ANALYSIS AND PRELIMINARY DETERMINATION FOR THE CONSTRUCTION PERMIT

FOR THE PROPOSED MODIFICATION

OF TWO COAL FIRED POWER BOILERS

FOR

WISCONSIN ELECTRIC POWER COMPANY, D/B/A WE ENERGIES-OAK CREEK STATION,

LOCATED AT

11060 S CHICAGO RD.,

OAK CREEK, MILWAUKEE COUNTY, WISCONSIN

Construction Permit No.: 12-SDD-047

Facility ID No.: 241007690

This review was performed by the Wisconsin Department of Natural Resources, Bureau of Air 

Management in accordance with Chapter 285, Wis. Stats., and Chapters NR 400 to NR 499, Wis. Adm. 

Code. 

Reviewed by: Steven D. Dunn Date:10/22/12

Peer review 

conducted by: POY Date:10/22/12

Preliminary Determination Approved by: Signature Date

Regional Supervisor or Central Office Designee:

AMS 10/22/12

Stationary Source Modeling Team Leader: SDD for John Roth 10/22/12

Compliance Engineer (reviewed/approved): SDD for permit only 10/22/12

cc: Ashok K. Singh - Southeast Region Headquarters 

Oak Creek Public Library 8620 S. Howell Ave. Oak Creek, WI 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 2 of 28

INTRODUCTION

Stationary sources that are not specifically exempt from the requirement to obtain a construction permit 

under s. 285.60(5), Wis. Stats. or ch. NR 406, Wis. Adm. Code may not commence construction, reconstruction, replacement, relocation or modification unless a construction permit for the project has been 

issued by the Department of Natural Resources (DNR’s) Air Management Program. Owners or operators 

subject to the construction permit requirements must submit a construction and operation permit application to the DNR. The application is reviewed following the provisions set forth in ss. 285.60 to 285.67, 

Wis. Stats. The criteria for permit issuance vary depending on whether the source is major or minor and 

whether the source is or proposed to be located in an attainment or nonattainment area.

Subject sources are to be reviewed with respect to the equipment and facility description provided in the 

application and for the resulting impact upon the air quality. The review ensures compliance with all applicable rules and statutory requirements. The preliminary determination will show why the source(s) 

should be approved, conditionally approved, or disapproved. It will encompass emission calculations and 

an air quality analysis using US EPA models, if applicable. Emissions from volatile organic compound 

(VOC) sources and small sources whose emissions are known to be insignificant are normally not 

modeled. As a precautionary note, the emission estimates are based on US EPA emission factors (AP-42) 

or theoretical data and can vary from actual stack test data.

A final decision on the construction permit and significant operation permit revision will not be made 

until the public has had an opportunity to comment on the Department’s analysis, preliminary 

determination and draft permit. The conditions proposed in the draft permit may be revised in any final 

permit issued based on comments received or further evaluation by the Department.

GENERAL APPLICATION INFORMATION

Owner/Operator: Wisconsin Electric Power Company, D/B/A We Energies-Oak Creek Station

11060 S Chicago Rd. 

Oak Creek, WI 53154-6736

Responsible Official: Pat Stiff

Asset Manager - Oak Creek (OCPP)

Application Contact Person: Bob Greco

Application Submitted By: Bob Greco

Application submittal date: March 9, 2012

Additional Information Submitted: March 9 2012 – October 10, 2012 

Date of Complete Application: July 31, 2012

PROJECT DESCRIPTION

We Energy (WE) received a permit to construct two coal-fired power generation boilers in 2004. These 

two boilers were only allowed to combust bituminous coal (along with small amounts of natural gas) in 

the air permit issued 2004. to allow construction to burn bituminous coal only. WE is applying to be 

allowed to burn subbituminous coal either in combination with bituminous coal or as the sole coal 

combusted in these boilers. The main purpose of this project, as stated by the applicant, is to use lower 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 3 of 28

cost subbituminous coal in the boilers and potentially save WE and ratepayers millions or tens of millions 

of dollars annually. These savings are realized due to the substantially lower cost on a $/MMBTU basis 

of subbituminous coal in comparison to bituminous coal.

This project requires a new review under major source permitting requirement sis now required. As of 

the date of this draft permit, Milwaukee County is in an area which is non-attainment for PM2.5. Thus, 

this review will apply the PSD regulations to all pollutants for which there is a significant increase except 

for NOx, PM2.5 and SO2. For these pollutants, NSR (major source non-attainment) permitting 

requirements will apply.

In order to combust a high level of subbituminous coal, the applicant believes a number of physical 

changes to the boiler may be required. These changes are:

1. Air heater and tube section corrosion protection

2. Additional boiler slag cleaning equipment

3. Additional or modified air heater baskets to maintain unit performance

4. Duct burners to maintain unit performance

5. Additional coal silo(s), feeder(s) and pulverizer(s) (mills) for additional coal capacity

6. Modified coal silo chute for feeding a new pulverizer

7. Internal mechanical mill changes and modifications to optimize coal crushing

8. Distributed control system (DCS) or controls modifications

9. Burner and burner pipe modifications to burn subbituminous coal

10. Boiler windbox modifications to accommodate additional mill(s), coal piping and burners

11. Modification to boiler tube spacing possibly including tube replacements

12. New primary air fan and motor to achieve required combustion air

13. New induced draft fan motor to achieve boiler pressure requirements

14. Additional baghouse compartments for particulate control

15. Additional baghouse fluidization system

16. Increase raw water capability to account for additional FGD blowdown

17. Increase wastewater treatment facility size

18. High velocity mist eliminators in the scrubber to minimize moisture carryover

19. Calcium bromide injection system for mercury oxidation and control

20. Additional controls and logic for all new mechanical equipment

21. Popcorn ash collector for subbituminous ash

22. Coal silo and feed chute stiffeners for explosion protection using subbituminous coal

23. Coal feed chute modifications for flowability with subbituminous coal

24. Tripper gallery explosion panels and fire protection for subbituminous coal

25. Control revisions to the crushers to utilize subbituminous coal

26. Revisions to dust suppression, freeze protection, and washdown systems

27. Coal mill inlet flow pressure measuring device

28. Additional fire suppression for mills

29. Adjustments and modifications to the boiler flame scanners

30. Modifications to the SCR ammonia control valve and SCR nozzles.

31. Additional SCR catalyst cleaning equipment

32. Increase air duct sizing to accommodate greater air flows

33. Modifications to the baghouse flue gas flow distribution devices

34. Baghouse structural steel modifications

35. Modifications and additions to flyash piping and controls

36. Fly ash silo structural improvements

37. Modify the wet flyash unloader flyash unloader internal paddle mixers

38. Modifications to WFGD spray nozzles
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 4 of 28

39. WESP modifications for flow stability.

The applicant does not anticipate that physical changes to the material handling systems will be required 

to utilize subbituminous coals in these units. However, as the conversion to subbituminous coals 

progresses, the applicant may conclude that new coal blending equipment may be necessary. New coal 

blending equipment may include new conveyors, new transfer houses, and/or new coal storage silos. 

Other material handling system changes may include additional coal pile storage including base material 

and dust control equipment, and crusher upgrades for additional pre-crushing. In addition, coal system 

upgrades to blend or transport subbituminous coal may include: transfer points, conveyors, chutes, portal 

reclaimer, controls, logic, dust collection and control systems, scales, washdown, building enclosures, fire 

protection, safety systems, miscellaneous mechanical and electrical support. If new or modified coal 

handling equipment is identified as required equipment in the future, a new construction permit to install 

this new equipment will be required.

None of these proposed changes will increase the heat input capacity of either boiler (B18 or B19) 

covered under this permit.

Other Actions:

This permit replaces and revises the conditions of the original construction permit for these units (03-RV166) and all subsequent revisions of that permit.

SOURCE DESCRIPTION

The plant is located at 4801 E. Elm Road in the city of Oak Creek, Milwaukee County, approximately 20 

miles south of Milwaukee. The site occupies more than 400 acres of land on the shore of Lake Michigan.

Description of New or Modified Units.

B18 – Super Critical Pulverized Coal (SCPC) Boiler and B19 – Super Critical Pulverized Coal (SCPC) 

Boiler. The specifications are for each SCPC boiler

Maximum Continuous Rating – 6,180 mmBtu/hr; 6,750 MMBTU based on CEM measured heat input.

Emission Unit Information.

