the chlorine in the fuels is converted to HCl and all the HCl produced exits the boiler through the stack. While this presumption results in an overestimate of HCl emissions, such a presumption has been reasonable because more accurate information on HCl emissions has not existed. With the two oat hull test burns, the U of M analyzed the chlorine content of the fuel going into the boilers and the HCl leaving the boilers. From this information, a hydrogen chloride control efficiency was calculated which reflects the fact that not all of the chlorine in the fuel is converted to HCl and that most of the HCl generated is removed by the limestone in the boiler and by other mechanisms. In their application, the U of M requests the use of emission factors for HCl instead of fuel analyses when performance test data is available to derive an emission factor. Attachment 3 includes calculations of such an emission factor for EU 001 for use with all solid fuels (i.e., oat hulls, coal, and wood). The derivation of the emission factor takes into account the measured HCl control efficiency, the results of the required coal chlorine analyses conducted by the U of


M, the results of oat hull chlorine analyses conducted by the U of M, and literature on the chlorine content of various types of wood. If any future testing demonstrates that the assumed control efficiency is not being achieved or that fuel chlorine content is higher than the worst-case assumed, the emission factor must be adjusted. While the derived emission factor applies only to EU 001, the U of M may propose additional emission factors for the other boilers if performance test data exists to support the development of such emission factors. 3.4 Periodic 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.

In evaluating the monitoring included in the permit, the MPCA considers the following:

• The likelihood of 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.

A review of the adequacy of existing periodic monitoring requirements for all emission units at the facility is currently being performed as part of the Part 70 permit application review and is outside the scope of this permit amendment. For this permit action, the existing monitoring requirements for existing emission units authorized to handle biomass have been reviewed to ensure that appropriate monitoring continues to apply with the handling biomass. For the new emission units handling biomass, a review of the adequacy of periodic monitoring required by applicable requirements was performed. Table 4 summarizes the results of the periodic monitoring review performed for this permit action.

Table 4. Periodic Monitoring Emission Unit or Group

Requirement (basis)

Additional Monitoring

Discussion

Total Facility

Operation and Maintenance Plan

None This existing permit requires an Operation and

Maintenance Plan for all air pollution control equipment which includes the two new baghouse filters controlling the biomass unloading, silo, and transfer equipment.


Emission Unit or Group

Requirement (basis)

Additional Monitoring

Discussion

Total Facility

Fugitive Control Plan

None The fugitive emission control plan approved on December 23, 1996 is amended to include the biomass unloading station as detailed in Permit Application Form GI-05D submitted on April 8, 2004.

New Biomass Handling Equipment

80% collection efficiency and less than or equal to 5% opacity

Daily visible emissions observation and periodic inspections

Collection and opacity requirements are from Minn. R. 7007.1000 but the rule does not include adequate periodic monitoring.

EU 001 and EU 005

Limits to avoid major modification under 40 CFR § 52.21

Performance testing Testing of EU 001 after startup of the new biomass handling equipment and of EU 005 after initial firing of oat hulls is required to confirm that a major modification will not occur.

GP 004 Limits to avoid classification as a major source under 40 CFR pt. 63

Calculate and maintain records of monthly and 12-month hydrogen chloride emissions

The existing permit contains an HCl limit and HCl monitoring but does not contain a requirement to calculate HCl emissions to verify compliance with the limit.

3.5 Insignificant Activities This permit amendment does not add any operations which are classified as insignificant activities.

3.6 Comments Recieved The public comment period commenced on November 5, 2005, and was initially to end on December 5, 2005. During this time, the MPCA received a request that the comment period be extended by two weeks. With agreement from the Permittee, the MPCA extended the public comment period to December 19, 2005. The U.S. Environmental Protection Agency did not submit comments on the draft permit. Comments were submitted by the U of M, the City of Minneapolis, the Southeast Como Improvement Association, Clean Water Action Alliance of Minnesota, and an individual (Attachment 6). The MPCA provided a written response to each commenter (Attachment 7). The U of M and City of Minneapolis wrote in support of the draft permit amendment. The Southeast Como Improvement Association and Clean Water Action Alliance of Minnesota provided comments supporting the permit conditions that prohibit animal wastes from being


tested as a fuel and MPCA’s position that a major permit amendment would be required to add a new fuel on a permanent basis, but also stated that annual emissions are projected to increase with this project, renewable energy sources and energy conservation need to be part of any energy discussion with the University, and the air permit does not consider the impacts of the air emissions on water quality. The MPCA does not dispute any of these assertions and our responses to the comments explain that the increase in emissions is acceptable and that the other issues are outside the scope of the air permitting program. The individual commenter stated that the increase in emissions contrasts with MPCA’s goals, as well as the goals of the City of Minneapolis and the U of M, and that biomass is not defined adequately to prevent the burning of animal carcasses and plants treated with toxic materials. The MPCA’s response to these comments explains how this permit is consistent with the MPCA goals identified by the commenter and that the goals of others are not a consideration in the air permitting process. In addition, the MPCA’s response points out that the U of M is prohibited from conducting tests of animal manures and wastes as well as any materials meeting the definition of a hazardous wastes, and that any decision to allow the U of M to burn a new fuel on a permanent basis would be subject to public notice and comment. Changes to the permit were not made as a result of the comments; however changes were made to correct deficiencies discovered by the MPCA after the permit was drafted. Operation the of fabric filters associated with coal and miscellaneous material handling was assumed for the netting analysis that was the basis for the 1996 construction permit as well as for the PSD applicability analysis for this permit. Therefore, permit terms associated with the operation of the baghouses have been added to this permit as Title I conditions. Also added are standard state requirements to take corrective actions as necessary, perform periodic inspections, and operate and maintain the fabric filters in compliance with an Operation and Maintenance Plan prepared by the facility. These conditions are found on newly added pages 12a and 12b of the permit. The addition of these changes does not require additional public notice since the changes impose new requirements on the U of M. One correction was made on page 52 of the permit. The list of associated items included in Group 003 was changed from EU 006 and EU 001 to EU 006 and EU 011.

4. Conclusion Based on the information provided by the University of Minnesota and Foster Wheeler Twin Cities, Inc., the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 05301050-021 and this technical support document, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules.


Staff Members on Permit Team: Steven Pak (permit writer) Suzanne Venem (enforcement)

Curtis Stock (stack testing) Bonnie Nelson (peer reviewer) Attachments: 1. Emissions Increase Calculations

2. U of M Report on Renewable Biofuels and Fuel Flexibility 3. Hydrogen Chloride Emission Factor 4. Facility Emissions Summary (Form GI-07) 5. Fugitive Emission Source Information (Form GI-05D) 6. Public Comments Received (hard copy only) 7. MPCA Response to Public Comments

Attachment 1 Emissions Increase Calculations

Fuel Combustion Table 1. Fuel Consumption, Boiler Output and Weather Conditions (2000-2003) Table 2. Baseline and Projected Fuel Usage, by Fuel Table 3. Projected Fuel Consumption with Growth, By Emission Unit Table 4. Emission Factors and Emissions – 2002 Table 5. Emission Factors and Emissions – 2003 Table 6. Emission Factors and Emissions – Average (2002-3) Table 7. Emission Factors and Emissions – Projected Table 8. Baseline and Projected Emissions (TPY) Table 9. Historical Fuel Usage Material Handling Summary Tables Scenario 1 – Emissions from 100% Grain by Truck to Coal Enclosure Scenario 2 – Emissions from 100% Grain by Rail to Coal Enclosure Scenario 3 – Emissions from 100% Grain at New Biomass Unloading Area Scenario 4 – Emissions from 100% Coal by Rail to Coal Enclosure Existing Emission Sources –Ash, Lime, Limestone, and Sand Handling and Storage Fuel Combustion and Material Handling Permit Change Form CH-04a Determination of Increases at Major Sources

Attachment 2 U of M Report on Renewable Biofuels and Fuel Flexibility

Attachment 3 Hydrogen Chloride Emission Factor

Attachment 4 Facility Emissions Summary (Form GI-07)

Attachment 5 Fugitive Emission Source Information (Form GI-05D)

Attachment 6 Public Comments Received

(included only with hard copy)

