# A TTACHMENT 

# 21 BEST AVAILABLE RETROFIT TECHNOLOGY

AT EGU FACILITIES

July 1, 2011

WISCONSIN DEPARTMENT OF NATURAL RESOURCES

101 South Webster Street

Box 7921 Madison, Wisconsin 53707-79212 Statement of Purpose

This document provides the draft findings for external review of implementing Best Available Retrofit Technology (BART) requi rements for electric generating utility (EGU) sources in Wisconsin. After modeling the potential visibility impairment of BART-eligible sources, the De partment finds nine EGU s ources subject to BART.

Boilers located at these sour ces are affected under the BART source category of fossil fuel boilers greater the 250 mm btu/hr. All of the EGUs foun d subject to BART are also subject to the Clean Air Inte rstate Rule (CAIR) under 40 CF R part 97, and therefore are not required to conduct a BART an alysis for sulfur dioxide (SO 2 ) and nitrogen oxide (NO

x ) emissions. However, these sources are required to conduct a BART analysis for particulate matter (PM).

The Department is proposing BART control of optimization of existing baghouses and electrostatic precipita tors at the EGU sources. BART control for baghouses achieves greater than 99% removal efficiency, while BART control for all but one electrostatic precipitator achieves greater than 98% removal efficiency. These proposed sourcespecific BART requirements are subject to review and comment by Federal Land Managers for the Class I areas, the US EPA, the affected source, and other interested parties. This feedback is used in order to inform the Department’s final decision on the

BART determination.

Introduction

Under the Clean Air Act, individual states are required to esta blish a plan and air pollution control program which mitigates current impacts and protects the visibility of

certain federal Class I areas. For Wisconsi n, the primary Class I areas include Boundary Waters Wilderness Area, Voyageurs National Park, Seney National Wildlife Refuge, and Isle Royal National Park (Appe ndix A). These visibility po llutant control programs are also frequently referred to as regional haze requirements or regional haze control programs. The pollutants emitted by Wisconsin stationary sources having the greatest impact on Class I area visibility are part iculate matter (PM) and gaseous pollutants including sulfur dioxide (SO 2 ) and oxides of nitrogen (NO

x ) that transform or react into small particles in the atmosphere. Other air pollutants includi ng ammonia and volatile organic compounds take part in formation of small particles, but their emission levels from these sources is proportionally much lo wer and less important to haze formation.

A core federal requirement for addressing vi sibility impairment at the federal Class I areas is the implementation of a control progr am for certain stati onary sources known as

Best Available Retrofit Tec hnology (BART). This BART c ontrol requirement addresses older sources that do not have air pollution control equipment and which are shown to directly affect visibility at the Class I area s. The federal requirements for identifying sources subject to BART, and the methods fo r determining appropriate emission control requirements, are set forth by the US EPA under 40 CFR Part 51, Appendix Y, Guidelines for BART Determinati ons Under the Regional Haze Rule

.3 In January 2008, the state adopt ed rules under ch. NR 433, Wis. Adm. Code, in order to meet the federal BART requirements. The st ate rule establishes a process for sources subject to BART to submit an analysis of potential pollution c ontrol technologies and

their installation cost and issues. This an alysis supports the De partment in making a determination of BART control requirements specific to the facility. Sources must implement BART requirements by December 31, 2013. The Department is currently proposing a rule modification to extend th e compliance date to December 31, 2015. The purpose of the modification is to allow fo r more complex installations of pollution control equipment that would enab le enhanced emission reductions.

Identified BART-eligible sources

The Department identified 12 Wisconsin EGU sources as BART-eligible, listed in Table 1. BART-eligible sources include those sources th at meet all of the criteria (listed below) as set by the Clean Air Act. These criteria are intended to identify older emission sources which likely do not have pollutant control sy stems and which also have a substantial remaining operating life. The criteria also identify sources which emit pollutants in quantities that may negatively affect visibility. These BA RT-eligible sources identify a core set of stationary sources which each state must address as a first step in any plan for regional haze and visibility protection. Th e BART requirement is not intended to be exhaustive of stationary sources that wa rrant control for meeting overall haze and visibility requirements.

• The source or emission unit(s) falls with in one of 26 source categories (Appendix B).

• The emission unit(s) was installed by A ugust 7, 1977, but not in operation before August 7, 1962.

• The source or emission unit(s) potential to emit for any single visibility-impairing pollutant is greater than 250 tons per year given its physical and operational design, and considering all federally en forceable and State enforceable permit

limits.4Table 1. Wisconsin EGU Sourceswith BART-eligible UnitsEmissions (grams/s)BART SourceCategoryPotential WI BART Facilities Eligible Emission UnitsSO2NOxPM10Modeled VisibilityImpairment(No. days > 0.5deciview)Alliant Energy – ColumbiaB-01,021266.1710.234.472WP & L Alliant Energy –EdgewaterB-244235011349Alliant Energy – Nelson DeweyB-22478751815Dairyland Power Coop – AlmaB-25613.2150.45.440Dairyland Power Coop – GenoaB-202411.2155.518.563Madison Gas & ElectricCompany – Blount StreetB-20,21,22,23 23.1 24.5 1.30Manitowoc Public Utilities B-27 93.2 32.6 17.55Wisconsin DOA / UW Madison –Charter StreetB-25 100.2 28.4 18.9 2We Energies – Oak CreekB-27,282087.0182.66.562We Energies – Pleasant Prairie *B-21,22----We Energies – ValleyB-21,22,23,241398.5445.864.064Fossil-fuel firedsteam electricplants of more than250 million Britishthermal units (Btu)per hour heat inputWisconsin Public ServiceCorporation – JP Pulliam PlantB-27797.3247.214.173* Pleasant Prairie self-identified as BART-subject.5 Sources Subject to BART

The next step in the BART process is to determine which BART-eligible sources cause substantial impairment to visibility at Class I ar eas. Such a source is subject to BART (BARTaffected), and as such must be eval uated for BART control requirements.

The Department used the CALPUF F air quality model to model th e source's emissions in order to determine the visibility impairment on a class I area. If the modeled re sults show a significant reduction in visibility, the source is subject to BART or "BART-a ffected". Overall, how much a source's emissions impair the visibility of a Cla ss I area is dependent on the type and amount of emissions, the distance to the receptor Class I area, and the prevalent meteorological conditions. Wisconsin stationary sources primarily affect visibility at the follo wing nearby Class I areas: Boundary Waters Wilderness Area, Voyageurs Na tional Park, Seney National Wildlife Refuge, and Isle Royal National Park (Appendix A). Emi ssions from Wisconsin stationary sources also affect other Class I areas, but m odeling indicates the duration and frequency of such visibility impacts are minimal.

The protocol for the CALPUFF modeling and thre shold for determining if a source is BARTaffected is as follows:

• A source is BART-affected if the modeled reducti on in visibility at any individual Class I area based on the facility modeled is greater than 0.5 deciviews (dv) for more than 2% of the year (7 days) as compared to the natural background visibility.

• The amount of emissions modeled is the aggreg ate of all visibility impacting pollutants (PM 10 , SO 2 , NO

x , Ammonia, VOCs) emitted from all of the BART-eligible emission units at a source. The amount of emissions modeled is the maximum actual daily emission rate based on operations during the cale ndar years of 2002, 2003, and 2004, if available and approved by the Department, or the source’s potential to emit. Since the intent is to quantify the impairment due to the BART-eligible sources, pollutants emitted from any other emission

units at the source are not include d in the modeling analysis.

• The modeling process measures the reduction in visibility versus the natural background of visibility. This background visibility set in the CALPUFF modeling is by default the average of the natural background visibility during the 20% best visibility days. The LADCO protocol discusses this approach to a pplying the CALPUFF model in more detail. 1

Based on these procedures, the Department determined nine EGU sources in Wisconsin to be BART-affected, listed in Table 2.

1 “ Single Source Modeling to Support Regional Haze BART Modeling Protocol.” March 21, 2006. Lake Michigan
Air Directors Consortium, Des Plaines, IL.6 Table 2. Wisconsin EGU Sources with Units Subject to BART.

WI BART Faciliti es Emission Units

Alliant Energy – Columbia B-01,02

Alliant Energy – Nelson Dewey B-22

WP & L Alliant Energy – Edgewater B-24

Dairyland Power Coop – Alma B-25

Dairyland Power Coop – Genoa B-20

We Energies – Oak Creek B-27,28

We Energies – Pleasant Prairie B-21,22

We Energies – Valley B-21,22,23,24

Wisconsin Public Service Corporation – JP Pulliam B-27

The CALPUFF modeling showed that the BART-eligi ble fossil fuel boilers at these facilities, when operating at potential maximum emission leve ls, could impair visibility in at least one Class I Area by more than 0.5 dv for greater than 7 days in any one year. For each of the other sources listed in Table 1, the modeled visibili ty impacts do not exceed 0.5 dv for more than 7 days in any one year, and th erefore are not BART-affected.

Determination of BART controls

Once a source is subject to BART, the Departme nt must determine the appropriate control requirements for that specific source; i.e. BART c ontrols are determined on a case-by-case basis.

To make this determination the state BART rule requires that an affected source submit to the Department an analysis of the applicable pollutant c ontrol options and a proposed BART level of control for each visibility-imp airing pollutant. The Department is then required to propose a BART level of control and associated complian ce requirements. Final BART requirements are determined based on stakeholder and public input, and incorporated into a facility's Title V operating permit.7 The determination of BART control requirement s for each source is based on five factors:

(1) The costs of compliance. (2) The energy and non-air environmental impacts. (3) Any existing pollution control technology in use at the source. (4) The remaining useful life of the source. (5) The degree of improvement in visibility whic h may reasonably be anticipated to result from the use of the technology.

