# A TTACHMENT 

# 3

### 1 

## BART Determination – Amended July 2011 Georgia Pacific Broadway Mi ll, 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 Availa ble Retrofit Technol ogy (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 af fected Georgia Pacific boilers (Attachment 1). This document amends the draft BART finding for Georgia Paci fic and provides respons e to public comment. The BART requirements for Georgia Pacific will comprise a component of Wisconsin's State Implementation Plan addressing regional haze and will cont ribute to reasonable progress goals (RPG) by 2015 and after. Specific requireme nts 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 Am ended BART Determination

The Georgia Pacific BART requir ements address emissions of pa rticulate matter (PM), sulfur dioxide (SO 2 

### ), and nitrogen oxides (NOx) from tw o power boilers B26 and B27. The two

affected boilers exhaust thr ough common Stack S10 along with th e coal-fired boilers B24, B25 and B28. The BART require ment for each pollutant is summarized as follows:

Particulate Matter (PM) The draft finding proposed PM requirements base d on the existing contro l equipment and permit limitations and required additi onal minimizing of PM emissions through the use of this equipment. The BART determ ination for PM is amended to require only the existing PM controls and permit limitations.

Sulfur Dioxide (SO 2 

### ) The draft finding proposed SO 2 

### requirements based on applicati on of dry scrubbing circulating fluidized bed (CFB) absorber tec hnology achieving 95% control of SO 2 

### emissions. The department developed costs and control leve ls based on a commercially available CFB unit called Turbosorp.

The BART determination for SO 2 

### is amended to reflect that CFB technology is capable of meeting a 93% long-term compliance requirement. This determination fu rther establishes "Base

SO 2 

### emissions" reflecting a presumptive fuel w ith specified sulfur contents. The BART compliance requirement is established by applying 93% control to the "Base SO 2 

### emissions"

Nitrogen Oxide (NOx) The draft finding proposed NOx requirements based on the appli cation of combustion modifications followed by a type of tail-end selective catalytic redu ction technology with regenerative heat recovery (regenerative SCR or referred to here as RSCR). These controls in

combination were estimated to ach ieve 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 modificat ions followed by selective noncatalytic reduction technology (SNCR) to achieve an overa ll 68% long-term compliance reduction. For B27, a cyclone boiler, the requirement reflec ts overfire air combustion modifications followed by one of several differe nt available control op tions: RSCR, rich-reagent injection (RRI), or SNCR. Th ese equipment configurations ar e determined to yield an 84% long-term compliance control requirement.

Summary of BART Control Leve ls and Visibility Improvement The baseline year average emi ssions (2002 – 2004) emitted from the Georgia Pacific Stack S10 boiler system is modeled to deter mine baseline visibility impact in deciviews (dv). The results, in Table 1, show the Seney Cla ss I area receiving a maximum da ily impact of 5.38 deciview. The average of each base line year's maximum daily impact for Seney is 4.14 deciview. Adding the maximum impact for each northe rn Class I areas results in a total impact of 8.12 deciview. This shows Seney recieves approximately one ha lf of the impact from Ge orgia Pacific to the

northern Class I areas. To be no ted is that the maximum impact fo r 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 SO 2 

### 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 th e average visibility impact (4.14 for Seney, 8.12 for northern areas) related to BART requirements ar e also modeled. The results s how, in Table 2, a 2.02 deciview improvement for Seney and 4.19 deci view improvement in total for the nort hern Class I areas.

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

Visibility Improvement (dv) BART Technology and Control Efficiency Seney Northern Areas Emission

Unit
SO 2 

### NO
x 

### PM 10 

### SO 2 

### NO
x 

### SO 2 

### NO
x



### 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 Nationa l Park, Seney Wilderness Area, Boundary Waters Canoe Wilderness Area and Voyageurs National Park.

### 4 BART Compliance Requirements The draft BART determination pr oposed emission limit ations for emissions levels from the

common Stack S10 – emissions for boilers B 24 through B28. Thes e proposed emission

limitations were calcula ted using fuel consum ption and emissions fo r each boiler over the baseline years of 2002 to 2004 and applying the BART control effi ciencies to boilers B26 and

B27.

In amending the compliance requirements th e fuel consumption duri ng the baseline years remains the primary basis for representing bo iler utilization and determining compliance requirements. The SO 2 

### emission requirements are cal culated using base year SO 2 

### 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 emissi ons are directly relate d to boiler combustion parameters which typically do not change over time.

Several compliance approaches or alternatives are provided in th e 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 aver ages (Table 2). Both 30 day and 12 month limits apply in tandem to ad dress daily visibility improve ment accounting for operating variability (30 day) while ensuri ng long-term BART reductions (12 month). The comp lete list of compliance methods are:

o Complying with a 30 day rolling em ission 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 emissi on 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 a nnual mass cap for the common stack

where additional SO 2 

### reductions are traded to o ffset avoided NOx reductions. Under the trading appr oach two tons of SO 2 

### must be reduced to offset each required ton of NOx reduction.

Georgia Pacific can comply with either the emission rate limit ation 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

SO 2 

### 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-do wn process similar to a determination of Best Available Control Technology (BACT). An impor tant distinction howev er is that BACT primarily considers cost of c ontrol in dollars per ton of po llutant reduced ($/ton). The

determination of BART cont rol 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 ($/ton) and cost of visibility improvement in decivi ews ($/dv). Consid eration is also given to the incremental (marginal) visibility improvement and cost.

Similar to BACT, the actual BART can be implemented by establis hing a requirement to install and operate the cont rol equipment at specific control effici encies or by establishing a continuous emission limitation. The Georgia Pacific BART requirements are implemented as emission limitations which are incorporat ed 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 te sting shows 99% control for co arse particulate matter (PM 10) 

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

the maximum actual baseline PM 10 

### 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 reduce d by only 2 days (122 days to 120 days).

Due to the small improvem ent in visibility, the Department determined the draft PM BART at Georgia Pacific to be the existing PM controls and permit limitations. Ho wever, the Department also originally proposed that the facility im plement a plan for con tinuously minimizing PM emissions through operational proced ures. 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, und er ch. NR 439, Wis. Adm. Code, for operating control equipment in a manner c onsistent 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 im provement to visibility. Ther efore the Department deems the

1 August 26, 2008 particulate test on Stack 10

### 7 existing PM controls and permit limitations c onstitute BART PM require ments for boilers B26

and B27. 2. Sulfur Dioxide (SO 2 

### ) BART

The Department compared wet flue gas desulfur ization (FGD) and dry circulating fluidized bed FGD in preparing the draft BART determination. This evaluati on showed that both technologies achieve comparable control of SO 2 

### , but the capital cost of wet F GD 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 th at BART should be based on th e application of dry CFB FGD technologies designed for high co ntrol efficiencies (90 – 95%). The latter portion of this statement means that any installe d scrubber system should be de signed for the highest control levels. The operation of the scrubb er can be scaled to meet the effective emission limitations as

necessary.