Attachment 7 MPCA Response to Public Comments

2002 2003co co

ng subbit fo wood ng subbit fo wood1 3.25 3.49 - 1.68 8.43 1 8.89 2.77 - 6.09 17.752 4.97 - 0.00 - 4.97 2 13.00 - 0.02 - 13.023 48.34 - 0.03 - 48.38 3 38.32 - 0.04 - 38.364 0.00 - - - 0.00 4 0.00 - - - 0.005 0.00 0.72 - - 0.72 5 0.00 0.48 0.03 - 0.51

total 56.57 4.21 0.04 1.68 62.49 total 60.20 3.25 0.09 6.09 69.64

pm10 pm101 0.00 5.05 - 0.04 5.09 1 0.01 4.01 - 0.14 4.162 0.45 - 0.00 - 0.45 2 1.18 - 0.18 - 1.363 4.37 - 0.22 - 4.59 3 3.47 - 0.25 - 3.714 - - - - 0.00 4 - - - - 0.005 - 0.07 - - 0.07 5 - 0.09 0.00 - 0.09

total 4.83 5.12 0.22 0.04 10.20 total 4.65 4.11 0.43 0.14 9.32

sox sox1 0.02 6.94 - 0.25 7.21 1 0.06 3.98 - 0.90 4.942 0.04 - 0.15 - 0.18 2 0.09 - 12.70 - 12.803 0.35 - 12.24 - 12.59 3 0.27 - 13.80 - 14.074 - - - - 0.00 4 - - - - 0.005 - 0.58 - - 0.58 5 - 0.60 0.31 - 0.91

total 0.40 7.52 12.39 0.25 20.56 total 0.43 4.58 26.81 0.90 32.72

nox nox1 3.95 70.25 - 4.85 79.06 1 13.60 54.69 - 17.55 85.842 4.50 - 0.03 - 4.53 2 12.27 - 2.98 - 15.253 45.52 - 2.51 - 48.03 3 35.52 - 3.01 - 38.534 - - - - 0.00 4 - - - - 0.005 - 0.83 - - 0.83 5 - 1.17 0.14 - 1.31

total 53.97 71.08 2.54 4.85 132.44 total 61.39 55.86 6.13 17.55 140.94

tsp tsp1 0.00 5.05 - 0.04 5.09 1 0.01 4.01 - 0.15 4.172 0.45 - 0.01 - 0.46 2 1.18 - 0.53 - 1.713 4.37 - 0.51 - 4.89 3 3.47 - 0.58 - 4.054 - - - - 0.00 4 - - - - 0.005 - 0.07 - - 0.07 5 - 0.09 0.00 - 0.09

total 4.83 5.12 0.52 0.04 10.50 total 4.65 4.11 1.11 0.15 10.02

voc voc1 0.21 1.19 - 0.17 1.58 1 0.58 0.95 - 0.61 2.142 0.33 - 0.00 - 0.33 2 0.85 - 0.03 - 0.883 3.17 - 0.03 - 3.20 3 2.51 - 0.04 - 2.544 - - - - 0.00 4 - - - - 0.005 - 0.01 - - 0.01 5 - 0.01 0.00 - 0.01

total 3.70 1.20 0.03 0.17 5.11 total 3.94 0.96 0.07 0.61 5.58

Worksheet in ole_1 Summaries 2/15/2006

Projectedco

ng subbit fo wood oat hulls1 6.07 3.89 3.89 2.09 2 8.98 0.01 3 25.54 0.04 4 5 6.58 0.01 - 3.54

total 40.59 10.46 0.06 3.89 5.63

pm101 0.01 7.77 0.09 4.18 2 0.81 0.09 3 2.31 0.23 4 5 0.87 0.00 - 0.47

total 3.13 8.64 0.32 0.09 4.65

sox1 0.04 0.71 0.57 0.38 2 0.06 6.43 3 0.18 13.02 4 5 6.24 0.16 - 3.36

total 0.29 6.94 19.60 0.57 3.74

nox1 8.33 62.87 11.20 33.85 2 8.31 1.40 3 23.86 2.76 4 5 10.31 0.07 - 5.55

total 40.50 73.18 4.23 11.20 33.85

tsp1 0.01 7.06 0.10 3.80 2 0.81 0.27 3 2.31 0.55 4 5 0.87 0.00 - 0.47

total 3.13 7.94 0.82 0.10 4.27

voc1 0.40 0.25 0.01 0.13 2 0.59 0.02 3 1.67 0.03 4 5 0.11 0.00 - 2.62

total 2.66 0.36 0.05 0.01 2.76



15.939.00

25.580.00

10.1460.64

12.050.902.540.001.34

16.84

1.706.49

13.200.009.75

31.14

116.259.71

26.620.00

15.93168.52

10.971.082.860.001.34

16.25

0.790.601.710.002.745.83


UM SE Heating Plant - Oat Hull AmendmentExisting Emission Sources - Ash, Lime, Limestone, and Sand Handling and Storage

Description Mpls. SE Lime Truck Unloading and Silo(Lime unloading and storage)

MPCA Permit 05301050-008 Reference Page 39 VSE7Lime Lime Pollution Net Controlled

Emission Emission Emission Emission Control Controlled Potential toMaximum Units per Factor Factor Factor Rate Efficiency Increase Emit (PTE)

Desc Pollutant Rate* Time Number Units Source (lb/hr) (%) (lb/hr) (ton/yr)

Unloading PM (Particulate Matter) 14 ton/hr 0.610 lb/ton AP-42 Table 11.17-4 8.54 99.0 0.09 0.37Unloading PM10 (Particulate Matter < 10 microns) 14 ton/hr 0.610 lb/ton AP-42 Table 11.17-4 8.54 99.0 0.09 0.37

vent PM (Particulate Matter) 14 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.01 (see notes) 0.01 0.04vent PM10 (Particulate Matter < 10 microns) 14 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.01 (see notes) 0.01 0.04

* Lime unloading and storage bin vent surge emission factors from AP-42 Section 11.17 Table 11.17-4.* The emission factor for the lime storage bin is controlled.

Description Minneapolis SE CFB Limestone Unloading and Storage(Limestone unloading and storage)

MPCA Permit 05301050-008 Reference Page 39 VSE5 and VSE6Limestone Limestone Pollution Net ControlledEmission Emission Emission Emission Control Controlled Potential to

Maximum Units per Factor Factor Factor Rate Efficiency Increase Emit (PTE)Desc Pollutant Rate* Time Number Units Source (lb/hr) (%) (lb/hr) (ton/yr)


vent PM (Particulate Matter) 14 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.01 (see notes) 0.01 0.04vent PM10 (Particulate Matter < 10 microns) 14 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.01 (see notes) 0.01 0.04

* Limestone unloading and storage bin vent surge emission factors from AP-42 Section 11.17 Table 11.17-4.* The emission factor for the limestone storage bin is controlled.

Worksheet in ole_1 2/15/2006 Ash Lime Sand Emiss


Description Minneapolis SE CFB Sand Unloading and Storage(Sand unloading and storage)

MPCA Permit 05301050-008 Reference Page 39 VSE5 and VSE6Sand Sand Pollution Net Controlled




vent PM (Particulate Matter) 5 ton/hr 0.0021 lb/ton AP-42 Table 11.12-2 0.01 99.0 0.00 0.00vent PM10 (Particulate Matter < 10 microns) 5 ton/hr 0.00099 lb/ton AP-42 Table 11.12-2 0.00 99.0 0.00 0.00

* Sand transfer emission factors from AP-42 Section 11.12 Table 11.12-2.

Description Minneapolis SE Boilers 3 and 4 ash conveying and silo(Ash unloading and storage)

MPCA Permit 05301050-008 Reference Page 40 VSE10 and VSE11Ash Ash Pollution Net Controlled



Unloading PM (Particulate Matter) 35.0 ton/hr 0.200 lb/ton AWMA Air Poll Man 7.00 99.0 0.07 0.31Unloading PM10 (Particulate Matter < 10 microns) 35.0 ton/hr 0.072 lb/ton AWMA Air Poll Man 2.52 99.0 0.03 0.11

vent PM (Particulate Matter) 35.0 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.02 (see notes) 0.02 0.09vent PM10 (Particulate Matter < 10 microns) 35.0 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.02 (see notes) 0.02 0.09

* Ash unloading emission factors from AWMA Air Pollution Engineering Manual (Second Edition, 2000), Table 1, page 693* The ash bin vent emission factor is assumed to be equal to the lime bin surge controlled emission factor (from AP-42 Table 11.17-4).



Description Minneapolis SE CFB ash silos(Ash unloading and storage)

MPCA Permit 05301050-008 Reference Page 40 VSE8 and VSE9Ash Ash Pollution Net Controlled




vent PM (Particulate Matter) 35.0 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.02 0.02 0.09vent PM10 (Particulate Matter < 10 microns) 35.0 ton/hr 0.00061 lb/ton AP-42 Table 11.17-4 0.02 0.02 0.09

* Ash unloading emission factors from AWMA Air Pollution Engineering Manual (Second Edition, 2000), Table 1, page 693* The ash bin vent emission factor is assumed to be equal to the lime bin surge controlled emission factor (from AP-42 Table 11.17-4).

Description Minneapolis SE CFB ash truck loading and handling(Ash handling and loading)

MPCA Permit 05301050-008 Reference Page 46 Mpls. SE CFB ash truck loading and handling (>20% water content)Ash Ash Pollution Net Controlled




* Ash unloading emission factors from AWMA Air Pollution Engineering Manual (Second Edition, 2000), Table 1, page 693

Pollutant lbs/hr tons/yrPM (Particulate Matter) 0.44 1.93PM10 (Particulate Matter < 10 microns) 0.31 1.34* This table is included as a point of reference. Please refer to the summary table.

Ash, Lime, Limestone and Sand Handlingand Storage Emissions Summary


Form CH-04a aq-f2-ch04a.doc Page 1 of 7

MINNESOTA POLLUTION CONTROL AGENCY AIR QUALITY 520 LAFAYETTE ROAD ST. PAUL, MN 55155-4194

PERMIT CHANGE FORM CH-04aDETERMINATION OF INCREASES AT

MAJOR SOURCES(FORMERLY FORM MOD-04A DETERMINATION OF INCREASES AT

MAJOR SOURCES) 05/25/04

1a) AQ Facility ID No.: 05301050

1b) AQ File No.: 86TC

2) Facility Name: University of Minnesota and Foster Wheeler Twin Cities, Inc.