All of the EGUs found subject to BART are also s ubject to the Clean Air In terstate Rule (CAIR) under 40 CFR part 97, and therefor e are not required to conduct a BART analysis for sulfur dioxide (SO 2 ) and nitrogen oxide (NO

x ) emissions. However, these sources are required to conduct a BART analysis for particulate matter (PM).

All of the BART-affected EGUs have high effi ciency control equipment (approximately 95% PM control and higher) currently in-use for particulate matter. In cases where emission controls are in place the federal BART program requires that, at a minimum, the BART determination consider the "betterment of existing control e quipment". This betterment considers if the equipment is being operated in the best manner possi ble or if there are modifications that can be made, so as to update the equipment comparable to current installations. In Wisconsin, the only cases requiring a betterment analysis are existi ng installations of baghous es and electrostatic precipitators (ESP) which are us ed for controlling particles a nd meeting opacity requirements.

The Department conducted an analysis of PM re ductions at several BART units in the state. These units were equipped with either baghouses or ESPs. The Department assessed the extent of visibility improvement using CALPUFF by re ducing currently reported PM emissions from these units (Appendix C). Based on this evaluation, the Department found that the visibility improvement resulting from reduction in PM em issions is not significant. The cost of incremental visibility improvement is also like ly to be very high for additional PM control by modifying the existing equipment configuration. For these reasons, the Department determined that sources with high efficiency PM controls su ch as a baghouse or an ESP meet a BART level of control technology, and proceeded to evaluate th e potential for “betterment of control” at each

unit.

The Department then allowed BART-affected sour ces to make an abbreviated PM related BART submittal, if the PM control equipment is intende d to continue operating in the future. This submittal included the following items: • Description of the type of PM control equi pment used, along with the range of collection efficiency expected from the pr operly operated control equipment. • Installation date of the equipment. • Answer the question: "Can existing PM contro l efficiency be improved without modifying the existing equipment configuration?" • Maintenance procedures for the equipment. • Description of PM rela ted emission monitoring. • Estimate of the remaining useful life of the BART unit.89 Proposed BART requirements

Each EGU source subject to PM BART submitted an analysis of potential control options for the BART-affected fossil fuel boiler(s) at the facility. These analyses may be found in Appendix E. Based on the submitted analyses, and consideration by the Department of available controls, costs, and visibility impair ment in keeping with the Guidelines , the Department is proposing

BART emission limitations for the boilers at thes e sources. A summary of this analysis is presented here. The Department's determina tion of BART for each EGU source is described more fully in Appendix C.

Visibility Improvement

DNR used the changes in visibility impairment fo r Seney National Wildlife Refuge Class I area, quantified using the CALPUFF model, to evaluate the effectiveness of additional PM controls at

the EGUs. DNR used 100% PM 10 control as an extreme for addi tional control from the baseline

maximum actual or PTE PM 10 emissions. Additional detailed assumptions and results for BART visibility modeling for the different facilities are found in Appendix C. One basis for measuring visibility impacts is the relative improvement in the maximum day visibility impairment. The other measure of visibility improvement evaluated is the number of days for which a change in visibility due to the BART controls can be qua ntified. This metric indicates the relative frequency and depth in visibility improvement.

ESPs

After applying additional PM 10 controls up to 100% at ESPs, the modeled improvement from the baseline maximum visibility impairment is 0.01 dv or less at all but one boiler unit. The modeling result with additional controls at the JP Pulliam boiler unit showed an improvement in the baseline maximum visibility of 0.02 dv. The number of days with a maximum visibility impairment of 0.1 dv or greater had a reducti on of only 1 day or less for each boiler unit.10Table 4. Modeled Visibility Improvements Resulting from Additional PM Control for ESPs (2002-2004 baseline)Visibility Impairment based on CALPUFF2002-2004 Baseline100% PM10Control onBART BoilersCalculated VisibilityImprovementBoiler UnitPM10ControlEfficiency (%)Max daydvaDays => 0.1dvbMax daydvaDays => 0.1dvbMax day dvimprovementDays =>0.1 dvAlliant EnergyColumbia – B21 96.4Columbia – B22 972.93 106 2.95-2.93 = 0.02108 - 106 =2Edgewater – B24c94.9 2.94 107 2.95-2.94 = 0.01108 - 107 =1Nelson Dewey – B22c952.95 1082.94 107 2.95-2.94 = 0.01108 - 107 =1WE EnergiesOak Creek – B2799.92 < 0.01 (est.) < 1 (est.)Oak Creek – B2899.77Not modeled< 0.01 (est.) < 1 (est.)Pleasant Prairie – B2199.91 < 0.01 (est.) < 1 (est.)Pleasant Prairie – B2299.75Not modeled< 0.01 (est.) < 1 (est.)Wisconsin Public Service CorporationJP Pulliam – B27c98.95.17 153 5.15 152 5.17-5.15 = 0.02153 - 152 =1aMaximum day visibility impairment measured in deciviews (only calculated at the Seney Class I area).bNumber of days with maximum visibility impairment => 0.1 deciviews.cAdditional non-BART boiler emissions were included in the modeling, but are assumed to not change the visibility improvement associated withadditional PM reductions from the BART boilers.11 Baghouses

After applying additional PM 10 controls up to 100% at baghouses, the modeled improvement from the baseline maximum visibility impairment is 0.01 dv or less for each boiler unit. The number of days with a maximum visibility im pairment of 0.1 dv or gr eater had a reduction of only 1 day or less for each boiler unit.

Table 5. Modeled Visibility Improvement Re sulting from Additional PM Control for Baghouses (2002-2004 baseline)

Visibility Impairment based on CALPUFF

Baseline 100% PM 10 Control on

BART Boilers Estimated Visibility Improvement

Boiler Unit

PM 10 Control Efficiency (%) Max day

dv b Days

=> 0.1

dv c Max day dv

b Days

=> 0.1

dv c Dv improvement Days

=> 0.1

dv

Dairyland Power Coop

Alma Station – B25 a 98.36 Not modeled < 0.01 < 1

Genoa Station – B20 a 97.67 Not modeled < 0.01 0 – 1

We Energies

Valley Station – B21 99.86 0.01 0 – 1

Valley Station – B22 99.24 0.01 0 – 1

Valley Station – B23 99.94 0.01 0 – 1

Valley Station – B24 99.95 Not modeled

0.01 0 – 1

a PM emissions during the 2002-2004 baseline period were controlled using an ESP.

b Maximum day visibility impairment measured in deciviews (only calculated at the Seney Class I area).

c Number of days with maximum visibility impairment => 0.1 deciviews.

Betterment of Controls

As mentioned above, the BART determination s hould at least consider the "betterment of existing control equipment" in cases where ESPs or baghouses are in place. In addition to optimizing the equipment operation, there are also modifications which can be made in order to update the equipment. These modifications incl ude upgrades such as flue gas conditioning and improved fabric material, and are described in A ppendix C. In general, there are fewer upgrade options for newer control equipment. For additi onal PM control by modification of the existing equipment configuration, the cost of incremental visibility improvement is likely to be very high, and therefore the Department did not require facil ities to evaluate this particular betterment option.12 ESPs

Typical new equipment design PM control effi ciencies for ESPs are between 99 and 99.9%, while some older ESPs only achieve 90%. 2 All but two of the Wisconsin utility boilers subject to BART and employing ESP control systems have a tested PM control efficiency greater than 99%. The ESP for Alliant Energy – Nelson Dewey boiler B22, which is relatively older compared to ESPs at other EGU facilities, has greater than 98% PM control. The ESP for Alliant Energy – Edgewater B24, which is older than the ESP at Nelson Dewey, has greater than 94% PM control. The specific betterment opti ons evaluated by each facility are described in Appendix C. The Department’s analysis of the submittals indicate that the control equipment already achieves a high PM control level, the so urces identified appropriate upgrade options, and the sources identified steps already taken to minimize emissions from the ESPs. The Department determined these control measures, along with the existing permit conditions at each facility, to

meet BART.

Baghouses

Typical new equipment design PM control effici encies for baghouses are also between 99 and 99.9%, while older baghouses have a range between 95 and 99.9%. 3 All of the Wisconsin utility boilers subject to BART and employing baghouse control systems have a tested PM control efficiency greater than 99%. The specific bette rment options evaluated by each facility with a baghouse are described in Appendix C. The Depa rtment’s analysis of the submittals indicate that the control equipment alrea dy achieves a high PM control level, the sources identified appropriate upgrade options, and the sources iden tified steps already steps taken to minimize emissions from the baghouses. The Department determined these control measures, along with the existing permit conditions at each facility, to meet BART.

Conclusion and Permit Requirements

For PM emissions, an existing ESP or an exis ting baghouse controls the flue for each BARTaffected boiler. The Department performed CA LPUFF modeling using an established baseline to determine visibility impacts for additional PM controls – from above 94% control up to 100% control – on ESPs and baghouses. The modeling dem onstrated insignificant continuous visibility improvement. A “betterment of control” analys is was also performed for each facility, which included steps for minimizing PM emissions and possible upgrades for the control equipment. Following the five-factor criteria in the Guidelines for evaluating BART, the Department

determined BART control for PM to be the existing controls along w ith the existing permit

conditions. These determinations are based primarily on the small continued visibility improvement from increasing PM control effici ency, as well as the options considered for

betterment of control. The PM control levels on ESPs and baghouses for these determinations are presented in Tables 6 and 7, respectively.

2 “Air Pollution Control Technology Fact Sheet – Dry Electro static Precipitator (ESP) – Wire-Plate Type.” US EPA.

Online. http://www.epa.gov/ttn/catc/dir1/fdespwpl.pdf

. June 24, 2010.

