ATTACHMENT 3
1

BART Determination – Amended July 2011 

Georgia Pacific Broadway Mill, Green Bay Wisconsin 

Facility ID 405032870 

Prepared by 

Wisconsin Department of Natural Resources 

Bureau of Air Management /RPMS Section 

July 1, 2011 

Contacts

Tom Karman – thomaskarman@wisconsin.gov

Jon Loftus – jonathanloftus@wisconsin.gov
2

Introduction 

The Georgia Pacific Broadway Mill in Green Bay, Wisconsin operates two coal-fired power 

boilers subject to Best Available Retrofit Technology (BART) under the Clean Air Act (CAA). 

In June of 2010, the Department provided for external review a draft finding of BART 

requirements applicable to the affected Georgia Pacific boilers (Attachment 1). This document 

amends the draft BART finding for Georgia Pacific and provides response to public comment. 

The BART requirements for Georgia Pacific will comprise a component of Wisconsin's State 

Implementation Plan addressing regional haze and will contribute to reasonable progress goals 

(RPG) by 2015 and after. Specific requirements and contribution by non-BART industrial 

boilers, at Georgia Pacific and sector-wide, to RPG will be evaluated as part of the next RPG 

evaluation in 2018 as described in the Haze SIP document. 

Section I. Summary of Amended BART Determination 

The Georgia Pacific BART requirements address emissions of particulate matter (PM), sulfur 

dioxide (SO2), and nitrogen oxides (NOx) from two power boilers B26 and B27. The two 

affected boilers exhaust through common Stack S10 along with the coal-fired boilers B24, B25 

and B28. The BART requirement for each pollutant is summarized as follows: 

Particulate Matter (PM)

The draft finding proposed PM requirements based on the existing control equipment and permit 

limitations and required additional minimizing of PM emissions through the use of this 

equipment. The BART determination for PM is amended to require only the existing PM 

controls and permit limitations. 

Sulfur Dioxide (SO2) 

The draft finding proposed SO2 requirements based on application of dry scrubbing circulating 

fluidized bed (CFB) absorber technology achieving 95% control of SO2 emissions. The 

department developed costs and control levels based on a commercially available CFB unit 

called Turbosorp. 

The BART determination for SO2 is amended to reflect that CFB technology is capable of 

meeting a 93% long-term compliance requirement. This determination further establishes "Base 

SO2 emissions" reflecting a presumptive fuel with specified sulfur contents. The BART 

compliance requirement is established by applying 93% control to the "Base SO2 emissions" 

Nitrogen Oxide (NOx) 

The draft finding proposed NOx requirements based on the application of combustion 

modifications followed by a type of tail-end selective catalytic reduction technology with 

regenerative heat recovery (regenerative SCR or referred to here as RSCR). These controls in 

combination were estimated to achieve control efficiencies of 84% and 92% for boilers B26 and 

B27, respectively. 
3

The BART determination for NOx is amended for both boilers B26 and B27. The requirement 

for boiler B26, a stoker boiler, now reflects combustion modifications followed by selective noncatalytic reduction technology (SNCR) to achieve an overall 68% long-term compliance 

reduction. For B27, a cyclone boiler, the requirement reflects overfire air combustion 

modifications followed by one of several different available control options: RSCR, rich-reagent 

injection (RRI), or SNCR. These equipment configurations are determined to yield an 84% 

long-term compliance control requirement. 

Summary of BART Control Levels and Visibility Improvement

The baseline year average emissions (2002 – 2004) emitted from the Georgia Pacific Stack S10 

boiler system is modeled to determine baseline visibility impact in deciviews (dv). The results, 

in Table 1, show the Seney Class I area receiving a maximum daily impact of 5.38 deciview. 

The average of each baseline year's maximum daily impact for Seney is 4.14 deciview. Adding 

the maximum impact for each northern Class I areas results in a total impact of 8.12 deciview. 

This shows Seney recieves approximately one half of the impact from Georgia Pacific to the 

northern Class I areas. To be noted is that the maximum impact for each area is not expected to 

occur simultaneously. Rather the total value is a metric for measuring total relative impact. 

Table 1. Visibility Impact (dv) for Uncontrolled Base Year SO2 and NOx 

Emissions: 2002, 2003, 2004 

Maximum Average Maximum Average

5.38 4.14 9.67 8.12

Seney Northern Class I Areas 

The improvements to the average visibility impact (4.14 for Seney, 8.12 for northern areas) 

related to BART requirements are also modeled. The results show, in Table 2, a 2.02 deciview 

improvement for Seney and 4.19 deciview improvement in total for the northern Class I areas. 

 

Table 2. Boiler B26 and B27 BART Control Levels and Resulting Visibility Improvement. 

BART Technology and Visibility Improvement (dv) 

Emission Control Efficiency Seney Northern Areas 

Unit 

SO2 NOx PM10 SO2 NOx SO2 NOx

B26 Dry FGD – 

93% 

OFA/FGR/SNC

R – 68% 

Existing Baghouse 

- > 99% 

B27 Dry FGD – 

93% 

OFA + RSCR – 

84% 

Existing Baghouse 

- > 99% 

1.23 0.52 2.79 0.87 

Total BART 2.02 4.19 

1) Visibility improvement values are the average of the maximum daily impact identified for each BART base year 

2002 to 2004 (Table 5.2) 

2) Pollutants when reduced together yield a greater visibility improvement than visibility improvement modeled for 

each pollutant individually. 

Northern Areas = Isle Royale National Park, Seney Wilderness Area, Boundary Waters Canoe Wilderness Area and 

Voyageurs National Park. 
4

BART Compliance Requirements 

The draft BART determination proposed emission limitations for emissions levels from the 

common Stack S10 – emissions for boilers B24 through B28. These proposed emission 

limitations were calculated using fuel consumption and emissions for each boiler over the 

baseline years of 2002 to 2004 and applying the BART control efficiencies to boilers B26 and 

B27. 

In amending the compliance requirements the fuel consumption during the baseline years 

remains the primary basis for representing boiler utilization and determining compliance 

requirements. The SO2 emission requirements are calculated using base year SO2 emissions that 

are first adjusted to reflect a surrogate fuel for each boiler. For NOx, base year emissions reflect 

the actual historic emission rates as NOx emissions are directly related to boiler combustion 

parameters which typically do not change over time. 

Several compliance approaches or alternatives are provided in the permit for meeting the BART 

requirements. These requirements are structured as either emission rate limitations or mass 

emission caps as 30 day or 12 month rolling averages (Table 2). Both 30 day and 12 month 

limits apply in tandem to address daily visibility improvement accounting for operating 

variability (30 day) while ensuring long-term BART reductions (12 month). The complete list of 

compliance methods are: 

o Complying with a 30 day rolling emission limit or a 30 day mass cap and 

annual mass cap individually for each boiler B26 and B27. 

o Complying with a 30 day rolling emission limit (original format) or a 30 day 

mass cap and annual mass cap for the common stack. 

o Complying with a 30 day mass cap and annual mass cap for the common stack 

where additional SO2 reductions are traded to offset avoided NOx reductions. 

Under the trading approach two tons of SO2 must be reduced to offset each 

required ton of NOx reduction. 

Georgia Pacific can comply with either the emission rate limitation or the set of mass cap 

limitations applicable to the individual BART boilers or to the common S10 stack. These 

emission limitations are presented in Table 3.
5

Table 3. Summary of BART Compliance Requirements 

Emission Rate Requirements Mass Cap Requirements 

Emission 

Unit(s) 

12 Month Rolling 

Emission Rate 

Limitation 

(lbs/mmBtu) 

30 Day Rolling 

Emission Rate 

Limitation 

(lbs/mmBtu) 

Tons Emitted in 

any 12 Month 

Period 

Tons Emitted in 

any 30 Day 

Period 

SO2

B26 0.27 254 33 

B27 0.23 502 47 

Stack S10 1.01 1.53 5,800 761 

NOx 

B26 0.22 207 27 

B27 0.20 437 41 

Stack S10 0.21 0.28 1,200 141 
6

Section II. Determination of BART Control Levels 

The determination of BART controls is a top-down process similar to a determination of Best 

Available Control Technology (BACT). An important distinction however is that BACT 

primarily considers cost of control in dollars per ton of pollutant reduced ($/ton). The 

determination of BART control levels, as outlined under 40 CFR Part 51, Appendix Y, 

Guidelines for BART Determinations Under the Regional Haze Rule, is primarily based on the 

degree of visibility improvement considered in conjunction with the following five factors: 

1. Available technology 

2. Cost of compliance 

3. Energy and non-air environmental impacts 

4. Existing pollution control equipment 

5. Remaining useful life 

The primary metrics for comparing cost of technologies are total cost, cost per ton of pollutant 

removed ($/ton) and cost of visibility improvement in deciviews ($/dv). Consideration is also 

given to the incremental (marginal) visibility improvement and cost. 

Similar to BACT, the actual BART can be implemented by establishing a requirement to install 

and operate the control equipment at specific control efficiencies or by establishing a continuous 

emission limitation. The Georgia Pacific BART requirements are implemented as emission 

limitations which are incorporated into the facility's Title V operating permit (Appendix A). 

1. Particulate Matter (PM) BART 

Georgia Pacific currently employs a baghouse to the common Stack S10 for particulate matter 

(PM) control. Emissions testing shows 99% control for coarse particulate matter (PM10). The 

For evaluating whether additional PM control is necessary under BART the Department modeled 

the maximum actual baseline PM10 emissions. A zero-out run of PM emissions (100% control) 

showed a maximum visibility improvement of 0.04 dv for Seney. The number of days with a 

maximum visibility impairment of 0.1 dv or greater were reduced by only 2 days (122 days to 

120 days). 

Due to the small improvement in visibility, the Department determined the draft PM BART at 

Georgia Pacific to be the existing PM controls and permit limitations. However, the Department 

also originally proposed that the facility implement a plan for continuously minimizing PM 

emissions through operational procedures. After further review, PM controls are operated at a 

very high level achieving 0.025 lbs/mmBtu emission rates.1

 Furthermore, Georgia Pacific is 

subject to malfunction and abatement plans, under ch. NR 439, Wis. Adm. Code, for operating 

control equipment in a manner consistent with testing parameters. Therefore, the Department 

concludes an additional plan for minimizing PM emissions will lead to negligible or no 

additional reduction in PM or improvement to visibility. Therefore the Department deems the 

 

1

 August 26, 2008 particulate test on Stack 10 
7

existing PM controls and permit limitations constitute BART PM requirements for boilers B26 

and B27. 

2. Sulfur Dioxide (SO2) BART 

The Department compared wet flue gas desulfurization (FGD) and dry circulating fluidized bed 

FGD in preparing the draft BART determination. This evaluation showed that both technologies 

achieve comparable control of SO2, but the capital cost of wet FGD is almost twice that of the 

dry CFB FGD. The Department concluded that the incremental costs do not substantiate the 

application of wet FGD and that BART should be based on the application of dry CFB FGD 

technologies designed for high control efficiencies (90 – 95%). The latter portion of this 

statement means that any installed scrubber system should be designed for the highest control 

levels. The operation of the scrubber can be scaled to meet the effective emission limitations as 

necessary. 

The Department maintains, under this amended BART determination, that dry CFB FGD 

represents SO2 BART for boilers B26 and B27. After further review, the Department has 

determined that this technology can achieve 95% control efficiency, but that long term operation 

and compliance is represented by 93% control efficiency. The basis for this conclusion is 

described here. This determination also updates the costs and visibility improvements originally 

estimated for the draft BART determination. 

• Dry CFB FGD Control Efficiency

Under draft BART determination a 95% SO2 control efficiency was proposed for the combined 

emissions of boilers B26 and B27. This control efficiency was based on circulating fluidized bed 

dry scrubbing as represented by an evaluation of Turbosorp control equipment and costs. 

Georgia Pacific provided comment that a 95% SO2 control efficiency does not provide 

compliance margin in accounting for operating variability. In response, the Department 

conducted addition review of actual operations and engineering assessments for both Turbosorb 

and other CFB type of installations. A summary of this review is shown in Table 2.1 below. 

The Turbosorp system is operating on Unit 4 of the AES Greenidge facility in North Carolina. 

This system is similar to the Georgia Pacific case where the Turbosorp unit was installed to an 

existing boiler unit - both similar in size and the flue gas characteristics to boilers B26 and B27 

(~100 MWe and firing mid- to high-sulfur coal).2

 Extensive performance testing at the facility 

provides insight into how changes in different factors, such as inlet SO2 concentration and boiler 

load changes, affect the overall control efficiency. The testing shows SO2 control efficiency 

decreased ~ 96.8% to ~ 95.3%, when the unit load is decreased from the 100 MWe down to the 

70 MWe (gross) range, a 30% change. This is an approximate decrease in control efficiency of 

1.5 %. From historic information, the Georgia Pacific stack S10 boiler system typically ranges 

in load between 600,000 and 800,000 lb/hr, a 25% load swing. Since actual demonstrated 

change in control efficiency is 1.5% for 30% load swing, similar to a 25% load swing, a 2% 

change is applied here to allow for a compliance margin. 

 

2 Greenidge Multi-pollutant Control Project. U.S. Department of Energy Cooperative Agreement DE-FC26-

06NT41426.. 
8

The Gainesville Regional Utilities also use a Turbosorp unit at the Deerhaven Station in Florida.3

 

The flue gas SO2 concentration is 2.2 lb/mmBtu with a removal efficiency approaching 95%. 

This Turbosorp unit treats flue gas with SO2 at 3.8 lb/mmBtu to achieve removals up to 97.2%. 

The Westmoreland Roanoke Valley power plant in North Carolina also uses CFB technology for 

SO2 removal. The Roanoke boiler unit is limited to 1.6% sulfur, and has a SO2 removal 

requirement of 93%. 

In 2006 the Washington Group International evaluated CFB technology for SO2 removal at each 

of two 200 MWe units at We Energies’ Oak Creek facility.4

 The design coal had a sulfur content 

of 0.5%. In the evaluation, We Energies settled on 95% SO2 removal because each unit was not 

“large” (i.e. > 250 MWe). The evaluation also indicated that 96-98% SO2 removal was possible 

with the addition of extra water, but that this removal had not been demonstrated at the time of 

the evaluation. 

In 2008 Alliant Energy evaluated CFB for SO2 removal at each of two 100-MWe units at the 

Nelson Dewey facility in Wisconsin.5

 The design coal was 85% powder river basin coal (PRB) 

and 15% petroleum coke, with a resulting emission rate of 2.4 lb/mmBtu SO2. The evaluation 

indicated a 95% long-term SO2 reduction. 

Across these multiple cases the SO2 control efficiency for CFB type of control equipment ranges 

from 93 to 98% removal. However the operating data and engineering assessments for units 

treating SO2 concentrations similar to the Georgia Pacific application show an expected control 

efficiency up to 95% removal. Assuming a 2% decrease in removal efficiency due to operating 

variability, as shown by the Greenidge testing, represents a compliance efficiency of 93% 

removal. The Department finds that 93% is sufficient in addressing variability and appropriate 

in determining long term performance requirements for a CFB unit applied to the Georgia Pacific 

BART boilers. 

 

3

 Ake, Terrence. “Commissioning a Large Turbosorp Circulating Dry Scrubber.” Presentation at Power Plant Air 

Pollutant Control “MEGA” Symposium. September 2010. Baltimore, MD. 

4

 Wisconsin Public Service Commission. Docket 6630-CE-299. February 15, 2011. 

5

 Wisconsin Public Service Commission. Docket 5-CE-138. February 15, 2011. 
Table 2.1 System Performance for Turbosorp and Other Dry FGD Technologies, Applied or Planned. N/A = Not Available

* Notes on Greenidge (existing Turbosorp)

• Was tested over 14-month period (Aug. 2007 to Sept. 2008) 

• SO2 inlet range 2.56 - 4.88 (avg. 3.62) 

• SO2 removal 96.3% (0.134 lb/mmBtu at stack) • Limit is 0.19 lb/mmBtu, or ~ 94.8% removal) 

• 93% SO2 removal below 60 MWe (gross); > 95% above 60 MWe (gross); > 97% above 90 MWe (gross) 

• Applicability to high-sulfur coal confirmed (96.5% removal for 4.8 lb/mmBtu over 11-hour period) 

* Notes on Deerhaven (existing Turbosorp)

• Tested for 12-hour period 

• SO2 inlet 2.2 lb/mmBtu => removal 95.4% (Guarantee is 95% with 2.3 lb/mmBtu) SO2 inlet 3.8 lb/mmBtu => removal 97.2%
10 

• Dry CFB FGD Cost and Visibility Improvement 

The cost estimates for the wet FGD and dry CFB FGD systems applied to boilers B26 and B27 

are updated to reflect the SO2 emission reductions. The visibility improvements are estimated 

using visibility improvement factors for SO2 reduction as developed in Section 5. Both the costs 

and visibility results are presented in Table 2.2. 

The cost estimate for the Turbosorp system is updated to reflect a capital cost estimate received 

by Georgia Pacific from Babcock Power. The rough-order-of-magnitude (ROM) cost for the 

Turbosorp system includes a scope of supply for boiler units B26, B27 and B28. The ROM cost 

is 25.5 million dollars (M$). Babcock Power in the quote stated that installation costs are 

typically 45 to 55% of the Turbosorp capital cost. The Department applied a 50% installation 

cost to the 25.5 M$ capital cost which yields a total installed cost of 38.3 M$. To note, the 

Turbosorp ROM cost is considered conservative in the comparison as the quoted cost includes 

boilers B26, B27 and B28, whereas the wet FGD cost estimate included only B26 and B27. In 

looking at the results both the capital cost and deciview cost is twice as much for the wet 

scrubber compared to the dry scrubber. Because of this cost difference the Department 

maintains that going from dry CFB FGD to wet FGD is not substantiated and that BART is 

based on the application of dry CFB FGD technologies. 

Table 2.2 Boiler B26 and B27 SO2 Control Cost and Visibility Improvement 

Control 

Option 

Control 

Efficiency 

Capital Installed 

(M$) 

Annual Cost 

(M$) $/ton DV improvement 2 M$/DV

95% 55.9 32.1 3,490 1.27 25.3 Wet FGD 98% 55.9 32.9 3,440 1.32 24.9 

Dry CFB 

FGD 1 93% 38.3 16.0 1,580 1.23 13.0 

1

 The Turbosorp ROM cost included B28, making the cost estimate conservative for the B26/B27 combined flue 

alone. 

2

 Based on modeled maximum dv improvement average at Seney for 2002 – 2004 (see Section 5 “Visibility 

Improvement”). 
11 

• Summary of SO2 BART Control and Visibility Improvement for Northern Class I Areas 

Control Efficiency

93%

M$/year

16.0

Controlled grams/sec

283

maximum average maximum average

dv per gram/sec = 0.005 0.004 0.011 0.010 

dv improvement = 1.49 1.23 3.06 2.79 

M$/dv = 10.7 13.0 5.2 5.7 

SO2 BART Boiler B26 & B27 - CFB FGD

Seney Northern Class I Areas

Northern Class I Areas = Isle Royale National Park, Seney Wilderness Area, Boundary Waters Canoe Wilderness 

Area and Voyageurs National Park. 

3. SO2 Base Emissions 

The Department, for several reasons, determined that actual SO2 base year emissions do not fully 

represent the appropriate basis for established BART SO2 emission limitations. First, the default 

basis for determining BART compliance requirements, per BART guidelines, is applying the 

determined BART control efficiency against base year emissions (2002 to 2004). But BART 

guidelines also provide that existing conditions can be taken into consideration. Therefore it is 

reasonable to evaluate applicable fuels and the variability that may occur in emission levels. 

Second, the Department received comment that the BART determination should account for 

switching to low sulfur content fuels as compared to coke and high sulfur bituminous coals. For 

this control approach Georgia Pacific did identify various levels of fuel switching as a cost 

effective SO2 control measure for both boilers B26 and B276

. 

Because of these issues and the integrated nature of operating Georgia Pacific's stack S10 boiler 

system, the Department has concluded it is appropriate to assess SO2 fuel switching in context of 

base year uncontrolled SO2 emissions. As a result, the Department determined that SO2 base 

year emissions (uncontrolled) should reflect a "base" fuel consistent with boiler design and 

operation. In addition, that the sulfur content of the base fuel should reflect fuels that are 

reasonably obtainable on a long-term consistent basis. This approach is similar to a BACT 

determination for coal fired sources where a fuel type and maximum sulfur content is first 

established and then the BACT control efficiency is used to calculate the BACT emission 

limitation. 

 

6

 Georgia Pacific, 2009, Attachment B Engineering Analysis for Control Technology Options Green Bay Broadway 

Mill. BART Analysis submitted to WDNR April, 2009. 
12 

• Fuel Switching 

The results of Georgia Pacific's BART analysis for fuel switching at each of the BART boilers 

B26 and B27 are shown in Table 3.1. For both boilers, substituting bituminous coal for 

petroleum coke, with 5 to 6% sulfur, is considered relatively cost-effective at 755 and 1,500 

$/ton for B26 and B27, respectively. 

Table 3.1 Analysis of Fuel Switching for Reduction of SO2 Emissions. 

Boiler B26:

Tons Reduced Cost (M$/yr) $/ton

Pet Coke to Bitum 869 0.7 755 

Pet Coke to Low Sulfur Bitum 911 1.0 1,082 

All fuel to Low Sulfur Bitum 1,333 1.6 1,224 

Boiler B27:

Tons Reduced Cost ($/yr) $/ton

Pet Coke w/ Low Fusion Bitum 950 1.4 1,505 

For boiler B27, the primary fuel switching alternatives are limited to replacing the petroleum 

coke with low fusion coal. Because the low fusion coal is important to maintaining necessary 

slagging characteristics in the boiler's cyclone furnace the Department does not consider other 

coals in fuel switching for boiler B27. 

For boiler B26, an additional option of switching to low sulfur bituminous coal is available at an 

estimated 1,224 $/ton. Looking closer at boiler B26 fuel options, summarized in Figure 3.1, 

substituting low sulfur coal for either petroleum coal or for all fuels comes at an added expense. 

Still on a $/ton basis all of these options would be considered cost-effective under most 

regulatory requirements. As such, the affect of cost and emission reduction is further evaluated 

in context of the amended BART control efficiency. 

When applying fuel switching options to boiler B26 followed by 93% FGD control there is a 

smaller difference in end emissions than if only fuel switching is employed. As shown in Table 

3.2, with FGD, the various levels of fuel switching yield a difference of 61 to 93 tons per year in 

reduced emissions. This analysis shows that the majority of SO2 reduction is achieved by 

eliminating the petroleum coke by substituting with the standard bituminous coal. This measure 

gains a 3% reduction in boiler emissions beyond scrubbed emissions. Going fully to low sulfur 

coals reduces emissions by a total of 93 tons or 4% beyond scrubbed emissions. Therefore there 

is only a 1% difference between the lower and maximum fuel switching options when employed 

with FGD. For this 1% additional reduction the cost is more than twice as much going from ~ 
13 

0.6 $M to 1.6 $M per year. Therefore, switching coke fuels with standard bituminous coals is 

deemed to represent the appropriate level of fuel switching in addition to technology control 

options. 

Figure 3.1 Boiler B26 Comparison of Fuel Switching for SO2 reduction. 

LSB

PC to LSB

PC to Bitum

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

- 500 1,000 1,500

SO2 reduction (tons/yr)

Cost (M$/yr)

PC = petroleum coke; Bitum = standard bituminous coal; LS = low sulfur bituminous 

Table 3.2 Boiler B26 SO2 Emission Reduction from Fuel Switching after 93% Control (tons) 

Fuel Switching Case Emissions after 

Fuel Switch

Emissions after 

93% control

Added 

Reduction by 

Fuel Switch

Marginal Fuel 

Switch Cost 

$/ton

Baseline Year Average 2,160 151 

Pet Coke to Bitum 1,291 90 61 10,780.03 

Pet Coke to Low Sulfur Bitum 1,249 87 64 15,451.76 

All fuel to Low Sulfur Bitum 827 58 93 17,488.92 

• "Base" Fuel Sulfur Content

For boiler B27 (the cyclone boiler), low fusion bituminous coal is assumed as the "base" fuel. 