Boiler/furnace number [or process line, etc.]: B18 and B19

Unit description: Coal fired boilers

Control technology status: SCR, baghouse, wet ESP wet FGD

Maximum continuous rating (mmBTU/hr): 6,180

Date of construction or last modification: Commence don June 25, 2005

Construction Permit Requirements:

Stack Information.

Stack identification number: S18&S19

Exhausting unit(s): B18&B19

This stack has an actual exhaust point: Y

Discharge height above ground level (ft): 550

Inside dimensions at outlet (ft): 25

Exhaust flow rate (normal) (ACFM): 1,750,000
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 5 of 28

Stack Information.

Exhaust flow rate (maximum) (ACFM): 1,899,000

Exhaust gas temperature (normal) (°F): 120

Exhaust gas temperature (maximum) (°F): 120

Exhaust gas discharge direction: Up

Stack equipped with any obstruction: No

Emission control devices are a baghouse, wet ESP, SCR and wet FGD. The boilers are also equipped with low NOx 

burners and flue gas recirculation.

Fuels and Firing Conditions.

Fuel name

Higher 

heating 

value

Max. sulphur 

content 

(wt%)

Max. ash 

content 

(wt%)

Excess 

combustion 

air (% O2)

Moisture 

content as 

fired (%)

Max. hourly 

consumption

Actual yearly 

consumption

Primary Fuel Bituminous 

coal

13,100 

BTU/lb

2.7 7.7 N/A 5.7 236 

tons/hour

N/A

Primary fuel Subbit. coal 8,400 

BTU/lb

0.35 6 N/A 29.9 368 

tons/hour

N/A

startup fuel Nat gas 0 0 N/A 0 N/A

startup fuel propane 0 0 N/A 0 N/A

Insignificant Emissions Units.

Description Number

Maintenance of Grounds, Equipment, and Buildings (lawn care, painting, etc.).: 

Boiler, Turbine, and HVAC System Maintenance.: 

Pollution Control Equipment Maintenance.: 

Internal Combustion Engines Used for Warehousing and Material Transport.: 

Fire Control Equipment.: 

Janitorial Activities.: 

Office Activities.: 

Convenience Water Heating.: 

Convenience Space Heating (< 5 million BTU/hr Burning Gas, Liquid, or Wood).: 

Fuel Oil Storage Tanks (< 10,000 gal.).: 

Stockpiled Contaminated Soils.: 

Demineralization and Oxygen Scavenging of Water for Boilers.: 

Purging of Natural Gas Lines.: 

Sanitary Sewer and Plumbing Venting.: 

CROSS MEDIA IMPACTS

Coal plants generate solid waste and water waste (stormwater, cooling water). Releases to these media 

are covered under separate Department permits.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 6 of 28

EMISSION CALCULATIONS.

The calculations have been provided by the applicant and have been reviewed and appear to be correct. 

Potential emissions for all pollutants subject to BACT or LAER have been recalculated from the 

application based on the final BACT or LAER determination emission rates.

WISCONSIN HAZARDOUS AIR POLLUTANT (NR 445) REVIEW

All HAP emissions are subject to Federal MACT standards. Thus, NR 445 limitations do not apply to the 

boilers.

COMPLIANCE AND TECHNOLOGY REVIEW

The applicant is proposing to be allowed to combust subbituminous coal in the existing power boilers at 

the Oak Creek/Elm Road power plant. These two existing power boilers were authorized for construction 

in 2004The primary emission limitations that will apply to these boilers come from the following 

authorities:

- Ch. NR 405, Wis. Adm. Code – Prevention of Significant Deterioration. This Adm. Code section 

requires emission units that have a significant increase in emissions of regulated pollutants to 

apply Best Available Control technology (BACT) to limit those emissions

- Ch. NR 408, Wis. Adm. Code – Non-attainment area new source permitting. This section 

requires emissions units which have a significant increase for a pollutant for which an area is not 

meeting the National Ambient Air Quality Standards to apply Lowest Achievable Emission Rate 

(LAER) controls to emissions of those pollutants

- Ch. NR 440, Wis. Adm. Code _ New Source Performance Standards (NSPS). These standards 

are promulgated by USEPA and apply to any new source of air pollution in one of the categories 

which has a promulgated performance standard. The boilers are subject to NSPS for large coalfired boilers. All of the PSD/NSR emission limitations are more stringent than the NSPS 

emission limitations.

- Federal hazardous air pollutant standards – These boilers were subject to new source MACT 

standards when initially permitted in 2004. This determination is commonly identified as a 

112(g) determination. Units subject to 112(g) need to eventually have their MACT requirements 

“trued-up” with the final MACT standard, without backsliding any requirements. However, this 

is not required at this time and the existing 112(g) MACT determination will continue to be 

MACT for these units. After the authority to construct under this permit expires, these MACT 

requirements will be revised and updated to be equivalent to the final utility MACT standard.

A. PSD (ch. NR 405 BACT emission limitations); The following pollutants are subject to BACT 

emission limitations: particulate matter (PM), particulate matter less than 10 microns (PM10), 

carbon monoxide, fluorides and greenhouse gases (GHG’s).

All PSD BACT analyses are done using the 5-step method recommended by USEPA. The 5-

steps of every BACT analysis are:

1. Identify possible control technologies
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 7 of 28

2. Identify the technologically feasible control technologies. This step does NOT involve looking at 

the economics of any control technology

3. Rank the technically feasible control technologies in order of effectiveness.

4. Evaluate the most effective control technologies. This evaluation is of the control technologies 

and their energy, economic and environmental impact

5. Choose BACT. This step involves both a potential control technology or technique and an 

emission limitation.

Prior to examining BACT or LAER for each specific pollutant, an analysis of the use of an alternative 

fuel (i.e. natural gas) to limit emissions is necessary. Ch. NR 405 and NR , Wis. Adm. Code, states in the 

definition of BACT that clean fuels are to be addressed as part of BACT for determining an emission 

limitation. However, this need to address clean fuels has also been covered by USEPA guidance 

concerning whether using a clean fuel represents redefining a source. A list of relevant USEPA

discussion (though not an exhaustive list) is as follows:

a. December 13, 2005, letter from Mr. Stephen D. Page, USEPA to Mr. Paul Plath, E3 Consulting: 

In this letter, USEPA states that requiring IGCC when an applicant proposes to build a pulverized 

coal fired boiler represent redefining the source. USEPA also states that requiring an applicant to 

consider the use of a gas turbine in-place of a coal fired boiler to generate electricity would not be 

required as this would be redefining the source.

b. March 2011, “GUIDANCE FOR DETERMINING BEST AVAILABLE CONTROL 

TECHNOLOGY FOR REDUCING CARBON DIOXIDE EMISSIONS FROM BIOENERGY 

PRODUCTION”. On pages 12-13 of this document, USEPA discusses limits on potential 

emissions control options that should be evaluated as part of a BACT analysis. USEPA states that 

BACT should not generally be applied to “...regulate the applicant’s purpose or objective for the 

proposed facility”. This document recommends that reviewing agencies use the methodology

elucidated by the EAB and that the reviewing agency explain its reasoning in the permit 

documentation.

c. EAB decision in Desert Rock Energy Company (9/24/2009). On page 64 of this decision, the 

EAB described the analysis of whether a control technology redefines the source as follows: 

As the Board explained there, the permit applicant initially “defines the proposed facility’s end, 

object, aim, or purpose – that is the facility’s basic design,”61 although the applicant’s definition must be 

“for reasons independent of air permitting.” 62 Prairie State, slip op. at 29, 30 n.23, 13 E.A.D. at __; 

accord NMU, slip op. at 26 & n.28, 14 E.A.D. at __. The inquiry, however, does not end there. The 

permit issuer (here, the Region) should take a “hard look” at the applicant’s determination in order to 

discern which design elements are inherent for the applicant’s purpose and which design elements “may 

be changed to achieve pollutant emissions reductions without disrupting the applicant’s basic business 

purpose for the proposed facility,” while keeping in mind that BACT, in most cases, should not be 

applied to regulate the applicant’s purpose or objective for the proposed facility. Prairie State, slip op. at 

30, 33-34, 13 E.A.D. at __; accord NMU, slip op. at 26-27, 14 E.A.D. at _

Based on these documents, the Department has examined the proposed project in a manner it believes is 

consistent with EPA policy and the Desert Rock EAB decision.