3 “Air Pollution Control Technology Fact Sheet – Fabric Filter – Pulse-Jet Cleaned Type.” US EPA. Online. http://www.macrotek.net/pdf/FS_Pulse_Clean_Dust_Collector.pdf. June 24 , 2010.13 The Department is proposing for public comment the PM related BART permit requirements in Tables 6 and 7, for ESPs and baghouses, respecti vely. The permit requirements are the existing Title V permit limits for PM. These limits establish continuous control, in accordance with the

Guidelines . Since the Department is not proposing si gnificant changes to the permits, a template for the draft revision of each EGU facility's Title V operating permit, which includes the proposed BART requirements, is presented in Appendix D.

Table 6. Proposed BART Determination for

EGU BART Sources with ESP Control

Unit PM Permit Emission Limit (Lbs/mmBtu)

Columbia – B21 0.60

Columbia – B22 0.10

Edgewater – B24 0.13

Nelson Dewey – B22 0.10

Oak Creek – B27 0.03

Oak Creek – B28 0.03

Pleasant Prairie – B21 0.10

Pleasant Prairie – B22 0.10

JP Pulliam – B27 0.3014 Table 7. Proposed BART Determination for EGU BART Sources with Baghouse Control

Unit PM Permit Emission Limit (Lbs/mmBtu)

Alma Station – B25 0.10

Genoa Station – B20 0.034

Valley Station – B21 0.15

Valley Station – B22 0.15

Valley Station – B23 0.15

Valley Station – B24 0.1515 Appendix A. Primary Federal Class I Areas Affected by Wisconsin Stationary Source

Emissions

Note: Rainbow Lake is not a listed Class I area under the Regional Haze Rule.16 Appendix B. BART-eligible Source Categories

(1) Fossil-fuel fired steam electric plants of more than 250 million British thermal units (BTU) per hour heat input

(2) Coal cleaning plants (thermal dryers)

(3) Kraft pulp mills

(4) Portland cement plants

(5) Primary zinc smelters

(6) Iron and steel mill plants

(7) Primary aluminum ore reduction plants

(8) Primary copper smelters

(9) Municipal incinerators capable of chargi ng more than 250 tons of refuse per day

(10) Hydrofluoric, sulfuric , and nitric acid plants

(11) Petroleum refineries

(12) Lime plants

(13) Phosphate rock processing plants

(14) Coke oven batteries

(15) Sulfur recovery plants

(16) Carbon black plants (furnace process)

(17) Primary lead smelters

(18) Fuel conversion plants

(19) Sintering plants

(20) Secondary meta l production facilities

(21) Chemical process plants

(22) Fossil-fuel boilers of more th an 250 million BTUs per hour heat input

(23) Petroleum storage and tr ansfer facilities with a capacity exceeding 300,000 barrels

(24) Taconite ore pr ocessing facilities

(25) Glass fiber processing plants

(26) Charcoal pr oduction facilities17 Appendix C. BART Determinations for EGU Facilities

The Department determined that several fossil-fuel boilers at different f acilities in Wisconsin are subject to BART for particulate matter (PM). Pursuant to this determination, each EGU facility submitted a PM BART analysis as required under s. NR 433.04. These analyses may be found in Appendix E. After reviewing this submittal and evaluating the visibility improvement resulting from additional control approaches, the Depart ment is proposing BART control levels and permit requirements as presented by this discussion.

Affected Boilers

Power boilers at each of the EGU sources are evaluated individually for BART eligibility under the category of "fossil-fuel fired steam electric plants of more than 250 mmBtu per hour.” The Department identified 16 boiler units among the 9 E GU facilities as subject to a determination of BART controls (BART-affected). CALPUFF air qua lity modeling confirms this status (refer to Table 1 above), which showed that potential em issions from the BART-eligible boilers at each source could impair visibility gr eater than the subject-t o threshold of 0.5 deci views (dv) for more than 7 days of the year.

Baseline operation and equipment

According to state rule the BART analysis s hould be conducted according to federal guidance as provided in 40 CFR part 51, Appe ndix Y. As such the regulatory baseline for determining BART is the operations demonstrated by the affected units during the period of 2002, 2003, and 2004. The federal requirements also state that any analysis should cons ider current existing equipment, operation, and system configurations in evaluating control technologies. In cases where emission controls are in place the federal BART program requires that, at a minimum, the

BART determination consider the "betterment of existing control equipment". This betterment considers if the equipment is being operated in the best manner possible or if there are modifications that can be made, so as to update the equipment comparable to current installations. The baseline information pertinent to the determination of PM related BART for the various EGU boilers is presented in Tables C1 to C4. Some control equipment modifications which took place before or during the 2002 – 2004 ba seline period are liste d in this section.

These modifications are also incl uded, and described more fully, in the “Betterment of Controls”

section below.18 Boilers with Electrostatic Precipitator (ESP) Control Units

1) Alliant Energy - Columbia facility . This facility has two BART-affected boilers, B21 and B22. Boiler B21 is a dry bottom boiler installed in 1971. The boiler has a heat input rating of 5,885 mmBtu/hr, and is permitted to burn coal, natu ral gas, No. 2 fuel oil, and additional

alternate fuels. Boiler B22 is identical to B21, but was installed in 1975. Flue gas from each boiler exhausts through a dedicated stack with emissions controlled by an ESP (PM) and concentric firing over-fire air (NO

x ).

The PM control system for boiler B21 is two hot side electrostatic prec ipitator units with a chevron design arrangement, installed in 1974. The PM control system for boiler B22 is two cold side ESP units (converted from hot side ESP units in 1988). Each control system includes a flue gas conditioning system. The facility also employs routine maintenance procedures to optimize performance of the ESP control units. Th e control levels for the baseline period were 99.2/96.4% (PM/ PM 10 ) and 99.5/99.5% (PM/ PM 10 ) for boilers B21 a nd B22, respectively,

based on stack test results. The 2005 Air Em issions Inventory (AEI) Summary Report for

Wisconsin indicates a PM 10 control level of 97% for boiler B22. The Department assumes this

control level is closer to th e actual performance during the ba seline period, and should be the assumed value associated with the visibility modeling below.

2) Alliant Energy – Edgewater facility . This facility has one BART -affected boiler, B24. The boiler is a cyclone type insta lled in 1967. Boiler B24 has a heat input rating of 3,529 mmBtu/hr, and is permitted to burn coal, No. 2 fuel oil, and cyclone air heater ash. Flue gas emissions from boiler B24 are controlled by an ESP (PM), as we ll as over-fire air and selective non-catalytic reduction (NO

x ).

The ESP control system for boiler B24 is from Bu ell Engine Company, Inc ., and was installed in 1969. The facility has taken several steps since original installation – in addition to routine maintenance procedures – to optimize performance of this ESP control unit:

• Physical flow distribution improvements

• Increased number of electrical fields from 4 to 12 fields

• Addition of flue gas conditioning

• Routine optimization: preci pitator inspections performed during outages; rapping optimization; soot blowing optimization

The control level for the base line period was 94.9/94.9% (PM/PM 10 ), based on stack test results.

3) Alliant Energy – Nelson Dewey facility . This facility has one BART-affected boiler, B22. The boiler is a cyclone type in stalled in 1961, but first operated in December of 1962. Boiler B22 has a heat input rating of 1,260 mmBtu/hr, and is permitted to burn sub-bituminous coal, bituminous coal, petroleum coke, metallurgical c oke, and additional alternate fuels. Flue gas emissions from boiler B22 are controlled by an ESP (PM) and SCR (NO

x ).

The ESP control system for boiler B24 is from Bu ell Engine Company, Inc ., and was installed in 1974. Alliant Energy – Nelson Dewey has also taken a number of steps since original installation to optimize performa nce of the ESP control units:19 • Precipitator inspections performed during outages

• Rapping optimization

• Soot blowing optimization

• Routine maintenance procedures

The control level for the base line period was 95/95% (PM/PM 10 ), based on stack test results.

4) We Energies – Oak Creek facility . This facility has two BART -affected boilers, B27 and B28. Boiler B27 is a dry bottom boiler installed in 1965. The boiler has a heat input rating of 2,856 mmBtu/hr, and is permitted to burn coal, natura l gas and propane. Bo iler B28 is also a dry bottom boiler, installed in 1967. This boiler ha s a heat input rating of 3,009 mmBtu/hr, and is permitted to burn coal, natural gas and propane. Flue gas from each boiler exhausts through a dedicated stack with emissions controlled by an ESP (PM) and low NOx burners with over-fire air (NO

x ).

The PM control systems for boilers B27 and B 28 were installed in 1992 and 1991, respectively. The facility utilizes several plant-specific maintenance procedures to assure continued performance of the ESPs:

• Malfunction Prevention and Abatement Plan (MPAP)

• Routine maintenance procedures, as we ll as unusual operations procedures

• Continuous Emissions Monitoring Systems (CEM S) maintenance procedures, plus shutdown, breakdown or malfunction reporting

These procedures are periodical ly reviewed and updated by We Energies due to changes in operation, equipment, or regulator y requirements. The control le vels for the baseline period were 99.92/96.92% (PM/PM 10 ) and 99.77/99.77% (PM/PM 10 ) for boilers B27 and B28, respectively, based on stack test results.

5) We Energies – Pleasant Prairie facility . This facility has two BART-affected boilers, B20 (Unit 1) and B21 (Unit 2). Boiler B20 is a dry bottom type installed in 1976, and first operated

in 1980. The boiler has a heat i nput rating of 6,449 mmBtu/hr, and is permitted to burn coal, as

well as distillate fuel oil and na tural gas. Boiler B22 is identical to B21, and was first operated in 1985. Flue gas from each boiler exhausts through a dedicated stack with emissions controlled by an ESP (PM), SCR (NO

x ) and wet FGD (SO2).