As previously stated the low fusion coal is a specific type of bituminous coal which produces 

specific slagging characteristics necessary to operating cyclone boilers. Because of this 
14 

characteristic and its higher fuel price the Department concludes this fuel is not widely used by 

all coal boilers and will continue to be readily available into the future. However, the coal 

supply information available through the Department of Energy does not clearly distinguish 

between bituminous coal and low fusion bituminous coal, therefore an evaluation of the sulfur 

content for low fusion coal is not performed. Because of it's limited use and lack of specific data 

for low fusion coal, the Department concludes that the sulfur content of the current fuel used by 

Georgia Pacific represents low fusion coal sulfur content into the future. Georgia Pacific's 

BART analysis identified the current low fusion coal as containing 2.6% of sulfur by weight. 

For boiler B26, the fuel switching analysis indicates standard bituminous coal is the appropriate 

"base" fuel. To determine the sulfur content of this base fuel the Department reviewed 

information for bituminous coal from mine sources historically utilized by Georgia Pacific. 

These coal sources are generally in the six-state region of Illinois, Indiana, Kentucky, Ohio, 

Pennsylvania, and West Virginia. Based on the Department of Energy’s 2009 Quarterly Coal 

Report the bituminous coals supplied from these six states in 2009 ranged in average sulfur 

content of 1.53 to 3.68% sulfur7

.

More broadly the Department evaluated EPA's database of coal fuel characteristics compiled 

under 1999 EGU mercury information collection request (ICR). This ICR process required 

electric utilities to test fuel characteristics for each delivery of coal for an entire year which 

resulted in over 40,000 fuel samples. Therefore the ICR database is deemed very robust and 

representative of the availability of fuels. Analysis of the ICR data shows that a sulfur content of 

2.5% by weight captures approximately 80% of bituminous coals fired by the electric utility 

sector on a heat input weighted basis (Figure 3.2). When looking at just the identified six-state 

region for Georgia Pacific coal sources (Figure 3.3) a sulfur content of 2.6% captures 

approximately 75% of the coal supplied to electric utilities from this region. 

Figure 3.2 Sulfur Content of Bituminous Fired Coals, 1999 EGU ICR Database 

 

7

 EIA, 2011, Average Quality of Coal by State of Origin: Total (All Sectors), 2009, Energy Information 

Administration, http://www.eia.gov/cneaf/electricity/cq/cqaxlfilees3.html 
15 

Figure 3.3 Sulfur Content of Bituminous Fired Coals – Six State Region, 1999 EGU ICR 

Database 
16 

Conclusion

The Department concludes that fuel switching is a cost-effective option to controlling SO2

emissions. However, most of the effective reductions are captured by switching to standard 

bituminous fuels. Also to note is that other facilities, including cyclone boilers, have switched 

and operate fully on low sulfur powder river basin (PRB) subbituminous coals. The Department 

considers this option to be beyond the scope of BART. The majority of these facilities switching 

to PRB coal are large electric utilities which invested in long term delivery and supply logistics. 

These facilities have also had to significantly alter coal transfer and combustion related 

equipment in addition to adopting extensive coal management procedures in order to manage fire 

hazards associated with burning PRB coals. The Department finds that imposing these potential 

impacts with little additional SO2 emissions reduction (fuel analysis to all low sulfur coal) is not 

warranted in context of the BART determination for this facility. Further, switching fuels to a 

base bituminous fuel is consistent with base design fuels of the boilers and therefore promotes 

efficient combustion and power production. 

Therefore, to address reasonable fuel switching alternatives and expected availability of base 

fuels the Department finds that a base fuel for boiler B26 is represented by bituminous coal with 

up to 2.5% sulfur and that a base fuel for boiler B27 is represented by low fusion bituminous 

coal with up to 2.6% sulfur content. 

• Adjusted Base SO2 Emissions 

The baseline year emissions for 2002 through 2004 are adjusted to reflect the sulfur content of 

the defined "base" fuels for each BART boiler. The base fuel assumption for boiler B26 is also 

applied to the remaining non-BART boilers, B24, B25, and B28, which are also stoker fired 

boilers. The specific applications of the defined base fuels are: 

o Low Fusion Bituminous Coal @ 2.6% sulfur – boiler B27 

o Bituminous Coal @ 2.5% sulfur – boilers B24, B25, B26 and B28 

The basis for calculating the adjusted SO2 emissions is the actual consumption of each fuel by 

boiler for each year. Each fuel not corresponding to the defined base fuel is replaced by the base 

fuel on a mmBtu for mmBtu basis. Boiler B27 fired a combination of low fusion bituminous 

coal and petroleum coke. The stoker boilers, including B26, fired a combination of bituminous 

coal, petroleum coke, and western low sulfur coals. Therefore the fuels replaced by the base 

fuels are petroleum coke and western low sulfur coal. In this calculation fuels consistent with 

the base fuel are not adjusted for sulfur content. The SO2 emissions for each boiler are then 

recalculated for each fuel and summed. The results are used to calculate the adjusted 3 year 

average SO2 emissions across the 2002 to 2004 base years. The adjusted base year SO2

emissions are summarized in Table 3.3 along with actual base year emissions. Also presented 

for comparison are emissions based on each boiler's heat input and current permitted SO2 limit. 

The details of base fuel substitutions and resulting emissions for each boiler are presented in 

appendix C. 
17 

As previously discussed the replacement of petroleum coke will reduce sulfur fuel content. 

Conversely, replacing low sulfur coal with the base fuel will increase fuel sulfur content and 

emissions for that portion of heat input. A basic premise in evaluating SO2 requirements is that 

Georgia Pacific is permitted to emit up to 4.45 lbs/mmbtu from Stack S10 when another power 

boiler at the facility, boiler B29, is operating. This latter boiler is a newer fluidized bed boiler 

with 90% SO2 scrubbing requirements which is used as a base load unit. When boiler B29 is not 

operating the SO2 limit for Stack S10 increases to 4.55 lbs/mmBtu. This overall facility limit 

was set to avoid exceeding historic daily and annual SO2 National Ambient Air Quality 

Standards (NAAQS). Applying this emission limitation to the base year heat input results in 

total annual SO2 emissions of 13,905 tons for the BART boilers and 19,534 tons for the entire 

S10 stack, Table 3.3. 

Typically the blending ratio of different coals and coke fuels with different heat contents is 

targeted to produce good firing characteristics. When the coke fuels are eliminated the amount 

of low sulfur coals that can be effectively blended will change in achieving good combustion. 

Because of these factors the Department concludes that a low sulfur fuel cannot be assumed 

when eliminating other historic fuel use (petroleum coke). Further, that when determining the 

BART emission requirements, a facility should not be penalized for historically emitting less 

than allowable emissions. Georgia Pacific clearly operated below their allowable SO2 emissions 

level during the base years. Therefore, in light of these reasons, using a base fuel that represents 

reasonably anticipated operating conditions is an appropriate basis for establishing SO2 emission 

requirements applicable to the Stack S10 boiler system. 

Table 3.3 Base Year (2002 – 2004) Average Heat Input and SO2 Emission Cases (tons) 

B26 & B27 B24, B25, & B28 Total Stack S10

Base Year Heat Input (mmbtu) 6,249,611 2,529,603 8,779,214 

Base Year Actual 10,875 2,028 12,903 

Adjusted Base Year 10,889 5,043 15,932 

Permit Allowable Base Year* 13,905 5,628 19,534 

BART Emissions (using Adjusted Base 

Year Emissions)** 5,043 757 5,800 

* Facility allowable when boiler B29 is operating

**BART is 93% control to B26 and B27 Adjusted Base Year Emissions

4. Nitrogen Oxide (NOx) BART 

The Department proposed 84% and 94% control efficiency of NOx emitted from boilers B26 and 

B27, respectively, in the draft BART determination. These proposed control levels were the 
18 

result of assumed combustion modifications to each individual boiler followed by a regenerative 

selective catalytic reduction (RSCR) unit operating on the common flue stack. For the RSCR, 

75% to 80% reduction was applied. In making the draft finding of RSCR as BART, the 

Department had also concluded that full-sized high-dust SCR configurations, capable of 80% or 

greater control, would likely be higher in cost and present challenging installation and operating 

conditions while garnering minimal additional visibility improvement. 

In amending NOx BART, the Department maintains regenerative SCR is applicable for boiler 

B27. For the RSCR, the Department finds that 75% control efficiency is achievable and 70% 

control efficiency is appropriate in setting compliance requirements. The combustion 

modifications and RSCR applied to boiler B27 yield an overall compliance control efficiency 

85%. The Department further finds that other combinations of technologies may result in 

comparable emission reductions in boiler B27 emissions. Because there is potential benefit, 

based on the BART five factors, the Department is setting NOx BART to be inclusive of these 

other options as well as the RSCR. On this basis the Department finds that 84% reduction is the 

NOx BART compliance control efficiency for boiler B27. 

For boiler B26, the Department has determined that RSCR control is not applicable under 

BART. This conclusion is based on potential operating issues and costs when considering the 

RSCR installation in light of the existing equipment configuration. In absence of RSCR, the 

Department re-evaluated the control efficiency of combustion modifications and SNCR 

applicable to B26 – the next top-down tier of control options. This review identified higher 

control efficiencies than previously identified under the draft BART assessment. The result of 

this analysis is that NOx BART for boiler B26 is amended to 68% control based on combustion 

modifications and selective non-catalytic reduction (SNCR). 

• Application of Regenerative SCR

The application of RSCR technology is further evaluated to address aspects of the existing 

equipment configuration which were not considered under the draft BART. Currently, flue gas 

from all boilers B24 through B28 exhausts to a common duct which then enters the existing 

fabric filter system. Just prior to the fabric filter system, the duct splits with flue gas traveling 

evenly to two parallel fabric filter units. The flue gas then exits each fabric filter unit in separate 

ducts and rejoins only after entering the stack structure. Previously the RSCR analysis 

accounted for a one flue duct configuration between the fabric filter system and the stack. 

Babcock Power, the primary vendor of the RSCR system, provided a quote to Georgia Pacific 

for two separate RSCR trains, each treating an individual flue gas stream exiting the fabric 

filter8. Under this quote, one RSCR train treats approximately 260,000 acfm of flue gas flow. 

According to testing of maximum flow rates, boiler B27 can range up to 199,500 acfm and 

together with B26 can total 337,500 acfm (Appendix B). Because control equipment is typically 

designed to handle maximum flow rates, one RSCR cannot treat both B26 and B27 – RSCR 

acfm of 260,000 vs. boiler B26 & B27 337,500 acfm. On this basis, the installation of one 

 

8

 Babcock Power Environmental, April 2010, Green Bay Operations, Units 6, 7, 8 BPEI ROM Submittal 502477 – 

Rev 3, submitted to Mr. Robert Bermke 
19 

RSCR is attributed to controlling boiler B27 emissions (duct 1) and the second RSCR (duct 2) 

for treating boiler B26 emissions. 

 

The existing split flue duct and fabric filter system is also pertinent to evaluating SO2 flue gas 

concentrations and associated impacts in operating the RSCR system. 

If BART SO2 requirements are met by scrubbing all flue gas (both ducts) at the same average 

control efficiency, then an RSCR on either duct will see SO2 concentrations up to the BART 

limit of 1.01 lbs/mmbtu (Stack S10 emission limit, Table 6.2). A predominant issue at this 

emission level is that the SCR catalyst converts SO2 to SO3 causing visible plume and acidic flue 

gas conditions. Based on discussions with Babcock Power (BP) an SO2 emission rate of 1.0 

lbs/mmbtu will result in SO3 concentrations of approximately 5.3 parts per million (ppm) @ 3% 

O29. The Institute of Clean Air Companies indicates the target for avoiding plume is to keep 

SO3 concentrations below 5 ppm.10 Babcock Power indicates that plume issues need to be 

further evaluated if SO2 concentrations to the RSCR are above 0.6 lbs/mmbtu. Therefore, SO2

BART for Georgia Pacific at a default flue gas concentration of 1.0 lbs/mmBtu will generate 

visible plume and creates concern for overall technical feasibility of applying the RSCR under 

these conditions. 

Another issue related to SO2 and conversion to SO3 is the formation of ammonium bisulfates 

(ABS) in the RSCR and downstream flue duct system. To avoid this issue at the 1.0 

lbs/mmBTU emission rate, Babcock Power indicates that an RSCR would be operated at higher 

temperatures up to 650F as compared to 500F. Therefore at the higher SO2 concentrations more 

energy will be required in reheating flue gas. The BP further states that even at 0.6 lbs/mmbtu 

(the draft BART SO2 limit) the RSCR will require steam sootblowers and increased maintenance 

cycles. Therefore, higher SO2 concentrations are not prohibitive to operating an RSCR but at a 

minimum do increase maintenance and operating cost throughout the system. In addition, any 

concentration higher than 0.6 lbs/mmbtu will have to be evaluated for plume generation and 

feasibility. 

In utilizing the existing fabric filter system the most efficient and technically feasible approach to 

installing an RSCR is likely to operate the upstream FGD system on one side of the fabric filter 

system to maximum control levels. This approach is consistent with the Turbosorb system quote 

which specifies one unit for each side of the duct system - similar to the RSCR installations. 

This two system approach allows operating at different SO2 control levels between the duct 

systems. Operating one scrubber at maximum levels can reduce SO2 concentrations to 0.15 to 

0.18 lbs/mmbtu in one flue gas duct. At these SO2 emission levels the RSCR unit is clearly 

feasible and will see benefits in operation and life, minimized buildup of ammonium bisulfate 

and acid deposition, and elimination of any SO3 plume generation. In Germany multiple tail-end 

SCR's after flue gas desulfurization have operated more than 10 years without replacing the SCR 

catalyst. Therefore this ability to focus SO2 reductions to one flue gas duct allows RSCR to be a 

feasible and cost-effective NOx control option. 

 

9

 WDNR, March 2011, Personal communication with John Bowman concerning RSCR coal-fired installations, 

jbowman@babcockpower.com, Babcock Power Environmental, Worcester, MA. 10 ICAC, 2009, Selective Catalytic Reduction (SCR) Control of NOx Emissions from Fossil Fuel-Fired Electric 

Power Plants, white paper prepared by NOx Control Technical Division, Institute of Clean Air Companies, Inc. 
20 

Conversely, where scrubber control is focused to the first duct the SO2 concentrations in the 

second duct will likely be at least as high as the average BART emission limit of 1.01 

lbs/mmBtu. In addition, SO2 concentrations may range higher in the second duct if trimmed 

only to meet the overall emission requirement to both BART boilers. At these higher SO2

concentration RSCR performance will degrade faster and SO3 plume generation will clearly be a 

feasibility issue. Therefore the Department finds that applying RSCR to a second duct and to 

boiler B26 will incur significant technical issues including generation of visible plume. 

• Boiler B27 NOx Control 

As previously discussed, the RSCR control technology is further evaluated for controlling the 

Stack S10 split duct system. The manufacturer of the RSCR technology, Babcock Power, in the 

equipment quote stated capability for achieving 75% control of NOx emissions11. In determining 

the BART emission limitations the Department applied a RSCR compliance control efficiency of 

70%. This difference in control efficiencies reflects a 7% compliance margin. In comparison, a 

10% compliance margin was used by the Department in setting compliance requirements based 

on SCR controls under the Wisconsin NOx RACT rule, s. NR 428.22, Wis.Adm. Code. 

Under the top-down approach, NOx control for boiler B27 is first overfire air combustion 

modifcations (OFA) followed by the RSCR equipment. The Department revised the OFA 

control efficiency after analyzing emissions data for OFA operating on cyclone boilers at the 

Nelson Dewey electric generating plant in Wisconsin12. The Nelson Dewey boilers are similar to 

boiler B27 both in size and in firing bituminous coals and petroleum coke. Based on the 

extensive experience of Alliant Energy, the operating utility, in optimizing and operating cyclone 

boiler OFA the Department deems this data to represent practical and achievable OFA control 

efficiencies. The analysis of emissions data shows OFA at Nelson Dewey achieving a 52% 

annual control efficiency. For purposes of determining BART compliance requirements the 

Department is applying 50% OFA control efficiency to boiler B27. Together the OFA and 

RSCR equipment result in 85% compliance control efficiency for boiler B27. 

A primary question in sizing the RSCR technology is "what portion of the Stack S10 flue gas 

flow must be treated to address boiler B27 emissions". This is because the boiler B27 emission 

rate of 0.63 lbs/mmBtu (after OFA, Table 4.1) is diluted to 0.58 lbs/mmBtu when combined with 

the other boiler emissions. Therefore proportionally more flue gas has to be treated at the lower 

concentration to result in the same tons of boiler B27 NOx reduction.. After analysis, 97% of 

flue gas in one split duct needs to be treated by an RSCR operating at the upper 75% control 

efficiency. This means one of the split ducts and RSCR unit is dedicated to treating boiler B27 

emissions. This apportionment of RSCR control requirement is corroborated in another way. 

During the baseline years, boiler B27 accounted for approximately 50% of the heat input to the 

boiler system and therefore equates to 50% of the overall system flue gas flow or one split duct. 

 

11 Babcock Power Environmental, April 2010, Green Bay Operations, Units 6, 7, 8 BPEI ROM Submittal 502477 – 

Rev 3, submitted to Mr. Robert Bermke. 12 USEPA, 2011, NOx emissions data from the acid rain data base for 1990 – 2010, Clean Air Markets Division 

(CAMD). 
21 

In considering both of these factors, consistent with the finding for boiler maximum flue gas 

flow rates, the Department concludes that one full RSCR on one duct is dedicated to controlling 

boiler B27 emissions. 

Control Alternatives

Since the RSCR requires significant capital and has associated impacts such as CO2 emissions 

from re-heating flue gas, the Department further evaluated next-tier control options. These 

options included combinations of the OFA control with rich reagent injection (RRI), selective 

non-catalytic reduction (SNCR), and in-duct selective catalytic reduction (IDSCR). The 

combination of control options and identified control efficiencies are presented in Table 4.1. The 

primary control approach of OFA/RSCR is shown in the table as Case 1. The alternative options 

are discussed further below. 

A NOx control technology specific to cyclone boilers is rich reagent injection (RRI) where urea 

is injected directly into the furnace. Because reagent is lost to combustion, the RRI approach 

uses more reagent than SNCR in reducing each NOx molecule. But the RRI approach has the 

benefit of reducing ammonia slip and avoiding ammonium bisulfate (ABS) impacts. The RRI 

can also be used with SNCR to achieve higher NOx reduction efficiency. The benefit here is that 

the SNCR can be applied with less ammonia slip and associated ABS impacts. Together the 

RRI/SNCR approach is capable of up to 60% NOx reduction13. In order for the RRI/SNCR to 

reach control levels similar to OFA/RSCR, the OFA system must be operated at a higher 60% 

control efficiency. Georgia Pacific identified this level of control for OFA in their BART 

analysis. However in the Department's experience 60% control is at the upper end of the control 

potential for OFA and likely decreases combustion efficiency of the boiler. It is for this reason 

that the 52% control efficiency, as demonstrated by the Nelson Dewey plant, is utilized in 

assessing the OFA/RSCR primary BART control option. Overall the OFA/RRI/SNCR (Case 2) 

may yield up to 84% control efficiency and an emission rate of 0.20 lbs/mmBtu for Boiler B27. 

Table 4.1. Boiler B27 Top-Tier NOx Control Alternatives. 

 

13 FuelTech, 2011, Rich Reagent Injection, http://www.ftek.com/en-US/products/apc/rri/ 
22 

Case Controls Control 

Efficiency

Combined 

Controls 

Emission Rate 

(lbs/mmbtu)

Case 1 uncontrolled 1.25

OFA 50% 0.63 

RSCR 70% 0.19 

Overall control efficiency 85% 0.19 

Case 2 unctrlled 1.25

OFA 60% 0.50 

RRI / SNCR 60% 0.20 

Overall control efficiency 84% 0.20 

Case 3 unctrlled 1.25

OFA 55% 0.56 

RRI / SNCR 40% 0.34 

In Duct SCR 45% 0.19 

Overall control efficiency 85% 0.19 

A third control alternative is the use of an in-duct SCR (IDSCR) consisting of 1 catalyst layer for 

up to 45% NOx reduction NOx14. The IDSCR is applied after the OFA and is designed to work 

with SNCR. The benefit of this approach is that the SCR can fit to the dimensions of the existing 

ductwork with little or no additional foundation requirement. In contrast, an SCR capable of 70 

– 80% control with 3 catalyst layers will be approximately 16 x 16 x 50 feet high according to 

design criteria in the OAQPS control cost manual15. In comparison, the existing space between 

the boiler B27 economizer to the air-heater is approximately 8 feet in depth by 15 feet high. 

Reworking the duct runs and retrofitting a full SCR will require significant alteration of the 

existing air-heater and ducting configuration as well as building modifications. 

The IDSCR can be more easily fit into the existing space and equipment configuration. Even 

before retrofit considerations, the capital costs of an IDSCR is approximately 30 to 70% of a 

conventional SCR12. Another benefit is that with one layer of catalyst the IDSCR will generate 

significantly less SO3. Therefore ABS and acid gas plant impacts are greatly reduced. In 

addition, the RRI and SNCR reagent injection rates are balanced to yield just enough urea or 

ammonia slip for effective utilization of the IDSCR. This approach optimizes the efficiency of 

reagent utilization and further minimizes ABS impacts. Under this integrated approach the target 

control efficiency for the SNCR is up to 40% NOx reduction and for the SCR catalyst bed an 

 

14 FuelTech, 2011, ASCR Advanced SCR, http://www.ftek.com/en-US/products/apc/ascr/; NOxOut Cascade, 

http://www.ftek.com/en-US/products/apc/noxout-cascade/ 15 USEPA, 2002, EPA Air Pollution Control Cost Manual – 6th Edition, Office of Air Quality Planning and 

Standards, EPA/452/B-02-001 
23 

additional 45%. Therefore, to once again achieve control similar to the RSCR approach, the 

control efficiency of the OFA system must be increased from the base 50% to 55%. 

 

Both control options, Case 2 and 3, are equipment configurations specific to Boiler B27 and have 

the benefit of not requiring up-front SO2 emission reductions. In addition these options may 

significantly reduce energy requirements by eliminating flue gas reheat and reducing pressure 

losses compared to the RSCR catalyst bed. It should be noted that these control efficiencies for 

RRI, SNCR, and IDSCR are not based on specific quotes for the Georgia Pacific boilers. Rather 

this analysis represents the potential of these technologies to achieve reductions similar to the 

OFA/RSCR approach. 

Cost-Effectiveness

Costs were initially estimated for OFA and RSCR systems in the draft BART determination. 

These costs are updated here to reflect vendor quotes and the applicability of cost factors as 

prescribed by the EPA air pollution control cost manual. The worksheets showing the updated 

costs for NOx control technologies are provided in Appendix B. Specifically, Babcock Power 

provided a system quote for installing two RSCR units to the Georgia Pacific Stack S10 system. 

This quote included a capital cost, an estimate that installation costs run 20 – 30% of capital 

costs and provided specific operating parameters related to reagent usage and utility 

requirements. This information is applied to develop the cost of controlling boiler B27 

emissions (one flue duct). The cost of the overfire air system is also revised to reflect a system 

quote by Combustion Components Associates (CCA) specifically for installation to boiler B27. 

Costs are developed for RRI and SNCR systems based on a quote by CCA for installation to 

boiler B27. The cost for the SNCR/IDSCR system approach is based on the actual installation 

cost for this type of system to unit 4 of the AES Greenidge facility16. Since the SCNR/IDSCR 

cost is not based on a specific quote for Boiler B27 the result is considered a scoping cost. 

The resulting costs and emission reductions for the evaluated technologies are provided in Table 

4.2. The cost-effectiveness of visibility improvement (M$/dv) is calculated for the Seney Class I 

area using a factor of 0.005 deciview per grams/sec of reduced NOx emissions (Table 5.2). This 

improvement factor represents the average of the maximum impact registered in each of the base 

years when applying the amended BART emission limitations. In comparison, the improvement 

factor in total for all four class I areas combined is 0.008 deciview per grams/sec. 

The results of the analysis show that the OFA/RSCR system yields 0.43 deciview improvement 

in visibility for Seney at a cost-effectiveness of 1,215 $/ton and 6.6 M$/DV. The alternative 

control options show a potential for visibility improvement similar with lower associated cost 

than the OFA/RSCR. To gauge the overall visibility improvement from each control option the 

maximum and average visibility impact is estimated for the northern Class I areas as well. These 

results are presented in Table 4.2 and Figure 4.1. 

