ATTACHMENT 2
1

BEST AVAILABLE RETROFIT TECHNOLOGY 

AT EGU FACILITIES 

July 1, 2011 

WISCONSIN DEPARTMENT OF NATURAL RESOURCES 

101 South Webster Street 

Box 7921 

Madison, Wisconsin 53707-7921 
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Statement of Purpose

This document provides the draft findings for external review of implementing Best 

Available Retrofit Technology (BART) requirements for electric generating utility 

(EGU) sources in Wisconsin. After modeling the potential visibility impairment of 

BART-eligible sources, the Department finds nine EGU sources subject to BART. 

Boilers located at these sources are affected under the BART source category of fossil 

fuel boilers greater the 250 mmbtu/hr. All of the EGUs found subject to BART are also 

subject to the Clean Air Interstate Rule (CAIR) under 40 CFR part 97, and therefore are 

not required to conduct a BART analysis for sulfur dioxide (SO2) and nitrogen oxide 

(NOx) 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 precipitators 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 establish a plan and air 

pollution control program which mitigates current impacts and protects the visibility of 

certain federal Class I areas. For Wisconsin, the primary Class I areas include Boundary 

Waters Wilderness Area, Voyageurs National Park, Seney National Wildlife Refuge, and 

Isle Royal National Park (Appendix A). These visibility pollutant 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 particulate matter (PM) and gaseous pollutants 

including sulfur dioxide (SO2) and oxides of nitrogen (NOx) that transform or react into 

small particles in the atmosphere. Other air pollutants including ammonia and volatile 

organic compounds take part in formation of small particles, but their emission levels 

from these sources is proportionally much lower and less important to haze formation. 

A core federal requirement for addressing visibility impairment at the federal Class I 

areas is the implementation of a control program for certain stationary sources known as 

Best Available Retrofit Technology (BART). This BART control requirement addresses 

older sources that do not have air pollution control equipment and which are shown to 

directly affect visibility at the Class I areas. The federal requirements for identifying 

sources subject to BART, and the methods for determining appropriate emission control 

requirements, are set forth by the US EPA under 40 CFR Part 51, Appendix Y, 

Guidelines for BART Determinations Under the Regional Haze Rule. 
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In January 2008, the state adopted rules under ch. NR 433, Wis. Adm. Code, in order to 

meet the federal BART requirements. The state rule establishes a process for sources 

subject to BART to submit an analysis of potential pollution control technologies and 

their installation cost and issues. This analysis supports the Department 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 the compliance date to December 31, 2015. The 

purpose of the modification is to allow for more complex installations of pollution 

control equipment that would enable 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 that 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 systems 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 BART-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. The BART requirement is not intended to be 

exhaustive of stationary sources that warrant control for meeting overall haze and 

visibility requirements. 

• The source or emission unit(s) falls within one of 26 source categories (Appendix 

B). 

• The emission unit(s) was installed by August 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 enforceable and State enforceable permit 

limits.
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Table 1. Wisconsin EGU Sources with BART-eligible Units 

Emissions (grams/s) BART Source 

Category Potential WI BART Facilities Eligible Emission Units SO2 NOx PM10

Alliant Energy – Columbia B-01,02 1266.1 710.2 34.4 WP & L Alliant Energy – Edgewater B-24 423 501 13 Alliant Energy – Nelson Dewey B-22 478 75 18 Dairyland Power Coop – Alma B-25 613.2 150.4 5.4 Dairyland Power Coop – Genoa B-20 2411.2 155.5 18.5 Madison Gas & Electric Company – Blount Street B-20,21,22,23 23.1 24.5 1.3 Manitowoc Public Utilities B-27 93.2 32.6 17.5 Wisconsin DOA / UW Madison – Charter Street B-25 100.2 28.4 18.9 We Energies – Oak Creek B-27,28 2087.0 182.6 6.5 We Energies – Pleasant Prairie * B-21,22 - - - We Energies – Valley B-21,22,23,24 1398.5 445.8 64.0 

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

Wisconsin Public Service Corporation – JP Pulliam Plant B-27 797.3 247.2 14.1 

* Pleasant Prairie self-identified as BART-subject.
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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 areas. Such a source is subject to BART (BARTaffected), and as such must be evaluated for BART control requirements. 