The permit applicant has defined this facility as a coal-fired electric power generation plant. The facility 

was first permitted for construction in 2004 and has operated for approximately two years. The proposed 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 8 of 28

project to evaluate and use a different type of coal is not a fundamental change to the type of plant that 

has been constructed. It is proposed to remain a coal-fired power plant.

The basic “design elements” of a coal-fired power plant are coal receiving, coal processing, coal 

combustion, emissions control and disposal of waste products such as bottom ash and flyash. The 

proposed project does not significantly change ant of these basic elements. Construction of these 

elements has occurred within the past 7-8 years and hundreds of millions of dollars were spent to build a 

coal-fired electric generation facility.

In this case, the Department determines that requiring the evaluation of a cleaner fuel (i.e. natural gas) 

does change the basic design of this facility. This is based on the facility being designed to burn coal an 

on the recent construction and expense involve in building such a facility. This is not meant as a 

determination that no coal fired electric generating plant could be asked to evaluate the use of natural gas 

as BACT. That decision is a fact specific determination and the age of the plant could be an important 

factor in such a determination. Additionally, the Department does rely to an extent on the determination 

of the Public Service Commission in 2004 that this plant was in the interest of electric ratepayers. This 

carries significant weight in that this was a relatively recent decision and large amounts of capital were 

expended to effect this approval.

For all BACT analyses, the performance data for other coal plants is contained in an Appendix to this 

Preliminary Determination. Much of the data in those tables is summarized in the text of each BACT 

review.

1. PM and PM10 –

Step 1: identify potential control technologies: fabric filters baghouses (FFB) and electrostatic 

precipitators (ESP) have been the primary PM control devices selected as the best available control 

technology (BACT) for new units. Other potential control technologies include wet scrubbers and 

mechanical collectors. In addition, some combination of units can be used to reduce PM emissions. For 

example, a wet flue gas desulfurization scrubber may also lessen PM emissions, especially backhalf or 

condensable emissions. For modern air pollution control systems on coal-fired electric generating units, 

the control of PM emissions by the primary control device can also be enhanced by the sulfur dioxide 

(SO2 and H2SO4) control systems. Therefore, the highest level of PM control will likely occur when the 

primary control device is combined or augmented with a secondary PM control system, such as wet FGD 

systems.

For all pulverized coal-fired (PC) electric generating units identified in Table 4-1, filterable PM emission

limits representing BACT range from 0.010 to 0.019 lb/mmBtu, and PM10 emission limits representing

BACT range from 0.018 to 0.055 lb/mmBtu. The reason these emission rates are different is that the 

PM10 number included condensable particulate while the “filterable” PM does not include these 

emissions. For new PC electric generating units firing subbituminous coals identified in Table 4-2, 

filterable PM limits representing BACT range from 0.010 to 0.019 lb/mmBtu, and PM10 emission limits 

representing BACT range from 0.018 to 0.035 lb/mmBtu. For new PC units firing only eastern 

bituminous coals, six units were permitted to use FFBs as the primary PM control device, and four units 

were permitted to use ESPs as the primary PM control device. For new PC units firing subbituminous 

coals, all (23 units) but one were permitted to use FFBs as the primary PM control device. 

Step 2 -Identify Technically Feasible Control Technologies.

All of the identified control technologies are feasible for controlling particulate matter emissions.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 9 of 28

STEP 3. Rank the Technically Feasible Technologies. All of the identified PM control technologies, 

including fabric filter baghouses, dry ESPs, wet ESPs, wet

scrubbers, and mechanical collectors are technically feasible technologies. 

1 Fabric Filter Baghouse, wet FGD, and wet ESP 

2 Fabric Filter Baghouse, wet FGD 

3 Dry ESP, Wet FGD, wet ESP

4 Dry ESP, wet FGD

5 Fabric Filter Baghouse 

6 Dry ESP 

7 Venturi Scrubber 

8 Mechanical Collectors 

STEP 4. Evaluate the Most Effective Controls.

The Elm Road units presently utilizes the top-ranked PM and PM10 air quality control systems, including 

Fabric Filter Baghouse, wet FGD, and wet ESP. Therefore, further analysis is unnecessary.

STEP 5. Proposed Particulate Matter (PM) and PM10 BACT Determination.

The following are the results of stack tests at the Elm Road facility, with date, front half, back half and 

total PM emissions in terms of lb/MMBTU:

1 01/20/10 0.0079 0.0013 0.0092

1 01/20/10 0.0067 0.0011 0.0078

1 01/20/10 0.0076 0.0012 0.0088

2 10/18/00 0.0029 0.0012 0.0041

2 06/22/04 0.0036 0.0021 0.0057

2 07/22/08 0.0030 0.0013 0.0043

The average result of these tests is an emission rate of 0.0067 lb/MMBTU, with a standard deviation of 

0.0023 lb/MMBTU. For unit 1, the average is 0.0086 lb/MMBTU and for unit 2 the emissions average is 

0.0047 lb/MMBTU. The Department is tasked in any BACT determination with determining the 

emissions rate and emissions control that achieve the maximum degree of emissions reduction, but which 

are also achievable over the life of the unit. 

In this case, the emissions controls are the top option of emissions control. Thus, that determination is 

complete. For establishing an emission rate, the Department examines what emission rate other units are 

required to achieve or have achieved, what the unit is question has achieved (if that data is available) and 

the quantity and reliability of any emission data for the unit that is being modified. In this case, the 

boilers at this facility are achieving an emission rate lower than that required of any similar coal fired 

power plant. Thus, it appears that the units are being operated well and that the emissions control devices 

are being operate to maximize their respective effectiveness.

Therefore, the primary question here is where to set the rate based on the available data. The single stack 

test on Unit 1 indicates a total particulate rate of 0.0086 lb/MMBTU. This is based on a single test and 

the Department has seen significance variation in these rates at tests at other electric utilities. Also, the 

unit is new and there is the possibility of deterioration in performance of any mechanical equipment, 

including air pollution control equipment. A reasonable estimate for this is 10% given the relatively 

harsh conditions associated with a coal-fired boiler. Multiplying the 0.0086 by 1.1 yields a rate of 0.0095 

lb/MMBTU.

Again, there can be variation in this rate due to stack testing as well as variations in boiler operations, thus

the Department believes another 20-25 percent above this rate is a reasonable to be achieved over the life

of this unit. This yields an emission arte of 0.012 lb/MMBTU as BACT.

This rate will be proposed as BACT. This permitted rate is the lowest permitted rate the Department is 

aware of for combined front and backhalf emissions. The Department will not be proposing a separate 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 10 of 28

front and backhalf rate in this permit but will, of course, accept comment on whether such a rate should 

be included in the final permit.

(1) PM and PM10 emissions may not exceed 0.012 pounds per million Btu of

heat input, over an 3-hour period.

(2) Whenever compliance emission testing is required, US EPA Reference

Method 5 or 5B and Reference Method 202 shall be used to demonstrate

compliance or an alternate method approved in writing by the

Department.

2. Carbon monoxide – Carbon monoxide is formed in combustion units when carbon is not 

completely combusted with oxygen to form carbon monoxide. Low carbon monoxide (CO) 

emissions are generally associated with good boiler operations.

Step 1 – Identify potential control technologies

The available control technologies for CO emissions include good combustion practices, oxidation

catalysts, and thermal oxidation.

Step 2 – Evaluate feasible control technologies

a. Good combustion practices or combustion controls generally include the following components:

1. Good air/fuel mixing in the combustion zone.

2. High temperatures and low oxygen levels in the primary combustion zone.

3. Excess oxygen levels high enough to complete combustion while maximizing boiler efficiency.

4. Sufficient residence time to complete combustion.

Combustion design for modern coal-fired boilers is intended to simultaneously minimize formation of CO 

and NOx emissions. This is a difficult task, since emissions of NOx and emissions of CO are inversely 

related. That is, measures used to reduce NOx emissions often lead to increases in CO emissions. 

Therefore, the boiler design to minimize CO emissions is interrelated with the boiler design to minimize 

NOx formation.

Pulverized coal-fired boilers burn coal in suspension in large, open furnaces. The ERGS units are

equipped with advanced low NOx burners and over fire air (OFA) which are designed to burn the coal in a

slow, controlled manner using diffusion-flame combustion processes. These burners use the minimum

possible quantity of combustion air in the primary combustion zone. Normally, the amount of primary air

is maintained below the stoichiometric requirement. Thus, the fuel is initially combusted under fuel-rich

conditions. This initial combustion zone helps to reduce NOx formation. Using this advanced low NOx

burner technology, the primary unburned combustible by-product produced from this primary combustion

zone is actually carbon monoxide. CO formation in this zone reduces NOx formation during the initial

combustion process, and provides an easier fuel to burn to completion in the OFA portion of the furnace.