The Department maintains, und er this amended BART dete rmination, that dry CFB FGD represents SO 2 

### BART for boilers B26 a nd B27. After further revi ew, the Department has

determined that this technology can achieve 95% control efficiency, but that long term operation and compliance is represented by 93% control efficien cy. The basis for this conclusion is

described here. This determinati on also updates the costs and visi bility improvements originally

estimated for the draf t BART determination.

• Dry CFB FGD Control Efficiency

Under draft BART determination a 95% SO 2 

### control efficiency was proposed for the combined

emissions of boilers B26 and B27. This control efficiency was ba sed on circulating fluidized bed dry scrubbing as represented by an evaluation of Turbosorp c ontrol equipment and costs. Georgia Pacific provided comment that a 95% SO 2 

### control efficiency does not provide compliance margin in accounting for operating variability. In response, the Department conducted addition review of actual operations a nd engineering assessments for both Turbosorb and other CFB type of installati ons. A summary of this review is shown in Table 2.1 below.

The Turbosorp system is operati ng on Unit 4 of the AES Greenidge facility in North Carolina. This system is similar to the Georgia Pacific ca se where the Turbosorp unit was installed to an existing boiler unit - both similar in size and the flue gas character istics 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 SO 2 

### concentration and boiler load changes, affect the overall control efficiency. The testing shows SO 2 

### control ef ficiency 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 decr ease in control efficiency of

1.5 %. From historic informati on, the Georgia Pacific stack S10 boiler system typically ranges in load between 600,000 and 800,00 0 lb/hr, a 25% load swing. Since actual demonstrated change in control efficiency is 1.5% for 30% load swing, simi lar to a 25% load swing, a 2% change is applied here to a llow for a compliance margin.

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

06NT41426..

### 8 The Gainesville Regional Utilitie s also use a Turbosor p unit at the Deerhave n Station in Florida. 3


### The flue gas SO 2 

### 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

SO 2 

### removal. The Roanoke boiler unit is limited to 1.6% su lfur, and has a SO 2 

### removal requirement of 93%.

In 2006 the Washington Group Internatio nal evaluated CFB technology for SO 2 

### removal at each

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

### The design coal ha d a sulfur content of 0.5%. In the evaluation, We Energies settled on 95% SO 2 

### removal because each unit was not “large” (i.e. > 250 MWe). The evaluation also in dicated that 96-98% SO 2 

### removal was possible with the addition of extra water, but that this removal had not be en demonstrated at the time of

the evaluation.

In 2008 Alliant Energy evaluated CFB for SO 2 

### removal at each of tw o 100-MWe units at the Nelson Dewey facility in Wisconsin. 5 

### The design coal was 85% pow der river basin coal (PRB) and 15% petroleum coke, with a resulti ng emission rate of 2.4 lb/mmBtu SO 2 

### . The evaluation indicated a 95% long-term SO 2 

### reduction.

Across these multiple cases the SO 2 

### control efficiency for CFB type of control equipment ranges from 93 to 98% removal. However the operatin g data and engineering assessments for units treating SO 2 

### concentrations similar to the Georgia Pacific applicati on show an expected control efficiency up to 95% removal. Assuming a 2% decrease in removal effi ciency due to operating variability, as shown by the Green idge testing, represents a co mpliance efficiency of 93% removal. The Department finds that 93% is sufficient in addr essing variability and appropriate in determining long term performance requirement s for a CFB unit applied to the Georgia Pacific

BART boilers.

3 Ake, Terrence. “Commissioning a La rge 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, 2011.9Table 2.1 System Performance for Turbosorp andOther 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)•SO2inlet range 2.56 - 4.88 (avg. 3.62)•SO2removal 96.3% (0.134lb/mmBtu at stack)•Limit is 0.19 lb/mmBtu, or ~ 94.8% removal)•93% SO2removal 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•SO2inlet 2.2 lb/mmBtu => removal 95.4% (Guarantee is 95% with 2.3 lb/mmBtu) SO2inlet 3.8 lb/mmBtu => removal 97.2%

### 10 • Dry CFB FGD Cost and Visibility Improvement

The cost estimates for the wet FGD and dry CF B FGD systems applied to boilers B26 and B27 are updated to reflect the SO 2 

### emission reductions. The visib ility improvements are estimated using visibility improvement fact ors for SO2 reduction as develope d in Section 5. Both the costs and visibility results ar e presented in Table 2.2.

The cost estimate for the Turbosor p 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 sc ope of supply for boile r units B26, B27 and B28. The ROM cost is 25.5 million dollars (M$). Babcock Power in the quote stated that installation costs are typically 45 to 55% of the Turb osorp capital cost. The Depar tment applied a 50% installation cost to the 25.5 M$ capital cost which yields a total installed cost of 38.3 M$. To note, the Turbosorp ROM cost is considered conservative in the comparis on as the quoted cost includes boilers B26, B27 and B28, whereas the wet FGD co st estimate included only B26 and B27. In looking at the results both the capital cost and deciview co st is twice as much for the wet scrubber compared to the dry scrubber. Becau se of this cost diff erence the Department maintains that going from dry CFB FGD to wet FGD is not s ubstantiated and that BART is based on the application of dry CFB FGD technologies.

Table 2.2 Boiler B26 and B27 SO 2 

### Control Cost and Vi sibility 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 SO 2 

### BART Control and Visibility Impro vement 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, Sene y Wilderness Area, Boundary Waters Canoe Wilderness Area and Voyageurs National Park.



### 3. SO 2 

### Base Emissions

The Department, for several reas ons, determined that actual SO 2 

### base year emissions do not fully represent the appropriate ba sis for established BART SO 2 

### emission limitations. First, the default basis for determining BART co mpliance requirements, per BART guidelines, is applying the

determined BART control effici ency against base year emis sions (2002 to 2004). But BART guidelines also provide th at existing conditions can be taken in to 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 a nd high sulfur bituminous coals. For this control approach Georgia P acific did identify various levels of fuel switching as a cost

effective SO 2 

### control measure for bot h boilers B26 and B27 6



### .

Because of these issues and the integrated nature of operating Georgia Pacific's stack S10 boiler system, the Department has conclu ded it is appropriate to assess SO 2 

### fuel switching in context of base year uncontrolled SO 2 

### emissions. As a result, the Department determined that SO 2 

### base year emissions (uncontrolled) s hould reflect a "base" fuel cons istent with boiler design and operation. In addition, that the su lfur 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 so urces where a fuel type and ma ximum sulfur content is first

established and then the BACT control efficien cy is used to calcula te 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 switchi ng at each of the BART boilers

B26 and B27 are shown in Tabl e 3.1. For both boilers, substituting bituminous coal for petroleum coke, with 5 to 6% sulfur, is considered relativ ely cost-effective at 755 and 1,500 $/ton for B26 and B 27, respectively.