 

16 USDOE, 2009, Greenidge Multi-pollutant Control Project - Final Report of Work Performed, DE-FC26-

06NT41426 
24 

This analysis clearly shows that the similar visibility improvement may be achieved with several 

control options other than OFA/RSCR. These options also have the potential to reduce cost and 

may minimize energy and plant impacts. Therefore the Department concludes that the minimum 

control efficiency across these control options of 84% NOx reduction represents BART for 

boiler B27. This control level does not presume that OFA/RSCR in not BART. However it does 

presume that this level of control allows various options in addition to OFA/RSCR in meeting 

BART. 

Table 4.2 Boiler B27 Control Cost and Visibility Improvement for Seney. 

Control Technology Control 

Efficiency

Tons 

Controlled

Capital 

Installed (M$)

Annual Cost 

($) $/ton

Visibility 

Improvement 

(dv)

M$/DV

OFA 50% 1,365 1.2 187,161 137 0.25 0.7 

RSCR 70% 1,910 8.1 3,519,674 1,842 0.35 10.0 

OFA / RSCR 85% 2,320 9.3 2,818,927 1,215 0.43 6.6 

OFA/RRI/SNCR 84% 2,292 4.0 1,872,794 817 0.42 4.4 

OFA/SNCR/IDSCR 85% 2,324 10.9 2,242,797 965 0.43 5.2 

Figure 4.1 Boiler B27 Control Options – Visibility Improvement for Seney and CostEffectiveness. 

OFA/RRI/SNCR OFA/RSCR

RSCR

OFA

OFA/SNCR/IDSCR

-

0.05

0.10

0.15

0.20

0.25

0.30

0.35

0.40

0.45

- 2.0 4.0 6.0 8.0 10.0 12.0

$M / DV

Visibility Improvement (dv)

• Boiler B26 NOx Control 

As previously discussed, the Department deems the RSCR as not representing BART control for 

boiler B26. However, to evaluate this issue further, a full list of controls including RSCR is 

carried forward in evaluating cost-effectiveness of technologies for Boiler B26. 
25 

 

In absence of applying RSCR control, the next tier of top-down NOx control identified for boiler 

B26 is a combination of flue gas recirculation (FGR) and over-fire air (OFA) combustion 

modifications followed by selective non-catalytic reduction (SNCR). In the draft BART analysis 

the combination of FGR and OFA was initially rated to achieve a minimum 20% reduction of 

NOx emissions. The 20% control level ensured no impact to combustion quality and is deemed 

appropriate when followed by the RSCR control. However, a 40% reduction is achievable for 

stoker boilers17. To determine if this full control potential can be achieved will require additional 

engineering and computer fluidized dynamic (CFD) modeling of the combustion process. 

Without this level of analysis, the Department is applying 35% compliance control efficiency for 

OFA/FGR as applied to boiler B26. 

 

SNCR technology is successfully demonstrated for up to 50 to 70% long term reduction of NOx 

emissions18. Similar to OFA/FGR design, to determine the SNCR maximum achievable control 

efficiency for boiler B26 requires engineering and CFD modeling analysis. In this case the depth 

of the control is dependent on boiler dynamics, reagent mixing conditions, residence time, 

temperature regime and ammonia injection rates which do not cause ammonium bisulfate 

buildup or acid conditions. Therefore, without CFD modeling, a SNCR compliance control 

efficiency of 50% is applied to boiler B26. The 50% control efficiency also represents the upper 

end of typical control ranges while the Department anticipates that significant reagent slip and 

plant impact will occur when going to higher control efficiencies. 

Together the discussed OFA/FGR and SNCR result in a total compliance control efficiency of 

68%. Applying this control efficiency to the uncontrolled emission rate, 0.68 lbs/mmbtu, yields 

a BART emission rate limitation of 0.22 lbs/mmbtu for boiler B26. Boiler B26's uncontrolled 

emission rate is revised versus the draft BART analysis based on current NOx emissions data. 

 

The control technologies evaluated for boiler B26 are listed in Table 4.4 with estimated costeffectiveness and visibility improvement results. The costing worksheet for each technology is 

provided in Appendix B. The costing of the RSCR control option is revised here using the same 

methods discussed for boiler B27. The costs of the OFA, FGR, and SNCR technologies are 

developed using costs and operating factors quoted by Combustion Components Associates 

(CCA) for installation to boiler B26. Control efficiencies provided in the CCA quote are lower 

than applied in this analysis; therefore urea injection and utility consumption rates are scaled 

accordingly. The application of default cost factors used in the draft BART analysis are adjusted 

to reflect guidance provided in the EPA air pollution control cost manual. For all technologies 

the visibility improvement for Seney is estimated using a factor of 0.005 deciview per grams/sec 

reduced (Table 5.2) 

 

Table 4.4 Boiler B26 Control Cost and Visibility Improvement for Seney. 

 

17 Tim Loviska, 2009, personal communication, Tloviska@detroitstoker.com 

18 ICAC, 2008, Selective Non-Catalytic Reduction (SNCR) for Controlling NOx Emissions, white paper prepared by 

SNCR Committee, Institute of Clean Air Companies, Inc. 
26 

Control Technology Control 

Efficiency

Tons 

Controlled

Capital 

Installed (M$)

Annual Cost 

($) $/ton

Visibility 

Improvement 

(dv)

M$/DV

OFA/FGR 35% 224 1.7 244,797 1,093 0.05 5.3 

SNCR 50% 320 2.7 681,223 2,128 0.07 10.4 

OFA/FGR/SNCR 68% 432 4.4 807,098 1,868 0.09 9.1 

RSCR 70% 448 8.1 2,160,437 4,821 0.09 23.6 

OFA/FGR/RSCR 81% 515 9.9 1,893,858 3,675 0.11 15.6 

The analysis shows that all of the evaluated control options are cost-effective with a maximum 

visibility improvement demonstrated by the OFA/FGR/RSCR system at 3,675 $/ton and 15.6 

M$/DV. These results also show that the majority of visibility improvement is captured by the 

OFA/FGR/SNCR system at 68% control. The cost of this system is estimated at 1,868 $/ton and 

9.1 M$/DV or almost half that of the RSCR based control approach. Figure 4.2 shows that the 

difference in visibility improvement between these two options is a little more than 0.01 

deciview. This difference is approximately 10 – 15% of additional improvement garnered by the 

RSCR system at approximately twice the cost. This same point in cost difference is 

demonstrated in Figure 4.3 which looks at the capital required by each technology option. These 

factors point to the RSCR based controls as beyond the knee in the curve for achieving visibility 

improvement in a cost-effective manner under BART. 

Conclusion

A number of factors, including cost-effectiveness and visibility improvement, demonstrate that 

OFA/FGR/SNCR at 68% control efficiency represents NOx BART for boiler B26. This premise 

is the result of the RSCR system garnering a small increment in visibility improvement relative 

to the SNCR based approach. In this context the RSCR system has a higher energy penalty and 

emits more CO2 as compared to the SNCR based system. In addition, the OFA/FGR/SNCR 

system is not anticipated to incur significant challenges for installation or operation as compared 

to the RSCR. Lastly, for RSCR to be feasible may require focused SO2 controls that may be 

dedicated for RSCR feasibility to boiler B27. 

Figure 4.2 Boiler B26 Control Options – Visibility Improvement for Seney and CostEffectiveness 
27 

OFA/FGR/SNCR

SNCR

OFA/FGR

RSCR

OFA/FGR/RSCR

-

0.02

0.04

0.06

0.08

0.10

0.12

- 5.0 10.0 15.0 20.0 25.0

M$-Annualized / DV 

Visibility Improvement (DV)

Figure 4.3 Boiler B26 Control Options – Visibility Improvement for Seney and Capital Cost 

OFA/FGR/RSCR

RSCR

OFA/FGR

SNCR

OFA/FGR/SNCR

-

0.02

0.04

0.06

0.08

0.10

0.12

- 2.0 4.0 6.0 8.0 10.0 12.0

Capital Cost ($)

Visibility Improvement (DV)

Summary of NOx BART for Boilers B26 and B27 and Visibility Improvement
28 

Control Efficiency

84%

M$/year

2.8

Controlled grams/sec

87

maximum average maximum average

dv per gram/sec = 0.009 0.005 0.012 0.008 

dv improvement = 0.76 0.42 1.02 0.71 

M$/dv = 3.71 6.68 2.76 3.96 

NOx BART Boiler B27 - OFA + RSCR

Seney Northern Class I Areas

Northern Class I Areas = Isle Royale National Park, Seney Wilderness Area, Boundary Waters Canoe Wilderness 

Area and Voyageurs National Park. 

Control Efficiency

68%

M$/year

0.6

Controlled grams/sec

18

maximum average maximum average

dv per gram/sec = 0.009 0.005 0.012 0.008 

dv improvement = 0.16 0.09 0.22 0.15 

M$/dv = 3.96 7.12 2.94 4.23 

NOx BART Boiler B26 - OFA/FGR + SNCR

Seney Northern Class I Areas

Northern Class I Areas = Isle Royale National Park, Seney Wilderness Area, Boundary Waters Canoe Wilderness 

Area and Voyageurs National Park. 

M$/year

3.5

Controlled grams/sec

105

maximum average maximum average

dv per gram/sec = 0.009 0.005 0.012 0.008 

dv improvement = 0.92 0.51 1.24 0.86 

M$/dv = 3.75 6.75 2.79 4.01 

Seney Northern Class I Areas

NOx BART Combined Boilers B26 & B27

Northern Class I Areas = Isle Royale National Park, Seney Wilderness Area, Boundary Waters Canoe Wilderness 

Area and Voyageurs National Park. 
29 

5. Visibility Improvement Related to BART 

The Department performed CALPUFF modeling to assess visibility improvement achieved 

under the amended BART requirements. The modeled emission cases are based on the 

maximum actual emissions during the baseline years for the combined stack S10. The base 

uncontrolled emission rates, in grams per second, for each pollutant are provided in the draft 

BART determination, Table C10. 

To provide the emissions model input for the BART case a surrogate control efficiency is 

applied to the Stack S10 maximum day emissions. This surrogate control efficiency is calculated 

from the difference between the BART annual mass cap emission limitation (Table 6.2) 

compared to the annual actual average emissions during the baseline years. The applied 

surrogate Stack S10 percent reduction is 70% for NOx and 57% for SO2. The resulting 

maximum day controlled emission rates are then modeled for every day in 2002 to 2004. 

In looking at the visibility improvement from BART one measure is the count of days showing 

visibility impact above 0.1 and 0.5 deciviews. The total number of days at each northern Class I 

area above these thresholds are shown in Table 5.1. These results show that Seney realizes the 

largest reduction of days for each case with the total number of days with impact above 0.5 

deciview reduced by 29 to 34 days over the baseline years. Above the 0.1 deciview threshold the 

number is reduced by 29 to 33 days over the baseline years. 

Table 5.1 Days of Visibility Impact after BART for the Northern Class I Areas. 
30 

Uncontrolled Emissions Uncontrolled Emissions

2002 2003 2004 2002 2003 2004

bowa 25 28 44 bowa 7 7 13

isle 34 51 52 isle 14 19 17

sene 107 118 113 sene 41 53 48

voya 10 13 20 voya 2 0 2

BART BART

2002 2003 2004 2002 2003 2004

bowa 18 16 25 bowa 2 2 2

isle 26 36 32 isle 6 6 3

sene 78 85 82 sene 12 22 14

voya 4 4 6 voya 0 0 0

Reduced Days of Impact with BART Reduced Days of Impact with BART

2002 2003 2004 2002 2003 2004

bowa 7 12 19 bowa 5 5 11

isle 8 15 20 isle 8 13 14

sene 29 33 31 sene 29 31 34

voya 6 9 14 voya 2 0 2

Number of days with delta-deciview => 0.1 Number of days with delta-deciview => 0.5

Another metric in comparing visibility impact is the maximum daily impact modeled in each 

year shown. These results are summarized in Table 5.2. The "maximum" is the highest value 

modeled in any of the three baseline years 2002 to 2004. The "average" is the average of the 

maximum value modeled in each base year – therefore an average of the maximum impact for 

2002, 2003, and 2004. These modeling results show for Seney that BART reduces the highest 

maximum impact seen over the three base years by 2.68 deciview. The average impact improves 

by 2.02 deciview. 

A total maximum and average value is also presented for all four northern Class I areas. This 

total value represents the sum of the maximum modeled for each individual class I area. 

Although the maximum impact is not expected to occur at all sites at the same time this metric is 

a means of measuring relative changes. The maximum value across the northern areas improved 

by 5.03 deciview and on average improved by 4.19 deciview. 

Modeling runs were also performed to assess the visibility improvement under BART related to 

the individual pollutants, shown in the Table 5.2 for SO2 and NOx. This information is used to 

calculate a visibility improvement factor in deciview improvement per gram/sec of pollutant 

reduced. These factors are then used in the visibility assessments of the individual control 

technologies when performing the BART evaluations (Sections II.2 and II.4). The "average" 

value is used for these technology evaluations as it represents a reasonably expected 

improvement rather than the maximum seen over all three baseline years. For example, to 

calculate visibility improvement at Seney the average value of 0.005 grams/sec is applied for 

NOx and 0.004 grams/sec is applied for SO2. To note though, also shown in the Table 5.2, the 

sum of visibility improvement for each pollutant does not sum to total improvement when 
31 

reducing both pollutants together. Thus using the individual pollutant visibility improvement 

factors under-estimates the total visibility improvement for the pollutant in context of the entire 

BART requirement. 

Table 5.2 Modeled Maximum Daily Impact (dv) for 2002, 2003, and 2004 

Maximum Average Maximum Average

 4.14 5.38 9.67 8.12 

BART 2.70 2.12 4.64 3.93 

SO2 3.89 2.91 6.61 5.34 

NOx 4.54 3.67 8.54 7.34 

BART 2.68 2.02 5.03 4.19 

SO2 1.49 1.23 3.06 2.79 

NOx 0.84 0.47 1.13 0.79 

sum of SO2 & NOx 2.33 1.70 4.19 3.57 

BART 0.007 0.005 0.013 0.011

SO2 0.005 0.004 0.011 0.010

NOx 0.009 0.005 0.012 0.008

Uncontrolled Emissions (max day)

Visibility Case / Paramenter

Residual Visibility Impact (RVI)

Visibility Improvement (VI) Result of 

"Uncontrolled" - "RVI"

Visibility Improvement / Gram Pollutant; 

Result of RVI / grams per sec reduced

Seney Northern Class I Areas 

Maximum = Maximum Daily Impact modeled for the base years (2002 – 2004) 

Average = Average of each base year maximum daily impact. 

6. Emission Limitations and Compliance Requirements 

BART emission limitations are determined for each boiler and each pollutant SO2 and NOx in 

two forms: 1) emission rate limitations (lbs/mmbtu) and, 2) allowable mass emissions (tons). 

The permit allows BART requirements to be satisfied by demonstrating compliance with either 

emission limitation format. 

The BART emission rate limits are determined by applying the BART control levels to the 

uncontrolled base emission rates. For SO2, the base uncontrolled emission rates reflect the 

adjusted base year emissions shown in Table 4.1. This base information and resulting BART 

emission rate limits, on a 30 day rolling basis, for boilers B26 and B27 are presented in Table 

6.1. 

Georgia Pacific can also comply with the mass cap limits for each boiler also shown in Table 

6.1. The 12 month mass cap is the result of applying the BART emission rate limit to the 

average of the annual heat input for each boiler during the baseline years 2002 to 2004. This 

limit is viewed as being consistent with achieving a long-term average BART level of control. 

The 30 day limit is set by applying the emission rate limit to the maximum day heat rate for each 

boiler, B26 and B27, and then multiplying by 30 days. The 30 day rolling mass cap is set in 

tandem with the 12 month mass cap to ensure that visibility is protected on a daily basis. This 

short term limit is then consistent with the visibility improvement modeled using maximum day 

emissions. 
32 

Table 6.1 BART Control Level and Requirements for Boilers B26 and B27. 

Control Level

30 Day Rolling 

Emission Rate 

Limitation 

(lbs/mmbtu)

Tons Emitted in 

any 12 Month 

Period

Tons Emitted 

in any 30 Day 

Period

SO2

B26 3.79 93% 0.27 254 33

B27 3.35 93% 0.23 502 47

NOx

B26 0.68 68% 0.22 207 27

B27 1.25 84% 0.20 437 41

BART Emission Requirements

Stack S10 

Boilers

Uncontrolled 

Emission Rate 

(lbs/mmbtu)

As an alternative the permit allows Georgia Pacific to demonstrate compliance with Stack S10 

emission limitations in lieu of the individual boiler requirements. Similar to the individual boiler 

limits, Stack S10 compliance can be demonstrated by meeting either an emission rate limitation 

or a mass cap limitation. The Stack S10 emission limitations are shown in Table 6.2. 

The mass requirement for Stack S10 incorporates the mass cap limits for boilers B26 and B27 as 

presented in Table 6.1. Uncontrolled emissions are then added for the non-BART boiler B24, 

B25, and B28 based on uncontrolled base year emissions for 2002 to 2004. As for the BART 

boilers, the non-BART boiler uncontrolled SO2 emissions reflect the adjusted base year 

emissions shown in Table 3.1. The NOx emissions for the non-BART boilers reflect the actual 

average reported emissions during the baseline years. The annual mass emissions are then 

totaled across the BART and non-BART boilers to determine the 12 month rolling cap. A 12 

month average emission rate is then calculated from the mass cap and total Stack S10 base year 

heat input. The 30 day mass cap is then calculated by multiplying the 12 month average 

emission rate by the maximum emission day heat input for Stack S10 and multiplying by 30. 

Under the emission rate compliance approach both a 30 day and 12 month rolling average 

emission rate applies to Stack S10. Once again, the 30 day limit is required to ensure a minimum 

visibility improvement on a continuous basis. In this case, where additional capacity can be 

utilized beyond that demonstrated and modeled for the maximum day emissions a different 

approach is used to determine stack emission rate limits. The mass cap requirements are 

consistent with annual average (12 month) and maximum day (30 day) heat inputs during the 

baseline years. If the associated average emission rates or BART emission rates are allowed and 

the boilers are used at high capacity rates then total emissions will exceed the BART mass caps. 

To ensure the mass caps are not exceeded, resulting in higher visibility impact, a surrogate 

maximum heat input representing 95% of Stack S10 boiler capacity is utilized to calculate 

emission rate limits. Therefore, mass cap requirements in Table 6.2 are divided by this boiler 

system maximum heat input for 30 days and 12 months to calculate the associated emission rate 

limitations also shown in Table 6.2. 
33 

Table 6.2 Alternative BART Compliance Requirements for Stack S10 

Tons Emitted in 

any 12 Month 

Period

Tons Emitted in 

any 30 Day Period

12 Month Rolling 

Emission Rate Limitation 

(lbs/mmbtu)

30 Day Rolling 

Emission Rate 

Limitation 

(lbs/mmbtu)

SO2 5,800 761 1.01 1.53

NOx 1,200 141 0.21 0.28

Mass Cap Requirement Emission Rate Requirement

Pollutant

7. SO2 and NOx Default Trading Program 

Under the state BART rule, s NR 433.06, Wis. Adm. Code, sources may trade emissions in 

complying with BART requirements. In using a trading approach, a facility is not allowed to 

trade with other facilities and must account for other sources at the facility serving the same 

function - thus avoiding load shifting. The rule also requires that any trading program fulfill two 

criteria: first, an additional 10% reduction beyond the BART requirement for the pollutant being 

offset with emissions trading. Second, any trading of emissions must result in visibility 

improvement equivalent to BART emission requirements plus the 10% additional reduction. 

• Permit Requirements 

An emission trading program is established in Georgia Pacific's permit which meets the criteria 

of s. NR 433.06. The program anticipates trading SO2 emission reductions beyond BART in lieu 

of NOx emission reductions and is structured using the Stack S10 mass cap to account for all 

similar sources. In this approach the additional 10% reduction is applied to both the NOx 30 day 

and 12 month mass cap requirements to yielding the required BART-Trade mass cap 

requirements, Table 7.1. Under the Trading program the SO2 mass cap requirement is restated 

and acts as the minimum requirement for SO2 at any time during the trading program. Therefore, 

this program allows for one-way trading – SO2 for NOx. To meet the second criteria under 

trading for meeting equivalent visibility improvement the trading program requires that two tons 

of SO2 must be used to offset every ton of required NOx reduction. The analysis establishing 

visibility equivalency under this trading ration is presented below. 

Table 7.1 BART-Trade Requirements. 
34 

Tons Emitted in 

any 12 Month 

Period

Tons Emitted in 

any 30 Day Period

SO2 5,800 761

NOx 1,080 127

Requires 2 tons SO2 

reduction for each ton of 

NOx over Emission Cap.

Mass Cap Requirement

Pollutant Trading Ratio

Note: NOx 12 month mass cap = 1,200 tons – 120 tons (10%), NOx 30 day mass cap = 141 tons – 14 tons (10%). 

• Evaluation of Visibility Equivalency 

To determine visibility equivalency, the Department performed CALPUFF modeling reflecting 

BART Trading mass cap requirements. The Department then performed CALPUFF modeling of 

varying NOx and SO2 control levels at different trading ratios of SO2 for NOx. The levels of 

NOx reduction tested (21%, 39%, and 54%) relate to control efficiencies of different control 

technologies or options other than the assumed BART controls (70%). These control efficiencies 

are determined for Stack S10 emissions in the same manner as for the BART visibility 

evaluation, Section II.5. The SO2 control levels are the result of offsetting the remaining NOx 

reduction requirements under the specified trading ratios. The emissions trading cases modeled 

by the Department are listed in Table 7.2. 

Table 7.2 CALPUFF Modeling Cases for Evaluating Emissions Trading 

SO2 NOx PM

BART-Trade 1 - NOx 70% control, SO2 57% control 221.4 41.0 17.2

2 - NOx 39% control, SO2 67% control 1:1 169.9 86.3 17.2

3 - NOx 39% control, SO2 86% control 3:1 72.1 86.3 17.2

4 - NOx 54% control, SO2 71% control 3:1 149.3 65.1 17.2

5 - NOx 39% control, SO2 76% control 2:1 123.6 86.3 17.2

6 - NOx 54% control, SO2 67% control 2:1 169.9 65.1 17.2

7 - NOx 21% control, SO2 72% control 1:1 144.1 111.8 17.2

8 - NOx 21% control, SO2 87% control 2:1 66.9 111.8 17.2

Sensitivity Runs

Modeling Scenario

Emission Rate (grams / sec)

Control Case Trading Ratio 

(SO2:NOx)

In determining equivalent visibility improvement for trading the Wisconsin BART rule, under 

provision s. NR 433.06(1)(b)2, Wis. Adm. Code, states that the demonstration shall meet the 

following test: 

"The improvement in visibility shall be demonstrated by comparing the 

20% best days of visibility and the 20% worst days of visibility in at least 

the 4 mandatory Class I federal areas nearest to the source and for each 

calendar year 2002, 2003 and 2004."
35 

The Department performed modeling for all Class I areas, but the evaluation of equivalency and 

trading ratios results presented here focuses to Seney as this area receives the greatest visibility 

impact. In the analysis the Department is also sensitive to seasonal differences which cause 

variation in impact related to each pollutant. Specifically, in this case, NOx emissions exhibit 

stronger visibility impairment during colder months than during the summer. Conversely, the 

impact related to SO2 emissions strengthens during warmer periods and as the availability of 

ammonia increases. Because of such effects the visibility equivalency is compared both on an 

overall annual basis but also for shorter 30 day periods on an ongoing basis. 

As a first assessment, the number of days of impact for all class I areas are compared between 

the various cases. Shown in Table 7.3, a trading ratio of 1 ton SO2 for 1 ton of NOx increases 

the total number of impact days in Case 2 and 7 (bolded values). The 1:1 ratio cases also show a 

modeled increase in the maximum day impact (bolded values) for the Seney Class I area, Table 

7.4. Based on increases in both of these visibility metrics the Department concludes that a 

trading ratio of 1:1 is insufficient for achieving equivalent visibility improvement. 
36 

Table 7.3 Number of Days with Visibility Impact > 0.1 Deciview. 