Secondary air is then introduced into the area above the primary fireball. This additional air, called over

fire air, brings the total amount of combustion air up to the level needed to complete combustion and

minimize CO emissions. For pulverized coal-fired boilers, this level is typically 2 – 6% oxygen.

Changes in excess air affect the availability of oxygen (O2) and combustion efficiency. Very low excess

O2 levels may cause high CO formation. Increased O2 levels reduce CO emissions until so much excess

air is introduced that the combustion temperatures begin to drop significantly. Very high O2 levels would

reduce boiler efficiency, increasing all pollutant emission rates. Because of these interrelationships, 

pulverized coal-fired boilers typically operate within a narrow range of excess O2 levels.

The applicant states the following concerning the technical feasibility of CO (oxidation) catalysts: While 

oxidation catalysts are feasible for reducing CO emissions by up to 80-90% from combustion turbines 

fired with natural gas and very low sulfur oil as well as for natural gas fired boilers, oxidation catalysts 

have not been used to reduce CO emissions from coal-fired boilers. Coal-fired boilers have several 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 11 of 28

characteristics that make the use of oxidation catalysts technically infeasible, including catalyst fouling 

and poisoning by sulfur compounds and fly ash, and low excess oxygen levels in the flue gas. The 

catalysts needed for catalytic reduction are generally noble metal catalysts which are very susceptible to 

catalyst poisoning from sulfur-bearing compounds. These catalysts experience rapid deactivation and 

fouling in gas streams with high particulate loading. To be effective, the oxidation catalyst must be placed 

in a location with gas temperatures of at least 600 oF. This location would be near the SCR systems, a 

location with high ash loading and low excess oxygen levels. Oxidation catalysts operate according to the 

following general reaction equation: 2CO + O2 → 2CO2

The typical excess oxygen levels in combustion turbines range from 12 – 15%, as compared to 2 – 6% in

coal-fired boilers. The low excess O2 levels in boilers limit the effectiveness of the oxidation catalyst.

There is some limited experience in using oxidation catalysts in conjunction with tailgas selective

catalytic reduction (SCR) systems on biomass-fired boilers. However, the ERGS units do not have

tailgas SCR systems . We are not aware of any coal-fired boiler equipped with a non-tailgas SCR and an

oxidation catalyst. Even if an oxidation catalyst could be used on the ERGS boilers, there is no evidence

that an oxidation catalyst could reduce CO emissions below the already very low levels of 20 ppm at 3%

oxygen which are currently being achieved using good combustion practices. Because of the already very

low CO emission rates which are currently achieved by the existing BACT controls, the technical

problems for the application of oxidation catalysts to coal-fired boilers, and the fact that we are not 

aware of the use of CO oxidation catalysts on any coal-fired boiler, oxidation catalysts are not a 

technically feasible CO control technology for coal-fired boilers.

As a first note, whether the control would be more effective than the “good combustion” option is not 

relevant as to whether any control option is technologically feasible. The Department concurs that a CO 

catalyst system has never been installed and demonstrated as technologically feasible on a coal-fired 

boilers. However, this determination alone does not eliminate the use of a CO catalyst as a potential 

emissions control option. The possibility of using a control demonstrated on another somewhat similar 

process is a key component of BACT. Without this type of analysis, an industry or emissions unit could 

forever avoid add-on controls claiming that no identical unit has demonstrated that the control will work 

on that specific emission unit.

The emission unit that have used a CO catalyst to control CO emissions are natural gas fired units. In 

general, natural gas combustion yields much lower SO2 and other trace elements such as metals that may 

poison any catalysts or at a minimum bind to potential reaction sites. The applicant also raises the issue 

that the environment of a coal-fired boiler would not have sufficient oxygen to allow the CO catalyst to 

function. Based on this, the Department concurs that the CO catalysts is not a technologically feasible 

option for limiting CO emissions. The Department believes that the use in the coal-fired boiler scenario is 

sufficiently different than current demonstrated uses as to make the CO catalyst and undemonstrated

technology for a coal-fired boiler.

Thermal oxidation has never been required nor used on a coal-fired boiler, and its theoretical ability to

reduce CO emissions from coal-fired boilers is questionable. Thermal oxidation would involve injecting

additional air into the flue gas and heating the oxygen enriched mixture to approximately 1,500 oF to

oxidize CO. However, since the combustion of the reheat fuel would itself result in CO emissions, there

is no evidence that thermal oxidation would result in any CO emission reductions. In addition, this

process could increase the generation of NOx in the flue gas that would have to be removed by the SCR.

Since thermal oxidation has never been demonstrated on a coal-fired boiler, and because there is no

evidence that it could reduce CO emissions, thermal oxidation is not a technically feasible CO control
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 12 of 28

technology.

Step 3 – Rank remaining control options

The only remaining control option is god combustion, thus it is the top ranked option (also the lowest 

ranked option).

Step 4- Evaluate the control options

The remaining control option is good combustion practices. It is in the interest of the boiler operator to 

have good combustion practices in order to maximize the efficiency, operability and reliability of the 

power boilers. In the case of CO emissions, there is continuous emission monitor (CEM) data available 

for the actual boiler operation. A summary of this data is as follows:

Year Month Unit 1 Emission Rate

lb/mmBtu

summary of monthly CO emissions in lb/MMBTU for units 1 and 2.

Month and year Unit 1 Unit 2

12/09 0.0206 N/A

1/10 0.0191 N/A

2/10 0.0241 N/A

3/10 0.0333 N/A

4/10 0.0246 N/A

5/10 0.0136 N/A

6/10 0.0142 N/A

7/10 0.0178 N/A

8/10 0.0254 0.019

9/10 0.0128 N/A

10/10 0.0269 0.020

11/10 0.0163 0.021

12/10 0.0164 0.024

1/11 0.0146 0.014

2/11 0.0100 0.017

3/11 0.0199 0.023

4/11 0.0126 0.012

5/11 0.0084 0.015

6/11 0.0201 0.017

7/11 0.0077 0.015

8/11 0.0245 0.017

9/11 0.0209 0.018

10/11 N/A 0.015

11/11 N/A 0.021

12/11 N/A 0.008

Average, Both Units 0.018

Standard Deviation, Both Units 0.006

Number of Data Points 38

Highest Data Point 0.0333

These emission rates were achieved on bituminous coal. The applicant asserts, and the Department 

concurs, that the use of subbituminous coal may lead to higher CO emission rates that bituminous coal. 

Subbituminous coal has a lower heating value per pound of coal and a higher moisture content than 

bituminous coal. These factors can lead to cooler combustion which can lead to higher CO emissions. 

Additionally, since subbituminous coal is a new fuel for these boilers, there could be greater CO 

emissions in the short term (few months to a couple of years) while operation on this fuel is mastered by 

the boiler operators and any needed control scheme changes are made. Finally, there is the possibility of 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 13 of 28

short-term spikes in CO emissions associated with shutdown and startup events (periods of unsteady state 

operation). Thus, these periods may also need to be addressed in any BACT determination.

The primary BACT emission limitation for CO will be the limitation that applies excluding startup and 

shutdown operations. This type of limit was included in the original permit and that permit also

contained a definition of startup and shutdown which is readily verifiable. It is important to note that this 

does not exclude and times of “malfunction” and these periods are covered by this emission limitation.

As the Table above indicates, the average CO emissions for these boilers have been 0.018 lb/MMBTU 

with the highest data point being 0.033 lb/MMBTU. Also, permitted emission levels for other similar

boilers have been within the 0.10-0.15 lb/MMBTU with averaging times ranging from 3 hours to annual. 

Even though this is the range of other BACT determinations, the available operation data indicates that a 

significantly lower level of CO emissions is achievable and has been achieved on these units.

As stated previously, a BACT limitation must be the maximum achievable emissions reduction, but also 

must be, in the Department’s opinion and achievable emission rate. The 0.018 lb/MMBTU was achieved 

with a relatively small standard deviation of 0.006. the standard deviation provides an indication of the 

variability of the data, but its use is not required to determine any BACT emissions limitation. However. 

ignoring it when there is such a relatively large quantity of data (as oppose to one or two stack tests) 

would not, in the Department’s opinion, be prudent in making a BACT determination. 