Table 3.1 Analysis of Fuel Switching for Reduction of SO 2 

### 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 limi ted to replacing the petroleum

coke with low fusion coal. Becau se the low fusion coal is important to maintaining necessary slagging characteristics in the boiler's cyclone furnace the De partment does not consider other

coals in fuel swit ching 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 cl oser at boiler B26 fuel opt ions, summarized in Figure 3.1, substituting low sulfur coal for eith er petroleum coal or for all fuel s comes at an added expense. Still on a $/ton basis all of th ese options would be consider ed cost-effective under most regulatory requirements. As suc h, the affect of cost and emissi on reduction is further evaluated in context of the amended BART control efficiency.

When applying fuel switching options to boile r B26 followed by 93% F GD control there is a smaller difference in end emissions than if only fuel switching is employ ed. As shown in Table 3.2, with FGD, the various levels of fuel switching yi eld a difference of 61 to 93 tons per year in reduced emissions. This analysis shows that the majority of SO 2 

### 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 tota l of 93 tons or 4% beyond scrubb ed emissions. Therefore there is only a 1% difference between the lower and maximum fuel swit ching options when employed

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

### 13 0.6 $M to 1.6 $M per year. Ther efore, switching coke fuels with standard bituminous coals is deemed to represent the appropria te level of fuel switching in addition to technology control options.

Figure 3.1 Boiler B26 Comparis on of Fuel Switching for SO 2 

### 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 bi tuminous coal; LS = low sulfur bituminous

Table 3.2 Boiler B26 SO 2 

### Emission Reduction from Fuel Sw itching 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 b ituminous coal is assumed as the "base" fuel. As previously stated the low fusion coal is a specific type of bitumi nous coal which produces specific slagging character istics necessary to operating cycl one boilers. Because of this

### 14 characteristic and its high er fuel price the Depar tment 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 thr ough the Department of Energy does not clearly distinguish

between bituminous coal and low fusion bituminous coal, therefore an ev aluation of the sulfur content for low fusion coal is not performed. Beca use of it's limited use and lack of specific data for low fusion coal, the Department concludes that the sulfur content of th e current fuel used by Georgia Pacific represents low fusion coal sulfur content into the future. Georgia Pacific's BART analysis identifi ed the current low fusion coal as containing 2.6% of sulfur by weight.

For boiler B26, the fuel sw itching 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-stat e region of Illinois, I ndiana, Kentucky, Ohio, Pennsylvania, and West Virgin ia. Based on the Department of Energy’s 2009 Quarterly Coal Report the bituminous coals supp lied from these six states in 2009 ranged in average sulfur

content of 1.53 to 3.68% sulfur 7



### .

More broadly the Department eval uated EPA's database of coal fuel characteristics compiled under 1999 EGU mercury informati on collection request (ICR). This ICR process required

electric utilities to test fuel ch aracteristics for each de livery of coal for an entire year which resulted in over 40,000 fuel samples. Therefore the ICR database is de emed 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 approxima tely 80% of bituminous coals fired by the electric utility sector on a heat input weighted ba sis (Figure 3.2). When looking at just the identified six-state region for Georgia Pacific coal sources (Figure 3.3) a sulf ur content of 2.6% captures approximately 75% of the co al supplied to electric ut ilities from this region.

Figure 3.2 Sulfur Content of Bituminous Fired Coal s, 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 – Si x State Region, 1999 EGU ICR

Database

### 16 Conclusion

The Department concludes that fuel switching is a cost-effective option to controlling SO 2 

### emissions. However, most of the effective reductions are ca ptured by switching to standard

bituminous fuels. Also to note is that other faci lities, including cyclone boilers, have switched and operate fully on low sulfur powder river basin (PRB) subbitumi nous coals. The Department considers this option to be beyond the scope of BART. The majority of these facilities switching to PRB coal are larg e electric utilities wh ich invested in long term deliv ery and supply logistics.

These facilities have also had to significantly alter coal tr ansfer and combustion related equipment in addition to adopting extensive coal management procedures in order to manage fire hazards associated with burning PR B coals. The Department finds that imposing these potential impacts with lit tle additional SO 2 

### 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 consiste nt with base design fuels of th e boilers and ther efore promotes

efficient combustion an d power production.

Therefore, to address reasonable fuel switching alternatives and expected availability of base fuels the Department finds that a base fuel for bo iler B26 is represented by bituminous coal with up to 2.5% sulfur and that a ba se fuel for boiler B27 is repr esented by low fusion bituminous coal with up to 2.6% sulfur content.

• Adjusted Base SO 2 

### 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 a ssumption for boiler B26 is also applied to the remaining non-BA RT 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 B 24, B25, B26 and B28

The basis for calculating the adjusted SO 2 

### 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 combin ation of low fusion bituminous coal and petroleum coke. The stoker boilers, including B26, fire d 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 co al. In this calculation fuels consistent with the base fuel are not adjusted for sulfur content. The SO 2 

### emissions for each boiler are then

recalculated for each fuel and summ ed. The results are used to calculate the adjusted 3 year average SO 2 

### emissions across the 2002 to 2004 base years. The adjusted base year SO 2 

### emissions are summarized in Table 3.3 along with actual base year emissi ons. Also presented for comparison are emis sions based on each boiler's heat input and current permitted SO 2 

### limit.

The details of base fuel substi tutions and resulting emissions for each boiler are presented in appendix C.

### 17 As previously discussed the replacement of petroleum coke wi ll reduce sulfur fuel content. Conversely, replacing low su lfur coal with the base fuel will increase fuel sulfur content and emissions for that portion of heat in put. A basic premise in evaluating SO 2 

### 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% SO 2 

### scrubbing requirements which is used as a base load unit. When boiler B29 is not operating the SO 2 

### limit for Stack S10 incr eases to 4.55 lbs/mmBtu. Th is overall facility limit was set to avoid exceeding hi storic daily and annual SO 2 

### National Ambient Air Quality Standards (NAAQS). Applying this emission limitation to the base year heat input results in

total annual SO 2 

### 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 di fferent coals and coke fuels with different heat contents is targeted to produce good firing ch aracteristics. When the coke fuels are elimin ated the amount of low sulfur coals that can be effectively blended will change in achieving good combustion.