The PM control systems for boilers B20 and B 21 were installed in 1980 and 1985, respectively. The facility utilizes several plant-specific maintenance procedures to assure continued performance of the ESPs:

• Malfunction Prevention and Abatement Plan (MPAP)

• Routine maintenance procedures, as we ll as unusual operations procedures

• Continuous Emissions Monitoring Systems (CEM S) maintenance procedures, plus shutdown, breakdown or malfunction reporting These procedures are periodical ly reviewed and updated by We Energies due to changes in operation, equipment, or regulator y requirements. New automatic voltage and rapper/vibrator

controllers were instal led during 2000-2001, in order to digita lly program and better control how20 the ESP plates are rapped and wires vibrated in order to optimize PM collection efficiency.

Additional removal of PM at the wet FGD downstream of the ESP is estimated to be 50 to 70% by We Energies.

The control levels from the ESPs fo r the baseline period were 99.91/99.91% (PM/PM 10 ) and 99.75/99.75% (PM/PM 10 ) for boilers B20 and B21, respectiv ely, based on stack test results.

6) Wisconsin Public Service Corporation – JP Pulliam facility . This facility has one BARTaffected boiler, B27 (Unit 8). The boiler is a dry bottom type in stalled in 1964. Boiler B27 has a heat input rating of 1,510 mmBtu/hr, and is permitted to burn coal and natural gas. Flue gas emissions from boiler B27 are controlled by an E SP (PM), as well as over-fire air and selective non-catalytic reduction (NO

x ).

The ESP control system for boiler B27 was in stalled in 1964, and r econstructed with new internal equipment and controls in 1994. Th e facility has taken several steps to optimize performance of this ESP control unit, in addi tion to routine precipitator inspections and

maintenance:

• Installation of flue gas conditioning

• Precipitator voltage cont rol equipment upgrades

• Modifications to ESP water wash system

• Replacement of primary coal crushers

The control level for the base line period was 98.9/98.9% (PM/PM 10 ), based on stack test results.21 Table C1. Baseline Operation of BA RT Boilers with ESP Control Units

Boiler Unit Boiler Type Boiler Installation

Year Maximum continuous rating (mmBtu/hr)

Alliant Energy

Columbia – B21 Dry bottom 1971 5,885

Columbia – B22 Dry bottom 1975 5,885

Edgewater – B24 Cyclone 1967 3,529

Nelson Dewey – B22 Cyclone 1961 1,260

We Energies

Oak Creek Station – B27 Dry bottom 1965 2,856

Oak Creek Station – B28 Dry bottom 1967 3,009

Pleasant Prairie – B20 Dry bottom 1976 6449

Pleasant Prairie – B21 Dry bottom 1976 6449

Wisconsin Public Service Corporation

JP Pulliam – B27 Dry bottom 1964 1,51022 Table C2. Baseline Operation of ES P Control Units on BART Boilers

2002-2004 Baseline Emissions *

Boiler Unit ESP

Installation

Year PM/PM 10 Control Efficiency (%) PM/PM 10 Emission Rate

(lbs/mmBtu) Average

PM/PM 10 Emissions (tpy)

Alliant Energy

Columbia – B21 1974 98.2 / 96.4 0.097 / 0.019 1836 / 361

Columbia – B22 1988 99.5 / 99.5 0.030 / 0.006 535 / 116

Edgewater – B24 1969 94.9 / 94.9 0.041 / 0.004 378 / 37

Nelson Dewey – B22 1974 95 / 95 0.031 / 0.011 97 / 35

We Energies

Oak Creek Station – B27 1992 99.92 / 99.92 0.007 / 0.002 60 / 14

Oak Creek Station – B28 1991 99.77 / 99.77 0.015 / 0.003 116 / 26

Pleasant Prairie – B20 1980 99.91 / 99.91 0.001 / - 24 / -

Pleasant Prairie – B21 1985 99.75 / 99.75 0.006 / - 119 / -

Wisconsin Public Service Corporation

JP Pulliam – B27 1994 98.9 / 98.9 0.033 / 0.006 158 / 30

* Emissions information based on Air Emissi ons Inventory Summary Reports for the

2002-2004 baseline.

Boilers with Baghouse Control Units

1) Dairyland Power Coop – Alma facility . This facility has one BART-affected boiler, B25. This boiler is a dry bottom type installed in 1973. Boiler B25 has a heat input rating of 3,784 mmBtu/hr, and is permitted to burn coal and No. 2 fuel oil. Flue gas emissions from the boiler are controlled by a baghouse (PM), a dry flue gas desulfurization (FGD) system (SO 2 ), and SCR (NO

x ).23 The PM control system for boiler B-25 during th e 2002-2004 baseline period was an ESP. This system was replaced by a pulse-j et fabric filter (PJFF) baghouse in 2007. The baghouse is made up of 12 separate compartments each containing 1,064 bags. The facility also employs routine inspection and maintenance procedures to ma intain performance of the baghouse. The PM 10 control level for the baseline pe riod (for the ESP) was 98.36%, base d on stack test results. The Alma facility submitted a PM control level of 99.89% for boiler B25 (for the existing baghouse).

2) Dairyland Power Coop – Genoa facility . This facility has one BART-affected boiler, B20. This boiler is a dry bottom type installed in 1966. Boiler B20 has a heat input rating of 3,040 mmBtu/hr, and is permitted to burn coal. Flue gas emissions from the boiler are controlled by a baghouse (PM), a dry FGD system (SO2), and SCR (NO

x ).

The PM control system for boiler B-20 during th e 2002-2004 baseline period was an ESP. This system was replaced by a PJFF baghouse in 2007. The baghouse is made up of 10 separate compartments each containing 984 bags. The f acility also employs routine inspection and maintenance procedures to maintain performan ce of the baghouse. The PM10 control level for the baseline period (for the ESP) was 97.67%, based on stack test results. The Genoa facility

submitted a PM control level of 99.86% fo r boiler B20 (for the existing baghouse).

3) We Energies – Valley facility . This facility has four BART -affected boilers, B21 through B24. Boilers B21 and B22 are dry bottom boilers insta lled in 1968, while boilers B23 and B24 are dry bottom boilers installed in 1969. Boilers B21 and B22 each have a heat input rating of 868 mmBtu/hr, and are permitted to burn coal, petrol eum coke, natural gas, and propane. Boilers B23 and B24 have a heat input rating of 840 mmBtu/hr, and are also permitted to burn coal, petroleum coke, natural gas, and propane. Flue gas streams from boilers B21 and B22 combine into a common duct and exhaust through a dedica ted stack, with emissions controlled by a baghouse (PM). Flue gas streams from boilers B23 and B24 also combine into a common duct and exhaust through a dedicated stack, with em issions controlled by a baghouse (PM). Nitrogen oxides from these boilers are controlled by low-NOx burners and OFA. Also, under NOx RACT, SNCR may be utilized on these boilers in the future.

The PM control system for boilers B21 and B22 is a reverse air fabric filt er, installed in 1994. The PM control system for boilers B23 and B24 is also a reverse air fabric filter, installed in 1995. The facility utilizes several plant-specific maintenance procedures to assure continued performance of the baghouses:

• Malfunction Prevention and Abatement Plan (MPAP)

• Routine maintenance procedures

• Continuous Emissions Monitoring Systems (CEM S) maintenance procedures, plus shutdown, breakdown or malfunction reporting

These procedures are periodical ly reviewed and updated by We Energies due to changes in operation, equipment, or regulator y requirements. The control le vels for the baseline period were 99.86/99.86% (PM/PM 10 ) and 99.24/99.24% (PM/PM 10 ) for boilers B21 and B22, respectively, based on stack test results. For boilers B23 and B24, the control levels for the baseline period were 99.94/99.94% (PM/PM 10 ) and 99.95/99.95% (PM/PM 10 ), respectively,

based on stack test results.24 Table C3. Baseline Operation of BART Boilers with Baghouse Control Units

Boiler Unit Boiler Type Boiler Installation

Year Maximum continuous rating (mmBtu/hr)

Dairyland Power Coop

Alma Station – B25 Dry bottom 1973 3,784

Genoa Station – B20 Dry bottom 1966 3,040

We Energies

Valley Station – B21 Dry bottom 1968 868

Valley Station – B22 Dry bottom 1968 868

Valley Station – B23 Dry bottom 1969 840

Valley Station – B24 Dry bottom 1969 84025 Table C4. Baseline Operation of Bagh ouse Control Units on BART Boilers

2002-2004 Baseline Emissions

Boiler Unit Baghouse

Installation

Year PM/PM 10 Control Efficiency (%) PM/PM 10 Emission Rate

(lbs/mmBtu) Average

PM/PM 10 Emissions (tpy)

Dairyland Power Coop

Alma Station – B25 * 2007 Not applicable

Genoa Station – B20 * 2007 Not applicable

Wisconsin Energy

Valley Station – B21 1994 99.86 / 99.86 0.011 / 0.002 24 / 4

Valley Station – B22 1994 99.24 / 99.24 0.059 / 0.010 119 / 19

Valley Station – B23 1995 99.94 / 99.94 0.025 / 0.004 55 / 9

Valley Station – B24 1995 99.95 / 99.95 0.025 / 0.004 53 / 9

* PM emissions during the 2002-2004 baseline period were controlled using an ESP.

Analysis of visibility a nd betterment of controls

The state BART rule requires each EGU facility to submit to the Department an analysis of the applicable pollutant control options and a proposed BART level of control for particulate matter. The Department is then required to propose a BA RT level of control and associated compliance requirements. Final BART requirements are incorporated into a facility's Title V operating permit.