Given this mean and a single standard deviation, this yields a rate of 0.024 lb/MMBTU. There is 

additional uncertainty in what future emissions will be for this unit due to the change in coal and the 

likelihood of higher emission in the future. Thus, a rate higher than a single standard deviation above the 

mean seems justified. Given this, the Department believes a rate at the mean plus two standard deviations 

is a reasonable BACT emission limitation. This limitation is within a range of the variation expected in 

performance and actually lower than the measured CO emissions in one of the months for which the 

Department has data. Adding this factor to the proposed limitation being significantly lower than that 

required for any similar unit and leads to a conclusion that this limitation is BACT for CO emissions from 

these units.

The next factor to examine is the possibility for even higher emissions during the initial operation 

(shakedown) period for use of subbituminous coal. The Department believes it is reasonable to conclude 

that these emissions will be higher than the rate that can be achieved over the long term. To account for 

this factor, the Department is proposing a rate of 0.050 lb/MMBTU for CO for an 18-month period after 

commencing operation on subbituminous coal.

There are existing emission limitations for these boilers covering maximum emission in 24 hours and 

maximum emissions during startup/shutdown. These BACT determinations will remain in the draft

permit.

Step 5 – Establish BACT

-0.030 lb CO/MMBTU commencing in any consecutive 30-day period excluding startup and shutdown 

emissions. This limitation applies commencing 18 months after the initial combustion of subbituminous 

coal in either unit.

- 0.050 lb Co/MMBTU commencing in any consecutive 30-day period excluding startup and shutdown 

emissions. This limitation only applies for 18 months after the initial combustion of subbituminous coal 

in either unit.

- existing BACT conditions as discussed in Step 4

3. Greenhouse gas (GHG) BACT – GHG emissions consist of compounds that have a global 

warming potential. In the case of a coal fired boiler, approximately 99% of potential GHG 

emissions are carbon dioxide. However, this analysis will look at controlling carbon dioxide, 

methane and nitrous oxide emissions.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 14 of 28

Step 1 – Identify potential control options

For carbon dioxide control options are efficient combustion and carbon capture and sequestration. For 

methane control options are efficient combustion, oxidation catalysts and thermal oxidation (same 

controls as for CO). For nitrous oxide potential controls are efficient combustion, low NOx operation, 

selective catalytic reduction, non-selective catalytic reduction (NSCR) and thermal NOx destruction

Step 2 – determine technologically feasible option

Carbon capture and sequestration are technologically feasible options. Oxidation catalysts and thermal 

oxidation were eliminated as technologically infeasible for CO control and are also eliminated here as 

infeasible for methane control.

NSCR has been used at nitric acid production plants to reduce nitrous oxide emissions. Essentially it 

involves a catalytic reaction to convert the nitrogen in the nitrous oxide to diatomic nitrogen. This 

technology is also used (called NSCR and an oxidation catalyst) to control NOx emissions from lean burn 

stationary engines. The Department can find no use of this in a solid fuel fired boiler or any applications 

being considered for coal fired boilers. The Department concludes that this technology is not 

demonstrated or available from coal fired boilers. Thus, it is eliminated from further consideration as 

BACT.

Thermal NOx destruction was eliminated in the NOx LAER analysis and will not be considered further.

Step 3

The remaining options are ranked as follows:

1. Efficient combustion plus carbon capture and sequestration

2. Capture and sequestration alone

3. Efficient combustion

Step 4 – Evaluate BACT

Carbon capture and sequestration is a theoretically feasible control option. However, due to the location 

of the plant, there is no known place to sequester the carbon near the facility. This would require the 

construction of a CO2 transport pipeline which would stretch for hundreds of miles costing tens of 

millions of dollars (if not hundreds of millions). Given this, plus the loss of efficiency (i.e. loss of 

generation to sell) that such a system would create, this option is considered economically infeasible for 

controlling these emissions.

The remaining option is good combustion. Good combustion for GHG minimization is defined as how 

much of the heat in the fuel is converted to useful electric energy. Thus, a BACT limit based on good 

combustion will limit the quantity f GHG emissions (or CO2 emissions) per unit of electric output. The 

applicant has proposed a limitation of exceed 2,570 pounds of CO2 per MWh of net electric output, averaged 

over any consecutive 12-month period. The Department has examined another BACT analysis on the BACT/LAER 

clearinghouse and finds a single BACT determination for a power plant in Iowa of 2927.1 lb CO2/MWh (net). This 

is significantly higher than the number proposed by the applicant as BACT for these boilers.

The actual boiler operation rate has been 2,203 lb CO2/MWh (net) with a standard deviation of 185 lb CO2. Given

the possibility of deterioration over time (these are newer boilers) and the standard deviation, the Department 

concludes that the proposed BACT limitation is a reasonable limitation.

Step 5 – Determine BACT

BACT is proposed as a CO2 emission limitation of 2,570 lb/MWh (net). Compliance to be monitored by 

measuring the electric output a using a CEM to measure CO2 emissions.

4 .BACT for visible emissions
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 15 of 28

Visible emissions are the result of emission of solid particulate, condensable particulate and potentially SO2 or 

NOx. In order to control visible emissions, 

Step 1 – identify control technologies

Control technologies for visible emissions are the same as those for PM, SO2 and NOx.

Step 2 – evaluate feasible technologies

The technologies that are feasible for PM, SO2 and NOx are also feasible for limiting visible emissions

Step 3 – Rank the remaining control options

For PM, NOx and SO2, the top control options were selected. Thus, these options will be the only option given 

further consideration.

Step 4 – Evaluate BACT

The units covered in this permit are subject to BACT for PM/PM10 and LAER for PM2.5, SO2 and NOx. Given 

that all of these emissions are controlled using the top control technology option and meet stringent BACT or LAER 

emission limitations, the use of these devices and meeting the emission limitations for these pollutants will ensure 

low visible emissions.

Additionally, an emission limitation is needed for visible emissions. Since these units are equipped with a wet FGD, 

opacity readings are difficult to take and not measurable by a continuous monitor as they exited the stack. Thus, the 

opacity requirement will be for the gas stream prior to entering the FGD. The Department believes that opacity of 

no greater than 10% represents BACT for visible emissions. The applicant has requested that a single six minute 

excursion from this level to 20% be allowed in each hour. This request seems reasonable and is included in the 

proposed BACT.

Step 5 – Establish BACT

BACT is visible emissions not to exceed 10% prior to the FGD except for one six minute period per hour when a 

maximum of 20% opacity is allowed. Opacity to be measured with a continuous opacity monitor (COM).

BACT for hydrogen fluorides (HF)

Step 1 – identify control technologies

Control technologies for HF are the same as those for PM and SO2. These controls reduce HF emissions by reacting 

with the HF and by saving fluorides in solid particulate form.

Step 2- Evaluate feasible technologies

Feasible technologies are the same as those for PM and SO2

Step 3 – Rank remaining control options

The applicant has identified the top option for PM control (baghouse and wet ESP) and the top option for SO2 

control (wet FGD) as the control technologies of choice for these pollutants. Since these are the top options for 

these pollutants, they are also the top options for HF

Step 4 – Evaluate BACT

BACT control technology is the use of a baghouse, wet ESP and wet FGD to control HF emissions.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 16 of 28

BACT limits for similar units generally range from 0.0002 lb/MMBTU to 0.0095 lb/MMBTU. Testing at the Elm 

Road facility indicates an emission rate of 0.000062 lb/MMBTU using bituminous coal. However, subbituminous 

coal may have a significantly different fluoride content. Thus, actual unit testing is not as useful for setting the HF 

BACT as it was for other pollutants. Thus, the Department is establishing BACT equivalent to the lowest rate in 

any other permit it is aware of or 0.0002 lb/MMBTU.

Step 5 – Establish BACT

BACT is 0.0002 lb/MMBTU demonstrated trough stack testing.

BACT for sulfuric acid mist

Step 1 – identify control technologies

Sulfuric acid mist is controlled similarly to sulfur dioxide. Thus, the control options for sulfuric acid mist are the 

same as those for sulfur dioxide. These controls are presently wet FGD, baghouse and wet ESP.

Step 2 – evaluate feasible control technologies

The control technologies identified for SO2 and particulate matter are feasible for sulfuric acid mist.

Step 3- Rank the remaining options

The top option of baghouse, wet ESP and wet FGD is currently used at the facility and is proposed for future use. 

No further ranking of alternatives is required.