Because of these factors the De partment 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 f acility should not be penalized for historically emitting less than allowable emissions. Georgia Pacific clearly operated below their allowable SO 2 

### emissions level during the base years. Theref ore, in light of these reasons, us ing a base fuel that represents reasonably anticipated operating conditions is an appropriate basis for establishing SO 2 

### emission requirements applicable to the Stack S10 boiler system.

Table 3.3 Base Year (2002 – 2004) Average Heat Input and SO 2 

### 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)** 757 5,043 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 determinatio n. These proposed control levels were the

### 18 result of assumed combustion modi fications to each i ndividual boiler follow ed by a regenerative selective catalytic reduction (R SCR) unit operating on the common flue st ack. For the RSCR, 75% to 80% reduction was applied. In ma king the draft finding of RSCR as BART, the Department had also concluded th at full-sized high-dust SCR conf igurations, capable of 80% or greater control, would likely be higher in cost and present ch allenging 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 Departme nt finds that 75% c ontrol efficiency is achievable and 70% control efficiency is appropriate in setti ng compliance requiremen ts. The combustion modifications and RSCR applied to boiler B27 yield an overall compliance control efficiency 85%. The Department further fi nds that other combinations of technologies may result in comparable emission reductions in boiler B27 emissions. Because there is poten tial benefit, based on the BART five factors, the Department is setting NOx BA RT 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 op erating issues and cost s when considering the RSCR installation in light of the existing equipment configura tion. In absence of RSCR, the Department re-evaluated the control efficien cy of combustion m odifications 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 B 26 is amended to 68% c ontrol based on combustion

modifications and selective non- catalytic reduction (SNCR).

• Application of Regenerative SCR

The application of RSCR technol ogy is further evaluated to a ddress aspects of the existing equipment configuration which we re not considered under the dr aft BART. Currently, flue gas from all boilers B24 through B28 exhausts to a common duct whic h then enters the existing fabric filter system. Just prior to the fabric filter sy stem, the duct splits w ith flue gas traveling evenly to two parallel fabr ic filter units. The flue gas then exits each fabric filter unit in separate ducts and rejoins only after en tering the stack structure. Previously the RSCR analysis

accounted for a one flue duct conf iguration between the fabric fi lter system and the stack.

Babcock Power, the primary vendo r of the RSCR system, provide d a quote to Georgia Pacific for two separate RSCR tr ains, each treating an individual fl ue gas stream exiting the fabric

filter 8 

### . Under this quote, one RSCR train treats approximately 260,000 acfm of flue gas flow. According to testing of maxi mum flow rates, boiler B 27 can range up to 199,500 acfm and together with B26 can total 337,500 acfm (Appendix B). Because co ntrol equipment is typically designed to handle maximum flow rates, one RSCR cannot treat bot h 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 control ling boiler B27 emissions (duct 1) and the second RSCR (duct 2) for treating boiler B26 emissions.

The existing split flue duct and fabric filte r system is also pertinent to evaluating SO 2 

### flue gas concentrations and associated impact s in operating th e RSCR system.

If BART SO 2 

### requirements are met by scr ubbing all flue gas (both du cts) at the same average control efficiency, th en an RSCR on either duct will see SO 2 

### concentrations up to the BART limit of 1.01 lbs/mmbtu (Stack S 10 emission limit, Table 6.2). A predominant issue at this

emission level is that th e SCR catalyst converts SO 2 

### to SO 3 

### causing visible plum e and acidic flue gas conditions. Based on discussion s with Babcock Power (BP) an SO 2 

### emission rate of 1.0

lbs/mmbtu will result in SO 3 

### concentrations of approximately 5.3 parts per million (ppm) @ 3%

O2 9 

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

SO 3 

### concentrations below 5 ppm. 10 

### Babcock Power indicates that plume issues need to be

further evaluated if SO 2 

### concentrations to th e RSCR are above 0.6 lbs/ mmbtu. Therefore, SO 2 

### BART for Georgia Pacific at a default flue ga s concentration of 1.0 lbs/mmBtu will generate visible plume and creates concer n for overall technical feasibili ty of applying the RSCR under

these conditions.

Another issue related to SO 2 

### and conversion to SO 3 

### is the formation of ammonium bisulfates (ABS) in the RSCR and downstr eam 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 SO 2 

### concentrations more energy will be required in reheati ng flue gas. The BP further st ates that even at 0.6 lbs/mmbtu (the draft BART SO 2 

### limit) the RSCR will require steam s ootblowers and increased maintenance cycles. Therefore, higher SO 2 

### concentrations are not prohibitive to operat ing 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 ha ve to be evaluated for plume generation and feasibility.

In utilizing the existing fa bric 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 si de of the duct system - simi lar to the RSCR installations. This two system approach allo ws operating at different SO 2 

### control levels between the duct systems. Operating one scrubber at maximum levels can reduce SO 2 

### concentrations to 0.15 to

0.18 lbs/mmbtu in one flue gas duct. At these SO 2 

### emission levels the RSCR unit is clearly feasible and will see benefits in operation a nd life, minimized buildup of ammonium bisulfate and acid deposition, and elimination of any SO 3 

### plume generation. In Ge rmany multiple tail-end SCR's after flue gas desulfuriza tion have operated more than 10 years without replacing the SCR catalyst. Therefore th is ability to focus SO 2 

### reductions to one flue gas duct allows RSCR to be a

feasible and cost-effectiv e 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 SO 2 

### concentrations in the second duct will likely be at least as hi gh as the average BART emission limit of 1.01 lbs/mmBtu. In addition, SO 2 

### concentrations may range higher in the second duct if trimmed only to meet the overall emis sion requirement to both BART boilers. At these higher SO 2 

### concentration RSCR performance will degrade faster and SO 3 

### plume generation will clearly be a feasibility issue. Ther efore the Department finds that applying RSCR to a second duct and to boiler B26 will incur significant technical issues including ge neration of visible plume.

• Boiler B27 NOx Control

As previously discussed, the RS CR 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 emissions 11 

### . In determining

the BART emission limitations th e Department applied a RSCR comp liance control efficiency of

70%. This difference in control efficiencies reflects a 7% compli ance margin. In comparison, a 10% compliance margin was used by the Departme nt in setting complianc e 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 fi rst overfire air combustion modifcations (OFA) followed by the RSCR equipmen t. The Department revised the OFA control efficiency after analyzing emissions da ta for OFA operating on cyclone boilers at the Nelson Dewey electric genera ting plant in Wisconsin 12 

### . 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 u tility, in optimizing a nd operating cyclone boiler OFA the Department deems this data to represent practical and achievable OFA control efficiencies. The analysis of emissions da ta shows OFA at Nelson Dewey achieving a 52% annual control efficiency. For purposes of determining BART comp liance requirements the Department is applying 50% OFA control efficiency to bo iler B27. Together the OFA and RSCR equipment result in 85% complian ce control efficiency for boiler B27.

A primary question in sizing th e RSCR technology is "what porti on of the Stack S10 flue gas

flow must be treated to address boiler B27 emissions". This is because th e 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 need s to be treated by an RSCR op erating at the upper 75% control efficiency. This means one of the split ducts and RSCR unit is de dicated to treating boiler B27 emissions. This apportionment of RSCR control requirement is corroborated in another way. During the baseline years, boile r 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 da ta base for 1990 – 2010, Clean Air Markets Division (CAMD).