Use this Form to calculate emissions increases at existing major NSR sources. If the facility is not a major source under NSR, use Form CH-04b. 3. Modified, Replacement, and/or Debottlenecked Emission Units

Use Table 1 to document the emissions increase individual units using the calculation method found in 40 CFR § 52.21(a). The procedure for calculating whether a significant emissions increase will occur depends on the type of emissions unit being modified. See instructions for calculating emissions increases. Complete a separate Table 1 for each modified, replacement, or debottlenecked emission unit. Make additional copies if more than three units are affected. Summarize the total increases for each pollutant in Table 2. Attach your calculations.

Table 1

EU 1 Modified Replacement Debottlenecked Clean Unit

POLLUTANT Projected

Actual* or Future

Potential Emissions (tpy)

Baseline Actual

Emissions (tpy)

Exclusions from

Projected Actuals

(tpy)

Description of Exclusions from

Projected Actuals

Increase

(tpy)

Baseline period (dates)

PM 10.97 4.63 6.34 2002-3 PM10 12.05 4.62 7.42 2002-3 NOx 116.25 82.45 33.81 2002-3 SO2 1.70 6.07 -4.37 2002-3 CO 15.93 13.09 2.85 2002-3 Ozone (VOC) 0.79 1.86 -1.07 2002-3 Lead Note 1 Fluorides Note 2 Sulfuric acid mist Note 3 Hydrogen Sulfide (H2S)

Note 3

Total Reduced Sulfur including H2S

Note 3

Total Reduced Sulfur Compounds including H2S

Note 3

MWC Organics MWC Acid Gas


MWC Metals MSW Landfill Gas

* Title/date of document(s) used as basis for projected actuals:

050330b EmCalcs Report, Tables 1-5, and Fuel Transfer Emission Calculations Scenarios 1 Through 5

Note 1. Oat hulls fuel is a food grade biomass and thus anticipated to contain negligible amounts of lead and to result in zero lead emissions

Note 2. Fluorides assumed less than or equal to HCl emissions, measured very low in stack testing (0.12 lbs/hr)

Note 3. Sulfur containing pollutants are assumed to follow the trend of SO2 emissions which decrease


POLLUTANT Projected

Actual* or Future


Baseline Actual

Emissions (tpy)

Exclusions from

Projected Actuals

(tpy)


Projected Actuals

Increase

(tpy)


PM 2.86 4.47 -1.61 2002-3 PM10 2.54 4.15 -1.61 2002-3 NOx 26.62 43.28 -16.66 2002-3 SO2 13.20 13.33 -0.13 2002-3 CO 25.58 43.37 -17.79 2002-3 Ozone (VOC) 1.71 2.87 -1.16 2002-3 Lead Note 1 Fluorides Note 2 Sulfuric acid mist Note 3 Hydrogen Sulfide (H2S)

Note 3

Total Reduced Sulfur (TRS) including H2S

Note 3

TRS Compounds including H2S

Note 3

MWC Organics MWC Acid Gas MWC Metals MSW Landfill Gas



POLLUTANT Projected

Actual* or Future


Baseline Actual

Emissions (tpy)

Exclusions from

Projected Actuals

(tpy)


Projected Actuals

Increase

(tpy)


PM 1.34 0.08 1.26 2002-3 PM10 1.34 0.08 1.26 2002-3 NOx 15.93 1.07 14.86 2002-3 SO2 9.75 0.75 9.00 2002-3 CO 10.14 0.61 9.52 2002-3 Ozone (VOC) 2.74 0.01 2.73 2002-3 Lead Note 1 Fluorides Note 2 Sulfuric acid mist Note 3 Hydrogen Sulfide (H2S)

Note 3


Note 3


Note 3


Existing Fuel Handling Equipment

EU017

-EU025

Modified Replacement Debottlenecked Clean Unit

See MOD-01 and associated calculations, Fuel Transfer Emission Calculations

Scenarios 1 Through 4 and boiler emission tables, which show projected increase in emissions due to use of oat hulls fuel.

POLLUTANT Projected

Actual* or Future


Baseline Actual

Emissions (tpy)

Exclusions from

Projected Actuals

(tpy)


Projected Actuals

Increase

(tpy)


PM 1.78 0.89 0.89 2002-3 PM10 0.72 0.22 0.50 2002-3 NOx SO2


CO Ozone (VOC) Lead Fluorides Sulfuric acid mist Hydrogen Sulfide (H2S)





Table 2 – Summary of Table 1 Results

EU 001

EU 003

EU

005 EU

017-

025 EU

002

POLLUTANT Increase

(tpy) Increase

(tpy) Increase

(tpy) Increase

(tpy) Increase (tpy) (a)

TOTAL INCREASE

(tpy) PM 6.34 -1.61 1.26 0.89 0.00 6.88 PM10 7.42 -1.61 1.26 0.50 0.00 7.57 NOx 33.81 -16.66 14.86 -0.18 31.83 SO2 -4.37 -0.13 9.00 0.00 4.50 CO 2.85 -17.79 9.52 0.00 -5.42 Ozone (VOC) -1.07 -1.16 2.73 0.00 0.49 Lead Fluorides Sulfuric acid mist Hydrogen Sulfide (H2S)


Total Reduced Sulfur Compounds including H2S

MWC Organics MWC Acid Gas MWC Metals MSW Landfill Gas (a) – Changes to EU002 are due to emission factor averaging for 2002-3.


4. Installation or Construction of New Emission Units

Use this page to document the emission increases from each new emission unit. Copy this page if more than five units are added. Attach your calculations.

Table 3 POLLUTANT

EU

024 EU

025

Total

PM 0.61 0.02 0.63 PM10 0.34 0.01 0.35 NOx SO2 CO Ozone (VOC) Lead Fluorides Sulfuric acid mist Hydrogen Sulfide (H2S)


Reduced Sulfur Compounds including H2S

MWC Organics MWC Acid Gas MWC Metals MSW Landfill Gas See Fuel Transfer Emission Calculations Scenario 3


5. Totals

Table 4 – Project Summary Column A Column B Column C Column D Column E POLLUTANT Emissions increases

from modified, replacement, or debottlenecked

units (from Table 2) (tpy)

Emissions from new units (from

Table 3) (tpy)

Total Increase

(tpy)

Significant Thresholds for major sources

PM 6.88 (Note 5) 6.88 25 1 PM10 7.57 (Note 5) 7.57 15 NOx 31.83 31.83 40 SO2 4.50 4.50 40 CO -5.42 -5.42 100 Ozone (VOC) 0.49 0.49 40 Lead 0.6 Fluorides 3 Sulfuric acid mist 7 Hydrogen Sulfide (H2S)

10


10

Reduced Sulfur Compounds

including H2S

10

MWC Organics 2 0.0000035 MWC Acid Gas 3 40 MWC Metals 4 15 MSW Landfill Gas 50

Note 1 - July 31, 1987, the National Ambient Air Quality Standard for TSP (PM) was repealed and replaced with a standard for PM10. The significant levels in this table are as they appear in the Code of Federal Regulations, March 1994. A source may not be required to comply with Nonattainment NSR for TSP increases above 25 tpy, but may be for PM10 above 15 tpy.

Note 2 - MWC Organics means Municipal Waste Combustor Organics. These are defined as total tetra-thro-octa-chlorinated dibenzo-para-dioxins and dibenzofurans.

Note 3 - MWC acid gases are measured as the sum of sulfur dioxide and hydrochloric acid. Note 4 – MWC Metals are measured as particulate matter Note 5 – Emissions from New Units are already included in Column B as part of EU017 – EU025 as shown in Table 2.

Presented to: The Minnesota Pollution Control Agency

As part of a permit amendment application to use oat hulls and other biofuels at the Southeast Steam Plant located in Minneapolis, MN.

The University of Minnesota

Renewable Biofuels and Fuel Flexibility:

Permitting Oat Hulls and other Biofuels as Part of the University of Minnesota

Energy Efficiency and Fossil Fuel Use Reduction Program

January 26, 2004

Renewable Biofuels Page 1 University of Minnesota

Executive Summary The University of Minnesota requests

permission from the Minnesota Pollution Control Agency to use “biofuels” to produce steam at the Minneapolis campus. Biofuels are an exciting opportunity for the University to reduce our use of fossil fuels, lower greenhouse gas emissions and beneficially reuse an agricultural residue.

We seek approval at this time because we have found a local and reliable supply of biofuel – oat hulls generated by General Mills. Pilot tests were conducted earlier this year with Agency approval. Test results prove that oat hulls, when combined with coal, can be burned within existing permit limits and without affecting plant performance.

Using renewable biofuels such as wood, oat hulls and other non-fossil energy sources are just one small part of the Regents’ broader commitment to energy efficiency and environmental responsibility. We actively manage energy consumption through a number of techniques and programs which have lead to lower energy use and less air pollution.

Energy Efficiency and Conservation In the past 12 years, we have reduced

campus steam consumption by nearly 23 percent despite an aggressive construction program that has increased total building space by nearly 18 percent. It is the result of a concerted effort to minimize energy losses at the steam plants and in each building. Conservation and efficiency improvements have eliminated the need to burn the equivalent of an additional 45,000 tons of coal per year.

Steam Plant Performance and Fuel Flexibility The University undertook extensive

steam plant renovations in the late 1990s. We installed new, energy-efficient boilers with state-of-the-art pollution controls. More than two-thirds of new installed capacity uses natural gas and fuel oil. The new capacity replaced a number of old coal-fired units at the Main plant in Minneapolis.

As a result of the renovation, we shifted from producing 90 percent of our steam from coal to a fuel-flexible program that relies on a minimum fuel mix of 70 percent natural gas and biofuels. Coal and fuel oil are now used for about 30 percent of all steam production and cogeneration.