Step 4 – Evaluate BACT

BACT will be the use of the baghouse, wet ESP and wet FGD. Emission limitations for similar units have ranged 

from 0.001-0.005 lb/MMBTU. The majority of BACT determinations are in the 0.004-0.005 lb/MMBTU range. 

Actual testing on the units at Elm Road indicate a sulfuric acid mist rate of 0.0025 lb/MMBTU, on average.

Sulfuric acid mist emission should be related to sulfur dioxide emissions in that if sulfur dioxide is well controlled, 

sulfuric acid mist should also be well controlled. Based on the available data, the Department is proposing a sulfuric 

acid mist BACT emission rate of 0.005 lb/MMBTU. This is consistent with other recent BACT determinations.

Step 5 – establish BACT

BACT is an emission rate of 0.005 lb/MMBTU. Compliance demonstrated through stack testing and meeting the 

sulfur dioxide BACT emission rate.

LAER – The Lowest Achievable Emission Rate (LAER) is required for any pollutant subject to review under ch.

NR 408, Wis. Adm. Code. In this case, the county in which the facility is located is non-attainment for particulate 

matter less than 2.5 microns (PM2.5). For PM2.5, direct emissions of PM2.5 are regulated as well as emissions of 

sulfur dioxide and NOx. Thus, PM2.5 direct emissions, SO2 emissions and NOx emissions from the facility are 

subject to LAER and non-attainment offsets (this requirement will be address in a separate section of this 

document).

The LAER analyses for each pollutant are as follows.

1. PM2.5 direct emissions – PM2.5 direct emissions result from coal combustion. These emissions consist of 

both fine solid particles that are not captured in the emission control devices as well as condensable 

compounds generally consisting of sulfate or ammonium salts. These salts are vapors in the exit stream 

but condense to form solids particulate matter outside of the boiler stack. The condensable salts are 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 17 of 28

commonly called “backhalf” emissions as they are captured in the backhalf of the particulate collection 

portion of the stack testing equipment used to measure these emissions.

Step 1 – Identify feasible control technologies – feasible control technologies are the same as those for 

controlling solid particulate matter (baghouse, ESP, wet ESP, wet scrubber, mechanical collector) as well as 

devices that limit NOx and SO2 emissions. These devices include SCR and flue gas scrubbers.

Step 2 – Evaluate feasible control technologies

All of the control technologies are feasible. The use of an SCR is questionable for controlling N2O emissions 

as it may generate these emissions while removing nitrogen compounds. Its use is eliminated as a control 

technology.

Step 3 – Rank the remaining options

The top option is use of a baghouse with a wet scrubber a polishing PM control device or wet ESP. the 

baghouse, wet scrubber (for SO2 control) and wet ESP are proposed as the control technology for PM2.5 

Thus, no further analysis of less effective options is required.

Step 4 – Evaluate LAER

LAER will be the use of a baghouse, wet ESP and wet flue gas scrubber (primarily for SO2 control). Thus, part 

of the LAER analysis is complete. The next step is to determine a LAER emission rate as well as whether 

PM2.5 and/or other pollutants should be determined to be LAER for these units.

Since SO2 is a precursor to PM2.5 formation and subject to LAER under this permit, the SO2 LAER 

requirements are also incorporated as part of LAER for PM2.5 direct emissions. Thus, sulfate emissions will be 

limited by meeting the SO2 LAER.

For direct PM2.5 emissions, these emissions are fine particulate and some non-sulfate condensable emissions.

Control of particulate matter has been established with a BACT emission limitation of 0.012 lb/MMBTU for all 

particulate. The Department is proposing this as LAER for PM2.5 for the following reasons:

- Good control of overall particulate matter is also good control for PM2.5

- Lack of availability of data on specific PM2.5 emissions form the boilers. The Department is unsure 

where such a limit would be set

Step 5 – Establish LAER

LAER is the control of PM2.5 emissions such that the BACT emission rate for total PM is met as well as the LAER 

for SO2 is achieved.

2. Sulfur dioxide – Sulfur dioxide is formed when sulfur in the cola is converted through the combustion 

process to sulfur dioxide (SO2)

Step 1 – identify possible control technologies – Feasible control technologies include lower sulfur coal, wet 

scrubbing and dry scrubbing of SO2 emissions.

Step 2 – evaluate feasible control technologies – All of the technologies identified in step 1 are feasible

Step 3 – rank the remaining control technologies. Normally this step involves a simple ranking of control 

technologies. However, in this specific case, a discussion of the effectiveness of requiring a low sulfur fuel will 

be included.

In general, one expects that with less sulfur going into a boiler, which less sulfur will be emitted from the boiler 

in the form of SO2. However, in the case of these units, the actual 30-day average SO2 emissions have been 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 18 of 28

0.015 lb/MMBTU with a standard deviation of 0.018 lb/MMBTU. This is a very low rate of SO2 emissions. 

For comparison, the lowest permitted level for a coal plant that the Department is aware of is 0.052 

lb/MMBTU. This is a comparison to lower subbituminous coal fired units.

The low sulfur fuel requirement would essentially require the combustion of the maximum quantity of 

subbituminous coal feasible. This level is not known presently, but is unlikely to be much above 25-30% 

without significant physical changes to the boiler. Based on this, and, in the Department’s view, unlikelihood 

that lower sulfur coal will achieve a statistically significant reduction in emissions, the Department is not 

proposing the use of lower sulfur coal as LAER for SO2. 

Therefore, the ranking of options is as follows:

1. FGD, subbituminous or bituminous coal

Since this is LAER, no further analysis of less effective alternatives is required.

Step 4 – Evaluate LAER

As mentioned in Step 3, the present SO2 emissions are 0.015 lb/MMBTU with a rather large standard deviation 

of 0.018 lb/MMBTU. As discussed previously in this document, LAER is the best control that can be achieved 

without regard to cost. The use of the FGD is the best control that can be achieved, but it is also important to 

determine what that best rate is. Based on the available data, and on the performance levels required for other

similar coal-fired boilers, an emission rate of 0.030 lb/MMBTU on a 30-day average is proposed as LAER. It 

should be noted that this is less than a single standard deviation from the mean performance actually achieved 

and takes into account that the operation of the FGD may decline due to general wear.

Step 5 – Establish LAER

LAER is proposed as 0.030 lb/MMBTU averaged over any 30-day period.

2. Nitrogen oxides (NOx) – NOx is primarily formed through the oxidation of diatomic nitrogen n the 

combustion air. This type of oxidation occurs in the hottest portions of the boiler.

Step 1 – Identify control technologies

Control technologies include selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR), 

SCONOx, overfire air, low NOx burners, oxygen enhanced combustion, fuel reburn and flue gas recirculation. 

The add-on control technologies (SCR, SNCR and SCONOx) may also be added to the other control 

technologies to yield the lowest NOx emissions.

Step 2 – Evaluate feasible control technologies

SCR, SNCR, overfire air, low NOx burners and flue gas recirculation are all feasible control technologies. For 

further analysis, low NOx burners, flue gas recirculation and overfire air will be combined as good combustion 

techniques.

SCONOx – This is a technology that catalytically reduces NOx emissions. This technology has been applied to 

natural gas fired units with relatively clean emission streams. The technology has not been applied to a coalfired boiler and it does not appear ripe for technology transfer to such units. Thus, it is eliminated from further 

consideration.

Fuel reburn – This is a technology that has been applied to older, existing boilers to reduce NOx emissions ta a 

relatively low cost . This technology has not been applied to new coal boilers and it is generally not compatible 

with the good combustion techniques identified previously. It will be carried forward.

Step 3 – Rank the remaining control options
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 19 of 28

The top option is use of an SCR in combination with good combustion technologies. This is the technology 

proposed as LAER. Therefore, no further analysis of less-effective options is necessary.

Step 4 – Evaluate LAER

BACT determinations for similar boilers have ranged from 0.05 – 0.09 lb/MMBTU for NOx averaged over any 

30-day period. Actual performance data at the facility shows an average NOx emission rate of 0.054 

lb/MMBTU with a standard deviation of 0.009 lb/MMBTU (all limits averaged over a 30-day period). Thus as 

done previously, a determination of what rate represents LAER and can be achieved over the life of these units 

is necessary.

Based on this data, and the possibility of deterioration in performance of the SCR unit due to normal wear, the 

Department concludes that a rate of 0.065 lb/MMBTU represents LAER for NOx emissions.

Step 5 – Establish LAER

BACT is proposed as the use of good combustion and an SCR to achieve an emission rate of 0.065 lb/MMBTU 

over any 30-day period.