### 21 In considering both of these fact ors, consistent with the finding for boil er maximum flue gas flow rates, the Department concludes that one full RSCR on one duct is de dicated to controlling

boiler B27 emissions.

Control Alternatives

Since the RSCR requires signifi cant capital and has associ ated impacts such as CO 2 

### emissions from re-heating flue gas, the De partment further evaluated next -tier control options. These options included combinations of the OFA control with rich reagent inje ction (RRI), selective non-catalytic reduction (SNCR), and in-duct se lective catalytic redu ction (IDSCR). The combination of control options a nd 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 re agent injection (RRI) where urea is injected directly into the furnace. Because reagent is lost to com bustion, 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 bisulf ate (ABS) impact s. The RRI

can also be used with SNCR to ach ieve higher NOx reduction efficien cy. The benefit here is that the SNCR can be applied with le ss ammonia slip and associated ABS impacts. Together the RRI/SNCR approach is capable of up to 60% NOx reduction 13 

### . In order for the RRI/SNCR to reach control levels similar to OFA/RSCR, the OFA system must be op erated at a higher 60% control efficiency. Georgia Pacific identified this level of control for OFA in their BART analysis. However in the Depart ment's experience 60% control is at the upper end of the control potential for OFA and likely decrea ses combustion efficiency of the boiler. It is for this reason that the 52% control efficiency, as demonstrat ed by the Nelson Dewey plant, is utilized in assessing the OFA/RSCR primar y BART control option. Overal l the OFA/RRI/SNCR (Case 2) may yield up to 84% control effi ciency 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-d uct SCR (IDSCR) consisting of 1 catalyst layer for up to 45% NOx reduction NOx 14 

### . The IDSCR is applied after th e 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 additi onal foundation requirement. In contrast, an SCR capable of 70 – 80% control with 3 catalyst la yers will be approximately 16 x 16 x 50 feet high according to design criteria in the OAQPS control cost manual 15 

### . 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 re trofitting a full SCR will requir e significant alteration of the existing air-heater and ducting configurati on as well as buildi ng modifications.

The IDSCR can be more easily fi t into the existing space and equi pment configuration. Even before retrofit considerations, th e capital costs of an IDSCR is approximately 30 to 70% of a

conventional SCR 12 

### . Another benefit is that with one la yer of catalyst the IDSCR will generate significantly less SO 3 

### . Therefore ABS and acid gas plant impacts are greatly reduced. In addition, the RRI and SNCR reagent injection rates are balanc ed to yield just enough urea or ammonia slip for effective utili zation of the IDSCR. This approach optimizes the efficiency of reagent utilization and further mi nimizes ABS impacts. Under this integrated approach the target control efficiency for the SNCR is up to 40% NOx reduction a nd for the SCR cat alyst 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/pr oducts/apc/noxout-cascade/

15 USEPA, 2002, EPA Air Pollution Control Cost Manual – 6 th 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 th e 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 SO 2 

### emission reductions. In addition these options may significantly reduce en ergy requirements by eliminating flue gas reheat and reducing pressure losses compared to the RSCR cata lyst bed. It should be noted that these control ef ficiencies for RRI, SNCR, and IDSCR are not ba sed on specific quotes for the Geor gia Pacific boilers. Rather this analysis represents the potential of these technologies to achieve re ductions 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 appl icability of cost factors as prescribed by the EPA air pollu tion 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 un its to the Georgia Pacific Stack S10 system. This quote included a capital co st, an estimate that installation costs run 20 – 30% of capital costs and provided specific operating paramete rs related to reagent usage and utility requirements. This information is applied to develop the cost of controlling boiler B27 emissions (one flue duct). The co st of the overfire air system is also revised to reflect a system quote by Combustion Components Asso ciates (CCA) specifi cally for installation to boiler B27.

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

boiler B27. The cost fo r the SNCR/IDSCR sy stem approach is based on the actual installation cost for this type of system to unit 4 of the AES Greenidge facility 16 

### . Since the SCNR/IDSCR cost is not based on a specific quote for Boiler B27 th e result is consid ered a scoping cost.

The resulting costs and emission re ductions for the evaluated tec hnologies are prov ided in Table

4.2. The cost-effectiv eness of visibility impr ovement (M$/dv) is calcula ted for the Seney Class I area using a factor of 0.005 deci view per grams/sec of reduced NOx emissions (Table 5.2). This improvement factor re presents the averag e of the maximum impact regi stered in each of the base years when applying the amende d BART emission limit ations. 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 anal ysis show that the OF A/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 fo r visibility improvement simila r with lower associated cost than the OFA/RSCR. To gauge the overall visibility improvem ent from each control option the maximum and average visibility imp act 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 visi bility improvement may be achieved with several control options other than OFA/RS CR. These options also have the potential to reduce cost and may minimize energy and plant imp acts. 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 BA RT. However it does presume that this level of cont rol allows various options in addition to OFA/RSCR in meeting

BART.

Table 4.2 Boiler B27 Control Cost a nd 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 Contro l Options – Visibility Impr ovement 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 / DVVisibility Improvement (dv)



### • Boiler B26 NOx Control

As previously discussed, the De partment deems the RSCR as not representing BART control for boiler B26. However, to evaluate this issue further, a full list of contro ls including RSCR is carried forward in evaluating cost-effectiv eness of technologi es for Boiler B26.

### 25 In absence of applying RSCR control, the next ti er of top-down NOx control identified for boiler B26 is a combination of flue gas recirculat ion (FGR) and over-fir e air (OFA) combustion modifications followed by selective non-catalytic reduction (SNCR). In th e draft BART analysis the combination of FGR and OFA was initially rated to achieve a mini mum 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 boilers 17 

### . To determine if this fu ll control potential can be achie ved will require additional engineering and computer fluidized dynamic (C FD) modeling of the co mbustion process. Without this level of analysis, the Department is applying 35% compliance control effi ciency for OFA/FGR as applied to boiler B26.

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

emissions 18 

### . Similar to OFA/FGR design, to determ ine the SNCR maximum achievable control efficiency for boiler B26 requires engineering and CFD modeling analys is. In this case the depth of the control is dependent on boiler dynamics, reagent mixing conditions, residence time, temperature regime and ammonia injection ra tes which do not cause ammonium bisulfate buildup or acid conditions. Th erefore, without CFD modeli ng, a SNCR compliance control efficiency of 50% is applied to boiler B26. The 50% c ontrol 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 effi ciency to the uncontrolled emi ssion rate, 0.68 lbs/mmbtu, yields

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

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

The control technologies evaluate d for boiler B26 are listed in Table 4.4 with estimated costeffectiveness and visibility impr ovement results. Th e costing worksheet fo r each technology is provided in Appendix B. The co sting of the RSCR control option is revised here using the same

methods discussed for boiler B 27. The costs of the OFA, FG R, and SNCR technologies are developed using costs and ope rating factors quoted by Combus tion 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 utilit y consumption rates are scaled accordingly. The application of de fault cost factors used in the dr aft 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 estimate d using a factor of 0.005 deciview per grams/sec reduced (Table 5.2)

Table 4.4 Boiler B26 Control Cost a nd 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 c ontrol options are cost-e ffective with a maximum visibility improvement demons trated by the OFA/FGR/RSCR system at 3,675 $/ton and 15.6 M$/DV. These results also show that the majority of visibil ity improvement is captured by the OFA/FGR/SNCR system at 68% contro l. 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 approa ch. Figure 4.2 shows that the difference in visibility improvement between th ese two options is a li ttle more than 0.01

deciview. This difference is approximately 10 – 15% of additio nal 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 tec hnology option. These factors point to the RSCR based controls as beyo nd the knee in th e curve for achiev ing visibility improvement in a cost-effective manner under BART.