We agreed to an annual voluntary limit on coal and fuel oil use as part of air quality permitting for the renovation. Our fuel-flexible design allowed us to accept the limit even though it is not required under state and federal rules.

Permitting expanded biofuels use at the Southeast plant will enhance our fuel flexibility while maintaining our ability to operate the renovated system as designed. And, as presented in this report, the University will continue to manage fossil fuel use and air pollution through a broad effort of pollution control, energy conservation and renewable fuels.

Our energy management programs go beyond state and federal requirements. Through diligence and creativity, we have reduced our reliance on all fossil fuels while providing a safe and comfortable environment for all who use the University of Minnesota.


A Description of the University Energy System The University of Minnesota manages

18 million square feet of building space in support of education and research conducted at the Twin Cities campus. Part of our responsibility is to provide heating, cooling and electricity to maintain the health, safety and comfort of the 60,000 students and staff we serve. Steam for heating, cooling and other processes is generated at two plants:

• The Southeast steam plant, located on the west side of the Minneapolis campus, and

• The St. Paul steam plant, located in the southeastern corner of the St. Paul campus.

The steam plants were renovated in the late-1990s to make the system more reliable, cost-effective and environmentally sound. The project was the result of nearly seven years of public review and analysis, beginning with an existing system review in 1989 and

concluding with an intensive air quality permitting process in 1996.

The renovation project’s first stage was a four-year vendor selection process which culminated in April 1992, when Foster Wheeler was selected to rebuild and operate the plants. Fuel flexibility was a key element of the winning proposal.

Foster Wheeler proposed a system that:

• Greatly increased natural gas / oil-fired steam capacity,

• Retained some coal-firing, but with state-of-the-art pollution controls,

• Included provisions for electricity to be cogenerated with steam, and

• Provided the capability to burn biofuels.

Foster Wheeler proposed to install a large gas/oil-fired boiler at St. Paul. More extensive reconstruction was to take place at the Southeast plant in Minneapolis. Two new gas/oil-fired


package boilers and a solid-fuel boiler were proposed to be installed. The solid-fuel boiler, called a circulating fluidized bed combustor (CFB), would be specially designed to burn a wide variety of solid fuels, including both coal and biofuels [see Figure 1].

The Southeast steam plant was also to be retrofitted to cogenerate electricity and steam (sometimes called “combined heat and power”). In the University’s cogeneration system, steam is produced at a much higher pressure than is required for campus distribution. Before leaving the plant, the steam is expanded in a turbine, which is connected to an electric generator. The steam is then distributed to the campus at medium pressure.

Cogeneration is a highly efficient process. More fuel is converted to usable energy than separately generating steam at the University and electricity at remote power plants. We estimate that we reduce regional air pollution emissions by nearly 50 percent for each kilowatt of electricity we cogenerate.

While CHP and district energy systems can utilize renewable energy fuels, they often use fossil fuels. Due to the increased fuel efficiency, even use of standard fossil fuels can have environmental benefits.”

From Designing a Clean Energy Future: A Resource Manual

Because the renovation project

substantially increased steam capacity at Southeast, the University would be able to retire a third steam plant from operation. The Main plant, also located on the Mississippi River, was designed to burn coal as its primary fuel. Main’s boilers were old, had only limited pollution control equipment and were highly inefficient. As

a result, air emissions were expected to drop, improving air quality in the surrounding community.

An air quality permit application for the proposed $100 million project was presented to the Minnesota Pollution Control Agency in early 1994. The application, containing thousands of pages of information, included emissions estimates, design criteria, and detailed computer modeling of air pollution impacts for both the old steam plants and the proposed project.

After a lengthy review, the Agency agreed that the Foster Wheeler project would meet all state and federal regulations, as well as improve air quality in the area. However, based on requests from the community, we agreed to conduct a voluntary environmental impact statement (EIS) under the direction of the Minnesota Environmental Quality Board.

Again, many months were spent reviewing the environmental impacts of the proposed project. The EIS was not limited to a review of air pollution impacts, but included a comparison of many hypothetical alternatives to the Foster Wheeler project. Water quality, land use compatibility, historical impacts (the Southeast plant is on the National Historic Register) and even potential project costs were assessed and subjected to public review and comment.

And again, when the EIS was completed, the project was found to be environmentally beneficial and allowed to proceed. On October 28, 1996, the Agency issued an air quality permit to the University.

Steam Plant Performance: Operating Efficiency and Fluctuating Demand


The renovation project selected by the

University was subjected to substantial scrutiny. After seven years of public review, the University, the Environmental Quality Board and the Minnesota Pollution Control Agency agreed that the proposed project would improve air quality and would balance safety, economics and environmental goals. The renovated system has now operated for more than five years and has achieved lower emissions than considered during any part of the review process. We believe that biofuels are another small part of our continued progress towards total system optimization. Coal must continue to be an integral part of the system for the following reasons:

1) The fluidized bed combustor, along with one of the two new gas/oil-fired units, is part of the cogeneration system. Since these are the most efficient units at Southeast, it makes both economic and environmental sense to cogenerate when possible. (The third unit, a medium pressure natural-gas fired boiler, provides steam directly to campus when demand is below the cogeneration system’s operating threshold.)

2) Since steam is provided primarily for heating and cooling, demand is relatively high in the summer and greatest in the winter. Steam demand frequently exceeds the total natural-gas fired capacity at the Southeast plant and other fuels are required.

3) Natural gas supplies are frequently curtailed to large users like the University when regional demand for heating residences and businesses is greatest. During these curtailment periods, the University has two alternative fuel options: burn fuel oil in the natural gas-fired boilers, which

CCOOGGEENNEERRAATTIIOONN IISS SSTTRROONNGGLLYY SSUUPPPPOORRTTEEDD BBYY BBOOTTHH SSTTAATTEE AANNDD FFEEDDEERRAALL OOFFFFIICCIIAALLSS

The renovated Southeast steam plant has the ability to cogenerate both steam and electricity from two new boilers. One is fueled by coal and biofuels and the other uses either natural gas or fuel oil. Cogeneration is very efficient because less energy is wasted than from dedicated electricity production. State and federal officials have both endorsed cogeneration, even if only fossil fuels are used.

Louis Troche is team leader of the U.S. Environmental Protection Agency’s Combined Heat and Power Partnership. He strongly supports the University’s cogeneration system and the use of renewable fuels. Speaking on behalf of the University, Troche writes, “[The University’s efforts to] cogenerate power while addressing concerns about heat-trapping [greenhouse] gases and criteria pollutants are commendable, and evaluating the possibility of burning biomass is a concrete example of their efforts in this area.”

State leaders have also voiced their support for cogeneration, especially if renewable fuels are part of the system. In July 2003, the Minnesota Project, the Minnesota Department of Commerce, and the University of Minnesota’s Regional Sustainable Development Partnerships released, “Designing a Clean Energy Future: A Resource Manual.” Their support for using biomass as a fuel is clear: “When district energy systems include CHP [combined heat and power cogeneration], they can achieve the highest efficiencies. While CHP and district energy systems can utilize renewable energy fuels, they often use fossil fuels. Due to the increased fuel efficiency, even use of standard fossil fuels can have benefits.”


increases emissions, or burn coal and biofuels in the fluidized bed combustor using cutting-edge pollution control with fewer emissions.

4) The University has successfully tested a blend of 35%oat hulls with low sulfur western coal using our existing material handling system. Utilizing the existing coal handling system allows the immediate use of oat hulls as a viable, environmentally friendly and economically advantageous fuel.

5) Our existing solid fuel system is not capable of feeding oat hulls alone into the boiler. Further investigation and testing is necessary to determine the viability of some other means of introducing the oat hulls as a solo fuel source.

For these reasons, coal-firing is an essential part of our energy system. Further restricting coal use beyond the voluntary 70/30 limit will; reduce energy efficiency at the Southeast plant; possibly compromise plant reliability and campus safety; and force the University to operate outside of basic plant design.

Steam Plant Performance: Drastically Lower Emissions Air pollution from our steam plants has

been reduced by more than half since 1996 (the year before the renovation was permitted). Our environmental performance has improved partly because of our reduced reliance on coal. But modern pollution controls and efficient combustion account for the greatest share of the reductions.

Before 1997, steam was produced by burning large quantities of coal in boilers that had only particulate emissions control. Except for two existing units at Southeast,

NNAATTUURRAALL GGAASS SSUUPPPPLLYY IISS AA CCOONNCCEERRNN Many experts are concerned about

regional natural gas supplies through the next decade. This concern was expressed at a recent hearing on the effects of the “Metropolitan Emissions Reduction Project,” a renovation project proposed by Xcel Energy that would convert uncontrolled coal-fired capacity at two Twin Cities power plants to natural gas. The project would increase statewide natural gas demand by 4 to 8 percent, adding stress to an already stretched system.

Andy Weissman, president of Energy Ventures Group, L.L.C., a national “boutique investment firm specializing in the energy industry,” presented his concerns as part of his presentation to the Public Utilities Commission: “Supplies of natural gas available to U.S. market likely to fall massively short of projected U.S. needs every year between 2005 and end of the decade.” He also called the pending natural gas supply crunch a “pending train wreck,” brought about by production declines and a “Shift to natural gas as [a] near-exclusive fuel to meet incremental electricity needs of U.S. economy.”