The Department used the CALPUFF air quality model to model the source's emissions in order 

to determine the visibility impairment on a class I area. If the modeled results show a significant 

reduction in visibility, the source is subject to BART or "BART-affected". Overall, how much a 

source's emissions impair the visibility of a Class 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 following nearby Class I areas: 

Boundary Waters Wilderness Area, Voyageurs National Park, Seney National Wildlife Refuge, 

and Isle Royal National Park (Appendix A). Emissions from Wisconsin stationary sources also 

affect other Class I areas, but modeling indicates the duration and frequency of such visibility 

impacts are minimal. 

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

• A source is BART-affected if the modeled reduction 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 aggregate of all visibility impacting pollutants 

(PM10, SO2, NOx, 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 calendar 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 included 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 applying 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. 
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Table 2. Wisconsin EGU Sources with Units Subject to BART. 

WI BART Facilities 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-eligible fossil fuel boilers at these facilities, 

when operating at potential maximum emission levels, 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 visibility impacts do not exceed 0.5 dv for more than 7 

days in any one year, and therefore are not BART-affected. 

Determination of BART controls

Once a source is subject to BART, the Department must determine the appropriate control 

requirements for that specific source; i.e. BART controls 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 control options and a proposed BART level of 

control for each visibility-impairing pollutant. The Department is then required to propose a 

BART level of control and associated compliance requirements. Final BART requirements are 

determined based on stakeholder and public input, and incorporated into a facility's Title V 

operating permit. 
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The determination of BART control requirements 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 which may reasonably be anticipated to result from 

the use of the technology.

All of the EGUs found subject to BART are also subject to the Clean Air Interstate Rule (CAIR) 

under 40 CFR part 97, and therefore are not required to conduct a BART analysis for sulfur 

dioxide (SO2) and nitrogen oxide (NOx) emissions. However, these sources are required to 

conduct a BART analysis for particulate matter (PM). 

All of the BART-affected EGUs have high efficiency 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 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. In Wisconsin, the only 

cases requiring a betterment analysis are existing installations of baghouses and electrostatic 

precipitators (ESP) which are used for controlling particles and meeting opacity requirements. 

The Department conducted an analysis of PM reductions 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 reducing 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 emissions is not significant. The cost of 

incremental visibility improvement is also likely 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 such as a baghouse or an ESP meet a BART level 

of control technology, and proceeded to evaluate the potential for “betterment of control” at each 

unit. 

The Department then allowed BART-affected sources to make an abbreviated PM related BART 

submittal, if the PM control equipment is intended to continue operating in the future. This 

submittal included the following items: 

• Description of the type of PM control equipment used, along with the range of collection 

efficiency expected from the properly operated control equipment. 

• Installation date of the equipment. 

• Answer the question: "Can existing PM control efficiency be improved without modifying the 

existing equipment configuration?" 

• Maintenance procedures for the equipment. 

• Description of PM related emission monitoring. 

• Estimate of the remaining useful life of the BART unit. 
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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 impairment in keeping with the Guidelines, the Department is proposing 

BART emission limitations for the boilers at these sources. A summary of this analysis is 

presented here. The Department's determination of BART for each EGU source is described 

more fully in Appendix C. 

Visibility Improvement

DNR used the changes in visibility impairment for 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% PM10 control as an extreme for additional control from the baseline 

maximum actual or PTE PM10 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 quantified. This metric indicates the relative 

frequency and depth in visibility improvement. 

ESPs 

After applying additional PM10 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 reduction of only 1 day or less for each boiler unit.
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Table 4. Modeled Visibility Improvements Resulting from Additional PM Control for ESPs (2002-2004 ba

Visibility Impairment based on CALPUFF 

2002-2004 Baseline 100% PM10 Control on BART Boilers 

Calc

I

Boiler Unit 

PM10 Control 

Efficiency (%) 

Max day 

dv a

Days => 0.1 

dv b

Max day 

dv a

Days => 0.1 

dv b Max da

improve

Alliant Energy 

Columbia – B21 96.4 Columbia – B22 97 

2.93 106 2.95-2.93 

Edgewater – B24 c 94.9 2.94 107 2.95-2.94 Nelson Dewey – B22 c 95 

2.95 108 

2.94 107 2.95-2.94 

WE Energies 

Oak Creek – B27 99.92 < 0.01 Oak Creek – B28 99.77 

Not modeled 

< 0.01 

Pleasant Prairie – B21 99.91 < 0.01 Pleasant Prairie – B22 99.75 

Not modeled 

< 0.01 

Wisconsin Public Service Corporation 

JP Pulliam – B27 c 98.9 5.17 153 5.15 152 5.17-5.15 a Maximum day visibility impairment measured in deciviews (only calculated at the Seney Class I area). b Number of days with maximum visibility impairment => 0.1 deciviews. c Additional non-BART boiler emissions were included in the modeling, but are assumed to not change the visibility impro

additional PM reductions from the BART boilers.
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Baghouses 

After applying additional PM10 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 impairment of 0.1 dv or greater had a reduction of 

only 1 day or less for each boiler unit. 