Conclusion A number of factors, including co st-effectiveness and visibility improvement, demonstrate that

OFA/FGR/SNCR at 68% control effi ciency 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 CO 2 

### as compared to the SNCR based sy stem. 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 SO 2 

### controls that may be

dedicated for RSCR feas ibility to boiler B27.

Figure 4.2 Boiler B26 Control Options – Visi bility 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 / DVVisibility Improvement (DV)



### Figure 4.3 Boiler B26 Control Options – Visibili ty 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 B 26 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, Sene y 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, Sene y 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, Sene y 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 requir ements. The modeled emissi on cases are based on the maximum actual emissions during the baseline years for the co mbined 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 em ission limitation (Table 6.2) compared to the annual actual average emissi ons during the baseline years. The applied surrogate Stack S10 percent reduction is 70% for NOx and 57% for SO 2 

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

In looking at the visibi lity improvement from BART one measure is the c ount 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 threshol ds are shown in Table 5. 1. These results show that Seney realizes the largest reduction of days for each case with th e 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 afte r 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 N umber of days with delta-deciview => 0.5



### Another metric in comparing vi sibility impact is the maximu m daily impact modeled in each year shown. These resu lts are summarized in Table 5.2. Th e "maximum" is th e highest value modeled in any of the three ba seline years 2002 to 2004. The "ave rage" is the average of the

maximum value modeled in each ba se year – therefore an average of the maximum impact for 2002, 2003, and 2004. These modeling results show fo r Seney that BART reduces the highest maximum impact seen over the th ree base years by 2.68 deciview. The average imp act improves by 2.02 deciview.

A total maximum and average value is also presen ted for all four northern Class I areas. This total value represents the sum of the maximu m modeled for each indivi dual class I area. Although the maximum impact is not ex pected 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 impr ovement under BART related to the individual pollutants, s hown in the Table 5.2 for SO 2 

### and NOx. This information is used to calculate a visibility im provement factor in deciview impr ovement per gram/sec of pollutant

reduced. These factors ar e then used in the visi bility assessments of the individual control technologies when performing th e BART evaluations (Sections II.2 and II.4). The "average"

value is used for these tec hnology evaluations as it repres ents a reasonably expected improvement rather than the maximum seen over all three baseline year s. 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 SO 2 

### . To note though, also s hown 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 po llutant visibility improvement

factors under-estimates the total vi sibility improvement fo r the pollutant in c ontext of the entire BART requirement.

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

Maximum Average Maximum Average

5.38 4.14 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 an d each pollutant SO 2 

### and NOx in two forms: 1) emission ra te limitations (lbs/mmbtu) and, 2) allowable mass emissions (tons). The permit allows BART requirements to be satis fied by demonstrating co mpliance with either

emission limitation format.

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

uncontrolled base emission rates. For SO 2 

### , the base uncontrolled em ission rates reflect the adjusted base year emissions shown in Table 4.1. This base informa tion and resulting BART emission rate limits, on a 30 day rolling basis, for boilers B26 a nd B27 are presented in Table

6.1.

Georgia Pacific can also comply with the mass cap limits for ea ch boiler also shown in Table 6.1. The 12 month mass cap is th e result of applying the BART emission rate limit to the average of the annual heat input for each boile r during the baseline years 2002 to 2004. This limit is viewed as being consiste nt with achieving a long-term av erage BART level of control. The 30 day limit is set by applyi ng the emission rate limit to the maximum day heat rate for each boiler, B26 and B27, and then mu ltiplying by 30 days. The 30 da y rolling mass cap is set in

tandem with the 12 month ma ss cap to ensure that vi sibility 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 P acific to demonstrate co mpliance with Stack S10

emission limitations in lieu of th e individual boiler requ irements. Similar to the individual boiler limits, Stack S10 compliance can be demonstrated by meeting either an em ission rate limitation or a mass cap limitation. Th e Stack S10 emission limitati ons are shown in Table 6.2.

The mass requirement for Stack S1 0 incorporates the mass cap limit s for boilers B26 and B27 as presented in Table 6.1. Uncontrolled emissions are then added for th e non-BART boiler B24, B25, and B28 based on uncontroll ed base year emissions for 2002 to 2004. As for the BART boilers, the non-BART boiler uncontrolled SO 2 

### emissions reflect the adjusted base year

emissions shown in Table 3.1. Th e NOx emissions for the non-BA RT boilers reflect the actual average reported emissions duri ng the baseline years. The annual mass emissions are then

totaled across the BART and non -BART boilers to determine th e 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 mul tiplying 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 m onth rolling average emission rate applies to Stack S 10. Once again, the 30 day limit is required to en sure a minimum visibility improvement on a continuous basis. In this cas e, where additional capacity can be utilized beyond that demonstrated and modele d for the maximum day emissions a different approach is used to determine stack emissi on rate limits. The mass cap requirements are consistent with annual average (12 month) a nd maximum day (30 day) heat inputs during the baseline years. If the associated average emissi on rates or BART emissi on rates are allowed and the boilers are used at high cap acity rates then total emissions will exceed the BART mass caps. To ensure the mass caps are not exceeded, resulting in higher vi sibility impact, a surrogate maximum heat input representing 95% of Stack S 10 boiler capacity is ut ilized to calculate emission rate limits. Therefore, mass cap requ irements in Table 6.2 ar e divided by this boiler system maximum heat input for 30 days and 12 months to calculate the associated emission rate

limitations also s hown in Table 6.2.