2002 2003 2004

bowa 18 15 25

isle 25 35 31

sene 75 84 79

voya 4 4 5

bowa 16 14 25

isle 25 33 31

sene 77 83 83

voya 3 3 5

bowa 10 9 15

isle 19 24 22

sene 56 68 56

voya 2 0 3

bowa 11 13 22

isle 21 30 29

sene 69 80 69

voya 3 3 3

bowa 11 13 19

isle 22 29 28

sene 70 80 70

voya 3 3 3

bowa 16 13 25

isle 24 32 29

sene 72 81 77

voya 3 3 4

bowa 15 13 26

isle 25 33 33

sene 78 85 83

voya 3 3 5

bowa 10 10 15

isle 21 27 25

sene 61 70 62

voya 2 1 3

3

4

Trading Ratio 

(NOx:SO2)

1 (BART-Trade)

2

Case No. of Days > 0.1 Deciview Class I Area

1 to 1

5

6

7

8

1 to 3

1 to 3

1 to 2

1 to 2

1 to 1

1 to 2

bowa = Boundary Waters Canoe Wilderness Are 

isle = Isle Royal National Park 

sene = Seney Wilderness Area 

voya = Voyageurs National Park 
37 

Table 7.4 Maximum Daily Impact for Each Base Year 

2002 2003 2004

1 (Bart-Trade) 1.33 2.56 2.14 

2 2.80 1.32 2.15 1 to 1

3 0.87 2.06 1.45 1 to 3

4 1.12 2.35 1.83 1 to 3

5 1.11 2.45 1.83 1 to 2

6 1.21 2.51 1.98 1 to 2

7 2.94 1.32 2.19 1 to 1

8 0.98 2.38 1.64 1 to 2

Trading Ratio 

(SO2:NOx)

Maximum Deciview

Case

Moving to the 2:1 trading ratio cases 5, 6, and 8 there is no increase in either the number of days 

or maximum daily impact when compared to the BART-Trading case 1. To screen more closely 

for potential visibility equivalency the modeled daily maximum impact across 2002 to 2004 is 

plotted for these cases, Figures 7.1, 7.2, and 7.3. This comparison shows that the residual 

visibility impacts compare well between the BART-Trading and 2:1 trading ratio cases. 

Figure 7.1 Daily Maximum Modeled Impact, 2002 – 2004: BART-Trade vs. Case 5. 

0

0.5

1

1.5

2

2.5

3

0 200 400 600 800 1000 1200

Deciview

BART-Trade

Case 5
38 

Figure 7.2 Daily Maximum Modeled Impact, 2002 – 2004: BART-Trade vs. Case 6. 

0

0.5

1

1.5

2

2.5

3

0 200 400 600 800 1000 1200

Deciview

BART-Trade

Case 6

Figure 7.3 Daily Maximum Modeled Impact, 2002 – 2004: BART-Trade vs. Case 8. 

0

0.5

1

1.5

2

2.5

3

0 200 400 600 800 1000 1200

Deciview

BART-Trade

Case 8
39 

Based on these positive results for the 2:1 trading ratio cases, the Department looked at the 20% 

best and worst days as required under the Wisconsin BART rule for determining visibility 

equivalency. To define the best and worst days the Department segmented the modeling results 

for days in which a 0.01 deciview visibility impact is predicted. The model delineated 

approximately 468 days during 2002 to 2004 based at 0.01 deciview or greater. The Department 

then segmented these days into the best and worst 94 days of impact (20% x 468 = 94). 

The analysis of the best days is relatively straightforward. Table 7.5 shows that the maximum 

modeled daily impact seen in each year, 2002 to 2004, for the Seney Class I areas increased 

under case 8 compared to the BART-Trading case by a maximum 0.02 deciview. The other 

cases show an increase in the maximum daily impact of 0.01 deciview over BART-Trading. 

These differential visibility impacts are derived by looking at the results on the same day. 

Table 7.5 "Best Day" Visibility Impact for 2:1 Trading Ratio Cases – Seney Class I Area. 

BART-Trade Case 5 Case 6 Case 8 Case 5 Case 6 Case 8

Max Impact 0.032 0.042 0.037 0.049 0.01 0.01 0.02 

Avg Impact 0.020 0.019 0.019 0.018 (0.00) (0.00) (0.00) 

Total Impact 1.963 1.788 1.867 1.685 (0.18) (0.10) (0.28) 

Difference from BART-Trade Case

However, when looking at the overall change to visibility, the average of the daily maximum 

impact slightly decreases. The BART-Trade average value is 0.02 deciview whereas cases 5, 6, 

and 8 show an average of 0.018 to 0.019. A simple total of the daily impacts show a decrease of 

0.1 deciview or more in total. Although these factors are general in nature they indicate that 

overall the visibility impact has decreased under the 2:1 trading ratio cases. 

Still an increase in maximum daily impact is realized under the modeling results. The question 

is whether the increases are of magnitude and on days that cause a perceptible degradation to 

visibility. To look at this the issue a plot is made of the change in visibility seen under the 

trading cases versus the visibility impact for the BART-Trading case for each day. The results 

for case 8 are presented because this case demonstrated the largest increase in maximum daily 

impact versus BART-Trading and should show the days with highest overall impacts. The plot, 

Figure 7.4, shows that there are clearly days where visibility impact increases and days where it 

decreases under emissions trading. For the days where visibility impact is greatest or 

approaching 0.032 deciview, the maximum added visibility impact is just less than 0.02 

deciview. The total resulting impact is approximately 0.05 deciview. When looking at all the 

remaining values of the plot the total impacts appear to all be less than the 0.05 deciview. 

With values of maximum daily impact remaining at or below the 0.05 deciview level, based on 

previous regional haze analysis, the Department concludes that the increased impacts to visibility 

do not create a perceptible change in visibility for the 20% "Best" days at the Seney Class I area. 

Further, from this analysis there is an overall improvement to the underlying base visibility 

which will yield more days with perceptibly improved visibility on days with lower visibility 

impacts. On this basis, the Department concludes that the 2:1 trading ratio ensures visibility 

equivalency for the 20% "Best Days". 
40 

Figure 7.4 Additional Maximum Impact when Trading 

Best Days - Case 8

-0.03

-0.02

-0.01

0

0.01

0.02

0.03

0 0.005 0.01 0.015 0.02 0.025 0.03 0.035

BART-Trade Maximum Impact (dv)

Increased Impact vs BARTTrade (dv)

Following a similar method, the visibility equivalency is evaluated for the 20% "Worst Days". 

As shown in Table 7.6, the trading cases all show an improvement in the overall visibility impact 

when compared to the BART-Trade emission levels. However, values for the maximum daily 

impact ranging from 2.38 to 2.45 deciview clearly demonstrate that days still occur with 

significant visibility impact. Therefore the potential for adding visibility impact to an individual 

day under the trading cases needs to be evaluated further. 

Table 7.6 "Worst Day" Visibility Impact for 2:1 Trading Ratio Cases – Seney Class I Area. 

BART-Trade Case 5 Case 6 Case 8 Case 5 Case 6 Case 8

Max Impact 2.56 2.45 2.51 2.38 (0.11) (0.06) (0.18) 

Avg Impact 0.60 0.49 0.54 0.43 (0.11) (0.06) (0.17) 

Total Impact 56.23 46.16 50.97 40.15 (10.07) (5.26) (16.08) 

Differential from BART Case

In looking at what happens to individual days Figures 7.5 through 7.7 show that under each 

trading case there are more days with decreases (negative values on the y-axis) in impact than 

increases. The Figures also illustrate that the magnitude of decreases on the individual days are 

greater than the increases. Under the worst result, Case 8, the increase to visibility impact is less 

than 0.2 deciview. But, the most significant finding is that when the base visibility impact (xaxis) is greater than 1 deciview the visibility is improved under the trading cases (negative yaxis). In other words, the days that still see the highest visibility impacts under the BART 

requirements are improved when two SO2 are traded for a ton of NOx reduction. 
41 

Below the 1.0 threshold each case shows days of increased and decreased visibility impact. 

However in all three cases the magnitude of decreases are greater than the increases in impact. 

The plots also show that the number of days with decreased impact appear similar or greater than 

the number of days with increased visibility impact. 

Figure 7.5 Additional Maximum Impact – Worst Days – Case 5. 

Worst Days - Case 5 - NOx 39%

-0.7

-0.6

-0.5

-0.4

-0.3

-0.2

-0.1

0

0.1

0.2

0 0.5 1 1.5 2 2.5 3

Deciview Impact - Bart Trade Case

Deciview Increase vs BART

Figure 7.6 Additional Maximum Impact – Worst Days – Case 6. 

Worst Days - Case 6 - NOx 54%

-0.4

-0.3

-0.2

-0.1

0

0.1

0.2

0 0.5 1 1.5 2 2.5 3

Deciview Impact - Bart Trade Case

Deciview Increase vs BART
42 

Figure 7.7 Additional Maximum Impact – Worst Days – Case 8 

Worst Days - Case 8 - NOx 21%

-1.2

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0 0.5 1 1.5 2 2.5 3

Deciview Impact - Bart Trade Case

Deciview Increase vs BART

To understand what these increases and decreases mean to visibility equivalency the distribution 

of days of impact and total deciview impact is counted at different visibility thresholds. The 

results shown in Table 7.7 confirm that the number of days in the highest impact range is 

reduced under the trading cases. For this same visibility range the total deciview impact (sum of 

impact for days > 1.0 deciview) is significantly reduced. On the whole for the trading cases both 

the number of days and total impact are reduced. It is only when going to the 0.25 to 0.5 

deciview range is there an increase in the number of days and at the <0.25 decieview range is 

there an increase in total impact. This means that all days of impact are shifting to the right in 

the table to result in an overall lower total impact. Therefore the trading cases are interpreted to 

be reducing the impact seen during the 20% worst days. 

Table 7.7 Number of Days with Modeled Visibility Impact (deciview) 

Deciview > 1.0 1- 0.75 0.75-0.50 0.5-0.25 <0.25 Total

BART-Trade 9 11 22 52 - 94 

Case 5 4 11 14 51 14 94 

Case 6 5 12 18 55 4 94 

Case 8 9 3 13 40 29 94 
43 

Table 7.8 Total Visibility Impact (deciview) in Each Visibility Impact Range. 

Deciview > 1.0 1- 0.75 0.75-0.50 0.5-0.25 <0.25 Total

BART-Trade 13 10 13 20 - 56 

Case 5 6 9 9 19 3 46 

Case 6 8 11 11 21 1 51 

Case 8 4 9 8 14 5 40 

Since the 20% worst days do not occur simultaneously the last visibility impact that must be 

considered is the effect of the days of increase on a continuous basis. To do this the difference in 

total visibility impact between the BART-Trade and trading cases is evaluated for each 30 day 

rolling period for 2002 to 2004. The plot of these results, figures 7.8 to 7.10, show that there are 

periods of net increase in visibility impact. However, the maximum increase seen across all of 

these cases is 0.002 deciview. Theoretically taking 0.002 deciview times 30 days yields an 

overall increase of 0.06 total deciview during the 30 day period. 

The Department concludes that the increase to visibility impact is minimal compared to the 

improvement to visibility seen under the trading cases. Although individual days may 

experience additional visibility impact these are relatively small changes in visibility. Further, 

the trading cases show that larger decreases in visibility impact are close in chronology to the 

days of increased impact. Therefore, the trading cases are as likely to decrease as increase 

visibility impact during any short-term period. For these reasons, the Department concludes that 

a trading ratio of two SO2 to one NOx results in equivalent visibility improvement. 
44 

Figure 7.8 

Difference in Daily Visibility Impact between Case 5 and BART-Trade

(30 day rolling average)

-0.060

-0.050

-0.040

-0.030

-0.020

-0.010

0.000

0.010

0 200 400 600 800 1000 1200

Day (2002 - 2204)

Deciview

Figure 7.9 

Difference in Daily Visibility Impact between Case 6 and BART-Trade

(30 day rolling average)

-0.030

-0.025

-0.020

-0.015

-0.010

-0.005

0.000

0.005

0 200 400 600 800 1000 1200

Day (2002 - 2204)

Deciview

Figure 7.10 
45 

Difference in Daily Visibility Impact between Case 8 and BART-Trade

(30 day rolling average)

-0.090

-0.080

-0.070

-0.060

-0.050

-0.040

-0.030

-0.020

-0.010

0.000

0.010

0 200 400 600 800 1000 1200

Day (2002 - 2204)

Deciview
46 

SECTION II - APPENDICES
47 

APPENDIX A 

Revisions to 

Title V Operating Permit Specific to 

BART Requirements 

FID 405032870 

July, 2011 
48 

Refer to file: 405032870-P03 FOP Renewal Draft Permit_Amended July 2011.doc 

DRAFT AIR POLLUTION CONTROL OPERATION PERMIT

EI FACILITY NO. 405032870 PERMIT NO. 405032870-P03 

TYPE: Part 70 Source 

Name of Source: Georgia-Pacific Consumer Products LP 

Street Address: 1919 South Broadway 

 Green Bay, Wisconsin 54304 

Responsible Official: Kelly Wolff 

Title: Operation Manager 

is authorized to operate an existing paper manufacturing facility in conformity with the conditions herein, 

and in compliance with the provisions of Chapter 285, Wis. Stats., and Chapters NR 400 to NR 499, 

Wis. Adm. Code. 

THIS OPERATION PERMIT BECOMES EFFECTIVE ON Draft AND EXPIRES Draft. A 

RENEWAL APPLICATION MUST BE SUBMITTED AT LEAST 12 MONTHS, BUT NOT 

MORE THAN 18 MONTHS, PRIOR TO THIS EXPIRATION DATE [s. NR 407.09(1)(b)1, Wis. 

Adm. Code]. 

No permittee may continue operation of a source after the operation permit expires, unless the permittee 

submits a timely and complete application for renewal of the permit [s. 285.66(3), Wis. Stats., and s. NR 

407.04(2), Wis. Adm. Code]. 

This authorization requires compliance by the permit holder with the emission limitations, monitoring 

requirements and other terms and conditions set forth in Parts I and II hereof. 

Dated at Green Bay, Wisconsin, Draft . 

 

STATE OF WISCONSIN 

Note: 

Draft revisions particular to Best Available Retrofit Technology (BART) are on pages 9 to 35, and 

are highlighted in gray. The accompanying draft support documents, “WI BART – Non EGU” and 

“BART Determination – Amended July 2011, Georgia Pacific Broadway Mill, Green Bay WI” for 

the proposed BART requirements make up an abbreviated form of the standard preliminary 

determination (PD) document that is typically used for operating permit renewals. The draft support 

documents contain a justification for the proposed emission control levels of sulfur dioxide, nitrogen 

oxides, and particulate matter, along with the accompanying modeled visibility impacts for 

reduction of these three pollutants. 
49 

DEPARTMENT OF NATURAL RESOURCES 

For the Secretary 

By Draft 

Richard Wulk 

Air Management Program 

Northeast Region 
50

Preamble

An asterisk "*" throughout this document denotes legal authority, limitations, and conditions which are 

not federally enforceable. 

Georgia-Pacific Consumer Products LP has several existing permits for individual emission units at the 

facility. The existing permits include Permit No. 87-IRS-098 (issued on January 20, 1988 for Process 

P10), Permit No. 89-MWH-084 (issued on January 26, 1990 for Processes P11 and P12), Permit No. 

89-MWH-143 (issued on May 18, 1990 for Processes P13, P14 and P15), and Permit No. 88-AJH-031B 

(issued on February 6, 1995 for Boiler B29). Permit No. 88-AJH-031 was originally issued on 

September 21, 1988, but was later revised as Permit No. 88-AJH-031A on March 29, 1990 and Permit 

No. 88-AJH-031B on February 6, 1995. 

The permittee entered into a consent decree with the United States of America on behalf of USEPA on 

May 28, 1996 concerning the operation of Boiler 8 (identified as Boiler B28 in this permit). Pursuant to 

the consent decree, the permittee altered the boiler in a permanent manner such that it would not be 

capable of operating at a heat input rate greater than 250 mmBTU per hour in any hour of operation 

while firing coal with a heat content as described in the decree. The fuel feed to the boiler has been 

restricted by welding stops into the Stephenson Link on the chain type feeder, and by modifying the 

adjusting rods to limit the height at which the throat blades on the chain type feeder are set, such that 

Boiler 8 will have a maximum heat input rate no greater than 235 million BTU (mmBTU) per hour while 

firing coal with the greater of the highest heating value previously fired or expected to be fired in the 

future. 

One condition from the consent decree was modified through a stipulate order dated July 18, 1997. The 

stipulated order established a maximum heat content in BTUs for the coal burned in Boiler 8. The 

permittee is required to notify USEPA within one week from the commencement of firing coal with a 

heat content greater than 13,500 BTUs per pound. The applicable requirements from the consent decree 

and the stipulated order are incorporated in this permit. 

The Title V operation permit includes revisions to Permit Nos. 89-MWH-143, 87-IRS-098 and 88-AJH031B. New emissions data for paper machines became available during 1996 as a result of studies and 

tests done by the National Council for Air and Stream Improvements (NCASI). By using the NCASI 

data, it was determined that the potential volatile organic compound (VOC) emissions from the processes 

covered by Permit No. 89-MWH-143 had increased from below the Prevention of Significant 

Deterioration (PSD) significance level (40 tons per year) to above this level. Georgia-Pacific has chosen 

to have Permit No. 89-MWH-143 revised as a PSD permit through this Title V operation permit. 

The revision to Permit No. 87-IRS-098 consists of a new Latest Available Control Techniques and 

Operating Practices (LACT) determination for the paper machine covered by this permit. LACT is 

being changed from a maximum VOC emission rate of 5.7 pounds per hour to current operating 

practices. 

The revision to Permit No. 88-AJH-031B is based on a request from the permittee to modify the nitrogen 

oxide emission limit on Boiler B29. The previous limit was 0.49 pounds of nitrogen oxides per million 

BTU (mmBTU) of heat input to the boiler. The Title V operation permit incorporates a two tiered 

nitrogen oxide limit. The nitrogen oxide limit is being increased to 0.60 pounds per million BTU during 

start-up (steam loads less than 200,000 pounds per hour), but will remain at 0.49 pounds per million 

BTU during steady state operations (steam loads greater than or equal to 200,000 pounds per hour). This 
51

two tiered limit is designed to give Georgia-Pacific some additional flexibility during the start-up phase 

of the boiler without increasing the potential nitrogen oxide emissions from the boiler. 

The permittee is subject to the National Emission Standards for Hazardous Air Pollutants (NESHAPs) 

outlined in the Maximum Achievable Control Technology (MACT) standards for the Pulp and Paper 

Industry. There is no pulping of virgin wood fiber or chemical recovery of pulping chemicals at the 

facility so the standards for chemical recovery operations at pulp and paper mills do not apply to the 

facility. However, the two chlorine dioxide bleaching processes (P12 and P13) are subject to the MACT 

standards for bleaching processes. The MACT standard for pulping and bleaching processes was issued 

as a final rule on November 14, 1997, and published in the Federal Register on April 15, 1998. The 

permittee will need to notify USEPA that this standard applies to the facility by April 15, 1999 and to 

demonstrate compliance with the applicable requirements in the MACT standard for pulping and 

bleaching processes no later than April 15, 2001. The third bleaching process (P31) is not subject to the 

MACT standards for bleaching because the permittee uses hydrogen peroxide and hypochlorite to bleach 

secondary fiber in this process and the MACT standard only applies to chlorine dioxide bleaching of 

secondary fiber. 

The permittee is also subject to the National Emission Standards for Hazardous Air Pollutants 

(NESHAPs) outlined in the Maximum Achievable Control Technology (MACT) standards for the 

Printing and Publishing Industry. Process P16 represents the flexographic and rotogravure printing 

presses at the facility. These presses are affected sources under the Printing and Publishing MACT 

standard so the operation of these presses must comply with the applicable requirements in the MACT 

standard no later than May 30, 1999. 

Active Construction Permits Expiration Date

92-RV-120 January 25, 2000 

Stack and Process Index: 

Stack S10, Control C10, 

Boiler B23 - 140 mmBTU per hour underfeed stoker boiler - Installed in 1933. 

Boiler B24 - 200 mmBTU per hour underfeed stoker boiler - Installed in 1947. 

Boiler B25 - 200 mmBTU per hour underfeed stoker boiler - Installed in 1950. 

Boiler B26 - 350 mmBTU per hour spreader stoker boiler - Installed in 1962. 

Boiler B27 - 615 mmBTU per hour cyclone furnace - Installed in 1969. 

Boiler B28 - 235 mmBTU per hour spreader stoker boiler originally rated at 249 mmBTU per 

hour. The boiler was derated to 235 mmBTU per hour in 1996 - Installed in 1975. 

Stack S11, Control C11 & C29, 

Boiler B29 - 486 mmBTU per hour fluidized bed boiler - Installed in 1992. 

Stack S01, 

Process P01 - Paper machine #5 - Installed in 1964. 

Stack S02, 

Process P02 - Paper machine #6 - Installed in 1965. 

Stack S03, 

Process P03 - Paper machine #7 - Installed in 1963. 

Stack S04, 

Process P04 - Paper machine #8 - Installed in 1966. 
52

Stack S05, 

Process P05 - Paper machine #9 - Installed in 1971. 

Stack and Process Index (continued):

Stack S06, Control C06, 

Process P06 - Dry former #1 - Installed in 1977. 

Stack S12, Control C12 

Process P10 - Dry former #2 - Installed in 1989. 

Stack S21, 

Process P15 - Paper machine #1 - Installed in 1992. 

Stack S32, 

Process P32 - Paper machine alpha - Installed in 1980. 

Stack S33, 

Process P33 - Paper machine #10 - Installed in 1984. 

Stack S43, 

Process P43 - Paper machine #3 - Installed in 1930. 

Stack S44, 

Process P44 - Paper machine #4 - Installed in 1936. 

Stack S07, 

Process P07 - Clean-up solvent usage for paper machines except P15 - Installed pre-1980. 

Stack S19, Control C19, 

Process P11 - Chlorine dioxide generation - Installed in 1992. 

Process P19 - Chlor-alkali process - Installed in 1967. 

Stack S20, Control C20, 

Process P12 - Chlorine dioxide bleaching - Installed in 1992. 

Stack S25, Control C25, 

Process P14 - Sodium chlorate generation - Installed in 1992. 

Stack S26, Control C13, 

Process P13 - Pulping & bleaching for paper machine #1 - Installed in 1992. 

Stack S30, 

Process P30 - Pulping for all paper machines except #1 - Installed in 1965. 

Stack S31, 

Process P31 - Bleach plant operations except for P12 and P13 - Installed in 1962. 

Stack S16, 

Process P16 - Flexographic and rotary printing presses - First unit installed in 1954. 

Stack S17, 

Process P17 - Letterpress printing operations - First unit installed in 1924. 

Stack S18, 

Process P18 - Offset printing presses - First unit installed in 1961. 

Stack F36, 

Process P36 - Wastewater treatment plant - Installed before 1980. 

Stack S34, Control C34, 

Process P34 - Ash handling for Boiler B29 - Installed in 1992. 

Stack S35, Control C35, 

Process P35 - Ash handling for Boilers B23 through B28 - Installed in 1984. 
53

Stack F37, 

Process P37 - Fugitive dust emissions from unpaved roadways - Installed in 1919. 

Stack F38, 

Process P38 - Fugitive dust emissions from outdoor storage piles - Installed in 1919. 

Permit Shield - Unless precluded by the Administrator of the USEPA, compliance with all emission 

limitations in this operation permit is considered to be compliance with all emission limitations 

established under ss. 285.01 to 285.87, Wis. Stats., and emission limitations under the federal clean air 

act, that are applicable to the source if the permit includes the applicable limitation or if the Department 

determines that the emission limitations do not apply. The following emission limitations were reviewed 

in the analysis and preliminary determination and were determined not to apply to this stationary source: 

- The New Source Performance Standard (NSPS) for steam generating units in s. NR 440.205, Wis. Adm. Code does 

 not apply to Boilers B23 through B27 because these boilers were installed before the applicability date for this NSPS. 