The determination of BART control requirements for each source is based on the following five factors from US EPA under 40 CFR Part 51, Appendix Y, Guidelines for BART Determinations Under the Regional Haze Rule :26 (1) The costs of compliance. (2) The energy and non-air environmental impacts. (3) Any existing pollution control technology in use at the source. (4) The remaining useful life of the source. (5) The degree of improvement in visibility whic h may reasonably be anticipated to result from the use of the technology.

In cases where emission controls are in place the federal BART program requires that, at a minimum, the BART determination considers the "betterment of existing control equipment". This betterment considers if the equipment is being operated in the best manner possible or if there are modifications that can be made, so as to update the equipment comparable to current installations. The existing in stallations of high-efficiency baghouses and electrostatic precipitators for BART-affected boilers require this betterment analysis.

Typical new equipment design PM control effi ciencies for ESPs are between 99 and 99.9%, while some older ESPs only achieve 90%. ESPs with control levels on the lower end may be improved with upgrading and/or optimization. Curre nt ESPs tend to be sized larger and have more fields. Typical new equi pment design PM control effici encies for baghouses are also between 99 and 99.9%, while older baghouses have a range between 95 and 99.9%.

The Department took the approach of first exam ining if any continuous visibility improvement could by achieved by further redu ction of PM. The Department achieved this by conducting a visibility impact analysis of additional PM reductions at several of the BART units (see Visibility section below). Next , the Department assessed the exte nt of visibility improvement using CALPUFF by reducing currently reporte d PM emissions from these units. The Department then evaluated the potential for bett erment at each unit. Finally, considering the visibility improvements and betterment analys es associated with additional controls, the Department made a PM related BART determination for each facility.

The Department allowed BART-affected sources to make an abbreviated PM related BART submittal, if the BART unit(s) is currently contro lled by high efficiency PM collectors, and this control equipment is intended to continue operati ng in the future. This submittal included the following items:

• Description of the type of PM control equi pment used, along with the range of collection efficiency expected from the pr operly operated control equipment. • Installation date of the equipment. • Answer the question: "Can existing PM contro l efficiency be improved without modifying the existing equipment configuration?" • Maintenance procedures for the equipment. • Description of PM rela ted emission monitoring. • Estimate of the remaining useful life of the BART unit.

These BART submittals are included in Appendix E.27 I. Visibility Improvement fr om Additional PM Controls.

Visibility impacts due to emissi ons from EGU sources are largest in the Seney National Wildlife Refuge. Therefore, the measure used to evaluate the effectiveness of additional PM controls is the relative changes seen in visibility for this Class I area, quantified using the CALPUFF model.

The emissions basis for the CALPUFF m odeling is the source's actual maximum PM 10 emissions – or “potential to emit” (PTE) if the maximum actual value was not available – demonstrated during the 2002 – 2004 BART baseline years. The Department used PM 10 emissions because it

was recommend in the Guidelines as an indicator for PM. Additional PM control applied to these emissions demonstrates a relative improveme nt in visibility. One basis for measuring visibility impacts is the relative improvement in the maximum day visibility impact (max dv). The other measure of visibility improvement evalua ted is the number of days for which a change in visibility due to the additiona l controls can be quantified. Th is metric indicates the relative frequency and depth in visibility improvement.

Electrostatic Precipitators

The results of CALPUFF modeling for BART units utilizing ESP control are shown in Table C5. Additional information for the emission inputs and stack parameters are in Tables C6 and C7, respectively. The baseline maximu m actual or PTE emissions of PM 10 were used in the modeling. Presumptive BART controls/limits of 95% SO 2 control and 0.10 Lbs/mmBtu NOx were assumed for modeling, with a few exceptio ns where maximum actual emissions or NOx RACT limits were used, as noted in Table C6. The Department used 100% PM 10 control as an

extreme for additional control from th e baseline maximum actual or PTE PM 10 emissions, although 100% control is not possibl e in practice. The Department originally included additional non-BART boilers in the modeling of multi-facility PM reductions – we assume that inclusion of these non-BART boiler emissions does not change the visibility improvement associated with

additional PM reductions from the BART boilers.

1) Alliant Energy facilities . Additional control of combined PM 10 emissions from Columbia boilers B21 and B22 resulted in a modeled impr ovement from the baseline maximum visibility impairment of 0.02 dv, and a reduction of 2 days for the number of days with a maximum visibility impairment of 0.1 dv or greater. Boil ers B21 and B22 each cont ribute roughly half to this visibility improvement, based on the modeled PM 10 emission rates from each boiler.

Additional control of PM 10 emissions from Edgewater boiler B24 and Nelson Dewey boiler B22 resulted in a modeled improvement from the ba seline maximum visibility impairment of 0.01 dv, for each boiler. The number of days with a maxi mum visibility impairment of 0.1 dv or greater had a reduction of 0 days, for each boiler.

2) We Energies facilities . The Department estimated the visibility improvement for additional

PM control at the Oak Creek and Pleasant Pr airie facilities based on the CALPUFF modeling results for the Alliant Energy – Columbia facility. The Oak Creek facility and Pleasant Prairie facility are both located south-east of the Columbia facility, and further from the Seney Class I area. Also, both facilities have similar or lower PM 10 emission rates compared to the Columbia facility. Thus, additional contro ls at Oak Creek boilers B27 and B28, and Pleasant Prairie boilers28 B21 and B22, are estimated to have an improve ment from the baseline maximum visibility impairment of less than 0.01 dv, for each boiler. The number of days with a maximum visibility impairment of 0.1 dv or greater is estimated to ha ve a reduction of 1 day or less, for each boiler.

3) Wisconsin Public Service Corporation – JP Pulliam facility . The JP Pulliam facility is located

north-east of the Columbia facil ity, and nearer to the Seney Cla ss I area. Additional PM control for boiler B27 resulted in a modeled improveme nt from the baseline maximum visibility impairment of 0.02 dv, and a reduction of 1 da y for the number of days with a maximum visibility impairment of 0.1 dv or greater.29 Table C5. Modeled Visibility Improvement Resulting from Additional PM Control for

ESPs

Visibility Impairment based on CALPUFF

2002-2004 Baseline 100% PM 10 Control on

BART Boilers Calculated Visibility Improvement

Boiler Unit
PM-10

Control Efficiency (%) Max day

dv a Days

=> 0.1

dv b Max

dv a Days

=> 0.1

dv b Dv improvement Days

=> 0.1 dv

Alliant Energy

Columbia – B21 96.4

Columbia – B22 97 2.93 106 2.95-2.93 =

0.02 108 -

106 =

2

Edgewater – B23, B25 * -

Edgewater – B24 94.9 2.94 108 2.95-2.94 =

0.01 108 -

108 =

0

Nelson Dewey – B21 * -

Nelson Dewey – B22 95 2.95 108

2.94 108 2.95-2.94 =

0.01 108 -

108 =

0

WE Energies

Oak Creek – B27 99.92 < 0.01 (est.) < 1 (est.)

Oak Creek – B28 99.77 Not modeled
< 0.01 (est.) < 1 (est.)

Pleasant Prairie – B21 99.91 < 0.01 (est.) < 1 (est.)

Pleasant Prairie – B22 99.75 Not modeled
< 0.01 (est.) < 1 (est.)

Wisconsin Public Service Corporation

JP Pulliam – B24,B25,B26 * -

JP Pulliam – B27 98.9

Weston – B01,B02,B03 * - 5.17 153 5.15 152 5.17-5.15 =

0.02 153 -

152 =

1

* Non-BART boilers.

a Maximum day visibility impairment measured in deciview s (only calculated at the Seney Class I area). Value based on results for 2003 year for Alliant Energy and 2002 year for WPSC.

b Number of days with maximum visibility impact => 0.1 deciviews. Value based on results for 2003 year.30 Table C6. Individual Unit Baseline Emission Rates used for Modeling Results in Table C8
Emission Rate Type

Baseline

Emissions (grams/sec) Emissions after

100% PM

Control on BART

Boilers (grams/sec) Boiler Unit

SO 2 a NO
x b PM 10 c SO 2 NO
x b PM 10 SO 2 NO
x PM 10

Alliant Energy

Columbia – B21 95%

control 0.10

Lbs/mmBtu Max

actual 27 70 19 27 70 0

Columbia – B22 95%

control 0.10

Lbs/mmBtu Max

actual 27 68 15 27 68 0

Edgewater – B23 * Max

actual 0.15

Lbs/mmBtu Assumed 67 13 13 67 13 13

Edgewater – B24 95%

control 0.10

Lbs/mmBtu Max

actual 16 37 13 16 37 0

Edgewater – B25 * Max

actual 0.15

Lbs/mmBtu Assumed 470 51 13 470 51 13

Nelson Dewey – B21 * 95%

control 0.10

Lbs/mmBtu Assumed 15 12 18 15 12 18

Nelson Dewey – B22 95%

control 0.10

Lbs/mmBtu PTE 15 12 18 15 12 0

WE Energies

Oak Creek – B27 95%

control 0.10

Lbs/mmBtu Allowable 9 38 3.3 9 38 0

Oak Creek – B28 95%

control 0.10

Lbs/mmBtu Allowable 8 36 3.2 8 36 0

Pleasant Prairie – B21 95%

control 0.10

Lbs/mmBtu PTE 31 81 16.4 31 81 0

Pleasant Prairie – B22 95%

control 0.10

Lbs/mmBtu PTE 30 78 16.4 30 78 0

Wisconsin Public Service Corporation

JP Pulliam – B24,B25,B26 * Max

actual Max actual Assumed 200 283 42 200 283 42

JP Pulliam – B27 95%

control 0.10

Lbs/mmBtu PTE 4 18 14 4 18 0

Weston – B21,B22,B23 * Max

actual Max actual Assumed 495 273 30 495 273 30

* Non-BART boilers.