### 33 Table 6.2 Alternative BART Comp liance 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 Emission Rate Requirement Mass Cap Requirement

Pollutant



### 7. SO 2 

### and NOx Default Trading Program

Under the state BART rule, s NR 433.06, Wis. Adm. Code, sour ces may trade emissions in complying with BART requirements. In using a trading approach, a facility is not allowed to

trade with other facilities and mu st account for other sources at the facili ty serving the same function - thus avoiding load shifti ng. The rule also requires that any trading program fulfill two criteria: first, an addi tional 10% reduction beyond the BART requirement for the pollutant being offset with emissions trading. Second, any trading of emissi ons must result in visibility improvement equivalent to BA RT 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 progr am anticipates trading SO 2 

### 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 applie d to both the NOx 30 day and 12 month mass cap requir ements to yielding the re quired BART-Trade mass cap requirements, Table 7.1. Unde r the Trading program the SO 2 

### mass cap requirement is restated and acts as the minimum requirement for SO 2 

### at any time during the trad ing program. Therefore, this program allows for one-way trading – SO 2 

### for NOx. To meet the second criteria under trading for meeting equivalent vi sibility improvement the trading program requires that two tons

of SO 2 

### must be used to offset every ton of requi red 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 Visibi lity Equivalency

To determine visibility equivalency, the Depa rtment performed CALP UFF modeling reflecting BART Trading mass cap requirements. The Depa rtment then performed CALPUFF modeling of varying NOx and SO 2 

### control levels at diff erent trading ratios of SO 2 

### 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 contro l efficiencies

are determined for Stack S10 emissions in the same mann er as for the BA RT visibility evaluation, Section II.5. The SO 2 control levels are the result of offsetti ng the remaining NOx reduction requirements under the sp ecified trading ratios. The e missions trading cases modeled by the Department are listed in Table 7.2.

Table 7.2 CALPUFF Modeling Cases fo r 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 visi bility 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 fede ral areas nearest to th e source and for each calendar year 2002, 2003 and 2004. "

### 35 The Department performed modeli ng for all Class I areas, but the evalua tion of equivalency and trading ratios results presented here focuses to Se ney as this area receive s the greatest visibility impact. In the analysis the De partment is also sensitive to seasonal differences which cause variation in impact related to each pollutant. Sp ecifically, in this case , NOx emissions exhibit stronger visibility impairment during colder months than during the summer. Conversely, the impact related to SO 2 

### emissions strengthens du ring warmer periods and as the availability of

ammonia increases. Because of such effects the visibility equi valency 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 Tabl e 7.3, a trading ratio of 1 ton SO 2 

### 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 maximu m day impact (bolded values) fo r the Seney Class I area, Table

7.4. Based on increases in both of these visibi lity metrics the Departme nt concludes that a trading ratio of 1:1 is insu fficient for achieving equivale nt 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 Imp act for Each Base Year

2002 2003 2004

1 (Bart-Trade) 2.56 1.33 2.14

2 2.80 1.32 2.15 1 to 1

3 2.06 0.87 1.45 1 to 3

4 2.35 1.12 1.83 1 to 3

5 2.45 1.11 1.83 1 to 2

6 2.51 1.21 1.98 1 to 2

7 2.94 1.32 2.19 1 to 1

8 2.38 0.98 1.64 1 to 2 Trading Ratio

(SO2:NOx) Maximum Deciview Case



### Moving to the 2:1 trading ratio ca ses 5, 6, and 8 there is no increase in either the number of days or maximum daily impact when co mpared to the BART-Trading case 1. To screen more closely for potential visibility equivalency the mode led daily maximum impact across 2002 to 2004 is plotted for these cases, Figures 7.1, 7.2, and 7.3. This comparison show s that the residual visibility impacts compare well between the BART-Trading and 2:1 tr ading ratio cases.

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

0 0.5

1 1.5

2 2.5

3

0 200 400 600 800 1000 1200Deciview 

### BART-Trade

Case 5

### 38 Figure 7.2 Daily Maximum Modeled Impact , 2002 – 2004: BART-Tra de vs. Case 6.



## 0 0.5 1 1.5

2 2.5 3

0 200 400 600 800 1000 1200Deciview 

### BART-Trade

Case 6



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



## 0 0.5 1 1.5

2 2.5 3

0 200 400 600 800 1000 1200Deciview 

### BART-Trade

Case 8

### 39 Based on these positive resu lts for the 2:1 trading ratio cases, the Department looked at the 20% best and worst days as required under the Wisc onsin BART rule for de termining visibility equivalency. To define the best and worst da ys the Department segmen ted the modeling results for days in which a 0.01 decivi ew visibility impact is pred icted. 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 a nd 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 Cl ass I areas increased under case 8 compared to the BART-Trading case by a maximum 0.02 d eciview. The other

cases show an increase in th e maximum daily impact of 0.01 deciview over BART-Trading. These differential visibility imp acts are derived by l ooking 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 ov erall change to visibility, th e average of the daily maximum impact slightly decrea ses. The BART-Trade average value is 0.02 deci view whereas cases 5, 6, and 8 show an average of 0.018 to 0.019. A simple total of the daily imp acts show a decrease of 0.1 deciview or more in total. Although these f actors are general in natu re they indicate that overall the visibility impact has decreased under the 2:1 tradi ng ratio cases.

Still an increase in maximum da ily 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 visi bility seen under the trading cases versus the visibili ty impact for the BART-Trading case for each day. The results for case 8 are presented because this case demonstrat ed the largest increas e in maximum daily impact versus BART-Tradi ng and should show the days with hi ghest overall impa cts. The plot, Figure 7.4, shows that ther e are clearly days where visibility impact increases and days where it decreases under emissions trading. For the da ys 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 approx imately 0.05 deciview. Wh en looking at all the remaining values of the plot th e total impacts appear to all be less than the 0.05 deciview.

With values of maximum daily impact remainin g at or below the 0.05 deciview level, based on previous regional haze analysis, the Department co ncludes that the increase d impacts to visibility do not create a perceptible change in visibility for the 20% "Best" da ys 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 im proved visibility on days with lower visibility impacts. On this basis, the Department conclu des 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 visi bility equivalency is evaluate d for the 20% "Worst Days". As shown in Table 7.6, the trading cases all show an improvement in the overa ll visibility impact when compared to the BART-Trade emission leve ls. However, values for the maximum daily impact ranging from 2.38 to 2.45 d eciview clearly demonstrate th at days still occur with significant visibility impact. Th erefore the potential for adding vi sibility 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 illust rate that the magnitude of decr eases 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. Bu t, the most significant fi nding is that when the ba se 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 SO 2 

### are traded for a ton of NOx reduction.

### 41 Below the 1.0 threshold each case shows days of increased and decreased visi bility impact.

However in all three cases the ma gnitude 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 visi bility 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 CaseDeciview 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 CaseDeciview 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 CaseDeciview Increase vs BART



### To understand what these increases and decreases mean to visibility equi valency the distribution of days of impact and total decivi ew impact is counted at differ ent visibility thresholds. The

results shown in Table 7.7 confirm that the num ber of days in the hi ghest impact range is

reduced under the trad ing cases. For this same visibility ra nge the total deciview impact (sum of impact for days > 1.0 deci view) is significantly reduced. On the whole for the trading cases both the number of days and total im pact are reduced. It is on ly when going to the 0.25 to 0.5 deciview range is there an incr ease 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 imp act 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 du ring the 20% worst days.