Maintaining limited fuel flexibility at the University of Minnesota reduces the financial and operating risks of increasing fuel-oil use. By retaining some coal-firing capability, we can operate with lower costs and with less air pollution. And the University still relies much more on natural gas for energy production than Minnesota utilities, which burn coal for 75 percent of their electricity production (see Figure 6 at the end of this document.)


sulfur dioxide emissions were totally uncontrolled. Nitrogen oxides and carbon monoxide emissions from all units were relatively high due to antiquated furnace design. Since the renovation all coal burned in Minneapolis is subjected to acid gas control and modern combustion techniques.

As a result of plant renovations, we have dramatically reduced emissions. For example, annual sulfur dioxide emissions have dropped from 597 tons in 1996 to 12.6 tons in 2001 (a 98 percent reduction), and nitrogen oxide emissions have been reduced by 88 percent [see Figure 2]. For these pollutants emissions have been reduced by more than we have reduced our reliance on coal (about a 65 percent reduction.)

The fluidized bed combustor is our primary coal-fired boiler. It was designed for fuel-flexibility and with state-of-the-art pollution control. Air is injected into the

combustor through a windbox at the bottom of the unit and by tangential blowers surrounding the bed. The swirling, upward action of the air creates an air-bed into which coal, limestone and any biofuel is added. Air, fuel and limestone, are completely and uniformly mixed at low temperatures, reducing nitrogen oxides and carbon monoxide to very low levels. The limestone reacts with chlorine and sulfur contained in the fuel to form particulate sulfides and sulfates which are collected in a baghouse after leaving the unit.

The fluidized bed provides superior environmental performance. In fact, actual coal-fired emissions of nitrogen oxides and carbon monoxide are comparable to permitted emissions from the new gas/oil boilers. The greatest emissions of sulfur dioxide and other acid gases occur when the new package boilers operate on fuel oil [see Figure 3].

Figure 2. Annual Emissions Before and After Southeast Plant Renovation

597

1,371

28012.6

114.2166.8

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600

800

1,000

1,200

1,400

SO2 NOX CO

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1996 2001


Steam Plant Performance: Greater Energy Efficiency Means Less Air Pollution Emissions have been reduced in part

because the new Southeast boilers are very efficient: they produce more steam from each gallon, cubic foot or ton of fuel than the old boilers they replaced. That’s guaranteed. When the design, operation and maintenance agreements were negotiated with Foster Wheeler, the University included incentives (and penalties) for using energy wisely.

Specifically, Foster Wheeler shares the fuel savings when they produce a pound of steam for less than a contract guaranteed amount of fuel. In addition, they agree to charge for no more than 4,500 BTU of fuel for each kilowatt of electricity produced by the new units.

The University also agreed to efficiency guarantees: we are required to return at least 90 percent of the steam generated by Foster Wheeler as condensate water at 160° F, so cold make-up water doesn’t have to be added to the system.

Our fuel-to-steam conversion efficiency has increased by approximately 10 percent with the new plant design. In addition, electricity produced from our cogeneration system reduces the fuel used by area electric utilities by the equivalent 7,700 tons of coal per year.

Greater system efficiencies mean less fossil fuel burned, less money spent and less air pollution.

Figure 3. Actual Fluidized Bed Emission Rates v. Permitted Rates for Oil/Natural Gas Boilers - Southeast Plant

0.171

0.008

0.4555

0.140

0.0166

0.040

0.0000

0.0500

0.1000

0.1500

0.2000

0.2500

0.3000

0.3500

0.4000

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0.5000

SO2 NOX CO

Pollutant

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/MM

Btu

)

Fluidized Bed - Coal Package Boiler - Natural Gas/Fuel Oil


Conservation and Energy Efficiency: Eliminating Demand for Fossil Fuels We are committed to energy

conservation in each and every building at the University of Minnesota. Our program is permanent, fully funded and highly successful.

Our Facilities Management Energy Efficiency Group was founded in 1994, on the heels of U-BEEP, the original University of Minnesota Building Energy Efficiency Program. The Facilities Management group is made up of eight staff members who are responsible for the proper design, operation and maintenance of our energy systems.

The efficiency program has been highly successful; reducing campus steam requirements by nearly 23 percent while total building space has increased by 18

percent [see Figure 4]. Technology, education and staff

diligence have all played a part in the program’s success. Nearly every building is monitored by a centralized data management system. Program staff can quickly respond to changes in building operation. Staff can also compare buildings that are used for similar activities to determine if building upgrades will improve energy performance.

Once upgrades are identified, improvement costs and benefits are calculated. If the improvements can be repaid through energy savings within six years, they are implemented. The University maintains a $6 million revolving fund to upgrade building systems, so capital requests do not have to go through traditional funding obstacles.

New buildings must meet the latest energy code, but the University takes the

Figure 4. Reduced Steam Consumption and Increased Building Space at the University of Minnesota

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500

1,000

1,500

2,000

2,500

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3,500

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

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15,000

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18,500

19,000

Thousands of Square Feet

Steam consumption Building Area


process a step further. Nearly every new building design is subjected to the “Xcel Energy Assets” program, where energy conservation improvements beyond what is required by code are considered.

Finally, we maintain, schedule and operate our building systems to minimize energy consumption. Staff members are trained to identify and fix chronic problems, and all personnel are encouraged to shut things off when they’re not being used. It’s not exactly rocket science, but it is highly effective.

Based on the energy performance of our steam plants and buildings, we estimate that improvements made in the last decade save the equivalent of 45,000 tons of coal from being burned each year.

The University saves the equivalent of 45,000 tons of coal per year from our energy conservation programs and through efficient steam plant design and operation. Regional utilities avoid using another 7,700 tons of coal per year due to cogeneration at our renovated Southeast steam plant.

Fuel Flexibility: Replacing Fossil Fuels with Biofuels at the Southeast Steam Plant Using biofuels at Southeast is not a new

idea because they have always been part of the plant design. The original air emission permit for the renovation included the ability to burn wood, which was the only biofuel available to the University at the time the permit was granted. Other biofuels were not included at that time because very little emissions data is available for other biofuels. We were not

comfortable accepting permit limits for future fuels without a chance to confirm their operational and environmental feasibility.

The University has burned limited but increased amounts of wood in each of the past two years. In fiscal year 2003, 32,000 MMBtu of wood were burned, or about nearly double the 17,000 MMBtu burned the year before. For FY 2003, wood made up 1.5 percent of all fuels used in Minneapolis.

Our ability to use wood has been limited by a lack of available supply at the specifications required by the University and Foster Wheeler. For this reason, the University has been seeking other renewable biofuels to supplement our flexible-fuel mix.

Fuel Flexibility: Oat Hulls as a Biofuel We have now identified oat hulls as

another viable biofuel. Oat hulls are a byproduct that is produced by General Mills at two plants in the metropolitan area. We believe that up to 60,000 tons could be available to the University each year.

General Mills is seeking a customer who can beneficially use oat hulls throughout the year. Based on successful pilot tests this summer, we believe we can use oat hulls to the benefit of the University, General Mills and the environment.

Fuel Flexibility: Successful Pilot Tests and Environmental Performance of Oat Hulls We requested permission from the

Minnesota Pollution Control Agency to test a combination of oat hulls and coal earlier


this year. Up to 4,000 tons of material would be needed to “shake down” operations and to test emissions. Approval was given by the Agency on February 18, 2003, noting that the characteristics of oat hulls and coal are similar. Emission testing was undertaken to evaluate emissions associated with this fuel source

We began pilot operations using a blend of 9 percent oat hulls and 91 percent coal. Emission testing was performed on March 28 after we had become comfortable with the biofuel blend. A similar process was used for a 35 percent blend later in the summer. Each test was successful: the plant operated as required and emissions were well below permitted levels for coal combustion in the fluidized bed [see Figure 5]. Comparable emissions resulted from each test.

Based on results of tests conducted this year, we believe we can burn oat hulls at up to 50 / 50 blend with coal with a new equipment installation. The University is also interested in blending oat hulls with natural gas in the fluidized bed combustor, but we know of no other facility that uses

this combination. Substantial testing with new equipment is required to determine if we can burn oat hulls and gas together. A preliminary estimate of approximately $2,000,000 is required for this equipment.

Unfortunately, testing is not possible before making necessary capital expenditures to modify the plant. Even with modifications, we are not sure that the system will be reliable (an important consideration on a University campus).

Since we have a proven ability to burn the oat hulls with coal, and coal is an integral part of our existing system, we plan to mix oat hulls with coal at this time.

The University could burn up to 15,000 tons of oat hulls per year by blending oat hulls with coal. With new material handling and burner equipment, it is expected that we could burn more than 30,000 tons per year, replacing a similar quantity of greenhouse-gas producing fossil fuels.

Fuel Flexibility: Proposed Permit Conditions for Biofuels

Figure 5. Fluidized Bed Emission Rates Burning Coal and Oat Hull Blends

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Coal 91% Coal/9% Oat Hulls 65% Coal/35% Oat Hulls


We are excited about the test results. We are able to blend renewable biofuels in combination with coal at the Southeast plant, reducing daily coal inputs while complying with permit conditions and closing the carbon cycle on a portion of our energy needs.

To successfully consummate an agreement with General Mills, the University has to be able to accept oat hulls throughout the year. This presents some difficulty for the University, as the fluidized bed combustor is not operated during extended periods in May and October, the periods of lowest steam demand. These periods are best used for routine maintenance of the unit. Otherwise, the fluidized bed is operated without electricity production, and the elevated steam pressure produced by the bed must be reduced without energy recovery.