AIR QUALITY REVIEW

All potential emissions for the emissions units covered in the draft construction permit are either the same 

or lower than the emissions rates which were modeled in previous construction permit for this facility. 

Therefore, based on Department modeling policy, no additional air quality analysis is required.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 20 of 28

EMISSIONS FROM NEW EQUIPMENT OR MODIFICATION. These are emissions per boiler. Total 

emissions are twice these levels.

Pollutant Lb/hour Tons/year

Particulate matter (PM) 81 355

PM10 81 355

PM2.5 81 525

SO2 202.5 887

NOx 439 1922

CO 202.5 887

VOC 23.6 95

HF 1.35 5.9

Sulfuric acid mist 33.7 147.8

Lead 0.05 0.234

Mercury 0.0075 0.033

Beryllium 0.002 0.010

CO2 1,423,211 6,233,666

GHG 1,457,965 6,385,890

While these represent maximum emissions from a single boiler, combined emissions are limited as follows: 

NOx: 2661 tons/year; VOC 95 tons/year; SO2: 1,774 tons/year and PM2.5: 525 tons/year.

EMISSIONS NETTING ANALYSIS 

See NAA analysis

FACILITY AND PROJECT CLASSIFICATION

1. Project Status.

The facility is a major PSD source and a major non-attainment source for PM2.5. The facility is also 

a Part 70 major source

2. Facility Status After the Permit is Issued.

The facility status is unchanged by the activities approved under this permit.

3. EPA Class Code After the Permit is Issued.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 21 of 28

“A” [Means the source’s maximum theoretical emissions and potential to emit for one 

or more pollutants are greater than major source thresholds. The source is a major 

source (will have a FOP)];

“SM80” [Means the source’s maximum theoretical emissions of one or more pollutants are 

greater than major source thresholds and potential to emit is at least 80% but less 

than 100% of major source thresholds. The source is a non-major source (will have 

a FESOP)];

“SM” [Means the source’s maximum theoretical emissions of one or more pollutants are 

greater than major source thresholds but potential to emit for all pollutants is less 

than 80% of major source thresholds. The source is a non-major source (usually 

will have a FESOP)];

“B” [Means the source’s maximum theoretical emissions and potential to emit for all 

pollutants are less than major source thresholds. The source is a non-major source 

(will have a SOP)].

4. Summary.

NSR Applicability

After Permit Issuance

Major Minor

PSD X

Non-Attainment X

Federal HAP X

Part 70 Applicability

Facility After Permit Issuance

Part 70 FESOP (Syn. Minor) non-part 70

Status X

EPA Class Code

EPA Class Code After Permit Issuance

A SM80 SM B

Status X

ENVIRONMENTAL ANALYSIS

An EIS was completed for these boilers when initially constructed. Since this permit only lowers emission 

limitations and construction was only completed in the last 3 years, no additional environmental analysis has been 

completed.

RULE APPLICABILITY

The proposed boilers are subject to the following new requirements:

Ch. NR 405 revised BACT for CO, PM/PM10, sulfuric acid mist and HF. A new BACT for greenhouse 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 22 of 28

gas emissions and visible emissions. Compliance with these limitations is demonstrated though a CEM 

for CO and greenhouse gases. PM/PM10, sulfuric acid mist and HF emissions are demonstrated through

stack testing. Visible emissions are monitored prior to the FGD. The water plume from the wet FGD

makes measuring the continuous opacity from the stack exit infeasible.

Ch. NR 408 new LAER for PM2.5, NOx and SO2. 

Compliance with the NOx and SO2 emission limitations are demonstrated through the use of continuous 

emissions monitors (CEM’s). Compliance with the PM2.5 emission limitation is demonstrated through 

stack testing for PM. Testing for PM2.5 direct emissions is infeasible based on the use of the wet FGD, at 

this time. The Department retains the authority to require PM2.5 testing when a suitable test method is 

available.

The Federal MACT standard is the existing 112(g) emission limitations in the original permit. These are not 

changed as the boilers under his permit are not considered new under the MACT standards.

The boilers are subject to NSPS requirements as they were constructed under the 2004 air permit. The changes 

proposed under this permit do not trigger any new NSPS requirements as the capacity of either of the boilers is not 

being increased and potential emissions of all pollutants subject to NSPS requirements are not increasing.

NEW SOURCE PERFORMANCE STANDARDS (NSPS) APPLICABILITY

For proposed construction of a source:

1. Is the proposed source in a source category for which there is an existing or proposed NSPS?

Yes No Not applicable. (If yes, identify the source category.)

2. Is the proposed source an affected facility?

Yes No Not applicable. (Explain if necessary to clarify.)

For the proposed modification of an existing source:

1. Is the existing source, which is being modified, in a source category for which there is an existing or 

proposed NSPS?

Yes No Not applicable. (If yes, identify the source category.). NSPS for large coal fired 

boilers.

2. Is the existing source, which is being modified, an affected facility (prior to modification)?

Yes No Not applicable. (Explain if necessary to clarify here and in the following items)

3. Does the proposed modification constitute a modification under NSPS to the existing source?

Yes No Not applicable.

4. Will the existing source be an affected facility after modification?

Yes No Not applicable.

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPS) APPLICABILITY

Part 61 NESHAPS:

1. Will the proposed new or modified source emit a pollutant controlled under an existing or proposed 

NESHAPS?
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 23 of 28

Yes No (if yes, identify the pollutant).

2. Is the proposed new or modified source subject to an existing or proposed NESHAPS?

Yes No (if yes, identify NESHAPS).

Part 63 NESHAPS:

1. Will the proposed new or modified source emit a pollutant controlled under an existing Part 63 

NESHAPS?

Yes No (if yes, identify the pollutant).

2. Is the proposed new or modified source subject to an existing Part 63 NESHAPS?

Yes No (if yes, identify NESHAPS).

3. Is the proposed project subject to s. 112(g) of the Clean Air Act?

Yes No.

The facility was subject to 112(g) upon construction. This unit is not required to meet the new utility 

MACT requirements until years after the compliance date. The original 112(g) requirements remain 

in this permit.

The facility is required to comply with the MACT standard within 8 years of the compliance date. 

However, the more stringent portions of the 112(g) determination (i.e. for mercury) may not be 

changed (no backsliding). Thus, the relevant utility MACT standard for these boilers is not included 

in this permit.

PSD - PRECONSTRUCTION MONITORING ANALYSIS

None required. This is an existing source which has been evaluated for ambient impact in the previous 

permit. In addition, the Department believes the current modeling network is sufficient to meet this 

requirement.

PSD - ADDITIONAL IMPACTS ANALYSIS

No additional significant impacts are expected as a result of this project. The stated purpose of this 

project is to use a cheaper fuel (subbituminous coal) in the existing power boilers. This permit will not 

allow for greater use or higher emission form the existing boilers.

NAA - OFFSET ANALYSIS AND NET EMISSIONS INCREASE CALCULATION

This facility is located in area which is presently non-attainment for PM2.5 emissions. For PM2.5, not 

only are direct PM2.5 emissions regulated, but also emissions of NOx and SO2 as PM2.5 precursors. 

Therefore, an evaluation of the emissions increase from this project is required as well as an offsetting (on 

a 1:1 basis) of any increase.

The first step in this analysis is to determine a baseline period for the boilers. Under ch. NR 

408.02(2m)(a), Wis. Adm. Code, defines baseline for an electric utility as “...the average rate, in tons per 

year, at which the unit actually emitted the air contaminant during any consecutive 24-month period 

selected by the owner or operator within the 5-year period immediately preceding when the owner or 

operator begins actual construction of the project. The department shall allow the use of a different time 

period upon a determination that it is more representative of normal source operation.” 

The applicant has requested to use a different time period than the 24-month period. The basis of this 

request is that the units are new (operating only since October 2009 for unit 1 and July 2010 for unit 2), 
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 24 of 28

and that they did not operate at a representative rate during the first few months to first year of operation. 

The applicant has proposed the period of October 2010-Septemebr 2011.

In the application the applicant states that CEM data has only been available since December 2009 for 

unit 1 and August 2010 for unit 2. Thus, for the units to have the same baseline period, the baseline 

period could not reasonable commence prior to August 2010. The application was submitted in March 

2012 and some preparation time was necessary, therefore the use of the October 2010-September 2011 

baseline period appears reasonable. The Department will allow this period to be used as an approved 

baseline period. This determination is primarily based on these units not operating normally due to the 

need for startup and shakedown work. In general, the Department uses the full two year period for all 

emissions units.