a SO2 values are based on “Max actual" 30-day average emission rates for 2002-2004 baseline years reported to US

EPA.

b NOx values are based on max actual for 2007.

c PM10 values are based on 2002-2004 baseline years.31 Table C7. Stack Parameters at EGU Facilities with ESPs

Boiler Facility

ID Stack

ID Stack Height (meters) Stack

Diameter (meters) Gas Exit Velocity (meters/sec) Stack Gas

Exit Temperature (K)

Columbia – B21 111003090 S11 152.4 6.40 20.96 411

Columbia – B22 111003090 S12 198.1 6.40 18.96 405 Edgewater – B23 * 460033090 S11 167.6 5.18 17.09 416 Edgewater – B24 460033090 S11 167.6 5.18 17.09 416 Edgewater – B25 * 460033090 S12 167.6 5.18 20.77 405 Nelson Dewey –

B21 * 122014530 S11 107.9 3.96 13.54 411 Nelson Dewey –

B22 122014530 S11 107.9 3.96 13.54 411

Oak Creek – B27 241007690 S14 169.8 5.27 27.81 398

Oak Creek – B28 169.8 5.27 27.81 398

Pleasant Prairie –

B21 230006260 S10 137.2 9.14 30.91 400

Pleasant Prairie –

B22 230006260 S10 137.2 9.14 30.91 400

JP Pulliam – B24,B25 * 405031990 S12 114.9 4.57 8.41 403

JP Pulliam – B26 * 405031990 S13 114.9 3.35 12.1 433

JP Pulliam – B27 405031990 S14 114.9 4.76 8.65 441

Weston – B01 * 737009020 S01 73.8 3.81 5.36 422

Weston – B02 * 737009020 S02 73.8 3.81 7.98 422

Weston – B03 * 737009020 S03 151.2 4.88 20.32 422

* Non-BART boilers.32 Baghouses

The results of CALPUFF modeling for BART un its utilizing existing baghouse controls are shown in Table C8. Additional information for the emission inputs and stack parameters are in Table C9 and C10, respectively. The baseli ne maximum actual or PTE emissions of PM 10 were used in the modeling. Presumptiv e BART controls/limits of 95% SO 2 control and 0.10 or 0.17 Lbs/mmBtu NOx were also assumed for modeling, as noted in Table C6. The Department used

100% PM 10 control as an extreme for additional cont rol from the baseline maximum actual or PTE PM10 emissions, although 100% control is not possible in practice. The Department originally included additional non-BART boilers in the modeling of multi-facility PM reductions

– we assume that inclusion of these non-BART boiler emissions does not change the visibility improvement associated with additional PM reductions from the BART boilers.

1) Dairyland Power Coop facilities . The Department estimated the visibility improvement for additional PM control at the Alma facility based on the CALPUFF modeling results for the Alliant Energy – Columbia facility. The Alma fa cility is located north-west of the Columbia facility, and further from the Seney Class I area. Also, the facility has lower PM 10 emission rates compared to either of the Columbia facility BA RT boilers. Thus, additi onal controls at Alma B25 is estimated to have an improvement from the baseline maximum visibility impairment of less than 0.01 dv, and a reduction of 1 day or less for the number of days with a maximum visibility impairment of 0.1 dv or greater.

The Department estimated the visibility improve ment for additional PM control at the Genoa facility based on the CALPUFF mo deling results for the Alliant En ergy – Columbia facility. The Genoa facility is located west of the Columbia f acility, and further from the Seney Class I area. Also, the facility has a similar PM 10 emission rate compared to eac h of the Columbia facility

BART boilers. DNR estimates additional controls at Genoa B20 to have an improvement from the baseline maximum visibility impairment of le ss than 0.01 dv, and a reduction of 1 day or less for the number of days with a maximum visi bility impairment of 0.1 dv or greater..

2) We Energies – Valley facility

.

The Department estimated the visibility improve ment for additional PM control at the Valley facility based on the CALPUFF mo deling results for the Alliant En ergy – Columbia facility. The Valley facility is located south-east of the Colu mbia facility, and further from the Seney Class I area. Also, the facility has similar PM 10 emission rates compared to each of the Columbia facility BART boilers. Thus, additional controls at Valley boilers B21, B22, B23, and B24 are estimated to have an improvement from the base line maximum visibility impairment of less than 0.01 dv, for each boiler. The number of days with a maximum visibility impairment of 0.1 dv or greater is estimated to have a reduction of 1 day or less, for each boiler.33 Table C8. Modeled Visibility Improvement Resulting from Additional PM Control for Baghouses

Visibility Impairment based on CALPUFF

Baseline 100% PM 10 Control on

BART Boilers Estimated Visibility Improvement

Boiler Unit
PM-10

Control Efficiency (%) Max day

dv b Days

=> 0.1

dv c Max

dv b Days =>

0.1 dv c Dv improvement Days

=> 0.1

dv

Dairyland Power Coop

Alma Station – B25 a 98.36 Not modeled < 0.01 < 1

Genoa Station – B20 a 97.67 Not modeled < 0.01 0 – 1

We Energies

Valley Station – B21 99.86 0.01 0 – 1

Valley Station – B22 99.24 0.01 0 – 1

Valley Station – B23 99.94 0.01 0 – 1

Valley Station – B24 99.95 Not modeled

0.01 0 – 1

a PM emissions during the 2002-2004 baseline period were controlled using an ESP.

b Maximum day visibility impairment measured in deciview s (only calculated at the Seney Class I area). Value based on results for 2003 year for Alliant Energy and 2002 year for WPSC.

c Number of days with visibility impairment => 0.1 deciviews. Value based on results for 2003 year.34 Table C9. Individual Unit Baseline Emission Rates used for Modeling Results in Table C8
Emission Rate Type

Baseline Emissions (grams/sec) Emissions after

100% PM

Control on BART

Boilers (grams/sec) Boiler Unit

SO 2 a NO
x b PM 10

c SO 2 NO
x b PM 10 SO 2 NO
x PM 10

Dairyland Power Coop

Alma Station – B25 95%

control 0.10

Lbs/mmBtu PTE 17 45 5.4 17 45 0

Genoa Station – B20 95%

control 0.10

Lbs/mmBtu PTE 33 37 18.5 33 37 0

Wisconsin Energy

Valley Station – B21 95%

control 0.17

Lbs/mmBtu PTE 7 12 16 7 12 0

Valley Station – B22 95%

control 0.17

Lbs/mmBtu PTE 7 12 16 7 12 0

Valley Station – B23 95%

control 0.17

Lbs/mmBtu PTE 7 13 16 7 13 0

Valley Station – B24 95%

control 0.17

Lbs/mmBtu PTE 7 12 16 7 12 0

a SO2 values are based on “Max actual" 30-day average emission rates for 2002-2004 baseline years reported to US

EPA.
b NOx values are based on max actual for 2007.

c PM10 values are based on 2002-2004 baseline years.

Table C10. Stack Parameters at EGU Facilities with Baghouses

Boiler Facility

ID Stack

ID Stack Height (meters) Stack

Diameter (meters) Gas Exit Velocity (meters/sec) Stack Gas

Exit Temperature (K)

Alma Station – B25 606034110 S11 213.4 5.33 27.98 446

Genoa Station –

B20 663020930 S10 152.4 4.62 35.35 425 Valley Station –

B21 241007800 S11 121.9 3.35 18.00 411 Valley Station –

B22 241007800 S11 121.9 3.35 18.00 411 Valley Station –

B23 241007800 S12 121.9 3.35 17.29 411 Valley Station –

B24 241007800 S12 121.9 3.35 17.29 41135 II. Betterment of Controls

As mentioned above, the BART determination s hould at least consider the "betterment of existing control equipment" in cases where ESPs or baghouses are in place. In addition to optimizing the equipment operation, there are also modifications which can be made in order to update the equipment. For ESPs these modifi cations include, but are not limited to, the following:

• Addition of electric fields . Electric fields may be added to the existing fields in order remove

additional PM.

• Ammonia injection . This system improves the cohesive ness of the dust layer formed on the collecting plates and typically results in less fly- ash re-entrainment when the plates are rapped. Drawbacks of this system include high capital cost and personnel safety in handling the

ammonia.

• ESP voltage control equipment upgrades . The control equipment is designed to manage ESP collection efficiency by controlling the magnit ude of voltage on the primary winding of the Transformer Rectifier (TR) Sets.

• Flue gas conditioning . This typically consists of SO3 addition to decrease the resistivity of fly ash produced from the combustion of low sulf ur coals. Decreased resistivity improves ESP collection efficiency. A dry sulfur pellet system may also be used to increase the reliability and safety of the system.

• Modifications to rapper equipment, controls and sequencing of rappers . Rapping is optimized by balancing the need to keep plat es clean with the re-entrainment of dust.

• Physical flow distribution improvements . Even and consistent distribution of flue gas within/across the ESP, as well as flue gas velocity adjustments, improve precipitator performance. Velocity impacts the residence time of the flue gas within the ESP and therefore

the contact time between th e flue gas and ESP fields.

• Soot blowing optimization . Soot blowing intervals are optim ized to balance cleaning with

increased dust.

• Water wash modifications . Washing of the ESPs removes a built up layer of ash that collects on ESP discharge electrodes.

For baghouses, in addition to equipment optimiza tion, modifications primarily include upgrading

fabric filter material and a ddition of baghouse compartments. Also, the Department views the addition of electric fields or baghouse compar tments as “modifying the existing equipment configuration,” and did not require the facilities to evaluate this option under an analysis for

betterment of controls.