To resolve the requirement to accept oat hulls throughout the year, we propose to burn the oat hulls in Southeast Units 3 and 4 when the fluidized bed is off-line. These boilers have extremely efficient limestone spray dryers and baghouses that scrub acid gases and collect particulates.

The pilot testing process used for oat hulls was a successful technique for determining operating and environmental performance. Consequently, we request that the process used for oat hulls be formalized as a standard criteria for adding other biofuels in the future. Formalizing the process within our permit will maintain the University’s operating flexibility and avoid unnecessary effort by the MPCA if other biofuels are found to be acceptable in the future.

Fuel Flexibility: Biofuels and Coal

We at the University believe it is important to minimize the combustion of all fossil fuels. Biofuels such as wood and oat hulls are one of a number of actions the University has taken to limit our use of fossil fuels.

The University is not asking for any change to our voluntary limit of using at least 70 percent natural gas and biofuels. We will continue to operate under the voluntary permit limit even though we are allowed to burn more coal under federal and state rules.

Additional restrictions would benefit neither the University or energy conservation in general. With further restrictions we would:

Cogenerate less electricity; Needlessly waste steam pressure; Place greater pressure on an

already stretched regional natural gas system;

Be forced to burn larger quantities of distillate fuel oil than would otherwise be required during periods of natural gas curtailment; and

Operate with greater risk to system reliability and student comfort and safety.

As presented in the previous sections, we stand behind the success of our energy efficiency and conservation programs:

Our new boilers are highly efficient; We cogenerate electricity, which is

encouraged by all levels of government;

We maintain a trained staff and state-of-the art controls to minimize energy consumption at campus facilities;

We already use nearly three times less coal in our fuel mix than state utilities [see Figure 6]; and


We are working to replace a portion of our fossil fuel consumption with renewable biofuels.

Renewable biofuels are encouraged by federal and state governments through legislative requirements, loans and subsidies. Our commitment to biofuels is a response to government’s call.

We believe that conservation and renewable fuels benefit both the University and the community-at-large. We will continue to seek ways to reduce energy consumption through current and new campus-wide initiatives. We ask that

additional biofuels use be permitted at our Southeast steam plant as part of our overall program.

Iowa University recently received approval from the U.S. Environmental Protection Agency to burn oat hulls. According to Iowa Governor Tom Vilsack, “The project is a great example of how cost effective it can be to use an environmentally-friendly fuel source.”

From: Iowa Department of Natural Resources

University of Minnesota Fuel Mix (2001)

Coal, 22%

Natural Gas, 77%

Biomass / RDF, 0%

Fuel Oil, 1%

Other, 0%

Nuclear, 0%

Minnesota Utilities Fuel Mix (2001)

Coal, 75%

Nuclear, 17%

Natural Gas, 1%

Biomass / RDF, 3%

Fuel Oil, 0%

Other, 4%

Figure 6. The University of Minnesota relies more on natural gas than state utilities.

Fuel Chlorine Analysis Page 1 May 26, 2005 University of Minnesota

Solid Fuels Monitoring for Compliance with HCl Emission Limits The University of Minnesota Steam Plant

(EU001 &EU005) May 25, 2005

Minnesota Pollution Control Agency staff intends to expand monitoring requirements for chlorine as part of the University of Minnesota – Twin Cities Steam plant air emission permit amendment to combust biomass in two solid-fuel fired boilers. This submittal presents the University’s proposal for monitoring hydrochloric acid (HCl) emissions when using biomass, as well as the basis for the proposal.

BACKGROUND

The current University air emission permit limits HCl emissions to less than 7 tons per year (TPY), ensuring that the University remains a Hazardous Air Pollutants (HAP) area source. The University has historically demonstrated compliance by measuring coal chlorine content and assuming that all chlorine is emitted to the atmosphere as HCl. (The existing permit includes a provision to combust wood, but contains no emission factor for HCl emissions from wood combustion.)

The pending permit amendment will allow the University to combust a wide variety of biomass fuels, contingent upon a demonstration of compliance with existing permit conditions, including annual HAP emissions. Agency staff wishes to incorporate new requirements for biomass to verify the calculation of a representative HCl emission factor and compliance with the existing HCl emission limit.

Simply measuring fuel chlorine content provides a worst-case estimate, but does not adequately consider the removal efficiency of acid gas control equipment. Both solid-fuel burning boilers – the fluidized bed combustor (EU001) and the spreader-stoker (EU005) – have integrated acid gas control systems which are effective for both sulfur dioxide (SO2) and HCl removal. Sulfur dioxide emissions are continuously monitored for both units.

Neither unit had been tested for HCl emission or removal efficiency until the past year, when performance tests were conducted on EU001 while using different blends of oat hulls and coal. Test results indicated HCl emissions were extremely low. As will be discussed later in this document, HCl removal efficiencies were greater than 99 percent. As a result, the University will be well below the 7 TPY permit limit when operating on either coal or a coal/biomass blend.

PURPOSE AND GOAL

The University proposes that required techniques used to determine annual HCl emissions reflect recent performance test results, including the proven ability of acid gas controls to limit emissions, regardless of solid fuel type. Specifically, the University intends to:

• Conduct initial performance tests on each new biofuel (both air emissions and fuel analyses) as proposed in our permit amendment application.

• Conduct additional performance testing following Agency testing frequency guidance.


• Assure continuous compliance via current continuous monitoring requirements for SO2.

The remainder of this document outlines the relationship between fuel chlorine content and measured emissions, as well as the relationship between HCl and SO2 emissions.

AVAILABLE SITE-SPECIFIC CHLORINE DATA

Subbituminous Coal

Coal chlorine content has been measured each month that coal has been used since the renovated steam plant began operation in 2000 (see Figure 1 for an explanation of the University’s coal sampling protocol). As indicated in Table 1, the average chlorine content is less than 100 ppm at the Southeast steam plant, which equates to annual HCl emissions of approximately 4.4 TPY in 2002, when 48,062 tons of coal was combusted. This estimate is worst-case because; 1) more coal was combusted in 2002 than any other year since the renovation, and; 2) no credit has been given for HCl removal by the acid gas control systems.

Figure 1: COAL SAMPLING CRITERIA

Coal Sampling: collect coal samples according to the most recent version of ASTM D-2234 as described following: Increment Sample Frequency: Collect a sample every 2 hours from each operating boiler from the coal scale for each boiler, by cutting (sweeping) the full width of the free-falling coal stream from the scale feeder belt. Increment Sample Size: the weight of each increment sample size shall be 2 lb. Gross Sample Preparation: Combine the gross samples from each operating boiler to make a total plant gross (composite) sample each day for each steam service facility. Crush and reduce the gross sample as specified in ASTM Method D 2013, Sample Preparation, to form the sample for laboratory analysis. Coal Analysis: analyze the composite sample daily for sulfur content using ASTM D 3177, moisture content using ASTM D 3173 and as received heating value using ASTM D-2015 or D-3286.

Hydrogen Chloride Monitoring: Determine hydrogen chloride emissions by collecting coal samples in an as-fired condition at the inlet to the steam generating units in GP004, combine the samples into a monthly composite, and analyzing the monthly composite for chlorine content, and by collecting a fuel oil sample from the fuel oil storage tank after each delivery of fuel oil and analyzing for chlorine and heat content.


Table 1. SE Plant Composite Coal Sample Data Proximate Analysis (% wt as received) HHV Ultimate Analysis (% wt as received)

Month Moisture Ash VM FC Btu/lb C H N O S Cl

% % % % % ppm

Jan-00 25.18 4.71 36.68 33.43 9,024 51.79 2.97 0.61 14.51 0.23 100 Feb-00 24.15 4.72 35.22 35.91 9,211 53.46 3.13 0.87 13.50 0.18 40

Mar-00 25.16 4.28 32.56 38.00 9,104 52.27 3.09 1.04 13.94 0.23

Apr-00 24.92 4.38 32.62 38.08 9,130 52.06 3.23 0.89 14.31 0.22 100 Nov-00 29.48 4.19 30.31 36.02 8,418 48.68 3.21 0.84 13.40 0.19 410

Dec-00 27.48 4.22 30.62 37.68 8,777 50.96 3.36 0.90 12.91 0.17 100

Jan-01 25.86 4.35 31.77 38.02 8,952 50.40 4.07 0.95 14.17 0.21 70 Feb-01 25.60 4.19 33.58 36.62 9,092 51.55 3.51 0.86 14.07 0.22 76

Mar-01 27.42 4.54 34.67 33.37 8,586 49.86 3.31 1.61 13.06 0.19 100

Jan-02 26.60 4.49 9,024 50.69 3.44 0.93 13.64 0.28 120 Feb-02 27.53 3.93 33.85 34.68 8,804 50.84 3.93 0.90 13.14 0.22 <100

Mar-02 27.59 4.51 31.66 36.25 8,679 49.96 3.52 0.94 13.21 0.27 200

Nov-02 26.48 4.56 31.14 37.82 8,846 51.05 3.42 0.83 13.41 0.24 100 Dec-02 27.91 4.50 30.67 36.92 8,671 49.86 3.30 0.80 13.44 0.20 <50

Jan-03 24.70 4.78 32.83 37.68 8,749 50.44 3.77 0.92 15.14 0.24 60

Feb-03 28.82 5.13 31.69 34.37 8,283 48.00 3.25 0.68 13.97 0.16 82 Mar-03 22.97 4.76 33.99 38.28 9,094 52.59 3.47 0.94 15.10 0.18 220