Using this baseline period, actual emissions in tons/year are as follows:

Pollutant Unit 1 emiss. Unit 2 emiss. Material handling total

CO 244 208 452

NOx 776 602 1,378

PM 130 59 103 292

PM10 130 59 71 260

PM2.5 130 59 43 232

SO2 253 186 439

Organic cmpds 10.6 2.5 13.1

Sulfuric acid 44 25 69

Fluroides 1.7 1.4 3.1

Lead 0.0686 0.0583 0.127

Mercury 0.0016 0.0019 0.0035

Beryllium 0.0042 0.0035 0.0077

CO2 3,108,338 2,561,163 5,669,501

GHG’s 3,132,575 2,581,185 5,713,760

Future maximum emissions from the two boilers combined (in tons/year) are as follows:

Pollutant Emiss (tons/year)

PM 710

PM10 710

PM2.5 525

SO2 1774

NOx 2661

Organics 95

Sulfuric acid 295.6

Fluorides 10.8

Lead 0.47

Mercury 0.066

Beryllium 0.020

CO2 12,467,332

GHG 12,771,780
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 25 of 28

Potential emission from material handling are only particulate in nature and are 161 tons/year

The net emissions increase for each pollutant, in tons/year, is as follows:

Pollutant Potent emiss Past actual emiss. Net emiss. increase

PM 871 292 579

PM10 871 260 609

PM2.5 686 232 454

SO2 1774 439 1,335

NOx 2,661 1,378 1,283

Organics 95 13.1 81.9

Sulfuric acid 295.6 69 226.6

Fluorides 10.8 3.1 7.7

Lead 0.47 0.127 0.343

Mercury 0.066 0.0035 0.0625

Beryllium 0.020 0.0077 0.0123

CO2 12,467,332 5,669,501 6,797,851

GHG 12,771,780 5,713,760 7,058,020

This Table uses the actual-to-potential methodology to determine the net emissions increase, for PM2.5 

the applicant is projecting a smaller actual increase in PM2.5 based on the fraction of material handling 

emissions that are projected to be PM2.5. Using the projected actual emission methodology yields an 

estimated future PM2.5 actual from material handling of 71.1 tons/year. This yields a net emissions 

increase for PM2.5 of: 525 tons/year + 71 tons/year – 232 tons/year = 364 tons/year

In order to offset the projected emissions increase for PM2.5, NOx and SO2, the applicant is proposing to

limit emissions from units 5, 6, 7 and 8 at the Oak Creek facility. The applicant has selected calendar 

years 2010 and 2011 as the baseline periods for these units. In addition, these units are subject to 

emission limitations through a Consent decree and permit which presently limit the potential to emit of 

these units. Thus, the emission Tables will contain both actual emissions and the potential to emissions 

that would have been allowed under the current emission limitations. The allowable emission to offset 

are the lesser of the actual or emissions that would be allowed under current emission limitations. The 

emissions from these units are as follows:

NOx emissions from units 5-8

Unit PTE (tons/year) Actual emiss. 

(tons/year)

Maximum creditable 

amount (tons/year)

5 1,110 1,263 1,110

6 991 992 991

7 1,497 1,057 1,057

8 1,395 1,209 1,209

Total 4,993 4,521 4,366

PM2.5 emissions from units 5-8

Unit PTE (tons/year) Actual emiss. 

(tons/year)

Maximum creditable 

amount (tons/year)
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 26 of 28

5 1,388 226 226

6 1,239 132 132

7 1,871 253 253

8 1,744 282 282

Total 6,241 893 893

SO2 emission from units 5-8

Unit PTE (tons/year) Actual emiss. 

(tons/year)

Maximum creditable 

amount (tons/year)

5 1,110 3,347 1,110

6 991 2,495 991

7 1,495 3,551 1,497

8 1,395 4,129 1,395

Total 4,993 13,522 4,993

The applicant has proposed to cap emissions from these units at 3000 tpy for NOx; 525 tons/year for 

PM2.5 and 2,400 tons/year for SO2. This yields an offset amount for each pollutant calculated as the 

difference between the maximum creditable emissions and the future allowed emissions. The following 

Table summarizes the quantity of offsets in tons year:

Pollutant Max creditable Future allowed emiss. Net credit

NOx 4,366 3,000 1,366

PM2.5 893 525 364

SO2 4,993 2,400 2,593

The required creditable amounts are 1,283 tons/year for NOx; 364 tons/year for PM2.5 and 1,335 

tons/year for SO2. Thus, this will generate sufficient credits to offset these increases in emissions.

NAA - ANALYSIS OF ALTERNATIVES

This was completed for the initial permitting of these units in 2004. For this permit, the alternative is to 

continue to combust a more expensive fuel (bituminous coal) versus a potentially less expensive fuel. 

The emissions under this permit are lower than those allowed under earlier permit. Without this permit, 

higher emission would be allowed in the future.

EMISSION REDUCTION OPTION

The potential increase in emissions of PM2.5, NOx and SO2 have been offset by reductions from the 

existing boilers at the Oak Creek facility.

CAM - COMPLIANCE ASSURANCE MONITORING.

Not required in a construction permit. 

CRITERIA FOR CONSTRUCTION PERMIT APPROVAL

Section 285.63, Wis. Stats., sets forth the specific language for permit approval criteria. The Department 

finds that:

1. The source will meet emission limitations. 

2. The source will not cause nor exacerbate a violation of an air quality standard or ambient air increComment [P1]: Should also add the criteria for 

an attainment area major project (PSD).
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Page 27 of 28

ment. 

3. The source will not preclude the construction or operation of another source for which an air pollution 

control permit application has been received. 

In addition to meeting the above criteria, all major source construction or major modifications located in 

nonattainment areas must meet the following criteria for permit approval. For this source the Department 

finds that:

1. Reasonable further progress toward the attainment and maintenance of all ambient air quality 

standards will be achieved.

2. The emission from the source will be at the lowest achievable emission rate (LAER) or the source 

will apply the best available control technology (BACT), as applicable.

3. The applicant's other major sources located in Wisconsin meet or are on a schedule to meet the 

requirements of ss. 285.01 to 285.87 and s. 299.15, Wis. Stats., and rules promulgated under those 

sections.

4. An analysis of alternatives has been made for the proposed project and it has been shown that the 

benefits of the construction or modification of the source significantly outweigh the 

environmental and social costs imposed as a result of the source's location, construction, or 

modification.

PRELIMINARY DETERMINATIONS FOR CONSTRUCTION PERMIT NO. 12-SDD-047

The Wisconsin Department of Natural Resources has reviewed the construction permit application and 

other materials submitted by Wisconsin Electric Power Company, D/B/A We Energies-Oak Creek Station

and hereby makes a preliminary determination that this project, when constructed or modified and 

operated consistent with the application and subsequent information submitted, will be able to meet the 

emission limits and conditions included in the attached Draft Permit. A final decision regarding emission 

limits and conditions will be made after the Department has reviewed and evaluated all comments 

received during the public comment period. The proposed emission limits and other proposed conditions 

in the Draft Permit are written in the same form that they will appear in the construction permit and 

operation permit revision. These proposed conditions may be changed as a result of public comments or 

further evaluation by the Department. The United States Environmental Protection Agency will be given 

the opportunity to comment on the operation permit revision of any Part-70 source prior to the 

Department making a final decision on the operation permit revision.
Preliminary Determination, FID No. 241007690, Permit Nos. 12-SDD-047 Pag

PERMIT FEE CALCULATION

Basic Fees.

Review of major source $16,000

Total Basic Fees $16,000.00

Additional Fees.

Nine basic emissions units (B18, B19, B5-8, P23, P48, P49)

Analysis of alternatives

Emission offset

Nine BACT/LAER determinations (PM/PM10, PM2.5, NOx, CO, SO2, HF, sulfuric 

acid, GHG, visibility)

Three contaminants for testing (PM, HF, sulfuric acid)

Public hearing request

$7,200

$2,500

$5,000

$40,500

$5,000

$1,500

Total Additional Fee $ 61,700

Total Fees (Total Basic Fees + Total Additional Fees) $77,700.00

Credit(s).

The initial fee submitted with the application. [$7,500] -$7,500.00

Total Credits -$7,500.00

TOTAL AMOUNT DUE (Total Fee + Total Credit) $70,200.00