- The New Source Performance Standard (NSPS) for steam generating units in s. NR 440.19, Wis. Adm. Code does 

 not apply to Boiler B28 because this boiler is rated at 235 million BTU per hour of heat input and the NSPS applies 

 to steam generating units of more than 250 million BTU per hour. This boiler was originally rated at 249 mmBTU 

 per hour, but was derated to 235 mmBTU per hour in 1996 to comply with the May 28, 1996 consent decree. 

 According to the Consent Decree, operation of the boiler above 250 mmBTU per hour in any hour of operation will 

 immediately subject it to the applicable requirements of the Standard of Performance for New Stationary Sources, 

 40 C.F.R. Part 60 (i.e. s. NR 440.19, Wis. Adm. Code). 

- The statewide sulfur dioxide limitations in s. NR 417.07, Wis. Adm. Code do not apply to the source because the 

 permittee is subject to the Reasonably Available Control Technology (RACT) sulfur limitations in ch. NR 418, 

 Wis. Adm. Code. 

- The biennial compliance emission testing requirement for sulfur dioxide does not apply to the source because the 

 source is not subject to any of the sulfur dioxide emission limitations specified in s. NR 439.075(2)(a)2., Wis. 

 Adm. Code. 

- The periodic fuel sampling and analysis requirements in s. NR 439.085, Wis. Adm. Code do not apply to the source 

 because the source is affected by the RACT sulfur limitations in s. NR 418.05, Wis. Adm. Code. 

- The Reasonably Available Control Technology (RACT) standard for lithographic printing in s. NR 422.142, Wis. 

 Adm. Code does not apply to Processes P17 and P18 because the facility is not located in one of the nine affected 

 southeastern Wisconsin counties. 

- The Reasonably Available Control Technology (RACT) standard for paper coating in s. NR 422.07, Wis. Adm. Code 

 does not apply to the paper machines operated by the permittee based on the definitions for "paper coating" and "web" 

 in s. NR 422.02, Wis. Adm. Code. 

- The requirements for control of organic compounds from process lines in s. NR 424.03(2), Wis. Adm. Code do not 

 apply to Processes P01 through P05, P32, P43, P44, P30, P17 and P18 because the emissions from these process 

 lines do not exceed 15 pounds per day (P32, P17 and P18) or they were installed before 1972 (other processes). 

- The requirements for control of organic compounds from process lines in ch. NR 424, Wis. Adm. Code do not apply 

 to the waste water treatment plant (Process P36) because the wastewater treatment plant is not considered a process 

 line according to the definition of process line in s. NR 400.02(72), Wis. Adm. Code. 

- The Maximum Achievable Control Technology (MACT) standard for pulping and bleaching at pulp and paper mills 

 does not apply to Process P31 because the permittee uses hydrogen peroxide and hypochlorite as bleaching agents 

 while the MACT standard covers only chlorine dioxide bleaching at paper mills that use secondary fiber. 

Part I -- The headings for the areas in the permit are defined below. The legal authority for these 

limitations or methods follows them in [brackets]. 

Pollutant -- This area will note which pollutant is being regulated by the permit. 

Limitations -- This area will list all applicable emission limitations that apply to the source, including 

 case-by-case limitations such as Latest Available Control Techniques (LACT), Best Available 

Control Technology (BACT), or Lowest Achievable Emission Rate (LAER). It will also list any 

voluntary restrictions on hours of operation, raw material use, or production rate requested by the 

permittee to limit potential to emit. 
54

Compliance Demonstration -- The compliance demonstration methods outlined in this area may be 

 used to demonstrate compliance with the associated emission limit or work practice standard listed 

 under the corresponding Limitations area. The compliance demonstration area contains limits on 

 parameters or other mechanisms that will be monitored periodically to ensure compliance with the 

 limitations. The requirement to test as well as initial and periodic test schedules, if testing is 

required, will be stated here. Not withstanding the compliance determination methods which the 

owner or operator of a source is authorized to use under ch. NR 439, Wis. Adm. Code, the 

department may use any relevant information or appropriate method to determine a source’s 

compliance with applicable limitations. 

 

Reference Test Methods, Recordkeeping, and Monitoring Requirements -- Specific EPA Reference 

 test methods or other approved test methods will be contained in this area and are the methods that 

 must be used whenever testing is required. A reference test method will be listed even if no testing 

 is immediately required. Also included in this area are any recordkeeping requirements and their 

 frequency and reporting requirements. Accuracy of monitoring equipment shall meet, at a minimum, 

 the requirements of ss. NR 439.055(3) and (4), Wis. Adm. Code, as specified in Part II of this 

 permit. 

Condition Type -- This area specifies other conditions that are applicable to the entire facility that 

may not be tied to one specific pollutant. 

Conditions -- This area lists specific conditions usually applicable to the entire facility or compliance 

requirements. 

Compliance Demonstration -- This area contains monitoring and testing requirements and methods to 

demonstrate compliance with the conditions. 

PART II -- This section contains the general limitations that the permittee must abide by. These 

requirements are standard for most sources of air pollutants so they are included in this section with 

every permit. 
55

PART I 

SPECIFIC PERMIT CONDITIONS

 

A. Stack S10; Control C10; Boilers B23, B24, B25 and B26 - These boilers are multiple retort underfeed stoker boilers (B23, B24 

(B26) that burn coal as a primary fuel, but also burn petroleum coke and mill-derived fuel pellets as alternate fuels. Boiler B23 has a h

BTU per hour and was installed in 1933. Boilers B24 and B25 have heat input capacities of 200 million BTU per hour and were instal

Boiler B26 has a heat input capacity of 350 million BTU per hour and was installed in 1962.19

Note: The limitations in this table apply to each boiler individually unless otherwise indicated. These boilers have the capacity to fire petrole

as alternate fuels. Please see the additional requirements that relate to these alternate operating scenarios for the boilers in Tables E and F of this p

requirements and emission limitations outlined in this section apply to the boilers regardless of the fuel being fired. 

POLLUTANT (a) LIMITATIONS & REQUIREMENTS (b) COMPLIANCE DEMONSTRATION (c) REFERENCE TEST ME

AND MONITORING REQU

(1) Particulate Matter Emissions Continued on Next Page ...

1) Emissions may not exceed 0.30 pounds of particulate matter from any stack per million BTU of heat input. [s. NR 415.06(1)(b), Wis. Adm. Code] 

1) The permittee shall perform compliance emission testing of particulate matter emissions from Stack S10 to demonstrate compliance with the particulate matter emission limit in A(1)(a)1):  a) Testing shall be conducted every 24 months as  long as the permit remains valid;  b) Each biennial test of particulate matter emissions  shall be performed within 90 days of the  anniversary date of the issuance of this permit or  within 90 days of an alternate date specified by  the Department in writing; Continued on Next Page ...

1) Reference Test Metho

Whenever particulate mathe Department, the permincluding backhalf. [s. N2) The permittee shall recompliance emission test[s. NR 439.04(1)(a), Wi3) The permittee shall keof fuel burned in this boi439.04(1)(d), Wis. Adm

(1) Particulate Matter Emissions 

2) The permittee shall only fire:  a) Coal as a primary fuel in this boiler; 

 c) The permittee may request and the Department  may approve a waiver from the required biennial  testing provided the results of the most recently 

4) The permittee shall rebaghouse once every eigday, whichever yields th

19 The Department recognizes that the emissions from Boilers B23, B24, B25, B26, B27 and B28 discharge through a com

it would be difficult to determine the emission rate from a specific boiler unless that boiler were the only one of the six boilers opera

also recognizes that all 6 boilers may not be operating at the time of the required compliance emissions tests. If the emissions from 

stringent limitations and requirements provided in Tables A, B and C of this Part I, then the emissions from each boiler discharging be deemed to be meeting such limitations and requirements. 
56

POLLUTANT (a) LIMITATIONS & REQUIREMENTS (b) COMPLIANCE DEMONSTRATION (c) REFERENCE TEST ME

AND MONITORING REQU

(continued) b) Petroleum coke and mill-derived 

 fuel pellets as alternate fuels in  this boiler. See Table E for additional requirements that apply while firing petroleum coke in this boiler. See Table F for additional requirements that apply while firing mill-derived fuel pellets in this boiler. [ss. 285.65(3) and 285.63(1)(a), Wis. Stats.] 3) The permittee shall operate the baghouse (C10) to control particulate matter emissions whenever the boiler is in operation. [s. NR 415.03, Wis. Adm. Code] 

(a) The permittee shall meet BART requirements for particulate matter emissions no later than December 31, 2011. (b) The permittee shall meet particulate matter emission requirements for BART by meeting the following conditions: (i) Conditions A.1.a.(1), A.1.a.(2) and A.1.a.(3); (ii) Conditions for visible emissions in A.2.a.(1) and A.2.a.(2); (iii) The facility malfunction prevention and abatement plan. [ss. NR 433.05, NR 439.11, Wis. Adm. Code] 

 completed biennial test demonstrate that particulate  matter emissions are 50 percent or less of the  applicable limitation in condition A(1)(a)1);  d) The testing shall be conducted in accordance  with the conditions in DD(4)(a)1). [ss. NR 439.07, 439.075(2)(a), 439.075(3)(b), and 439.075(4)(a)1.b., Wis. Adm. Code] 2) The permittee shall maintain the pressure drop across the baghouse between 3.0 and 12.0 inches of water column. [ss. NR 407.09(4)(a)1., and 439.055(1)(a), Wis. Adm. Code] 3) The permittee shall take appropriate investigative and corrective action in accordance with the procedures in the Malfunction Prevention and Abatement Plan required for this control device whenever the pressure drop is outside of the operating ranges specified in condition A(1)(b)2). [s. NR 407.09(4)(a)1., Wis. Adm. Code] 4) The permittee shall perform periodic internal inspections of the baghouse (C10) to ensure that the control equipment is operating properly. The time interval between inspections may not exceed eighteen (18) months. [s. NR 407.09(4)(a)1., Wis. Adm. Code] 5) The permittee shall prepare and follow a plan for periodic internal inspections of the boiler. This plan shall include the frequency of these inspections and the items to be inspected. [s. NR 407.09(4)(a)1., Wis. Adm. Code] 

[s. NR 439.055(2)(b), W5) The permittee shall ke a) the date, time, and in the inspections requir b) a list of the items ins c) any maintenance or r these inspections. [s. NR 439.04(1)(d), Wi6) The permittee shall ke a) the date, time, and in the inspections requir b) a list of the items ins c) any maintenance or r these inspections. [s. NR 439.04(1)(d), Wi

(2) Visible  Emissions 

1) Opacity may not exceed 20% or number 1 on the Ringlemann chart. 

1) The permittee shall calibrate, maintain and operate the continuous emissions monitoring system required 

1) Reference Test Metho

visible emission testing i
57

POLLUTANT (a) LIMITATIONS & REQUIREMENTS (b) COMPLIANCE DEMONSTRATION (c) REFERENCE TEST ME

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 [s. NR 431.04(2), Wis. Adm. Code] 

2) The permittee shall calibrate, maintain and operate a continuous monitoring system that meets the performance specifications of condition A(2)(b)1) for the measurement of opacity. [ss. NR 439.095(1)(a), and 439.095(5)(a)1.,Wis. Adm. Code] 

by condition A(2)(a)2) in accordance with the performance specifications in Performance Specification 1 in 40 CFR part 60, Appendix B. [s. NR 439.09(1), Wis. Adm. Code] 2) The permittee shall follow a quality control and quality assurance plan as approved by the Department for the continuous monitoring system required by condition A(2)(a)2). [ss. NR 439.09(8), and 439.095(6), Wis. Adm. Code] 

permittee shall use U.S. [s. NR 439.06(9)(a)1., W2) The continuous monitA(2)(a)2) shall complete for each successive 10-serecording for each succe439.09(9)(a), Wis. Adm3) Unless otherwise specexcess visible emissions which the average opacitA(2)(a)1). [s. NR 439.04) The permittee shall sureports to the Departmeneach calendar quarter. [5) The excess emission rshall contain the informaDD(3)(a)1)b). [s. NR 43

(3) Sulfur  Dioxide Continued on Next Page ...

1) Emissions may not exceed 4.45 pounds of sulfur dioxide per million BTU of heat input when Boiler B29 is operating.20 [ss. 285.65(3) and 

285.63(1)(a), Wis. Stats. & s. NR 404.04(2)(a)2., Wis. Adm. Code] 

1) Reference Test Metho

Whenever sulfur dioxide Department, the permitte6B, 6C or 8. [s. NR 439

(3) Sulfur  Dioxide 

2) Emissions may not exceed 4.55 pounds of sulfur dioxide per million 

1) The permittee shall calibrate, maintain and operate the continuous emissions monitoring system required 

2) The continuous monitA(3)(a)3) shall perform s

20 The 4.45 pounds of sulfur dioxide per million BTU of heat input emission limitation comes from Permit No. 88-AJH-03

than the emission limitation from s. NR 418.05(1)(c)1., Wis. Adm. Code (4.55 pounds per million BTU) which appears in condition restrictive limit is necessary to protect the National Ambient Air Quality Standard for sulfur dioxide when Boiler B29 is operating. 
58

POLLUTANT (a) LIMITATIONS & REQUIREMENTS (b) COMPLIANCE DEMONSTRATION (c) REFERENCE TEST ME

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(continued) 

BTU of heat input when Boiler B29 is not operating. [s. NR 418.05(1)(c)1., Wis. Adm. Code] 3) The permittee shall calibrate, maintain and operate a continuous monitoring system that meets the performance specifications of condition A(3)(b)(1) for the measurement of sulfur dioxide. [ss. NR 418.05(4)(a), 439.095(1)(a), and 439.095(5)(a)2.b., Wis. Adm. Code] 

(4) Best Available Retrofit Technology (BART) applies to boiler B26. (a) The permittee shall meet BART requirements for sulfur dioxide emissions no later than December 31, 2015. (b) The permittee shall meet sulfur dioxide emission requirements for BART by meeting one of the following limitations: (i) a sulfur dioxide emission rate limitation of 0.27 pounds per million BTU of heat input to boiler B26 on the basis of a 30-day rolling average; or (ii) total emissions of sulfur dioxide not to exceed 254 tons in any 12-month period and 33 tons in any 30-day period on boiler B26; or (iii) a sulfur dioxide emission rate limitation of 1.01 pounds per million 

by condition A(3)(a)3) in accordance with the performance specifications in Performance Specification 2 in 40 CFR part 60, Appendix B. [s. NR 439.09(2), Wis. Adm. Code] 2) The permittee shall follow a quality control and quality assurance plan as approved by the Department for the continuous monitoring system required by condition A(3)(a)3). [s. NR 439.09(8), Wis. Adm. Code] 

(3) In determining compliance with emission limitations of condition A(3)(a)(4) the permittee shall determine sulfur dioxide emissions using emission data measured according to conditions A(3)(b)(1) and A(3)(b)(2) and according to the following: (a) For condition A(3)(a)(4)(b)(i): (i) In calculating the 30-day rolling average emission rate, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B26.(ii) The 30-day rolling average emission rate in pounds per million BTU shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours boiler B26 operated during the averaging period. The 30

−day rolling 

period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30

−day rolling average emission rate shall be 

calculated and recorded at the end of each day. (b) For condition A(3)(a)(4)(b)(ii): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B26. 

recording as follows:  a) Complete one cycle o recording for each su b) The values recorded  c) Hourly averages shal equally spaced over e periods when calibrat maintenance activities  these periods, a valid  data points separated [s. NR 439.09(9)(b), Wi3) Excess emissions for saverage during which the exceed the emission limi[s. NR 439.09(10)(b)2., 4) For purposes of reporhour rolling average, any only one 24-hour periodleast 18 and not more thaaverage emission rates in 439.09(10)(c), Wis. Adm5) The permittee shall sureports to the Departmeneach calendar quarter. [6) The excess emission rshall contain the informaDD(3)(a)1)b). [s. NR 43

(7) The procedures and mdemonstration and for peconditions A(3)(b)(3) anapplicable requirements NR 439 and NR 440, Wi
59

POLLUTANT (a) LIMITATIONS & REQUIREMENTS (b) COMPLIANCE DEMONSTRATION (c) REFERENCE TEST ME

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(3) Sulfur  Dioxide (continued) 

BTU of heat input to stack S10 on the basis of a 12-month rolling average and 1.53 pounds per million BTU of heat input to stack S10 on the basis of a 30-day rolling average; or (iv) total emissions of sulfur dioxide not to exceed 5,800 tons in any 12-month period and 761 tons in any 30-day period on stack S10; or (v) under the emissions trading program provided under condition A(3a)(b)(5), the permittee shall meet the following emission limitations: (1) the sulfur dioxide emission limitations in condition A(3)(a)(4)(b)(iv), and (2) the sulfur dioxide emission limitations specified in condition A(3a)(a)(1)(b)(v)(2). [s. NR 433.05, Wis. Adm. Code] Note: The sulfur dioxide BART emission limitation on boiler B26 is based on eliminating the firing of coke fuels, combined with continuous operation of a circulating fluidized bed sulfur dioxide scrubber system achieving a minimum 93% sulfur dioxide removal. This technology is noted to establish a basis for determining alternative emission requirements if constraints are encountered in implementing these 

(ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that boiler B26 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. (c) For condition A(3)(a)(4)(b)(iii): (i) In calculating the 12-month rolling average and 30-day rolling average emission rates, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10.(ii) The 12-month rolling average and 30-day rolling average emission rates, in pounds per million BTU, shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 12-month rolling period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month rolling average emission limit shall be calculated and recorded at the end of each month. The 30−day rolling period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day rolling average emission rate shall be calculated and recorded at the end of each day. (d) For condition A(3)(a)(4)(b)(iv): 

(8) In meeting the procedcompliance demonstratiorequired by conditions Apermittee shall determine based on records of the aheat content of the fuel, i[ss. NR 433.05 and NR 4(9) In meeting the complconditions A(3)(b)(3)(b)permittee shall perform (a) Tons of emissions shcalculating emissions ov(b) Monthly emissions shemissions in that month. used to calculate emissio[ss. NR 433.05 and NR 4
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(3) Sulfur  Dioxide (continued) 

specific technologies which warrant a revision of the individual boiler determined control level as allowed for under s. NR 433.05(5). 

(i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day compliance period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. (e) For condition A(3)(a)(4)(b)(v): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. 
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(3) Sulfur  Dioxide (continued) 

(4) In demonstrating compliance with emission limitations of condition A(3)(a)(4) the permittee may propose an emissions trading program if the program achieves an improvement in visibility in the mandatory class I federal areas greater than would be achieved through the installation and operation of BART on each boiler subject to BART. The permittee proposing to use an emissions trading program shall submit an emissions trading plan to the department. The plan shall be subject to department and administrator approval and meet the following criteria: (a) The plan shall contain the proposed control strategy and the method of demonstrating compliance; (b) The plan shall achieve either of the following: (i) For each visibility impairing pollutant for which compliance is demonstrated through use of a trading plan, an emission reduction at least 10% greater than would be achieved through the installation and operation of BART on each boiler subject to BART; (ii) An improvement in visibility in the mandatory class I federal areas greater than or equal to the visibility improvement achieved under condition A(3)(b)(4)(b)(i). The improvement in visibility shall be demonstrated by comparing the 20% best days of visibility and the 20% worst days of visibility in at least the 4 mandatory class I federal areas nearest to the source and for each calendar year 2002, 2003 and 2004. The daily visibility shall be determined using an air quality model approved by the EPA for predicting visibility impacts from single emission sources and conducting the air quality modeling 
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(3) Sulfur  Dioxide (continued) 

analyses according to the guidelines in 40 CFR part 51, Appendix Y, incorporated by reference in s. NR 484.04(11m); (c) Trading shall be between all boilers serving a similar function located on the same property; (d) Boilers participating in the trading shall achieve the required emission reductions on a continuous basis and shall be subject to continuous emission monitoring, which meets the applicable requirements under ch. NR 439; (e) The plan shall specify the monitoring devices and procedures which will be used to provide information sufficient to assess the performance of the proposed emission control measures and to quantify on an hourly average basis the mass flow of each pollutant in pounds per hour and the emission rate of each pollutant in pounds per mmBtu heat input for each boiler participating in the trading. The procedures and methods required for compliance demonstration and for performance testing shall be according to the applicable requirements of ch. NR 439; (f) Excess emission reductions, for the purposes of meeting the BART requirements, shall be emission reductions beyond those required to meet all state and federal requirements and may not include emission reductions used in any other banking or trading program. [ss. NR 433.06(1), NR 439, and NR 484.04, Wis. Adm. Code] (5) If the department approves the emissions trading plan from condition A(3)(b)(4), the department shall propose to revise the source’s air quality permit to include the requirements of the emissions trading plan in lieu of the BART requirements for the boilers 
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(3) Sulfur  Dioxide (continued) 

identified in the emissions trading plan. [s. NR 433.06(2), Wis. Adm. Code] (6) After the department incorporates the emissions trading plan from condition A(3)(b)(4) into the revised air operation permit, the permittee shall comply with the requirements of the emissions trading plan for the boilers identified in the plan. [s. NR 433.06(3), Wis. Adm. Code] (7) The permittee shall notify the Department 90 days prior to selecting a new emission limitation – from the emission limitation options under A(3)(a)(4)(b) – to be complied with. [s. NR 433.05, Wis. Adm. Code] 

3a. Nitrogen Oxides requirements for Boiler B26 

(1) Best Available Retrofit Technology (BART) applies to boiler B26. (a) The permittee shall meet BART requirements for nitrogen oxides emissions no later than December 31, 2015. (b) The permittee shall meet nitrogen oxides emission requirements for BART by meeting one of the following limitations: (i) a nitrogen oxides emission rate limitation of 0.22 pounds per million BTU of heat input to boiler B26 on the basis of a 30-day rolling average; or (ii) total nitrogen oxides emissions of 207 tons in any 12-month period and 27 tons in any 30-day period on boiler B26; or 

(1) The permittee shall calibrate, maintain and operate a continuous monitoring system for the measurement of nitrogen oxides which meets the performance specifications of condition A(3a)(b)(2) and A(3a)(b)(3). [s. NR 439.095(5)(a) and (f), Wis. Adm. Code](2) The permittee shall calibrate, maintain and operate the continuous emission monitor required by condition A(3a)(b)(1) in accordance with the performance specification 2 in 40 CFR Part 60, Appendix B. [ss. NR 439.09(2), NR 439.095(6), Wis. Adm. Code](3) The continuous emission monitor required by condition A(3a)(b)(1) shall follow a quality control and quality assurance plan, as approved by the Department. [ss. NR 439.09(8) and NR 439.095(6), Wis. Adm. Code](4) In determining compliance with emission limitations of condition A(3a)(a)(1) the permittee shall determine nitrogen oxides emissions using 

(1) The procedures and mdemonstration and for pecondition A(3a)(b)(4) anapplicable requirements NR 439 and NR 440, Wi(2) In meeting the procedcompliance demonstratiorequired by conditions Apermittee shall determine based on records of the aheat content of the fuel, i[ss. NR 433.05 and NR 4(3) In meeting the complconditions A(3a)(b)(3)(bthe permittee shall perfo(a) Tons of emissions shcalculating emissions ov(b) Monthly emissions shemissions in that month. 
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(3a) Nitrogen Oxides (continued) 

(iii) nitrogen oxides emission rate limitations of 0.21 pounds per million BTU of heat input to stack S10 on the basis of a 12-month rolling average, and 0.28 pounds per million BTU of heat input to stack S10 on the basis of a 30-day rolling average; or (iv) total nitrogen oxides emissions of 1,200 tons in any 12-month period and 141 tons in any 30-day period on stack S10; or (v) under the emissions trading program provided for under condition A(3a)(b)(5), the permittee shall meet the following emission limitations: (1) total nitrogen oxides emission limitation of 1,080 tons in any 12-month consecutive period and 127 tons in any 30-day consecutive period on stack S10; (2) The emission limitation on nitrogen oxides in condition A(3a)(a)(1)(b)(v)(1) shall be met when: (a) total actual sulfur dioxide emissions do not exceed [5,800 - (N1*T)] tons for any 12-month consecutive period on stack S10, and (b) total actual sulfur dioxide emissions do not exceed [761 - (N2*T)] tons sulfur dioxide for any 30-day consecutive period on stack S10, where 

emission data measured according to conditions A(3a)(b)(1), A(3a)(b)(2), and A(3a)(b)(3) and according to the following requirements: (a) For condition A(3a)(a)(1)(b)(i): (i) In calculating the 30-day rolling average emission rate, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B26.(ii) The 30-day rolling average emission rate in pounds per million BTU shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours boiler B26 operated during the averaging period. The 30−day rolling period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day rolling average emission rate shall be calculated and recorded at the end of each day. (b) For condition A(3a)(a)(1)(b)(ii): i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B26. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that boiler B26 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. 

used to calculate emissio[ss. NR 433.05 and NR 4
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(3a) Nitrogen Oxides (continued) 

N1 = the difference between (actual total tons nitrogen oxides) and (1,080 tons nitrogen oxides) per consecutive 12-month period on stack S10, N2 = the difference between (actual total tons nitrogen oxides) and (127 tons nitrogen oxides) per consecutive 30-day period, T = 2.0 = the ratio of (sulfur dioxide tons reduced from 5,800 tons) to (nitrogen oxides tons increased from 1,080 tons) over any consecutive 12-month period, and the ratio of (sulfur dioxide tons reduced from 761 tons) to (nitrogen oxides tons increased from 127 tons) over any consecutive 30-day period. [s. NR 433.05, Wis. Adm. Code] Note: The nitrogen oxides BART emission limitation on boiler B26 is based on continuous operation of over-fire air and flue gas recirculation control designed specifically for NOx control and continuous operation of selective non-catalytic reduction. This technology is noted to establish a basis for determining alternative emission requirements if constraints in implementing these specific technologies are encountered as allowed for under s. NR 433.05(5) warrant a revision of the individual boiler determined control level. 