Apr-03 23.66 4.62 34.56 37.16 8,759 51.36 3.48 0.88 15.74 0.26 210

Nov-03 25.73 4.39 32.43 37.45 8,861 52.27 3.57 0.69 13.13 0.21 <100 Dec-03 23.88 4.04 33.59 38.49 9,045 52.46 3.67 0.71 15.05 0.19 <100

Jan-04 25.95 4.47 33.08 36.50 8,757 50.32 3.44 0.69 14.91 0.21 <100

Jan-04 23.92 4.60 33.87 37.61 8,998 52.63 3.64 0.68 14.32 0.20 <100 Feb-04 24.81 5.96 32.59 36.64 8,743 49.85 3.50 0.71 15.00 0.19 <100

Mar-04 26.20 5.33 31.95 36.52 8,559 48.04 3.70 0.68 15.90 0.18 <100

Dec-04 27.63 4.37 31.52 36.48 8,629 50.97 3.66 0.71 12.43 0.23 <100 Jan-05 27.17 3.93 31.92 36.98 8,651 51.10 3.68 0.69 12.82 0.20 <100

Feb-05 28.08 3.92 30.85 37.15 8,537 51.37 3.76 0.57 12.13 0.17 <100

Mar-05 28.29 3.94 30.87 36.90 8,498 51.04 3.77 0.53 12.25 0.18 <100

AVERAGE 26.18 4.49 32.63 36.70 8,803 50.92 3.49 0.82 13.88 0.21 91.54


Oat Hulls & Coal/Oat Hull Blend – Fuel Analyses

A total of 16 samples have been analyzed by the University of Minnesota for biomass chlorine: 11 samples were analyzed by Interpoll Laboratories prior to the initial draft permit amendment request submitted in December 2002. In addition, one composite sample was analyzed as part of the air emission performance test conducted on August 29, 2003, and one composite oat-hull sample and three samples of the coal/oat hull blend were analyzed as part of the emission performance test conducted on March 28, 2003 (one per test run). Analytical results are presented in Table 2.

Table 2. Solid Fuel Chlorine Content (as-received) Sample

Date Sample Type Sample ID Chlorine (%)

7/3/2002 Ground Oat Hulls 17558-01 0.130 7/3/2002 Ground Oat Hulls 17558-02 0.170 7/3/2002 Ground Oat Hulls 17558-03 0.170 7/3/2002 Ground Oat Hulls 17558-04 0.180 7/3/2002 Ground Oat Hulls 17558-05 0.120 7/3/2002 Unground Oat Hulls 17558-06 0.110 7/3/2002 Unground Oat Hulls 17558-07 0.110 7/3/2002 Unground Oat Hulls 17558-08 0.100 7/3/2002 Unground Oat Hulls 17558-09 0.110 7/3/2002 Unground Oat Hulls 17558-10 0.140 7/3/2002 Unground Oat Hulls 17558-11 0.088 1/13/2003 Coal <0.01 1/29/2003 Oat Hulls 0.100 3/28/2003 9% Oat Hull Blend Run 1 0.013 3/28/2003 9% Oat Hull Blend Run 2 0.011 3/28/2003 9% Oat Hull Blend Run 3 0.010 8/21/2003 34.4% Oat Hull Blend Test 1 0.025

As indicated, the chlorine content range for oat hulls is relatively narrow, with a maximum content of 1,800 ppm (0.18%).

Coal/Oat Hull Blend – Air Emission Tests

HCl emissions were measured for three test runs during each of the two performance tests conducted on EU001 in 2003. As shown in Table 3, emissions are extremely low, indicating high removal efficiencies. In fact, HCl emissions were below detection limits during the August test. Typically, the estimated emission rate is assumed to be one-half of analytical detection limits, so the emission factor and estimated annual emissions given in Table 3 are overestimates.

Assuming worst-case fuel chlorine content and the maximum blend of oat hulls, annual HCl emissions are estimated to be 0.27 TPY.


Table 3. HCl Emission Calculations 9% Oat Hulls, 91% Coal 3/28/03 3/28/03 3/28/03 3/28/03 Run 1 Run 2 Run 3 Average Stack Flow, DSCFM 57878 56471 56141 56830 Fuel Chlorine, % 0.013 0.011 0.010 0.011 Fuel Input, lb/hr 30329 30366 30364 30353 Fuel Chlorine Input, lb/hr 3.94 3.34 3.04 3.44 HCl Emissions, mg/dscm 0.03444 0.03451 0.03204 0.03366 HCl Emissions, ppm,d 0.0227 0.0228 0.0211 0.0222 HCl Emissions, lb/hr 0.00747 0.00730 0.00674 0.00717 Cl Emissions, lb/hr 0.00726 0.00710 0.00655 0.00697 Removal Efficiency, % 99.82 99.79 99.78 99.80 Emission Factor, lb HCl/ton fuel 0.00048 0.00047 0.00043 0.00046 34.4% Oat Hulls, 65.6% Coal 8/21/03 8/21/03 8/21/03 3/28/03 Run 1 Run 2 Run 3 Average Stack Flow, DSCFM 58063 59740 59307 59037 Fuel Chlorine, % 0.00025 * * Fuel Input, lb/hr 31611 31649 31686 31649 Fuel Chlorine Input, lb/hr 0.08 * * HCl Emissions, mg/dscm** 0.53988 0.62857 0.47716 0.54854 HCl Emissions, ppm,d** 0.3560 0.4144 0.3146 0.3617 HCl Emissions, lb/hr** 0.1174 0.1407 0.1060 0.1214 Cl Emissions, lb/hr** 0.1142 0.1368 0.1031 0.1180 Removal Efficiency, % *** *** *** HCl Emission Factor, lb/ton fuel** 0.00722 0.00864 0.00651 0.0075 * fuel analyses for all were runs were combined into one composite sample ** it appears that emissions were below detection levels, so actual values would be below the values indicated *** % removal can't be determined due to detection levels higher than fuel chlorine input and lack of fuel chlorine content Average Minimum Maximum Oat Hull Cl Content, mg/kg* 1298 880 1800 Oat Hull Cl Content, % 0.1298 0.088 0.18 *From 12/19/02 test burn application Worst-Case Scenario Oat Hull Cl Content, mg/kg 1800 Oat Hull Cl Content, lb/ton 3.60 Uncontrolled HCl Emissions, lb/ton 3.70 Control Efficiency, % 99.8 HCl Emission Factor, lb/ton fuel 0.0076

Source: Based on table provided by Steven Pak, MPCA


DEVELOPING AN EMISSION FACTOR: PERFORMANCE TESTING AND CONTINUOUS EMISSION MONITORING

SO2 emissions were continuously monitored during all HCl performance tests. Average SO2 concentrations were similar for each test run and each testing period – 0.002 lb/MMBtu (0.035 lb/ton). Continuous monitoring during 2002 and 2003, while burning coal, measured a higher average emission rate of 0.0143 lb/MMBtu (0.250 lb/ton coal). Assuming a linear relationship between HCl and SO2 control, a reasonable emission factor for HCl emissions from the coal/oat hull blend is:

HClEF = HClTEST x ( SO2CEM / SO2TEST )

0.0076 x (0.250 / 0.035) = 0.054 lb/ton

@ 46,429 TPY coal + 25,000 TPY oat hulls = 71,429 TPY coal/oat hull blend

HClANNUAL = 0.054 x 71,429 / 2,000 = 1.93 TPY HCl

(Calculations assume that emissions from EU005 will equal emissions from EU001. An actual emission factor for EU005 will be calculated as a result of future performance testing.)

Based on these calculations, the University requests that the default emission factor for HCl be set at 0.054 lb/ton of 34.4% coal/oat hull blend.

A similar relationship was found during research conducted under EPA contract at a 160 MW coal-fired atmospheric fluidized bed combustor in 1994. SO2 emissions ranged from 106 to 206 ppm, while HCl emissions from non-detectable to 0.035 ppm. (see http://www.epa.gov/ttn/emc/ftir/reports/r07.html) Comparably low emissions were found during emission tests on a bubbling fluidized bed reactor firing sludge and wood waste (see attached report: “Bubbling Fluid Bed Boiler Emissions Firing Bark and Sludge.”)

SUMMARY

The Univerisity requests that an emission factor of 0.054 lb/ton biomass be incorporated into the permit. Compliance will be assured by proper operation of the acid gas control system as measured by the sulfur dioxide continuous emission monitor for EU001. A different emission factor will be calculated for EU005 based on future performance testing in accordance with amended permit conditions.


CONFIRMATION OF WOOD CHLORINE CONTENT

Agency staff has requested a review of wood chlorine content to ensure that the biomass emission factor is relevant. The following table, extracted from a literature review database, indicates that untreated wood contains chlorine at much lower levels than oat hulls.