Table 5. Modeled Visibility Improvement Resulting from Additional PM Control for 

Baghouses (2002-2004 baseline)

Visibility Impairment based on CALPUFF 

Baseline 

100% PM10 

Control on 

BART Boilers 

Estimated Visibility 

Improvement 

Boiler Unit 

PM10

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 should 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 include upgrades such as flue gas conditioning and 

improved fabric material, and are described in Appendix C. In general, there are fewer upgrade 

options for newer control equipment. For additional 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 facilities to evaluate this particular betterment 

option. 
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ESPs 

Typical new equipment design PM control efficiencies 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 options 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 sources 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 efficiencies 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 betterment options evaluated by each facility with a 

baghouse 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 sources identified 

appropriate upgrade options, and the sources identified 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 existing baghouse controls the flue for each BARTaffected boiler. The Department performed CALPUFF 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 demonstrated insignificant continuous visibility 

improvement. A “betterment of control” analysis 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 with the existing permit 

conditions. These determinations are based primarily on the small continued visibility 

improvement from increasing PM control efficiency, 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 Electrostatic 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, respectively. 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 significant 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 0.30 
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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 0.15
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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. 
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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 charging 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 metal production facilities 

(21) Chemical process plants 

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

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

(24) Taconite ore processing facilities 

(25) Glass fiber processing plants 

(26) Charcoal production facilities 
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Appendix C. BART Determinations for EGU Facilities 

The Department determined that several fossil-fuel boilers at different facilities 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 Department 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 EGU facilities as subject to a determination of 

BART controls (BART-affected). CALPUFF air quality modeling confirms this status (refer to 

Table 1 above), which showed that potential emissions from the BART-eligible boilers at each 

source could impair visibility greater than the subject-to threshold of 0.5 deciviews (dv) for more 

than 7 days of the year. 

Baseline operation and equipment 

According to state rule the BART analysis should be conducted according to federal guidance as 

provided in 40 CFR part 51, Appendix 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 consider 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 baseline period are listed in this section. 

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

section below.
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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, natural 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 (NOx).

The PM control system for boiler B21 is two hot side electrostatic precipitator 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. The control levels for the baseline period were 

99.2/96.4% (PM/ PM10) and 99.5/99.5% (PM/ PM10) for boilers B21 and B22, respectively, 

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

Wisconsin indicates a PM10 control level of 97% for boiler B22. The Department assumes this 

control level is closer to the actual performance during the baseline 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 installed 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 well as over-fire air and selective non-catalytic 

reduction (NOx). 

The ESP control system for boiler B24 is from Buell 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: precipitator inspections performed during outages; rapping 

optimization; soot blowing optimization 

The control level for the baseline period was 94.9/94.9% (PM/PM10), 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 installed 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 coke, and additional alternate fuels. Flue gas 

emissions from boiler B22 are controlled by an ESP (PM) and SCR (NOx). 

The ESP control system for boiler B24 is from Buell Engine Company, Inc., and was installed in 

1974. Alliant Energy – Nelson Dewey has also taken a number of steps since original 

installation to optimize performance of the ESP control units: 
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• Precipitator inspections performed during outages 

• Rapping optimization 

• Soot blowing optimization 

• Routine maintenance procedures 

The control level for the baseline period was 95/95% (PM/PM10), 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, natural gas and propane. Boiler B28 is also a dry 

bottom boiler, installed in 1967. This boiler has 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 (NOx).