(c) For condition A(3a)(a)(1)(b)(iii): (i) In calculating the 30-day rolling average emission rate, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10.(ii) The 30-day rolling average emission rate in pounds per million BTU shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 30

−day rolling period shall 

consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30

−day rolling 

average emission rate shall be calculated and recorded at the end of each day. (d) For condition A(3a)(a)(1)(b)(iv): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30

−day 

compliance period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30

−day total emissions shall be 

calculated and recorded at the end of each day. 
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(3a) Nitrogen Oxides (continued) 

(e) For condition A(3a)(a)(1)(b)(v): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. (5) In demonstrating compliance with emission limitations of condition A(3a)(a)(1) the permittee may propose an emissions trading program if the program achieves an improvement in visibility in the mandatory class I federal areas greater than would be achieved through the installation and operation of BART on each boiler subject to BART. The permittee proposing to use an emissions trading program shall submit an emissions trading plan to the department. The plan shall be subject to department and administrator approval and meet the following criteria: (a) The plan shall contain the proposed control strategy and the method of demonstrating compliance; (b) The plan shall achieve either of the following: (i) For each visibility impairing pollutant for which compliance is demonstrated through use of a trading 
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(3a) Nitrogen Oxides (continued) 

plan, an emission reduction at least 10% greater than would be achieved through the installation and operation of BART on each boiler subject to BART; (ii) An improvement in visibility in the mandatory class I federal areas greater than or equal to the visibility improvement achieved under condition A(3a)(b)(5)(b)(i). The improvement in visibility shall be demonstrated by comparing the 20% best days of visibility and the 20% worst days of visibility in at least the 4 mandatory class I federal areas nearest to the source and for each calendar year 2002, 2003 and 2004. The daily visibility shall be determined using an air quality model approved by the EPA for predicting visibility impacts from single emission sources and conducting the air quality modeling analyses according to the guidelines in 40 CFR part 51, Appendix Y, incorporated by reference in s. NR 484.04(11m); (c) Trading shall be between all boilers serving a similar function located on the same property; (d) Boilers participating in the trading shall achieve the required emission reductions on a continuous basis and shall be subject to continuous emission monitoring, which meets the applicable requirements under ch. NR 439; (e) The plan shall specify the monitoring devices and procedures which will be used to provide information sufficient to assess the performance of the proposed emission control measures and to quantify on an hourly average basis the mass flow of each pollutant in pounds per hour and the emission rate of each pollutant in pounds per mmBtu heat input for each boiler participating in the trading. The procedures and methods required for compliance demonstration and for performance testing shall be according to the applicable requirements of ch. NR 439; (f) Excess emission reductions, for the purposes of meeting the BART requirements, shall be emission 
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(3a) Nitrogen Oxides (continued) 

reductions beyond those required to meet all state and federal requirements and may not include emission reductions used in any other banking or trading program. [ss. NR 433.06(1), NR 439, and NR 484.04, Wis. Adm. Code](6) If the department approves the emissions trading plan from condition A(3a)(b)(5), the department shall propose to revise the source’s air quality permit to include the requirements of the emissions trading plan in lieu of the BART requirements for the boilers identified in the emissions trading plan. [s. NR 433.06(2), Wis. Adm. Code] (7) After the department incorporates the emissions trading plan from condition A(3a)(b)(5) into the revised air operation permit, the permittee shall comply with the requirements of the emissions trading plan for the boilers identified in the plan. [s. NR 433.06(3), Wis. Adm. Code] (8 The permittee shall notify the Department 90 days prior to selecting a new emission limitation – from the emission limitation options under A(3a)(a)(1)(b) – to be complied with. [s. NR 433.05, Wis. Adm. Code] 
69

B. Stack S10; Control C10; Boiler B27 - This is a cyclone furnace type boiler that burns coal as its primary fuel, natural gas and disfuels, and petroleum coke as an alternate fuel. The boiler has a heat input rating of 615 million BTU per hour and was installed in 196

This boiler has the capacity to fire petroleum coke as an alternate fuel. Please see the additional requirements that relate to this alternate operaTable E of this permit. Note: The requirements and emission limitations outlined in this section apply to the boiler regardless of the fuel bein

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(1) Particulate Matter Emissions Continued on Next Page ...

1) Emissions may not exceed 0.30 pounds of particulate matter from any stack per million BTU of heat input. [s. NR 415.06(1)(b), Wis. Adm. Code] 

1) The permittee shall perform compliance emission testing of particulate matter emissions from Stack S10 to demonstrate compliance with the particulate matter emission limit in B(1)(a)1):  a) Testing shall be conducted every 24 months as  long as the permit remains valid;  b) Each biennial test of particulate matter emissions  shall be performed within 90 days of the  anniversary date of the issuance of this permit or  within 90 days of an alternate date specified by  the Department in writing;  c) The permittee may request and the Department  may approve a waiver from the required biennial  testing provided the results of the most recently  completed biennial test demonstrate that particulate  matter emissions are 50 percent or less of the  applicable limitation in condition B(1)(a)1);  d) The testing shall be conducted in accordance  with the conditions in DD(4)(a)1). [ss. NR 439.07, 439.075(2)(a), 439.075(3)(b), and 439.075(4)(a)1.b., Wis. Adm. Code] 

1) Reference Test Metho

Whenever particulate mathe Department, the permincluding backhalf. [s. N2) The permittee shall recompliance emission test[s. NR 439.04(1)(a), Wi3) The permittee shall keof fuel burned in this boi439.04(1)(d), Wis. Adm

21 The Department recognizes that the emissions from Boilers B23, B24, B25, B26, B27 and B28 discharge through a com

it would be difficult to determine the emission rate from a specific boiler unless that boiler were the only one of the six boilers opera

also recognizes that all 6 boilers may not be operating at the time of the required compliance emissions tests. If the emissions from 

stringent limitations and requirements provided in Tables A, B and C of this Part I, then the emissions from each boiler discharging be deemed to be meeting such limitations and requirements. 
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(1) Particulate Matter Emissions (continued) 

2) The permittee shall only fire:  a) Coal as a primary fuel in this boiler;  b) Natural gas and distillate fuel oil  (#1 and #2) as supplemental fuels  in this boiler; and  c) Petroleum coke as an alternate  fuel in this boiler. See Table E for additional requirements that apply while firing petroleum coke in the boiler. [ss. 285.65(3) and 285.63(1)(a), Wis. Stats.] 3) The permittee shall operate the baghouse (C10) to control particulate matter emissions whenever the boiler is in operation. [s. NR 415.03, Wis. Adm. Code] 

(4) Best Available Retrofit Technology (BART) applies to boiler B27. (a) The permittee shall meet BART requirements for particulate matter emissions no later than December 31, 2011. (b) The permittee shall meet particulate matter emission requirements for BART by meeting the following conditions: (i) Conditions B.1.a.(1), B.1.a.(2) and B.1.a.(3); (ii) Conditions for visible emissions in B.2.a.(1) and B.2.a.(2); 

2) The permittee shall maintain the pressure drop across the baghouse between 3.0 and 12.0 inches of water column. [ss. NR 407.09(4)(a)1., and 439.055(1)(a), Wis. Adm. Code] 3) The permittee shall take appropriate investigative and corrective action in accordance with the procedures in the Malfunction Prevention and Abatement Plan required for this control device whenever the pressure drop is outside of the operating range specified in condition B(1)(b)2). [s. NR 407.09(4)(a)1., Wis. Adm. Code] 4) The permittee shall perform periodic internal inspections of the baghouse (C10) to ensure that the control equipment is operating properly. The time interval between inspections may not exceed eighteen (18) months. [s. NR 407.09(4)(a)1., Wis. Adm. Code] 5) The permittee shall prepare and follow a plan for periodic internal inspections of the boiler. This plan shall include the frequency of these inspections and the items to be inspected. [s. NR 407.09(4)(a)1., Wis. Adm. Code] 

4) The permittee shall rebaghouse once every eigday, whichever yields th[s. NR 439.055(2)(b), W5) The permittee shall ke a) the date, time, and in the inspections requir b) a list of the items ins c) any maintenance or r these inspections. [s. NR 439.04(1)(d), Wi6) The permittee shall ke a) the date, time, and in the inspections requir b) a list of the items ins c) any maintenance or r these inspections. [s. NR 439.04(1)(d), Wi
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(iii) The facility malfunction prevention and abatement plan. [ss. NR 433.05, NR 439.11, Wis. Adm. Code] 

(2) Visible  Emissions 

1) Opacity may not exceed 20% or number 1 on the Ringlemann chart. [s. NR 431.04(2), Wis. Adm. Code] 2) The permittee shall calibrate, maintain and operate a continuous monitoring system that meets the performance specifications of condition B(2)(b)1) for the measurement of opacity. [s. NR 439.095(1)(a), Wis. Adm. Code] 

1) The permittee shall calibrate, maintain and operate the continuous emissions monitoring system required by condition B(2)(a)2) in accordance with the performance specifications in Performance Specification 1 in 40 CFR part 60, Appendix B. [s. NR 439.09(1), Wis. Adm. Code] 2) The permittee shall follow a quality control and quality assurance plan as approved by the Department for the continuous monitoring system required by condition B(2)(a)2). [ss. NR 439.09(8), and 439.095(6), Wis. Adm. Code] 

1) Reference Test Metho

visible emission testing ipermittee shall use U.S. [s. NR 439.06(9)(a)1., W2) The continuous monitB(2)(a)2) shall complete for each successive 10-serecording for each succe439.09(9)(a), Wis. Adm3) Unless otherwise specexcess visible emissions which the average opacitB(2)(a)1). [s. NR 439.04) The permittee shall sureports to the Departmeneach calendar quarter. [5) The excess emission rshall contain the informaDD(3)(a)1)b). [s. NR 43
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(3) Sulfur  Dioxide Continued on Next Page ...

1) Emissions may not exceed 4.45 pounds of sulfur dioxide per million BTU of heat input when Boiler B29 is operating.22 [ss. 285.65(3) and 

285.63(1)(a), Wis. Stats. & s. NR 404.04(2)(a)2., Wis. Adm. Code] 

1) Reference Test Metho

Whenever sulfur dioxide Department, the permitte6B, 6C or 8. [s. NR 439

(3) Sulfur  Dioxide (continued) 

2) Emissions may not exceed 4.55 pounds of sulfur dioxide per million BTU of heat input when Boiler B29 is not operating. [s. NR 418.05(1)(c)1., Wis. Adm. Code] 3) The permittee shall calibrate, maintain and operate a continuous monitoring system that meets the performance specifications of condition B(3)(b)1) for the measurement of sulfur dioxide. [ss. NR 418.05(4)(a), 439.095(1)(a), and 439.095(5)(a)2.b., Wis. Adm. Code] 

(4) Best Available Retrofit Technology (BART) applies to boiler B27. (a) The permittee shall meet BART requirements for sulfur dioxide emissions no later than December 31, 2015. 

1) The permittee shall calibrate, maintain and operate the continuous emissions monitoring system required by condition B(3)(a)3) in accordance with the performance specifications in Performance Specification 2 in 40 CFR part 60, Appendix B. [s. NR 439.09(2), Wis. Adm. Code] 2) The permittee shall follow a quality control and quality assurance plan as approved by the Department for the continuous monitoring system required by condition B(3)(a)3). [s. NR 439.09(8), Wis. Adm. Code] (3) In determining compliance with emission limitations of condition B(3)(a)(4) the permittee shall determine sulfur dioxide emissions using emission data measured according to conditions B(3)(b)(1) and B(3)(b)(2) and according to the following: (a) For condition B(3)(a)(4)(b)(i): (i) In calculating the 30-day rolling average emission rate, in pounds per million BTU, the permittee shall 

2) The continuous monitB(3)(a)3) shall perform srecording as follows:  a) Complete one cycle o recording for each su b) The values recorded  c) Hourly averages shal equally spaced over e periods when calibrat maintenance activities  these periods, a valid  data points separated [s. NR 439.09(9)(b), Wi3) Excess emissions for saverage during which the exceed the emission limi[s. NR 439.09(10)(b)2., 4) For purposes of reporhour rolling average, any only one 24-hour period

22 The 4.45 pounds of sulfur dioxide per million BTU of heat input emission limitation comes from Permit No. 88-AJH-03

than the emission limitation from s. NR 418.05(1)(c)1., Wis. Adm. Code (4.55 pounds per million BTU) which appears in condition restrictive limit is necessary to protect the National Ambient Air Quality Standard for sulfur dioxide when Boiler B29 is operating. 
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(3) Sulfur  Dioxide (continued) 

(b) The permittee shall meet sulfur dioxide emission requirements for BART by meeting one of the following limitations: (i) a sulfur dioxide emission rate limitation of 0.23 pounds per million BTU of heat input to boiler B27 on the basis of a 30-day rolling average; or (ii) total sulfur dioxide emissions of 502 tons in any 12-month period and 47 tons in any 30-day period on boiler B27; or (iii) a sulfur dioxide emission rate limitation of 1.01 pounds per million BTU of heat input to stack S10 on the basis of a 12-month rolling average and 1.53 pounds per million BTU of heat input to stack S10 on the basis of a 30-day rolling average; or (iv) total sulfur dioxide emissions of 5,800 tons in any 12-month period and 761 tons in any 30-day period on stack S10; or (v) under the emissions trading program provided under condition B(3a)(b)(5), the permittee shall meet the following emission limitations: (1) the sulfur dioxide emission limitations in condition B(3)(a)(4)(b)(iv), and (2) the sulfur dioxide emission 

not exclude emissions for any period of time for which flue gas is exiting boiler B27.(ii) The 30-day rolling average emission rate in pounds per million BTU shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours boiler B27 operated during the averaging period. The 30−day rolling period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day rolling average emission rate shall be calculated and recorded at the end of each day. (b) For condition B(3)(a)(4)(b)(ii): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B27. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that boiler B27 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. (c) For condition B(3)(a)(4)(b)(iii): (i) In calculating the 12-month rolling average and 30-day rolling average emission rates, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is 

least 18 and not more thaaverage emission rates in 439.09(10)(c), Wis. Adm5) The permittee shall sureports to the Departmeneach calendar quarter. [6) The excess emission rshall contain the informaDD(3)(a)1)b). [s. NR 43

(7) The procedures and mdemonstration and for pecondition B(3)(b)(3) and applicable requirements NR 439 and NR 440, Wi(8) In meeting the procedcompliance demonstratiorequired by conditions Bshall determine the heat records of the amount of content of the fuel, in mi[ss. NR 433.05 and NR 4
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(3) Sulfur  Dioxide (continued) 

limitations specified in condition B(3a)(a)(1)(b)(v)(2). [s. NR 433.05, Wis. Adm. Code] Note: The sulfur dioxide BART emission limitation on boiler B27 is based on eliminating the firing of coke fuels, combined with continuous operation of a circulating fluidized bed sulfur dioxide scrubber system achieving a minimum 93% sulfur dioxide removal. This technology is noted to establish a basis for determining alternative emission requirements if constraints are encountered in implementing these specific technologies which warrant a revision of the individual boiler determined control level as allowed for under s. NR 433.05(5). 

exiting Stack S10.(ii) The 12-month rolling average and 30-day rolling average emission rates, in pounds per million BTU, shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 12-month rolling period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month rolling average emission limit shall be calculated and recorded at the end of each month. The 30−day rolling period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day rolling average emission rate shall be calculated and recorded at the end of each day. (d) For condition B(3)(a)(4)(b)(iv): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day compliance period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. 
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(3) Sulfur  Dioxide (continued) 

(e) For condition B(3)(a)(4)(b)(v): i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. (4) In demonstrating compliance with emission limitations of condition B(3)(a)(4) the permittee may propose an emissions trading program if the program achieves an improvement in visibility in the mandatory class I federal areas greater than would be achieved through the installation and operation of BART on each boiler subject to BART. The permittee proposing to use an emissions trading program shall submit an emissions trading plan to the department. The plan shall be subject to department and administrator approval and meet the following criteria: (a) The plan shall contain the proposed control strategy and the method of demonstrating compliance; (b) The plan shall achieve either of the following: 
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(3) Sulfur  Dioxide (continued) 

(i) For each visibility impairing pollutant for which compliance is demonstrated through use of a trading plan, an emission reduction at least 10% greater than would be achieved through the installation and operation of BART on each boiler subject to BART; (ii) An improvement in visibility in the mandatory class I federal areas greater than or equal to the visibility improvement achieved under condition B(3)(b)(4)(b)(i). The improvement in visibility shall be demonstrated by comparing the 20% best days of visibility and the 20% worst days of visibility in at least the 4 mandatory class I federal areas nearest to the source and for each calendar year 2002, 2003 and 2004. The daily visibility shall be determined using an air quality model approved by the EPA for predicting visibility impacts from single emission sources and conducting the air quality modeling analyses according to the guidelines in 40 CFR part 51, Appendix Y, incorporated by reference in s. NR 484.04(11m); (c) Trading shall be between all boilers serving a similar function located on the same property; (d) Boilers participating in the trading shall achieve the required emission reductions on a continuous basis and shall be subject to continuous emission monitoring, which meets the applicable requirements under ch. NR 439; (e) The plan shall specify the monitoring devices and procedures which will be used to provide information sufficient to assess the performance of the proposed emission control measures and to quantify on an hourly average basis the mass flow of each pollutant in pounds per hour and the emission rate of each pollutant in pounds per mmBtu heat input for each boiler participating in the trading. The procedures and methods required for compliance demonstration and for performance testing shall be according to the 
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(3) Sulfur  Dioxide (continued) 

applicable requirements of ch. NR 439; (f) Excess emission reductions, for the purposes of meeting the BART requirements, shall be emission reductions beyond those required to meet all state and federal requirements and may not include emission reductions used in any other banking or trading program. [ss. NR 433.06(1), NR 439, and NR 484.04, Wis. Adm. Code] (5) If the department approves the emissions trading plan from condition B(3)(b)(4)(b), the department shall propose to revise the source’s air quality permit to include the requirements of the emissions trading plan in lieu of the BART requirements for the boilers identified in the emissions trading plan. [s. NR 433.06(2), Wis. Adm. Code] (6) After the department incorporates the emissions trading plan from condition B(3)(b)(4)(b) into the revised air operation permit, the permittee shall comply with the requirements of the emissions trading plan for the boilers identified in the plan. [s. NR 433.06(3), Wis. Adm. Code] (7) The permittee shall notify the Department 90 days prior to selecting a new emission limitation – from the emission limitation options under B(3)(a)(4)(b) – to be complied with. [s. NR 433.05, Wis. Adm. Code] 

3a. Nitrogen Oxides requirements 

(1) Best Available Retrofit Technology (BART) applies to boiler B27. (a) The permittee shall meet BART requirements for nitrogen oxides emissions no later than December 31, 2015. 

(1) The permittee shall calibrate, maintain and operate a continuous monitoring system for the measurement of nitrogen oxides which meets the performance specifications of condition B(3a)(b)(2) and B(3a)(b)(3). [ss. NR 439.095(5)(a) and (f), Wis. Adm. Code]

(1) The procedures and mdemonstration and for pecondition B(3a)(b)(4) and applicable requirements NR 439 and NR 440, Wi(2) In meeting the proced
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 (3a) Nitrogen oxides (continued) 

(b) The permittee shall meet nitrogen oxides emission requirements for BART by meeting one of the following limitations: (i) a nitrogen oxides emission rate limitation of 0.20 pounds per million BTU of heat input to boiler B27 on the basis of a 30-day rolling average; or (ii) total nitrogen oxides emissions of 437 tons in any 12-month period and 41 tons per 30-day rolling average on boiler B27; or (iii) nitrogen oxides emission rate limitations of 0.21 pounds per million BTU of heat input to stack S10 on the basis of a 12-month rolling average, and 0.28 pounds per million BTU of heat input to stack S10 on the basis of a 30-day rolling average; or (iv) total nitrogen oxides emissions of 1,200 tons in any 12-month period and 141 tons in any 30-day period on stack S10; or (v) under the emissions trading program provided for under condition B(3a)(b)(5), the permittee shall meet the following emission limitations: (1) total nitrogen oxides emission limitation of 1,080 tons in any 12-month period and 127 tons in any 30-

(2) The permittee shall calibrate, maintain and operate the continuous emission monitor required by condition B(3a)(b)(1) in accordance with the performance specification 2 in 40 CFR Part 60, Appendix B. [ss. NR 439.09(2), NR 439.095(6), Wis. Adm. Code](3) The continuous emission monitor required by condition B(3a)(b)(1) shall follow a quality control and quality assurance plan, as approved by the Department. [ss. NR 439.09(8) and NR 439.095(6), Wis. Adm. Code](4) In determining compliance with emission limitations of condition B(3a)(a)(1) the permittee shall determine nitrogen oxides emissions using emission data measured according to conditions B(3a)(b)(1), B(3a)(b)(2), and B(3a)(b)(3) and according to the following requirements: (a) For condition B(3a)(a)(1)(b)(i): (i) In calculating the 30-day rolling average emission rate, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B27.(ii) The 30-day rolling average emission rate in pounds per million BTU shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours boiler B27 operated during the averaging period. The 30−day rolling period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day rolling average emission rate shall be calculated and recorded at the end of each day. (b) For condition B(3a)(a)(1)(b)(ii): 

compliance demonstratiorequired by conditions Bpermittee shall determine based on records of the aheat content of the fuel, i[ss. NR 433.05 and NR 4
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(3a) Nitrogen oxides (continued) 

day period on stack S10; (2) The emission limitation on nitrogen oxides in condition B(3a)(a)(1)(b)(v)(1) shall be met when: (a) total actual sulfur dioxide emissions do not exceed [5,800 - (N1*T)] tons for any consecutive 12-month period on stack S10, and (b) total actual sulfur dioxide emissions do not exceed [761 - (N2*T)] tons sulfur dioxide for any consecutive 30-day period on stack S10, where N1 = the difference between (actual total tons nitrogen oxides) and (1,080 tons nitrogen oxides) per consecutive 12-month period on stack S10, N2 = the difference between (actual total tons nitrogen oxides) and (127 tons nitrogen oxides) per consecutive 30-day period, T = 2.0 = the ratio of (sulfur dioxide tons reduced from 5,800 tons) to (nitrogen oxides tons increased from 1,080 tons) over any consecutive 12-month period, and the ratio of (sulfur dioxide tons reduced from 761 tons) to (nitrogen oxides tons increased from 127 tons) over any consecutive 30-day period. [s. NR 433.05, Wis. Adm. Code] 

(i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting boiler B27. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that boiler B27 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30