Table 4. Literature Search: Chlorine Content by Wood Species

Wood Species Chlorine Content Phyllis Reference ID

Birch and maple: 0.027% (68)

Oak, birch and maple: 0.018% (106)

Mixed hardwood chips: 0.029% (250)

Pine chips: 0.02% (1786)

Pine chips (including bark): 0.007% (1269)

Hybrid poplar: 0.009% (806)

Source: Energy Research Center of the Netherlands, Phyllis Database, found at: http://www.ecn.nl/phyllis/

University of MinnesotaSoutheast Steam Plant

MPCA-derived HCl Emission Factor

9% Oat Hulls, 91% Coal 3/28/03 3/28/03 3/28/03 3/28/03Run 1 Run 2 Run 3 Average

Stack Flow, DSCFM 57878 56471 56141 56830Fuel Chlorine, % 0.013 0.011 0.010 0.011Fuel Input, lb/hr 30329 30366 30364 30353Fuel Chlorine Input, lb/hr 3.94 3.34 3.04 3.44HCl Emissions, mg/dscm 0.03444 0.03451 0.03204 0.03366HCl Emissions, ppm,d 0.0227 0.0228 0.0211 0.0222HCl Emissions, lb/hr 0.00747 0.00730 0.00674 0.00717Cl Emissions, lb/hr 0.00726 0.00710 0.00655 0.00697Removal Efficiency, % 99.82 99.79 99.78 99.80Emission Factor, lb HCl/ton fuel 0.00048 0.00047 0.00043 0.00046

34.4% Oat Hulls, 65.6% Coal 8/21/03 8/21/03 8/21/03 3/28/03Run 1 Run 2 Run 3 Average

Stack Flow, DSCFM 58063 59740 59307 59037Fuel Chlorine, % 0.00025 * * Fuel Input, lb/hr 31611 31649 31686 31649Fuel Chlorine Input, lb/hr 0.08 * * HCl Emissions, mg/dscm** 0.53988 0.62857 0.47716 0.54854HCl Emissions, ppm,d** 0.3560 0.4144 0.3146 0.3617HCl Emissions, lb/hr** 0.1174 0.1407 0.1060 0.1214Cl Emissions, lb/hr** 0.1142 0.1368 0.1031 0.1180Removal Efficiency, % *** *** *** HCl Emission Factor, lb/ton fuel** 0.00722 0.00864 0.00651 0.0075* fuel analyses for runs 2 and 3 not included in test report** it appears that emissions were below detection levels, so actual values would be below the values indicated *** % removal can't be determined due to detection levels higher than fuel chlorine input and lack of fuel chlorine content

Fuel Chlorine Content, mg/kg Average Minimum MaximumOat Hull* 1298 880 1800Coal** 40 410Wood*** < 100 1900* SE Plant analyses of 11 samples included in 12/19/02 test burn application** January '00 thru March '05 SE Plant composite coal sample data*** Alkali Deposits Found in Biomass Power Plants: A Preliminary Investigation of Their Extent and Nature

Worst-Case ScenarioFuel Cl Content, mg/kg 1900Fuel Cl Content, lb/ton 3.80Uncontrolled HCl Emissions, lb/ton 3.91Control Efficiency, % 99.0HCl Emission Factor, lb/ton fuel 0.0391 *

The EF of 0.054 lb HCl/ton fuel proposed by the U of M is acceptable since it would result in a higher estimate of HCl emissions.

Form GI-07 Page 1 of 4


PERMIT APPLICATION FORM GI-07 FACILITY EMISSIONS SUMMARY

5/26/98

1) AQ Facility ID No.: 05301050 2) Facility Name: University of Minnesota/Foster Wheeler Twin Cities - Steam Plants

3a)

3b) 3c) CAS#: CAS#: CAS#:

Emission

Emission

3d) Pollutant Name: CO Pollutant Name: PM10 Pollutant Name: SOx

Source Source 3e) 3f) Type ID No. Potential Actual Potential Actual Potential Actual

Lbs per Hr

Unc tpy

Lim tpy

Tons per yr

Lbs per Hr

Unc tpy

Lim tpy

Tons per yr

Lbs per Hr

Unc tpy

Lim tpy

Tons per yr

EU 001 70.75 13.09 4.78 4.62 96.10 6.07

EU 002 20.78 9.00 9.06 0.09 267.60 6.49

EU 003 (b) 43.37 9.64 4.15 (b) 13.33

EU 004 5.75 0.00 1.01 0.00 56.78 0.00

EU 005 52.34 0.61 0.95 0.08 62.83 0.75

GP (a) 001 280.9 31.8 248.9

EU (d) 024 0.08 0.34 0.05

EU (d) 025 0.0013 0.0057 0.0008

4) Potential Actual Potential Actual Potential Actual Total Unc Lim Yr Unc Lim Yr Unc Lim Yr

Facility 280.9 66.07 32.1 9.76 248.9 26.64



PERMIT APPLICATION FORM GI-07 FACILITY EMISSIONS SUMMARY

5/26/98

1) AQ Facility ID No.: 05301050 2) Facility Name: University of Minnesota/Foster Wheeler Twin Cities - Steam Plants

3a)

3b) 3c) CAS#: CAS#: CAS#:

Emission

Emission

3d) Pollutant Name: NOx Pollutant Name: TSP Pollutant Name: VOC

Source Source 3e) 3f) Type ID No. Potential Actual Potential Actual Potential Actual

Lbs per Hr

Unc tpy

Lim tpy

Tons per yr

Lbs per Hr

Unc tpy

Lim tpy

Tons per yr

Lbs per Hr

Unc tpy

Lim tpy

Tons per yr

EU 001 58.96 * 82.45 4.78 * 4.63 3.98 1.86

EU 002 72.75 9.89 9.06 1.08 1.01 0.60

EU 003 (b) 43.28 9.64 4.47 1.07 2.87

EU 004 198.74 0.00 1.01 0.00 0.51 0.00

EU 005 146.61 1.07 0.95 0.08 0.56 0.01

GP (a) 001 734.8 32.9 31.2

EU (d) 024 0.14 0.61 0.08

EU (d) 025 0.005 0.023 0.003

4) Potential Actual Potential Actual Potential Actual Total Unc Lim Yr Unc Lim Yr Unc Lim Yr

Facility 734.8 136.69 33.5 10.26 31.2 5.34


(a) – GP001 includes EU006, St. Paul - Medium Pressure Package Boiler, which is not affected by the proposed amendment. (b) – Allowable emissions (lb/hr) are regulated as combined emissions of EU002 and EU003 (c) – Actual emissions are represented as average emissions for 2002 and 2003. (d) – From Scenario 3, Oat Handling Emissions. Potential emissions are limited by capacity of EU001. Actual emissions estimated based

on projected annual boiler operation. Therefore, these emissions are not included in the baseline actual tpy.

Form GI-05D Page 1 of 2


PERMIT APPLICATION FORM GI-05D FUGITIVE EMISSION

SOURCE INFORMATION 5/26/98

1) AQ Facility ID No.: 86TC 2) Facility Name: University of Minnesota and Foster Wheeler Twin Cities, Inc.

3a) 3b) 3c) 3d)

Fugitive Source ID

No.

Pollutant Emitted

(particulate matter (PM)

or VOC)

Control Equip ID

No. Description of Fugitive Emission Source

PM , PM-10 Unloading Dock - Fugitive Dust Plan will be revised for the pneumatic system as noted below

The Biomass Unloading Dock will receive biomass materials from fully enclosed walking floor trucks. The

biomass fuel will be transferred pneumatically from the unloading dock to a silo that will be constructed inside of

the heating plant. All subsequent transfer will occur inside the facility. All tasks associated with this process are

generated from the MP-2 Maintenance Management System

a. During transfer of biomass from the truck to the silo, a Foster Wheeler employee will be present to ensure

that the pneumatic system with associated dust control devices is fully operational to minimize any fugitive

emissions.

b. Biomass transfer points including, but not limited to, truck unloading and baghouse will be scheduled for

daily cleaning to recover dust.

c. Preventative maintenance procedures to ensure proper operation of the dust collection system is performed

daily, weekly and monthly, etc. as required.”



INSTRUCTIONS FOR FILLING OUT AQ FORM GI-05D Fugitive Emission Source Information

Fugitive emissions are air emissions outside of your building which cannot reasonably pass through a stack, chimney, vent or other equivalent opening. Examples of fugitive emission sources include coal or sawdust piles, gravel roads, and outdoor VOC/HAP service valves, pumps, and flanges. Emissions inside a building that do not pass through a stack are not fugitive emissions. These emissions should be assigned to a building vent and reported as stack emissions on the Stack/Vent Information Form (GI-04), and the Emission Unit Description Form (GI-05B).

1) AQ Facility ID No. -- Fill in your Air Quality Facility ID Number as indicated on the

Facility Information Form (GI-01), item 1a. 2) Facility Name -- Enter your facility name as indicated on the Facility Information Form

(GI-01), item 2. 3a) Fugitive Source (FS) ID No. -- Number all sources of fugitive emissions at your facility

beginning with FS ID No. 001. Sources may be grouped together and given a common number if appropriate (for example, for VOC/HAP service valves, flanges, pumps, etc.). The ID numbers used on this form must be consistent with any references to Fugitive Source ID numbers on other forms.

3b) Pollutant Emitted -- Enter the name(s) of the fugitive pollutant(s) emitted. 3c) Control Equipment (CE) ID No. -- The Control Equipment ID number can be obtained

from the Pollution Control Equipment Information Form (GI-05A). In general, emissions vented through control equipment are not fugitive emissions. An example would be a water spray bar at the end of a conveyor used to transfer material onto an outdoor storage pile. If this does not apply, leave the Control Equipment ID number column blank.

3d) Description of the Fugitive Emission Source -- Describe the fugitive emission source in

sufficient detail to identify this source at the facility, for example, coal stockpile, road from mine to North Crusher, etc.

Documents

AIR EMISSION PERMIT NO. 05301050-021 [AMENDMENT TO AIR