Electrostatic Precipitators

1) Alliant Energy - Columbia facility . The Columbia facility submitted PM control levels of 99.1% and 99.5% for boilers B21 (Unit 1) and B 22 (Unit 2), respectively. The analysis for

betterment of control indicates continuous maintenance procedures and high PM control levels for these ESPs. In February 2011, WPL received approval from the PSCW to install scrubbers and baghouses at Columbia Units 1 and 2 to re duce SO2 and mercury emissions, respectively, at the generating facility. The scr ubbers and baghouses at Columbia Units 1 and 2 are expected to36 be placed into service in 2014 and support complian ce obligations for current and anticipated air quality regulatory requirements, including CATR , the Utility MACT Rule and the Wisconsin State Mercury Rule. The ESP will remain operating at Columbia - the baghouse will supplement the existing controls and in particular is be ing added to help support compliance for reasons related to other emissions including SO2 and mercury. The additional PM reduction from the baghouse is a co-benefit and the permitting proc ess will require a new Title V operating permit PM limit in order to ensure no significant net increases of PM emissions after the project has been completed. The permit limitation for PM is expected to be proposed by Alliant in July 2011 – the PM limit and resulting emissions will be lower for B21 after installation of the baghouse. The proposed PM permit limitation will be made available for public comment as part of the draft Regional Haze SIP public comment period.

2) Alliant Energy – Edgewater facility . The Edgewater facility submitted a PM control level of 94.9% (PM, PM 10 ) for boiler B24. The Department had c oncerns about this control efficiency, and requested additional information from the facili ty to justify why a highe r level of control is not demonstrated. For example, a control level similar to the ESP control unit at Nelson Dewey cyclone boiler B22 seems reasonable, because the fl ue gas conditions are similar for each boiler. The facility responded that it has taken several st eps since original installation – in addition to

additional electrical fields and routine maintenance procedures – to better the control of this ESP

control unit:

• Physical flow distribution improvements.

• Addition of flue gas conditioning.

• Rapping optimization and soot blowing optimization.

The Department expects the next stack test to be higher than 95%, based on the above improvements which may not have been reflected in the most recent testing.

3) Alliant Energy – Nelson Dewey facility . The Nelson Dewey facility submitted control levels of 97.1% (PM) and 95% (PM 10 ) for boiler B22 as part of its PM BART analysis. These values were confirmed by a 2005 stack test. The facil ity followed up with a more recent stack test

which showed removal efficiencies above 98% fo r PM. The facility has optimized rapping and soot blowing to better th e control of this ESP control unit. Th e analysis for betterment of control indicates a high PM control level and steps ta ken to minimize emissions from this ESP.

4) WE Energies – Oak Creek facility . The Oak Creek facility submitted PM control levels of 99.92 and 99.77% for boilers B27 and B28, respectively. Additionally, for SO 2 control the facility plans to install wet FGD downstream of the ESP by 2013, which is expected to yield an additional 50 to 70% removal of PM. The analys is for betterment of cont rol indicates continuous maintenance procedures and very high PM control levels for these ESPs.

5) WE Energies – Pleas ant Prairie facility . The Pleasant Prairie facility submitted a PM control level of 99.91 and 99.75% (PM, PM 10 ) for boilers B21 and B22, resp ectively. The analysis for

betterment of control indicates continuous maintenance procedur es and very high PM control

levels for these ESPs.37 6) Wisconsin Public Service Corporation – JP Pulliam facility . The JP Pulliam facility

submitted a PM control level of 99.8% for boiler B 27. The facility also evaluated additional ESP configuration changes to determ ine if the ESP performance would be improved effectively. The evaluated improvements included modifications to rapper equipment, controls, and sequencing of the rappers. The evaluation showed that these projects together would result in incremental efficiency gains of less than 0.05%. An ammoni a injection system was also evaluated, but was not implemented for the cost and safety issu es mentioned above for this technology. The analysis for betterment of control indicates a ve ry high PM control leve l and an evaluation of upgrade options for this ESP.38 Baghouses

1) Dairyland Power Coop – Alma facility

.

The Alma facility submitted a PM control level of 99.89% for boiler B25. The pulse-jet fabric filter (PJFF) baghouse system was installed in 2 007 (operational in 2009) as a replacement for an ESP. The manufacturer guaranteed PM em issions are not to exceed 0.015 pounds/mmBtu, excluding the back half section. The analysis for betterment of control indicates continuous maintenance procedures and a very high PM control level for this baghouse system.

2) Dairyland Power Coop – Genoa facility

.

The Genoa facility submitted a PM control leve l of 99.86% for boiler B20. The pulse-jet fabric filter (PJFF) baghouse system was installed in 2007 (operational in 2009), and replaced an ESP. The manufacturer guaranteed PM emissions are not to exceed 0.015 pounds/mmBtu, excluding the back half section; and 0.034 pounds/mmBtu, incl uding the back half s ection. The analysis

for betterment of control indicates continuous maintenance procedures and a very high PM control level for this baghouse system.

3) We Energies – Valley facility

.

The Pleasant Prairie facility submitted PM control levels of 99.91 and 99.75% (PM, PM 10 ) for boilers B21 and B22, respectively. Baghouses fo r boilers B21 and B22 were installed in 1994, while the baghouses for boilers B23 and B24 were installed in 1995. The analysis for betterment of control indicates continuous maintenance proc edures and very high PM control levels for these baghouse systems.39 III. Proposed BART Controls and Visibility Improvement

Electrostatic Precipitators

All but two of the Wisconsin utility boilers s ubject to BART and employing ESP control systems have a tested PM control efficiency greater than 99%. The ESP for Alliant Energy – Nelson Dewey boiler B22, which is older than ESPs at other EGU facilities, is greater than 98% PM control. The ESP for Alliant Energy – Edgewa ter B24, which is older than the ESP at Nelson Dewey, is greater than 94% PM control. Th e Department performed CALPUFF modeling using an established baseline to determine visibility impacts for additional controls on the ESPs. After applying additional PM 10 controls up to 100% at ESPs, the modeled improvement from the baseline maximum visibility impairment is 0.01 dv or less at all but one boiler unit. The modeling result with additional controls at the JP Pulliam boiler unit showed an improvement in the baseline maximum visibility of 0.02 dv. Although visibility imp acts above the 0.01 dv modeled estimate are possible at the Columbia B21 PM permit level of 0.6 lbs/mmBtu, the PM controls are operated at a very high level achieving PM and PM 10 emission rates less than 0.1 lbs/mmBtu and 0.02 lbs/mmBtu, respectively. Colu mbia is also subject to malfunction and abatement plans for operating control equipment under s. NR 439 consistent with testing parameters, and will have a lower PM limit a nd lower resulting emissions for B21 after a baghouse installation scheduled for 2014. The numb er of days with a maximum visibility impairment of 0.1 dv or greater had a reduction of only 1 day or less for each boiler unit. In addition, the cost of incremental visibility im provement is likely to be very high for any additional PM control by modifying the existin g equipment configuration. Due to the small visibility improvement from increasing PM cont rol efficiency, the Department determined BART for PM to be the existing PM controls and permit conditions.40 Baghouses

All of the Wisconsin utility boilers subject to BART and employing baghouse control systems have a tested PM control efficiency greater than 99%. The Department performed CALPUFF modeling using an established baseline to determ ine visibility impacts for additional controls on the baghouses. After applying additional PM 10 controls up to 100% at baghouses, the modeled improvement from the baseline maximum visibility impairment is 0.01 dv or less for each boiler unit. The number of days with a maximum vi sibility impairment of 0.1 dv or greater had a reduction of only 1 day or less for each boiler unit. In addition, the cost of incremental visibility improvement is likely to be very high for additional PM control by modifying the existing equipment configuration. Due to the small visibility improvement from increasing PM control efficiency, the Department determined BART for PM to be the existing PM controls and permit

conditions.

IV. Permit requirements

The Department is proposing the BART PM permit limitations in Tables C11 and C12 for public comment. The permit requirements are the existing Title V permit limits and conditions for PM.

These limits establish continuous control, in accordance with the Guidelines . The Department determines that the existing PM control e quipment and permit limitations for each BARTaffected boiler represents BART. The proposed BART requirements include compliance demonstrated through periodic stack testing.

Since the Department is not propos ing significant changes to the perm its at this point, a template for the draft revision of each EGU facility's Title V operating permit, which includes the proposed BART requirements, is presented in Appendix D.41 Table C11. Proposed BART Determination for EGU BART Sources with ESP Control

Unit PM Permit Emission Limit (Lbs/mmBtu)

Alliant Energy

Columbia – B21 0.60

Columbia – B22 0.10

Edgewater – B24 0.13

Nelson Dewey – B22 0.10

WE Energies

Oak Creek – B27 0.03

Oak Creek – B28 0.03

Pleasant Prairie – B21 0.10

Pleasant Prairie – B22 0.10

Wisconsin Public Service Corporation

JP Pulliam – B27 0.3042 Table C12. Proposed BART Determinatio n for EGU BART Sources with Baghouse

Control

Unit PM Permit Emission Limit (Lbs/mmBtu)

Dairyland Power Coop

Alma Station – B25 0.10

Genoa Station – B20 0.034

WE Energies

Valley Station – B21 0.15

Valley Station – B22 0.15

Valley Station – B23 0.15

Valley Station – B24 0.1543 Appendix D. Draft Title V Operating Permits for EGUs

Note: The template that follows will be used for proposed BART language within each permit.