−day period shall consist of the day 

of monitoring and the previous 29 consecutive calendar days. A new 30

−day total emissions shall 

be calculated and recorded at the end of each day. (c) For condition B(3a)(a)(1)(b)(iii): (i) In calculating the 30-day rolling average emission rate, in pounds per million BTU, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10.(ii) The 30-day rolling average emission rate in pounds per million BTU shall be calculated as the average of the hourly emissions, in pounds per million BTU, obtained from the continuous emissions monitoring system over the hours that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 30

−day rolling period shall 

consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30

−day rolling 

average emission rate shall be calculated and recorded at the end of each day. (d) For condition B(3a)(a)(1)(b)(iv): (i) In calculating the total emissions, in tons per 12-
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(3a) Nitrogen oxides (continued) 

Note: The nitrogen oxides BART emission limitation on boiler B27 is based on continuous operation of over-fire air designed specifically for NOx control and in combination with one or more of the following equipment configurations to achieve additional 60 – 70% control of nitrogen oxides beyond the over-fire air: selective catalytic reduction, selective non-catalytic reduction, and rich reagent injection. This technology is noted to establish a basis for determining alternative emission requirements if constraints in implementing these specific technologies are encountered as allowed for under s. NR 433.05(5) warrant a revision of the individual boiler determined control level. 

month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the compliance period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day compliance period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. (e) For condition B(3a)(a)(1)(b)(v): (i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, the permittee shall not exclude emissions for any period of time for which flue gas is exiting Stack S10. (ii) The total emissions, in tons per 12-month period and tons per 30-day period, shall be calculated as the sum of the daily emissions, in tons, obtained from the continuous emissions monitoring system over the days that any of the boilers B25, B26, B27 or B28 operated during the averaging period. The 12-month period shall consist of the month of monitoring and the previous 11 consecutive calendar months. A new 12-month total emissions shall be calculated and recorded at the end of each month. The 30−day period shall consist of the day of monitoring and the previous 29 consecutive calendar days. A new 30−day total emissions shall be calculated and recorded at the end of each day. 
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(3a) Nitrogen oxides (continued) 

(5) In demonstrating compliance with emission limitations of condition B(3a)(a)(1) the permittee may propose an emissions trading program if the program achieves an improvement in visibility in the mandatory class I federal areas greater than would be achieved through the installation and operation of BART on each boiler subject to BART. The permittee proposing to use an emissions trading program shall submit an emissions trading plan to the department. The plan shall be subject to department and administrator approval and meet the following criteria: (a) The plan shall contain the proposed control strategy and the method of demonstrating compliance; (b) The plan shall achieve either of the following: (i) For each visibility impairing pollutant for which compliance is demonstrated through use of a trading plan, an emission reduction at least 10% greater than would be achieved through the installation and operation of BART on each boiler subject to BART; (ii) An improvement in visibility in the mandatory class I federal areas greater than or equal to the visibility improvement achieved under condition B(3a)(b)(5)(b)(i). The improvement in visibility shall be demonstrated by comparing the 20% best days of visibility and the 20% worst days of visibility in at least the 4 mandatory class I federal areas nearest to the source and for each calendar year 2002, 2003 and 2004. The daily visibility shall be determined using an air quality model approved by the EPA for predicting visibility impacts from single emission sources and conducting the air quality modeling analyses according to the guidelines in 40 CFR part 51, Appendix Y, incorporated by reference in s. NR 484.04(11m); 
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(3a) Nitrogen oxides (continued) 

(c) Trading shall be between all boilers serving a similar function located on the same property; (d) Boilers participating in the trading shall achieve the required emission reductions on a continuous basis and shall be subject to continuous emission monitoring, which meets the applicable requirements under ch. NR 439; (e) The plan shall specify the monitoring devices and procedures which will be used to provide information sufficient to assess the performance of the proposed emission control measures and to quantify on an hourly average basis the mass flow of each pollutant in pounds per hour and the emission rate of each pollutant in pounds per mmBtu heat input for each boiler participating in the trading. The procedures and methods required for compliance demonstration and for performance testing shall be according to the applicable requirements of ch. NR 439; (f) Excess emission reductions, for the purposes of meeting the BART requirements, shall be emission reductions beyond those required to meet all state and federal requirements and may not include emission reductions used in any other banking or trading program. [ss. NR 433.06(1), NR 439, and NR 484.04, Wis. Adm. Code](6) If the department approves the emissions trading plan from condition B(3a)(b)(5), the department shall propose to revise the source’s air quality permit to include the requirements of the emissions trading plan in lieu of the BART requirements for the boilers identified in the emissions trading plan. [s. NR 433.06(2), Wis. Adm. Code] (7) After the department incorporates the emissions trading plan from condition B(3a)(b)(5) into the 
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revised air operation permit, the permittee shall comply with the requirements of the emissions trading plan for the boilers identified in the plan. [s. NR 433.06(3), Wis. Adm. Code] (7) The permittee shall notify the Department 90 days prior to selecting a new emission limitation – from the emission limitation options under B(3a)(a)(1)(b) – to be complied with. [s. NR 433.05, Wis. Adm. Code]
84
85

APPENDIX B 

Control Equipment Costing Sheets 

for 

Georgia Pacific BART Boilers 

SO2 and NOx 

WDNR – July 2011 
86

Summary of SO2 Control Cost Estimates for Georgia Pacific Boilers B26 and B27 

Combined Flue

Dry FGD Wet FGD 

Parameter 

B26/27 93% control 

a,b

B26/27 95% control 

b

B26/27 98% control 

b

Boiler Size (MW) 76.3 76.3 76.3 

Baseline Emissions (tpy) 10,875 10,875 10,875 

Maximum Reduction (%) 93 95 98 

Fraction Reduced 0.93 0.95 0.98 

Emissions Reduction (tpy) 10,114 10,331 10,658 

 

 

Total Installed Cost 38,250,000 55,869,465 55,869,465 

 

Operating labor 131,400 43,800 43,800 

Supervisor Labor 19,710 6,570 6,570 

Maintenance labor & equipment 2,748,242 87,600 87,600 

Electricity- direct 404,976 705,846 705,846 

Electricity- fan make-up 201,680 --- --- 

Sorbent 4,182,080 18,833,008 19,427,735 

Process water 2,832 348,016 359,006 

Landfill Scrubber system solids 860,289 1,256,030 1,295,694 

Additional Process Steam --- 2,429,442 2,506,162 

 

Overhead rate 1,739,611 82,782 82,782 

Taxes, insurance, admin. Factor 809,671 2,234,779 2,234,779 

Capital recovery factor 2,222,547 6,134,467 6,134,467 

 

Total Annual Operating Cost 

($) 16,020,671 32,162,340 32,884,440 

Effectiveness, ($/ton) 1,584 3,113 3,086 

a

 Total Installed Cost for Turbosorb based on Babcock Power quote received by GP in 20101. 

The cost included B28, making the cost estimate conservative for the B26/B27 combined flue 

alone.

b Dry FGD operating cost and wet FGD capital/operating costs are estimated from the BART 

analysis submitted by GP2. 
87

NOx

Boiler B27 - Overfire Air

Boiler Capacity 50 MW Tons/Year grams/sec

Emissions 103 2,729

Existing Control Efficiency 0%

Control Efficiency 50% OFA

Controlled Emissions 52 1,365 

Emitted 52 1,365 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.25 deciview

OFA Cost:

Reference

Total Direct Cost (TDC) 4 693,980

OFA Equipment 570,000 

Instrumentation 24,812 2

Electrical 99,168 2

Indirect Cost (IC) % of TDC 536,565

Construction Cost 412,585 2

Owners Cost 3% 20,819 3

Total Installed Cost (TIC) 1,230,545

Annual Operating Cost 187,161

Maintenance labor & Parts: 1.50% 18,458 3

Electricity: 52,539 2

Overhead Rate: 0 3

Taxes and Insurance: 0 3

Capital Recovery: 9.44% 116,163 2

Total Annualized Cost 187,161

OFA Control Cost

S/ton = 137 

$/dv = 0.74 
88

NOx

Boiler B27 - Regenerative SCR

Boiler Capacity 50 MW Tons/Year grams/sec

Emissions 103 2,729

Existing Control Efficiency 0%

Control Efficiency 70% RSCR

Controlled Emissions 72 1,910 

Emitted 31 819 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.35 deciview

RSCR Cost:

Reference

Total Direct Cost (TDC) 1 6,100,000

RSCR:

Indirect Cost (IC) % of TDC 2,013,000

Installation: 30% 1,830,000 1

Owners Cost: 3% 183,000 2

Total Installed Cost (TIC) 8,113,000

Annual Operating Cost 3,519,674

Additional Operating & Supervisory Labor: - 3

Maintenance labor & Parts: 1.50% 121,695 3

Electricity: see worksheet 365,574 1

Ammonia Consumption: 5.81 tons/ ton NOx 1,775,815 6

Ammonia Inventory: 12000 gal tank 7,186 1

Natural Gas: 2.5 mmbtu/hr 146,292 `

Catalyst: 3 year 337,245 1

Overhead Rate: - 3

Taxes and Insurance: - 3

Capital Recovery: 9.44% 765,867 2

Total Annualized Cost 3,519,674

RSCR Control Cost

S/ton = 1,842 

$/dv = 10 
89

RSCR Electricity Worksheet

Enduse Capacity kW

booster fan 891 bhp 664 

comb air fan 30 bhp 22 

hydraulic power unit 8 bhp 6 

ammonia pumps 0.5 bhp 0 

instrument comp 15 bhp 11 

misc instruments 2 kw 2 

Hydraulic heaters, est. 1 kw 1 

Total kW 707 

Annual Consumption 8760 hours / year 6,196,168 

Annual Cost 0.059 cents / kWh 365,574 
90

Boiler B27 - OverFire Air + Regenerative SCR 

Boiler Capacity 50 MW Tons/Year grams/sec

Emissions 103 2,729

Existing Control Efficiency 0%

Control Efficiency 50% OFA 1,365 52 

Control Efficiency 70% RSCR 955 36 

Total Control Efficiency 85% OFA + RSCR 2,320 88 

Emitted 15 409 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.43 deciview

OFA Cost:

OFA Annualized Cost 187,161

RSCR Cost:

Reference

Total Direct Cost (TDC) 6,100,000

RSCR 6,100,000 1

Indirect Cost (IC) % of TDC 2,013,000

Installation: 30% 1,830,000 

Owners Cost: 3% 183,000 2

Total Installed Cost (TIC) 8,113,000

Annual Operating Cost 2,631,767

Additional Operating & Supervisory Labor: - 3

Maintenance labor & Parts: 1.50% 121,695 3

Electricity: see worksheet 365,574 1

Ammonia Consumption: 5.81 tons/ ton NOx 887,907 

Ammonia Inventory: 12000 gal tank 7,186 1

Natural Gas: 2.5 mmbtu/hr 146,292 1

Catalyst: 3 year 337,245 2

Overhead Rate: - 3

Taxes and Insurance: - 3

Capital Recovery: 9.44% 765,867 2

Total Annualized Cost 2,631,767

OFA + RSCR Control Cost

Total Annualized Cost = 2,818,927 

S/ton = 1,215 

$/dv = 6.6 

Total Controlled Emissions
91

Boiler B27 - OverFire Air + Rich Reagent Injection + Selective non-Catalytic Reduction

Boiler Capacity 50 MW Tons/Year grams/sec

Emissions 103 2,729

Existing Control Efficiency 0%

Control Efficiency 60% OFA 1,637 62 

Control Efficiency 60% RRI/SNCR 655 25 

Total Control Efficiency 84% OFA + RSCR 2,292 87 

Emitted 17 437 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.42 deciview

OFA Cost:

OFA Annualized Cost 187,161

RRI/SNCR Cost:

Reference

Total Direct Cost (TDC) 1,935,579

RRI/SNCR 1,190,365 4

Concrete 69,918 2

Piping & Insulation 443,204 2

Electrical 232,092 2

Indirect Cost (IC) % of TDC 387,116

General Facilities 5% 96,778.97 3

Engineering & Home Office 10% 193,557.95 3

Process Contingency 5% 96,778.97 3

Total Installed Cost (TIC) 2,322,695

Project Contingency 15% of TIC 348,404 3

Total Plant Cost (TPC) 2,671,100

Preproduction Cost 2 % of TPC 53,422 

Inventory 42000 gal 1.35 $/gal 56,700 4 / 2

Total Capital Cost 2,781,222

Annual Operating Cost 1,685,633

urea 88+33 gal/hr (CAA rates) 1,372,140 4

water double GP 473 946 2

Electricity 50,000 2

Overhead Rate: 0 3

Taxes and Insurance: 0 3

Capital Recovery: 9.44% of TCC 262,547 2

Total Annualized Cost 1,685,633

OFA + RRI/SNCR Control Cost

Total Annualized Cost = 1,872,794 

S/ton = 817 

$/dv = 4.4 

Total Controlled Emissions
92

Boiler B27 - OverFire Air + Selective non-Catalytic Reduction + InDuct SCR

Boiler Capacity 50 MW Tons/Year grams/sec

Emissions 103 2,729

Existing Control Efficiency 0%

Control Efficiency 1 55% OFA 1,501 57 

Control Efficiency 2 40% SNCR 491 19 

Control Efficiency 3 45% InDuct SCR 332 13 

Total Control Efficiency 85% OFA + RSCR 2,324 88 

Emitted 15 405 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.43 deciview

OFA Cost:

OFA Annualized Cost 187,161

SNCR / InDuct SCR

Reference

Total Plant Cost (TCC) -

SNCR / InDuct Total System 188 $/kw 9,450,000 5

Preproduction Cost 2 % of TPC 189,000 3

Inventory 42000 gal 1.35 $/gal 56,700 4 / 2

Total Capital Cost 9,695,700

Annual Operating Cost 2,055,636

urea 33 gal/hr (double SNCR rate CAA rate 4 855,360

water double GP 473 946 2

Electricity 50,000 2

Catalyst 1/2 RSCR 234,056 2

Overhead Rate: 0 3

Taxes and Insurance: 0 3

Capital Recovery: 9.44% of TCC 915,274 2

Total Annualized Cost 2,055,636

OFA + RRI/SNCR Control Cost

Total Annualized Cost = 2,242,797 

S/ton = 965 

$/dv = 5.2 

Total Controlled Emissions
93

NOx

Boiler B26 - Overfire Air / Flue Gas Recirculation

Boiler Capacity 25 MW Tons/Year grams/sec

Emissions 27 640

Existing Control Efficiency 0%

Control Efficiency 35% OFA

Controlled Emissions 224 9 

Emitted 17 416 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.05 deciview

Note: Boiler B26 uncontrolled emission rate = 0.68 lbs/mmbtu

OFA / FGR Cost:

Reference

Total Direct Cost (TDC) 1,294,486

OFA Equipment 1,232,000 4

Instrumentation 17,270 2

Electrical 45,216 2

Indirect Cost (IC) % of TDC 442,890

Construction Cost 404,055 2

Owners Cost 3% 38,835 3

Total Installed Cost (TIC) 1,737,376

Annual Operating Cost 244,797

Maintenance labor & Parts: 1.50% 26,061 3

Electricity: 54,728 2

Overhead Rate: 0 3

Taxes and Insurance: 0 3

Capital Recovery: 9.44% 164,008 2

Total Annualized Cost 244,797 

OFA / FGR Control Cost

S/ton = 1,093 

$/dv = 5.34 
94

NOx

Boiler B26 - Selective non-Catalytic Reduction

Boiler Capacity 25 MW Tons/Year grams/sec

Emissions 27 640

Existing Control Efficiency 0%

Control Efficiency 50% SNCR

Controlled Emissions 320 13 

Emitted 13 320 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.07 deciview

Note: Boiler B26 uncontrolled emission rate = 0.68 lbs/mmbtu

Reference

Total Direct Cost (TDC) 1,897,155

SNCR 1,217,000 4

Concrete 68,917 2

Piping & Insulation 398,190 2

Electrical 213,048 2

Indirect Cost (IC) % of TDC 379,431

General Facilities 5% 94,857.75 3

Engineering & Home Office 10% 189,715.50 3

Process Contingency 5% 94,857.75 3

Total Installed Cost (TIC) 2,276,586 

Project Contingency 15% of TIC 341,488 3

Total Plant Cost (TPC) 2,618,074 

Preproduction Cost 2 % of TPC 52,361 3

Inventory 6000 gal 1.35 $/gal 8,100 4 / 2

Total Capital Cost 2,678,535 

Annual Operating Cost 681,223

Maintenance labor & Parts: 1.50% 40,178.03 

ureaal/hr (double CAA r 4 337,245

water double GP 473 946 2

Electricity 50,000 2

Overhead Rate: 0 3

Taxes and Insurance: 0 3

Capital Recovery: 9.44% of TCC 252,854 2

Total Annualized Cost 681,223 

SNCR Control Cost

S/ton = 2,128 

$/dv = 10.40 
95

NOx

Boiler B26 - OverFire Air / Flue Gas Recirculation + Selective non-Catalytic Reduction

Boiler Capacity 25 MW Tons/Year grams/sec

Emissions 27 640

Existing Control Efficiency 0%

Control Efficiency 1 35% OFA/FGR 224 9

Control Efficiency 2 50% SNCR 208 9

Controlled Emissions 18 432 

Emitted 9 208 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.09 deciview

Note: Boiler B26 uncontrolled emission rate = 0.68 lbs/mmbtu

OFA / FGR Cost:

Annualized Cost 244,797

SNCR Cost:

Reference

Total Direct Cost (TDC) 1,897,155

SNCR 1,217,000 4

Concrete 68,917 2

Piping & Insulation 398,190 2

Electrical 213,048 2

Indirect Cost (IC) % of TDC 379,431

General Facilities 5% 94,857.75 3

Engineering & Home Office 10% 189,715.50 3

Process Contingency 5% 94,857.75 3

Total Installed Cost (TIC) 2,276,586

Project Contingency 15% of TIC 341,488 3

Total Plant Cost (TPC) 2,618,074

Preproduction Cost 2 % of TPC 52,361 3

Inventory 6000 gal 1.35 $/gal - 4 / 2

Total Capital Cost 2,670,435

Annual Operating Cost 562,301

Maintenance labor & Parts: 1.50% 40,057 3

urea adjusted SNCR only rate 219,209 4

water double GP 473 946 2

Electricity 50,000 2

Overhead Rate: 0 3

Taxes and Insurance: 0 3

Capital Recovery: 9.44% of TCC 252,089 2

Total Annualized Cost 562,301

OFA/FGR + SNCR Control Cost

Annualized Cost = 807,098 

S/ton = 1,868 

$/dv = 9.13 

Total Controlled Emissions
96

NOx

Boiler B27 - Regenerative SCR

Boiler Capacity 25 MW Tons/Year grams/sec

Emissions 27 640

Existing Control Efficiency 0%

Control Efficiency 1 70% RSCR 448 19

Control Efficiency 2 0 0

Controlled Emissions 19 448 

Emitted 8 192 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.09 deciview

Note: Boiler B26 uncontrolled emission rate = 0.68 lbs/mmbtu

RSCR Cost:

Reference

Total Direct Cost (TDC) 1 6,100,000

RSCR:

Indirect Cost (IC) % of TDC 2,013,000

Installation: 30% 1,830,000 1

Owners Cost: 3% 183,000 2

Total Installed Cost (TIC) 8,113,000

Annual Operating Cost 2,160,437

Maintenance labor & Parts: 1.50% 121,695 3

Electricity: see worksheet 365,574 1

Ammonia Consumption: 5.81 tons/ ton NOx & 160$/ton 416,578 

Ammonia Inventory: 12000 gal tank 7,186 1

Natural Gas: 2.5 mmbtu/hr 146292 1

Catalyst: 3 year 337,245 2

Overhead Rate: - 3

Taxes and Insurance: - 3

Capital Recovery: 9.44% 765,867 2

Total Annualized Cost 2,160,437

RSCR Control Cost

S/ton = 4,821 

$/dv = 24 

Total Controlled Emissions
97

RSCR Electricity Worksheet

Enduse Capacity kW

booster fan 891 bhp 664 

comb air fan 30 bhp 22 

hydraulic power unit 8 bhp 6 

ammonia pumps 0.5 bhp 0 

instrument comp 15 bhp 11 

misc instruments 2 kw 2 

Hydraulic heaters, est. 1 kw 1 

Total kW 707 

Annual Consumption 8760 hours / year 6,196,168 

Annual Cost 0.059 cents / kWh 365,574 
98

NOx

Boiler B27 - OverFire Air / Flue Gas Recirculation + Regenerative SCR

Boiler Capacity 25 MW Tons/Year grams/sec

Emissions 27 640

Existing Control Efficiency 0%

Control Efficiency 1 35% OFA/FGR 224 9

Control Efficiency 2 70% RSCR 291 12

Controlled Emissions 22 515 

Emitted 5 125 

Visibility Improvement - Seney 0.005 dv per gr/sec 0.11 deciview

Note: Boiler B26 uncontrolled emission rate = 0.68 lbs/mmbtu

OFA/FGR Cost:

Annualized Cost 244,797

RSCR Cost:

Reference

Total Direct Cost (TDC) 1 6,100,000

RSCR:

Indirect Cost (IC) % of TDC 2,013,000

Installation: 30% 1,830,000 1

Owners Cost: 3% 183,000 2

Total Installed Cost (TIC) 8,113,000

Annual Operating Cost 1,649,061

Maintenance labor & Parts: 1.50% 121,695 3

Electricity: see worksheet - 1

Ammonia Consumption: 1 tons/ ton NOx & 160$/ton 270,776 

Ammonia Inventory: 12000 gal tank 7,186 1

Natural Gas: 2.5 mmbtu/hr 146292 1

Catalyst: 3 year 337,245 2

Overhead Rate: - 3

Taxes and Insurance: - 3

Capital Recovery: 9.44% 765,867 2

Total Annualized Cost 1,649,061

OFA/FGR + RSCR Control Cost

Annualized Cost = 1,893,858 

S/ton = 3,675 

$/dv = 16

Total Controlled Emissions
99

References – Appendix B

1) Babcock Power Environmental, April, 2010; Equipment Quote to Georgia Pacific, Green Bay 

Operations, Units 6, 7, 8, BPEI ROM Submittal 502477 – Rev 3, Worcester, Ma. 

2) Georgia Pacific, 2009, Attachment B Engineering Analysis for Control Technology Options 

Green Bay Broadway Mill. BART Analysis submitted to WDNR April, 2009. 

3) USEPA, 2002, EPA Air Pollution Control Cost Manual – 6th Edition, Office of Air Quality 

Planning and Standards, EPA/452/B-02-001. 

4) Combustion Components Associates, 2009, Georgia Pacific Coal Stoker and Cyclone Boiler 

SNCR, RRI, OFA & FGR System Budget Proposal for Green Bay Mill, prepared by Edmund 

Schindler, Monroe Connetticut. 

5) USDOE, 2009, Greenidge Multi-pollutant Control Project - Final Report of Work Performed, 

DE-FC26-06NT41426. 

6) WDNR, June 2010, Best Available Retrofit Technology At Non-EGU Facilities, Note 5, page 

62, Wisconsin Department of Natural Resources, Madison, Wi. 
100

APPENDIX C 

Fuel Switching Analysis 

for 

Base SO2 Emissions 

WDNR, July 2011 
101

Table C.1 Analysis for Adjusted B24 Base SO2 Emissions 

Parameter 2002 2003 2004 3-yr Average

Actual

High Fusion Coal (tons) 25,204 8,264 6,474 13,314 

% S High Fusion --- --- --- --- 

Western Coal (tons) 0 2,241 5,981 2,741 

% S Western --- --- --- --- 

Actual SO2 Total Emissions (tons) 429 180 166 258 

Adjusted

%S High Fusion Coal 2.5 2.5 2.5 2.5 

SO2 High Fusion (tons) 1,260 413 324 666 

Replace Western Coal with High Fusion %S 2.5 2.5 2.5 2.5 

SO2 High Fusion - Replacement of Western (tons) 1 0 99 263 121 

Adjusted SO2 Total Emissions (tons) 1,260 512 587 786 

1

 Ratio of coal heat content for one ton High Fusion coal replacing one ton Western coal is 

assumed at 1.14. 