The PM control systems for boilers B27 and B28 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 well as unusual operations procedures 

• Continuous Emissions Monitoring Systems (CEMS) maintenance procedures, plus shutdown, 

breakdown or malfunction reporting 

These procedures are periodically reviewed and updated by We Energies due to changes in 

operation, equipment, or regulatory requirements. The control levels for the baseline period 

were 99.92/96.92% (PM/PM10) and 99.77/99.77% (PM/PM10) 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 input rating of 6,449 mmBtu/hr, and is permitted to burn coal, as 

well as distillate fuel oil and natural 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 (NOx) and wet FGD (SO2).

The PM control systems for boilers B20 and B21 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 well as unusual operations procedures 

• Continuous Emissions Monitoring Systems (CEMS) maintenance procedures, plus shutdown, 

breakdown or malfunction reporting 

These procedures are periodically reviewed and updated by We Energies due to changes in 

operation, equipment, or regulatory requirements. New automatic voltage and rapper/vibrator 

controllers were installed during 2000-2001, in order to digitally program and better control how 
20

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 for the baseline period were 99.91/99.91% (PM/PM10) and 

99.75/99.75% (PM/PM10) for boilers B20 and B21, respectively, 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 installed 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 ESP (PM), as well as over-fire air and selective 

non-catalytic reduction (NOx). 

The ESP control system for boiler B27 was installed in 1964, and reconstructed with new 

internal equipment and controls in 1994. The facility has taken several steps to optimize 

performance of this ESP control unit, in addition to routine precipitator inspections and 

maintenance: 

• Installation of flue gas conditioning 

• Precipitator voltage control equipment upgrades 

• Modifications to ESP water wash system 

• Replacement of primary coal crushers 

The control level for the baseline period was 98.9/98.9% (PM/PM10), based on stack test results. 
21

Table C1. Baseline Operation of BART 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 1,510 
22

Table C2. Baseline Operation of ESP Control Units on BART Boilers 

2002-2004 Baseline Emissions * 

Boiler Unit 

ESP 

Installation 

Year 

PM/PM10

Control 

Efficiency (%) 

PM/PM10

Emission Rate 

(lbs/mmBtu) 

Average 

PM/PM10

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 Emissions 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 (SO2), and SCR 

(NOx).
23

The PM control system for boiler B-25 during the 2002-2004 baseline period was an ESP. This 

system was replaced by a pulse-jet 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 maintain performance of the baghouse. The PM10

control level for the baseline period (for the ESP) was 98.36%, based 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 (NOx).

The PM control system for boiler B-20 during the 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 facility also employs routine inspection and 

maintenance procedures to maintain performance 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% for 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 installed 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, petroleum 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 dedicated 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 emissions 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 filter, 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 (CEMS) maintenance procedures, plus shutdown, 

breakdown or malfunction reporting 

These procedures are periodically reviewed and updated by We Energies due to changes in 

operation, equipment, or regulatory requirements. The control levels for the baseline period 

were 99.86/99.86% (PM/PM10) and 99.24/99.24% (PM/PM10) 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/PM10) and 99.95/99.95% (PM/PM10), 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 840 
25

Table C4. Baseline Operation of Baghouse Control Units on BART Boilers 

2002-2004 Baseline Emissions 

Boiler Unit 

Baghouse 

Installation 

Year 

PM/PM10

Control 

Efficiency (%) 

PM/PM10

Emission Rate 

(lbs/mmBtu) 

Average 

PM/PM10

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 and 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 BART 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 which 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 installations of high-efficiency baghouses and electrostatic 

precipitators for BART-affected boilers require this betterment analysis. 

Typical new equipment design PM control efficiencies 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. Current ESPs tend to be sized larger and have 

more fields. Typical new equipment design PM control efficiencies 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 examining if any continuous visibility improvement 

could by achieved by further reduction 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 extent of visibility improvement 

using CALPUFF by reducing currently reported PM emissions from these units. The 

Department then evaluated the potential for betterment at each unit. Finally, considering the 

visibility improvements and betterment analyses 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 controlled by high efficiency PM collectors, and this 

control equipment is intended to continue operating in the future. This submittal included the 

following items: 

• Description of the type of PM control equipment used, along with the range of collection 

efficiency expected from the properly operated control equipment. 

• Installation date of the equipment. 

• Answer the question: "Can existing PM control efficiency be improved without modifying the 

existing equipment configuration?" 

• Maintenance procedures for the equipment. 

• Description of PM related emission monitoring. 

• Estimate of the remaining useful life of the BART unit. 