PART *X* : BEST AVAILABLE RETROFIT TECHNOLOGY (BART) (Note: Text that is underlined and highlighted in gray varies between different boilers)

1.0 Applicability

A Best Available Retrofit Technology (BART) determination has been made for the BARTsubject emission units at this facility to comply with the requirements of 40 CFR Part 51. These requirements are submitted as a Title V air permit revision.

2.0 BART-affected Unit Description

Boiler *X* was brought into service in *YEAR.* This boiler relies on *TYPE* coal. Boiler

*X* is rated at *XX* mmBtu/hr and exhausts to *its own stack*. The boiler has an *ESP/baghouse* currently in-use for controlling partic les and meeting opacity requirements.

3.0 BART Determination

Best Available Retrofit Technol ogy (BART) applies to boiler *X*

. (a) BART shall be applied no later than December 31, 2015. (b) BART for particulate matter (PM) emissions has been determined to be: (i.) The existing PM emission limita tions specified in Conditions *XX* and *XX* , as well as compliance with the visible emissions limitations specified in Condition *XX* ; (ii) Compliance with the Compliance Assura nce Monitoring (CAM) Plan in Part *X* , and the

Malfunction Prevention and Abatement (MPA) Plan, located in Part *X* ; [ss. NR 415.03 and NR 433.05, Wis. Adm. Code] Note: Any revisions to the CAM Plan will be part of future Title V permit renewals.44 Appendix E. PM BART Analyses from EGU Sources in Wisconsin

Appendix E.1. PM BART Analysis and Responses from Alliant Energy – Columbia

Appendix E.2. PM BART Analysis and Responses from Alliant Energy – Edgewater

Appendix E.3. PM BART Analysis and Responses from Alliant Energy – Nelson Dewey

Appendix E.4. PM BART Analysis and Responses from Dairyland Power Coop – Alma

Appendix E.5. PM BART Analysis and Responses from Dairyland Power Coop – Genoa

Appendix E.6. PM BART Analysis from We Energies – Oak Creek

Appendix E.7. PM BART Analysis from We Energies – Pleasant Prairie

Appendix E.8. PM BART Analysis from We Energies – Valley

Appendix E.9. PM BART Analysis and Responses from Wisconsin Public Service Corporation

– Pulliam45 Appendix E.1. PM BART Analysis from Alliant Energy – Columbia for Boiler Units B21 (1) and B22 (2), March 5, 2009.46 Appendix E.2. PM BART Analysis from Alliant Energy – Edgewater for Boiler Unit B24 (4), March 5, 2009.47 Appendix E.2. Response from Alliant Energy – Edgewa ter Regarding PM Control on Boiler Unit B24 (4), June 22, 2009.48 Appendix E.2. Response from Alliant Energy – Edgewa ter Regarding PM Control on Boiler Unit B24 (4), June 22, 2009 (cont.).49 Appendix E.2. Response from Alliant Energy – Edgewa ter Regarding PM Control on Boiler Unit B24 (4), April 28, 2010 (cont.)

From: Pincombe, Bradley [mailto:BradleyPincombe@alliantenergy.com]

Sent: Wednesday, April 28, 2010 11:11 AM

To: Loftus, Jonathan P - DNR

Cc: Hanson, Jeffrey; Pluta, Michele Subject: RE: ESP Performance at Edgewater 4

Jon,

In his 4/15/2010 e-mail to you below, Jeff Jaeckels advi sed that due to some out-of-office situations (and due to his impending departure) there would be a slight delay in our response to your questions concerning the performance of the Edgewater Unit 4 ESP. I apologize for that delay but am now able to provide the following information:

 WPL has not performed any recent testing on the performance of E dgewater Unit 4’s ESP.

 As you suggest, the difference in performance cited in our PM BART submittals between the Edgewater Unit 4 ESP and the Nelson Dewey Unit 2 ESP is likely attributable to several factors. The following are notable (but may not be the only) potent ial factors behind why the documented efficiency may differ for these units:

1. The EDG4 ESP was installed as original equipment when the unit was constructed and went into
service in 1969. The NED2 ESP was retrofitted to t hat unit in 1974. The NED2 ESP is in fact newer than
the EDG4 ESP

.

2. Even and consistent distribution of flue gas within/a cross the ESP improves pr ecipitator performance
and the newer NED2 ESP benefitted from ti ghter specifications on flue gas distribution. As noted in our 6/22/2009 letter, improvements have been made to the EDG4 ESP to address/improve flue gas distribution but flue gas distribution remains a differentiating factor in performance between the EDG4 and
NED2 ESPs.

3. Likewise, flue gas velocity differs between the NED2 and EDG4 ESPs. Velocity – which impacts the residence time of the flue gas within the ESP and t herefore the contact time between the flue gas and ESP fields – impacts the control efficiency/performance of the precipitator. It is our understanding that the flue gas moves thru the ESP at EDG4 at approx 3- 4 feet/second faster than it does thru the NED2 ESP. Again, as noted in our 6/22/2009 letter, improvements have been to the EDG4 ESP to address velocity however flue gas velocity is another differ entiating factor in performance between the EDG4 and
NED2 ESPs.

WPL maintains both of these ESPs in accordance wi th the plants’ complian ce assurance monitoring plans and routinely performs compliance tests for Title V operating permit requirements limiting particulate

matter emissions. We believe that this is the most re levant indication of actual ESP performance at the plants.

Again, Jeff Hanson and Michele Plut a are available and should both be contacted should you require further information to address yo ur questions regardin g the performance of EDG4’s ESP. In Jeff Jaeckels’ absence, we collectively look forward to working with you as you progress the PM BART

determinations.

Brad Pincombe Manager, Environmental Services Emerging Issues & Strategic Projects Alliant Energy (608) 458-4928 Desk (608) 575-7154 Cell50 bradleypincombe@alliantenergy.com

Appendix E.3. PM BART Analysis from Alliant Energy – Nelson Dewey for Boiler Unit B22 (2), March 5, 2009.51 Appendix E.3. Response from Alliant Energy – Nelson Dewey for Boiler Unit B22 (2), April 20, 2009.52 Appendix E.3. Response from Alliant Energy – Nelson Dewey for Boiler Unit B22 (2), April 20, 2009 (cont.).53 Appendix E.3. Response from Alliant Energy – Nelson Dewey for Boiler Unit B22 (2), May 26,

2009.54 Appendix E.3. Response from Alliant Energy – Nelson Dewey for Boiler Unit B22 (2), May 26, 2009 (cont.).55 Appendix E.4. PM BART Analysis from Dairyland Po wer Coop – Alma (JP Madgett) for Boiler Unit B25 (JPM), January 5, 2009.56 Appendix E.4. PM BART Analysis from Dairyland Po wer Coop – Alma (JP Madgett) for Boiler Unit B25 (JPM), January 5, 2009 (cont.).57 Appendix E.4. Response from Dairyland Power Coop – Alma (JP Madgett) for Boiler Unit B25 (JPM), April 15, 2009.58 Appendix E.5. PM BART Analysis from Dairyland Power Coop – Genoa for Boiler Unit B20 (3), January 5, 2009.59 Appendix E.5. PM BART Analysis from Dairyland Power Coop – Genoa for Boiler Unit B20 (3), January 5, 2009 (cont.).60 Appendix E.5. Response from Dairyland Power Coop – Genoa for Boiler Unit B20 (3), April 15, 2009.61 Appendix E.6. PM BART Analysis from We Energies – Oak Creek for Boiler Units B27 (7) and B28 (8), February 23, 2009.62 Appendix E.6. PM BART Analysis from We Energies – Oak Creek for Boiler Units B27 (7) and B28 (8), February 23, 2009 (cont.).63 Appendix E.6. PM BART Analysis from We Energies – Oak Creek for Boiler Units B27 (7) and B28 (8), February 23, 2009 (cont.)64 Appendix E.7. PM BART Analysis from We Energies – Pleasant Prairie for Boiler Units B21 (1) and B22 (2), February 23, 2009.65 Appendix E.7. PM BART Analysis from We Energies – Pleasant Prairie for Boiler Units B21 (1) and B22 (2), February 23, 2009 (cont.).66 Appendix E.7. PM BART Analysis from We Energies – Pleasant Prairie for Boiler Units B21 (1) and B22 (2), February 23, 2009 (cont.).67 Appendix E.8. PM BART Analysis from We Energies – Valley for Boiler Units B21, B22, B23 and B24, February 23, 2009.68 Appendix E.8. PM BART Analysis from We Energies – Valley for Boiler Units B21, B22, B23 and B24, February 23, 2009 (cont.).69 Appendix E.8. PM BART Analysis from We Energies – Valley for Boiler Units B21, B22, B23 and B24, February 23, 2009 (cont.).70 Appendix E.9. PM BART Analysis from Wisconsin Pub lic Service Corporation – Pulliam for Boiler Unit B27 (8), January 2, 2009.71 Appendix E.9. PM BART Analysis from Wisconsin Pub lic Service Corporation – Pulliam for Boiler Unit B27 (8), January 2, 2009 (cont.).72 Appendix E.9. Response from Wisconsin Public Servi ce Corporation – Pulli am for Boiler Unit B27 (8), March 10, 2009.73 Appendix E.9. Response from Wisconsin Public Servi ce Corporation – Pulli am for Boiler Unit B27 (8), March 10, 2009 (cont.).74 Appendix E.9. Response from Wisconsin Public Servi ce Corporation – Pulli am for Boiler Unit B27 (8), March 10, 2009 (cont.).75 Appendix E.9. Response from Wisconsin Public Servi ce Corporation – Pulli am for Boiler Unit B27 (8), April 28, 2009.76 Appendix E.9. Response from Wisconsin Public Servi ce Corporation – Pulli am for Boiler Unit B27 (8), April 28, 2009 (cont.).