Table C.2 Analysis for Adjusted B25 Base SO2 Emissions 

Parameter 2002 2003 2004 3-yr Average

Actual

High Fusion Coal (tons) 34,847 11,526 8,308 18,227 

%S High Fusion --- --- --- --- 

Western Coal (tons) 0 2,982 8,407 3,796 

%S Western Coal --- --- --- --- 

Actual SO2 Total Emissions (tons) 588 246 213 349 

Adjusted

%S High Fusion 2.5 2.5 2.5 2.5 

SO2 High Fusion (tons) 1,742 576 415 911 

Replace Western Coal with High Fusion %S 2.5 2.5 2.5 2.5 

SO2 High Fusion - Replacement of Western (tons) 1 0 131 370 167 

Adjusted SO2 Total Emissions (tons) 1,742 708 785 1,078 

1

 Ratio of coal heat content for one ton High Fusion coal replacing one ton Western coal is 

assumed at 1.14. 
102

Table C.3 Analysis for Adjusted B26 Base SO2 Emissions 

Parameter 2002 2003 2004 3-yr Average

Actual Emissions

High Fusion Coal (tons) 45,060 18,112 894 21,355 

%S High Fusion 1.01 0.96 0.96 

Low Fusion Coal (tons) 0 8,771 5,009 4,593 

%S Low Fusion 2.33 2.36 2.43 2.37 

Western Coal (tons) 9,997 33,588 64,601 36,062 

%S Western 0.54 0.49 0.5 0.51 

Pet Coke (tons) 10,971 12,084 14,119 12,391 

%S Pet Coke 5.89 5.38 5.49 5.59 

Actual SO2 Total Emissions (tons) 1,926 2,413 2,141 2,160 

Adjusted Emissions

%S High Fusion 2.5 2.5 2.5 2.5 

SO2 High Fusion (tons) 2,253 906 45 1,068 

SO2 Low Fusion - Estimated (tons) 0 414 243 219 

Replace Western Coal with High Fusion %S 2.5 2.5 2.5 2.5 

SO2 High Fusion - Replacement of Western (tons) 1 440 1,478 2,842 1,587 

Replace Coke with High Fusion %S 2.5 2.5 2.5 2.50 

SO2 High Fusion - Replacement of Coke (tons) 2 614 677 791 694 

Adjusted SO2 Total Emissions (tons) 3,307 3,474 3,921 3,568 

1

 Ratio of coal heat content for one ton High Fusion coal replacing one ton Western coal is 

assumed at 1.14. 

2

 Ratio of coal heat content for one ton High Fusion coal replacing one ton Coke is assumed at 

0.89. 

Table C.4 Analysis for Adjusted B27 Base SO2 Emissions 

Parameter 2002 2003 2004 3-yr Average

Actual

Low Fusion Coal (tons) 132,187 126,175 131,213 129,858 

%S Low Fusion 2.33 2.37 2.43 2.38 

Pet Coke (tons) 32,961 29,212 30,262 30,812 

%S Pet Coke 5.89 5.38 5.49 5.59 

Actual SO2 Total Emissions (tons) 8,807 8,810 8,527 8,715 

Adjusted

SO2 Low Fusion - Estimate (tons) 5,402 5,775 5,606 5,594 

Replace Coke with Low Fusion %S 2.6 2.6 2.6 2.60 

SO2 Low Fusion - Replacement of Coke (tons) 1 1,846 1,636 1,695 1,725 

Adjusted SO2 Total Emissions (tons) 7,248 7,411 7,301 7,320 

1

 Ratio of coal heat content for one ton Low Fusion coal replacing one ton Coke is assumed at 

0.93. 
103

Table C.5 Analysis for Adjusted B28 Base SO2 Emissions 

Parameter 2002 2003 2004 3-yr Average

Actual

High Fusion Coal (tons) 25,621 9,311 407 11,780 

%S High Fusion --- --- --- --- 

Low Fusion Coal (tons) 17,861 20,445 48,902 29,069 

%S Low Fusion --- --- --- --- 

Western Coal (tons) 25,056 28,399 11,455 21,637 

%S Western Coal N/A N/A N/A N/A 

Actual SO2 Total Emissions (tons) 1,664 1,656 942 1,421 

Adjusted

%S High Fusion 2.5 2.5 2.5 2.5 

SO2 High Fusion (tons) 1,842 669 29 847 

%S Low Fusion Coal - Estimated 2.33 2.36 2.43 2.37 

SO2 Low Fusion - Estimated (tons) 832 965 2,377 1,391 

Replace Western Coal with High Fusion %S 2.5 2.5 2.5 2.5 

SO2 High Fusion - Replacement of Western (tons) 1 1,102 1,250 504 952 

Adjusted SO2 Total Emissions (tons) 3,776 2,884 2,910 3,180 

1

 Ratio of coal heat content for one ton High Fusion coal replacing one ton Western coal is 

assumed at 1.14. 
104

APPENDIX D 

Fluor Daniel Study 2000 - Summary of Stack 10 Flows

Stack 10 Flow was tested; individual boiler flows are calculated values)

From Table 2 - Partial Load

Steam M lb/hr AWCFM (319F)

Boiler 5 (hasn’t run in over a year) 34 38277

Boiler 6 174.6 118413

Boiler 7 439 152470

Boiler 8 132.5 119828

Infilt 67969

Total 780.1 496957

From Table 4 - Full Load

Steam M lb/hr AWCFM (319F)

Boiler 5 (hasn’t run in over a year) 112.5 70755

Boiler 6 237 134705

Boiler 7 478.9 186175

Boiler 8 171.7 139891

Infilt 64121

Total 1000.1 595647

From Table 6 - Max Operation

No flyash reinjection

Steam M lb/hr AWCFM (319F)

Boiler 4 (no longer exists) 95.2 63894

Boiler 5 (hasn’t run in over a year) 96.8 44150

Boiler 6 223 138010

Boiler 7 467.8 199487

Boiler 8 168.9 142532

Infilt 57827

Total 1051.7 645900

From Table 8 - Max Operation

With flyash reinjection

Steam M lb/hr AWCFM (319F)

Boiler 4 (no longer exists) 99.3 66121

Boiler 5 (hasn’t run in over a year) 93 51777

Boiler 6 215 131456

Boiler 7 447.8 196493

Boiler 8 170 134892

Infilt 74861

Total 1025.1 655600
105

Section III. Response to Comments

The Department received comment to the draft BART determination from the Class I area 

Federal Land Managers, from Georgia Pacific – Green Bay, and from McGillivray, Westerberg 

& Bender LLC on behalf of Sierra Club of Wisconsin. The Department's response to these 

comments and how the issue affects the amended BART determination is described in this 

section. 

1. Federal Land Managers 

The Federal Land Managers agreed with the preliminary BART determination and emission 

requirement. 

2. Georgia Pacific – Green Bay 

The Draft Permit should clearly identify that the BART-derived Stack S10 limit doesn’t 

apply when only one Boiler B28 (a non-BART boiler) is operating. 

Response: 

The Title V permit for Georgia-Pacific (GP) allows a compliance approach of either meeting an 

emission limitation for each individual BART boiler (B26 and B27), or an emission limitation 

for the common Stack S10. The common stack exhausts emissions from boilers B24, B25, B26, 

B27 and B28. If Georgia Pacific elects to comply with the individual BART boiler limitations 

then there is no requirement to comply with the common stack limit. Or in other words there is 

no emission limitation applicable to boilers B24, B25, or B28 if Georgia Pacific is complying 

with the individual BART boiler limits. The common stack emission limitations are applicable 

only if Georgia Pacific elects to demonstrate compliance on this basis. 

Under this consideration however, Georgia Pacific cannot alternate the elected approach for 

demonstrating compliance. This aspect is important as certain actions such as curtailing boiler 

operation can be pursued to demonstrate compliance with one emission limitation format. In 

pursuing such an action Georgia Pacific cannot simply claim that the limits no longer apply 

because the boiler is not operating. Therefore, the permit requires Georgia Pacific to notify the 

Department 90 days prior to first establishing or when changing the election of emission 

limitation requirements for demonstrating compliance. 

 

Best Available Retrofit Technology determinations are to be done one pollutant at a time. 

o Georgia Pacific states that the analysis of individual control options should be based on precontrol conditions, e.g. the Department cannot presume any SO2 reductions resulting from 

BART in the technical feasibility and operation of NOx controls, specifically RSCR. 

Response: 
106

The Department does not agree that individual pollutant controls should be evaluated one 

pollutant at a time in separate context. First, the evaluation of visibility improvement is 

synergistic between the pollutants with the emission reduction requirements to be implemented 

concurrently. Further, BART guidance is to evaluate controls in context of the existing 

equipment configurations and known conditions. Therefore the Department's approach is to 

evaluate controls accounting for actual existing or projected equipment configurations based on 

the most efficient control approaches in light of visibility improvement and the five factor 

evaluation criteria applied in the BART determination. 

 

On this basis if SO2 emission reductions required under BART is the basis for evaluating NOx 

controls. Therefore for the Georgia Pacific boiler system, the analysis of a RSCR or any tail-end 

SCR will assume placement after the reduction of SO2 emissions. However, the Department also 

concludes that it is appropriate to consider the various SO2 reduction approaches, under the 

existing equipment configuration, and their potential efficiencies for achieving the overall 

control requirement. As such, the evaluation of the RSCR technology applied to the GP boiler 

system also considers that the common flue duct splits prior to the existing fabric filter. Under 

this condition the most efficient approach may be to apply FGD and RSCR technology to one 

side of the split duct system (refer to the Section II.4). 

Further, the Department considers different SO2 control approaches in evaluating NOx controls 

based on solutions considered viable under the five factor analysis. For this reason, if a control 

approach such as shutting down one boiler significantly reduces total SO2 emissions and but still 

results in high SO2 flue gas concentrations from the remaining boilers then this condition will be 

considered in evaluating NOx BART controls. However, if other SO2 control options are 

available and are equal under the five factors then these control options are used as the basis for 

evaluating NOx controls. 

 

o Georgia Pacific considers that the cost of SO2 controls as a pre-requisite for NOx control 

should be included in the cost of the NOx control system. 

Response: 

The department agrees that all costs should be counted in evaluating BART controls. Any 

portion of cost for SO2 control incurred beyond the SO2 BART requirement should be applied to 

evaluating the cost of NOx control. However, the full benefit of visibility improvement 

associated with any required SO2 control, whether for SO2 BART or NOx BART, would then 

also be included in the evaluation of overall visibility improvement. 

In the determination of the amended GP BART requirements no control for SO2 beyond that of 

the SO2 BART is assumed as a pre-requisite to implementing NOx emission reductions. 

Conversely, the NOx BART determination looked at how SO2 controls can be configured, in 

meeting the same SO2 BART, in order to provide the most efficient use of RSCR NOx control 

equipment on one flue gas stream exiting the existing fabric filter system. In this manner the 

Department looked at how controls can be best integrated for the highest available NOx 

reduction, in context of the five factor analysis, in a manner which does not require reductions 

beyond SO2 BART. 
107

o Georgia Pacific concluded that the draft BART determination and default application of 

surrogate control equipment can preclude the technical feasibility of some emission trading 

options. 

Response: 

The BART emissions trading program is set forth under s. NR 433.06, Wis Adm Code. The 

requirements establish that any emissions trading program must demonstrate visibility 

improvement equivalent to that achieved through the BART level of controls. This approach 

clearly requires that the BART level of controls is established first and independently of 

emissions trading. Then the Department must set appropriate criteria for emissions trading 

which maintains visibility improvement garnered from the BART level of control. The 

Department must follow this approach and cannot account for all possible control strategies in 

establishing emissions trading requirements. Similar to BACT, the BART Determination and 

emission trading criteria allow Georgia Pacific to structure the best possible control approach 

meeting the BART determined requirements. 

The Department has incorporated a default emissions trading compliance option under the BART 

compliance requirements. The Department concluded, based on analysis of technologies and 

cost, that the most likely emissions trading approach is to over-control SO2 emissions from nonBART boilers at a lower cost rather than fully controlling NOx to the BART control levels. On 

this basis, mass emission caps and emissions trading ratios are set forth in Georgia Pacific's 

permit which can be utilized while fulfilling the emissions trading criteria under s. NR 433.06, 

Wis. Adm. Code. 

Vendor data and performance guarantees do not determine BART absolutely. 

Response: 

The Department agrees that a vendor statement of performance is not the only factor to consider 

in determining a BART level of control. The Department's approach considered vendor 

information, control levels demonstrated by other operating units, and potential operating 

variability. 

o Georgia Pacific specifically requested for the department to re-examine the technical 

feasibility of RSCR in light that no units have been installed for coal fired boilers or in 

conditions of high SO2 flue gas concentrations. 

Response: 

The Department re-examined the applicability of RSCR in context of the existing flue duct 

configuration and potential flue gas SO2 concentrations. The RSCR vendor provided a quote to 

Georgia Pacific for the Stack S10 system and further confirmed with the Department that RSCR 

is applicable to coal fired units. The vendor further identified implications for operating RSCR 

at different SO2 flue gas concentrations. The Department finds that control strategies can be 
108

implemented for reducing SO2 concentrations under the SO2 BART requirement which allows 

operating RSCR for control of boiler B27's portion of NOx emissions in the flue gas. This 

approach is based on the common flue duct splitting to two separate duct runs. The control of 

boiler B27 requires full RSCR control of one split duct. 

The Department, however, found that SO2 concentrations in the second duct are not conducive to 

operating RSCR to control boiler B26's portion of NOx emissions in the flue gas. Under the 

BART five factor analysis RSCR was eliminated as a control option for boiler B26. 

Operating variability must also be considered in determining BART. 

The emission requirement set for BART needs to incorporate the operating variability into a 

compliance margin, i.e. an enforceable operating permit limit should provide the permittee an 

appropriate level of operating flexibility to allow the facility to achieve continuous compliance 

with all permit limits. 

Response: 

The Department agrees that the long-term performance of control equipment and operating 

variability must be considered in establishing a reasonably achievable control level and emission 

limitation. In this context, the Department believes the emission limitations set for the Georgia 

Pacific boilers on a 30 day and 12 month rolling basis address normal operating variability (refer 

to Section II.6). 

The Department addressed control levels and compliance margins as follows for SO2 and NOx. 

SO2

The draft BART determination proposed control levels of 95% removal based on circulating 

fluidized bed technology as represented by TurboSorb. The Department reviewed emissions 

data for operating Turbosorb units and engineering assessments for CFB technology. The 

Department adjusted the SO2 BART control efficiency from 95% to 93% removal in setting 

BART compliance requirements. Refer to Section II.2 for the determination of SO2 BART 

control levels 

NOx

The draft BART determination proposed control levels of 84% for boiler B26 and 92% for 

Boiler B27. Under the amended determination the BART compliance requirement is based on 

NOx control levels of 68% and 84% for boilers B26 and B27, respectively. These emission 

limitations are determined with incorporated compliance margins for the surrogate control 

equipment. Refer to Section II.4 for the determination of NOx BART control levels. 

The visibility improvement metric used by WDNR in determining BART is insufficient. 

The BART guidelines specify that an initial criterion for visibility benefits is the change in days 

above a 0.5 deciview impact. To completely evaluate the differences between options, the 

determination needs to include this information. 
109

Response: 

The 0.5 deciview is a threshold under the Regional Haze requirements which identifies eligible 

facilities to be evaluated for BART controls. The rule does not specify that further emission 

reductions are not necessary once the 0.5 deciview threshold is achieved. The amount of 

deciview impact for the Georgia Pacific boilers and the amount of improvement resulting from 

the BART controls is estimated in the BART determination. The maximum day visibility impact 

from uncontrolled emissions to the Seney Class I area is 5.38 deciview. Under BART, the 

maximum daily impact is estimated to decrease to 2.02 deciview and the number of days above 

0.5 deciview decrease by an estimated 29 to 34 days. These results show that a change greater 

than 0.5 deciview is achieved and that days are reduced. 

o Georgia Pacific requests, consistent with BART guidelines, that the Department not consider 

imperceptible visibility changes (in evaluating controls for BART). 

Response: 

The Department assessed small changes in visibility when evaluating control technologies. The 

CALPUFF model used in estimating visibility impacts for a source defines deciview changes in 

0.01 increments. The Department agrees this increment by itself is imperceptible to visibility. 

However, small changes in measured visibility improvement, due to emission reductions from 

the same source and with other sources, contribute to overall improvements in visibility. 

Therefore, under the top-down BART approach control technologies are evaluated based on the 

resulting total visibility improvement. The amended BART requirement is estimated to yield 

visibility improvement for Seney of 0.52 deciview from NOx reduction and 1.23 deciview from 

SO2 reductions (average of 3 year maximum daily impact). Therefore the control technologies 

and associated emission reductions yield significant changes that contribute to perceptible 

visibility improvement. 

 

The Department did evaluate the increment of visibility improvement between two technologies 

when the control envelope defines a significant cost increase between the top-available control 

and the next tier down. For example, the Department determined wet-FGD could cost on the 

order of two times the cost of dry-FGD with little additional SO2 control. Wet FGD produced 

only a maximum 0.09 improvement versus dry-FGD in visibility for the Seney Class I area. The 

dry-FGD garners a maximum 1.23 dv improvement. Therefore wet-FGD is eliminated as a 

BART control option because dry-FGD produced nearly equivalent visibility improvement. 

Similar approaches are used in comparing SCR, RSCR, and SNCR based control options in the 

NOx BART determination. 

o Additional Particulate Matter requirements are unnecessary. 

Response: 

The Department agrees that no additional requirement for particulate matter is necessary under 

the BART requirement. The Department modeled potential control efficiency improvements to 

the existing fabric filter system compared to the existing permit limit. This increased control 
110

resulted in a maximum of 0.04 dv visibility improvement. In context that this visibility 

improvement is the entire result of a control measure the Department deems this level of 

visibility improvement as marginal in contribution to a perceptible visibility change. 

Allowable emissions for both BART and non-BART boilers should be used to establish 

proposed Stack 10 permit limits. 

Response: 

The Department does not agree that permit limits for BART and non-BART boilers are the basis 

for establishing Stack 10 requirements. Refer to Section II, Table 3.3 for a comparison of 

allowable and actual emissions. The emission requirements are to be set based on the 

determined BART control efficiencies and an assessment of reasonable operating conditions for 

the entire boiler system (refer to Section II.3 for SO2 base emissions). On this basis the 

Department determined a base fuel for adjusting uncontrolled SO2 emission baseline. The base 

fuel assumes sulfur content reflecting bituminous coals. The SO2 emission requirement is then 

calculated using this adjusted SO2 base emissions. The setting of the NOx emission limit is 

based on current actual emission rates. These rates are related to boiler combustion parameters 

and therefore reflect expected ongoing uncontrolled emissions. 

WDNR needs to calculate incremental cost effectiveness of proposed control analysis. 

Response: 

The Department staff performed a top-down analysis of the available control technologies and 

control levels. As part of this analysis, the Department staff provided the costs associated with 

each control technology and control level. The Department evaluated incremental costs and 

visibility impacts when the control envelope of control options demonstrated a significant 

increase in cost versus the resulting visibility improvement. 

3. Sierra Club of Wisconsin 

DNR must also establish BART limits for EGUs. 

Response: 

The Department established BART limits for EGUs. The state BART rule, ch. NR 433, Wis. 

Adm. Code, establishes that EGUs satisfy SO2 and NOx BART if complying with the federal 

Clean Air Interstate Rule (CAIR). The Wisconsin EGUs elected this compliance option. With 

the implementation of the Clean Air Transport Rule (CATR) to replace CAIR the Department 

will have to evaluate if EGUs still satisfy the SO2 and NOx BART requirement. For PM BART, 

the Department evaluated control options and determined existing controls constitute BART. 
111

Control technologies with costs less than 51 M$/dv should be considered for BART.

Response: 

The Department applied the top-down approach required under BART in evaluating control 

options. Under this approach, contribution to visibility improvement and the necessary cost, 

expressed as M$ per deciview, is a primary evaluation criteria. As Sierra Club states on this 

basis all evaluated control options appear cost-effective. However, the BART guidelines also 

provide that marginal or incremental cost should be considered and that a control envelope 

should be developed representing the available control options. This information can be used to 

evaluate the relative magnitude of visibility improvement versus cost between the top-tier 

options. The Department applied this method in determine controls representing BART. In 

addition the BART guidance requires consideration of non-cost factors in making a BART 

determination. The Department applied these criteria in establishing BART. Addressing both 

factors eliminated several top-tier control options as the basis for BART. 

Wet Scrubber Technology is available at lower cost and can achieve greater than 98% 

reduction.

Response: 

See WDNR response to Comment 2 from Sierra Club above. In the BART preliminary 

determination, WDNR viewed wet FGD at 95% and 98% control as inappropriate due to it’s 

incremental visibility improvement and cost-effectiveness, and energy and environmental 

impacts, compared to dry FGD. The wet FGD costs were based on GP’s BART submittal. The 

comment from Sierra Club offers no alternative cost to refute the costs presented by WDNR. 

Wet FGD above 98% control remains inappropriate in terms of cost-effectiveness and energy 

and environmental impacts compared to dry FGD. 

The Department needs to consider fuel switching to low sulfur coal and natural gas as a 

control option.

Response: 

In the final determination for GP, the Department utilizes a base coal to replace the historical use 

of petroleum coke. This base fuel is a bituminous coal with 2.5% or 2.6% sulfur content 

depending on the boiler, compared to coke at 5-6 % sulfur content. The Department evaluated 

the effectiveness of various levels of fuel switching including the use of low sulfur bituminous 

coal and subbituminous coal. The low sulfur bituminous coal does not yield additional benefit 

compared to the use of standard bituminous coal when applying the dry FGD 93% control 

efficiency. The Department considered switching to subbituminous powder river basin coal as 

beyond the scope of BART under the five factor analysis. Refer to Section II.3 for detail 

discussion of this analysis. 

Regarding the use of natural gas instead of coal, US EPA states in Appendix Y “note that it is not 

our intent to direct States to switch fuel forms, e.g. from coal to gas.” 
112

The proposed emission limits do not represent the degree of control represented by BART. 

o Assuming emissions for B24 and B25 which have not operated for several years creates a 

less stringent requirement. 

Response:

The Department has determined that including B24 and B25 historic operation levels in setting 

emission requirements for stack S10 is appropriate. The BART guidelines specify using 

emissions from the baseline years, 2002 to 2004, as the default basis for establishing BART. 

During this baseline period these boilers operated as part of the stack S10 boiler system. Even as 

these boilers have not recently operated the Stack S10 system has demonstrated the use of this 

capacity. The Department finds that applying the heat input from boilers B24 and B25 to the 

operating levels of the remaining boilers during baseline year operation does not exceed their 

capacity. Therefore, the Department uses the average operating level (heat input) during the 

baseline years as the basis for establishing Stack S10 requirements. The Department also finds 

adjusting SO2 base emissions to reflect an assumed "base" fuel for each boiler is appropriate to 

account for variability of fuel sulfur content and fuel switching control options. (Section II.3) 

 

o Potential future control requirements for B24, B25 and B28 may create a less stringent 

requirement for the BART boilers. The Department must ensure that boilers B26 and B27 

are meeting BART-level emission reductions during all operating scenarios. 

Response: 

The Department cannot anticipate or regulate based on future potential requirements. As the 

BART guidelines establish the BART determination should consider the existing equipment 

configuration and operations. Under this consideration, the emissions exiting from stack S10 

cannot be distinguished as originating from BART or non-BART boilers. Therefore allowing 

compliance with either the individual boiler requirements or common stack requirements is 

appropriate and reflects a reduction of total emissions versus the baseline year emissions. In 

fact, establishing the alternative Stack S10 requirements establishes a baseline for BART and 

non-BART boiler operation. This compliance approach, if utilized, addresses the appropriate 

benchmark against simply shifting load between boilers. 

The Department has not shown that the proposed limits will protect air quality (increased 

increments and NAAQS for NO2, SO2 and PM2.5). 

Response: 

The BART requirement is a requirement for visibility improvement under the federal Regional 

Haze rule. The air protection standards referenced by Sierra Club are not applicable to the 

BART determination. However, the Department agrees that compliance with these requirements 

must be demonstrated under the applicable regulatory programs. 
113

The Department must clarify the sequence of permits for Georgia Pacific. 

Response: 

The Department is in the process of renewing the permit for Georgia Pacific. The process for 

incorporating BART requirements is separate from the renewal process but subject to public 

comment as well. Both processes for modifying the permit will proceed separately with 

requirements effective as each revision is finalized.