These BART submittals are included in Appendix E. 
27

I. Visibility Improvement from Additional PM Controls. 

Visibility impacts due to emissions 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 modeling is the source's actual maximum PM10 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 PM10 emissions because it 

was recommend in the Guidelines as an indicator for PM. Additional PM control applied to 

these emissions demonstrates a relative improvement 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 evaluated is the number of days for which a change 

in visibility due to the additional controls can be quantified. This 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 maximum actual or PTE emissions of PM10 were used in the 

modeling. Presumptive BART controls/limits of 95% SO2 control and 0.10 Lbs/mmBtu NOx 

were assumed for modeling, with a few exceptions where maximum actual emissions or NOx 

RACT limits were used, as noted in Table C6. The Department used 100% PM10 control as an 

extreme for additional control 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) Alliant Energy facilities. Additional control of combined PM10 emissions from Columbia 

boilers B21 and B22 resulted in a modeled improvement 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. Boilers B21 and B22 each contribute roughly half to 

this visibility improvement, based on the modeled PM10 emission rates from each boiler. 

Additional control of PM10 emissions from Edgewater boiler B24 and Nelson Dewey boiler B22 

resulted in a modeled improvement from the baseline maximum visibility impairment of 0.01 dv, 

for each boiler. The number of days with a maximum 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 Prairie 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 PM10 emission rates compared to the Columbia 

facility. Thus, additional controls at Oak Creek boilers B27 and B28, and Pleasant Prairie boilers 
28

B21 and B22, are estimated to have an improvement 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 have 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 facility, and nearer to the Seney Class I area. Additional PM control 

for boiler B27 resulted in a modeled improvement from the baseline maximum visibility 

impairment of 0.02 dv, and a reduction of 1 day 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% PM10

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 deciviews (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 

SO2 

a

 NOx 

b

 PM10 c SO2

NOx b PM10 SO2 NOx PM10

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 units 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 baseline maximum actual or PTE emissions of PM10 were 

used in the modeling. Presumptive BART controls/limits of 95% SO2 control and 0.10 or 0.17 

Lbs/mmBtu NOx were also assumed for modeling, as noted in Table C6. The Department used 

100% PM10 control as an extreme for additional control 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 facility is located north-west of the Columbia 

facility, and further from the Seney Class I area. Also, the facility has lower PM10 emission rates 

compared to either of the Columbia facility BART boilers. Thus, additional 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 improvement for additional PM control at the Genoa 

facility based on the CALPUFF modeling results for the Alliant Energy – Columbia facility. The 

Genoa facility is located west of the Columbia facility, and further from the Seney Class I area. 

Also, the facility has a similar PM10 emission rate compared to each of the Columbia facility 

BART boilers. DNR estimates additional controls at Genoa B20 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.. 

2) We Energies – Valley facility. 

The Department estimated the visibility improvement for additional PM control at the Valley 

facility based on the CALPUFF modeling results for the Alliant Energy – Columbia facility. The 

Valley facility is located south-east of the Columbia facility, and further from the Seney Class I 

area. Also, the facility has similar PM10 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 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 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% PM10 

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 deciviews (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 

SO2 

a

 NOx 

b PM10 

c SO2

NOx b PM10 SO2 NOx PM10

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 17.29 411
35

II. Betterment of Controls 

As mentioned above, the BART determination should 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 modifications 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 cohesiveness 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 magnitude 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 sulfur 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 plates 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 the flue gas and ESP fields. 

• Soot blowing optimization. Soot blowing intervals are optimized 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 optimization, modifications primarily include upgrading 

fabric filter material and addition of baghouse compartments. Also, the Department views the 

addition of electric fields or baghouse compartments 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 B22 (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 reduce SO2 and mercury emissions, respectively, at 

the generating facility. The scrubbers and baghouses at Columbia Units 1 and 2 are expected to 
36

be placed into service in 2014 and support compliance 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 being 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 process 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, PM10) for boiler B24. The Department had concerns about this control efficiency, 

and requested additional information from the facility to justify why a higher 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 flue gas conditions are similar for each boiler. 

The facility responded that it has taken several steps 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% (PM10) for boiler B22 as part of its PM BART analysis. These values 

were confirmed by a 2005 stack test. The facility followed up with a more recent stack test 

which showed removal efficiencies above 98% for PM. The facility has optimized rapping and 

soot blowing to better the control of this ESP control unit. The analysis for betterment of control 

indicates a high PM control level and steps taken 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 SO2 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 analysis for betterment of control indicates continuous 

maintenance procedures and very high PM control levels for these ESPs. 

5) WE Energies – Pleasant Prairie facility. The Pleasant Prairie facility submitted a PM control 

level of 99.91 and 99.75% (PM, PM10) for boilers B21 and B22, respectively. The analysis for 

betterment of control indicates continuous maintenance procedures 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 B27. The facility also evaluated additional ESP 

configuration changes to determine 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 ammonia injection system was also evaluated, but was 

not implemented for the cost and safety issues mentioned above for this technology. The 

analysis for betterment of control indicates a very high PM control level 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 2007 (operational in 2009) as a replacement for an 

ESP. The manufacturer guaranteed PM emissions 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 level 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, including 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. 

3) We Energies – Valley facility. 

The Pleasant Prairie facility submitted PM control levels of 99.91 and 99.75% (PM, PM10) for 

boilers B21 and B22, respectively. Baghouses for 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 procedures 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 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 older than ESPs at other EGU facilities, is greater than 98% PM 

control. The ESP for Alliant Energy – Edgewater B24, which is older than the ESP at Nelson 

Dewey, is greater than 94% PM control. The Department performed CALPUFF modeling using 

an established baseline to determine visibility impacts for additional controls on the ESPs. After 

applying additional PM10 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 impacts 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 PM10 emission rates less than 0.1 

lbs/mmBtu and 0.02 lbs/mmBtu, respectively. Columbia 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 and lower resulting emissions for B21 after a 

baghouse installation scheduled for 2014. The number 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 improvement is likely to be very high for any 

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. 
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 determine visibility impacts for additional controls on 

the baghouses. After applying additional PM10 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 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 equipment 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 proposing significant changes to the permits 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 0.30 
42

Table C12. Proposed BART Determination 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 0.15 
43

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 particles and meeting opacity requirements. 

3.0 BART Determination 

Best Available Retrofit Technology (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 limitations specified in Conditions *XX* and *XX*, as well as 

compliance with the visible emissions limitations specified in Condition *XX*; 

(ii) Compliance with the Compliance Assurance 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 

– Pulliam
45

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 – Edgewater Regarding PM Control on Boiler 

Unit B24 (4), June 22, 2009. 
48

Appendix E.2. Response from Alliant Energy – Edgewater Regarding PM Control on Boiler 

Unit B24 (4), June 22, 2009 (cont.). 
49

Appendix E.2. Response from Alliant Energy – Edgewater 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 advised 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 Edgewater 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) potential 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 that unit in 1974. The NED2 ESP is in fact newer than 

the EDG4 ESP.

2. Even and consistent distribution of flue gas within/across the ESP improves precipitator performance 

and the newer NED2 ESP benefitted from tighter 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 therefore 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 differentiating factor in performance between the EDG4 and 

NED2 ESPs.

WPL maintains both of these ESPs in accordance with the plants’ compliance 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 relevant indication of actual ESP performance at the 

plants.

Again, Jeff Hanson and Michele Pluta are available and should both be contacted should you require 

further information to address your questions regarding 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 Cell
50

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 Power Coop – Alma (JP Madgett) for Boiler 

Unit B25 (JPM), January 5, 2009. 
56

Appendix E.4. PM BART Analysis from Dairyland Power 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 Public Service Corporation – Pulliam for 

Boiler Unit B27 (8), January 2, 2009. 
71

Appendix E.9. PM BART Analysis from Wisconsin Public Service Corporation – Pulliam for 

Boiler Unit B27 (8), January 2, 2009 (cont.).
72

Appendix E.9. Response from Wisconsin Public Service Corporation – Pulliam for Boiler Unit 

B27 (8), March 10, 2009. 
73

Appendix E.9. Response from Wisconsin Public Service Corporation – Pulliam for Boiler Unit 

B27 (8), March 10, 2009 (cont.). 
74

Appendix E.9. Response from Wisconsin Public Service Corporation – Pulliam for Boiler Unit 

B27 (8), March 10, 2009 (cont.). 
75

Appendix E.9. Response from Wisconsin Public Service Corporation – Pulliam for Boiler Unit 

B27 (8), April 28, 2009. 
76

Appendix E.9. Response from Wisconsin Public Service Corporation – Pulliam for Boiler Unit 

B27 (8), April 28, 2009 (cont.).