Table 7.7 Number of Days with Mo deled Visibility Im pact (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 (decivi ew) 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 o ccur simultaneously the last vi sibility 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 betwee n the BART-Trade and trading cas es 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 incr ease 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 deci view during the 30 day period.

The Department concludes that the increase to visibility impact is mi nimal compared to the improvement to visibility seen under the trading cases. Although individual days may experience additional visibi lity impact these are relatively sma ll changes in visibility. Further, the trading cases show that larg er decreases in visibility impa ct are close in chronology to the days of increased impact . Therefore, the tradi ng cases are as likely to decrease as increase visibility impact during any shor t-term period. For these reasons, the Department concludes that a trading ratio of two SO 2 

### to one NOx results in equiva lent 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 Imp act 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 manufacturi ng facility in conformity w ith 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 EXPI RATION DATE [s. NR 407.09(1)(b)1, Wis. Adm. Code].

No permittee may continue operation of a source af ter the operation permit expires, unless the permittee submits a timely and complete app lication 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 perm it 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 Re trofit 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 a bbreviated form of the standard preliminary determination (PD) document that is typically u sed for operating permit renewals. The draft support documents contain a justification for the proposed em ission 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 lega l 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 (issu ed on January 26, 1990 for Pro cesses P11 and P12), Permit No. 89-MWH-143 (issued on May 18, 1990 for Processes P13, P14 and P15), an d 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 Pe rmit 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 th e United States of America on behalf of USEPA on May 28, 1996 concerning the operation of Boiler 8 (iden tified 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 fe ed to the boiler has been restricted by welding stops into the Stephenson Li nk 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 valu e previously fired or expected to be fired in the

future.

One condition from the consent decree was modified th rough 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. Th e applicable requirements from the consent decree and the stipulated order are in corporated 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 pape r 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-1 43 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 T itle 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 th is 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. Th e Title V operation permit incorporates a two tiered nitrogen oxide limit. The nitrogen oxide limit is be ing increased to 0.60 pounds per million BTU during start-up (steam loads less than 200,000 pounds pe r hour), but will remain at 0.49 pounds per million BTU during steady state operations (steam loads great er 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 Emissi on Standards for Hazardous Air Pollutants (NESHAPs)

outlined in the Maximum Achievable Control Tec hnology (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 ope rations at pulp and paper mills do not apply to the facility. However, the two chlori ne dioxide bleaching processes (P12 and P13) are subject to the MACT standards for bleaching processes. The MACT sta ndard 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 standa rd applies to the facility by April 15, 1999 and to demonstrate compliance with the applicable requi rements in the MACT standard for pulping and bleaching processes no later than April 15, 2001. The th ird 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 standa rd 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 repr esents the flexographic and rotogravure printing presses at the facility. These pres ses 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 underf eed stoker boiler - Installed in 1933. Boiler B24 - 200 mmBTU per hour underf eed stoker boiler - Installed in 1947. Boiler B25 - 200 mmBTU per hour underf eed stoker boiler - Installed in 1950. Boiler B26 - 350 mmBTU per hour spreader stoker boiler - Installed in 1962. Boiler B27 - 615 mmBTU per hour cycl one 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 pa per 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 ex cept for P12 and P13 - Installed in 1962.

Stack S16, Process P16 - Flexographic and rotary prin ting presses - First unit installed in 1954. Stack S17, Process P17 - Letterpress printing op erations - First unit installed in 1924. Stack S18, Process P18 - Offset printing p resses - 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 perm it is considered to be complia nce with all emission limitations established under ss. 285.01 to 285.87, Wis. Stats., a nd emission limitations unde r the federal clean air act, that are applicable to the source if the permit in cludes the applicable limitation or if the Department

determines that the emission limitati ons do not apply. The following em ission limitations were reviewed in the analysis and preliminary dete rmination and were determined not to apply to this stationary source:

- The New Source Performance Standard (NSPS) for steam ge nerating units in s. NR 440.205, Wis. Adm. Code does not apply to Boilers B23 through B27 because these boilers were in stalled before the applicab ility date for this NSPS. - The New Source Performance Standard (NSPS) for steam ge nerating 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 2 35 mmBTU per hour in 1996 to comply w ith 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 appl y to the source because the permittee is subj ect to the Reasonably Available Control Technology (RACT) sulfur limitations in ch. NR 418,

Wis. Adm. Code. - The biennial compliance emission testi ng requirement for sulfur dioxide does not apply to the s ource 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 an d analysis requirements in s. NR 439.085, Wis. Adm. Code do not apply to the source

because the source is affect ed by the RACT sulfur limitations in s. NR 418.05, Wis. Adm. Code. - The Reasonably Available Control Tec hnology (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 Technol ogy (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 de finitions for "paper coating" and "web" in s. NR 422.02, Wis. Adm. Code. - The requirements for control of organi c 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 organi c 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 Tec hnology (MACT) standard for pulping an d 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 blea ching at paper mills that use secondary fiber.



### Part I -- The headings for the areas in the permit ar e 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 Availabl e 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 me thods 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 co mpliance demonstration area contains limits on parameters or other mechanisms that will be m onitored periodically to ensure compliance with the limitations. The requirement to test as well as in itial and periodic test schedules, if testing is required, will be stated here. Not withstandi ng 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, Recordkeep ing, 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 refe rence test method will be listed even if no testing is immediately required. Also included in this area are any recordkeepi ng 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), Wi s. Adm. Code, as specified in Part II of this permit.

Condition Type -- This area specifies other conditions that are applicable to th e entire facility that may not be tied to one specific pollutant.

Conditions -- This area lists specific conditions usually applicable to the entir e facility or compliance requirements.

Compliance Demonstration -- This area contains monitoring a nd testing requirements and methods to demonstrate compliance with the conditions.

PART II -- This section contains the general limita tions that the permittee must abide by. These requirements are standard for most sources of air po llutants so they are included in this section with every permit.55PART ISPECIFIC PERMIT CONDITIONSA. Stack S10; Control C10; Boilers B23, B24, B25 and B26- These boilers are multiple retort underfeed stoker boilers (B23, B24 and B25) orspreader stoker boilers(B26) that burn coal as a primary fuel, but also burn petroleum coke and mill-derived fuel pellets as alternate fuels. BoilerB23 has a heat input capacity of 140 millionBTU per hour and was installed in 1933. Boilers B24 and B25 have heat input capacities of 200 million BTU per hour and were installed in 1947 and 1950 respectively.Boiler B26 has a heat input capacity of 350 million BTU per hour and was installed in 1962.19Note: The limitations in this table apply to eachboiler individually unless otherwise indicated.These boilers have the capacity to fire petroleum coke and mill-derived fuel pelletsas alternate fuels. Please see the additional requirements thatrelate to these alternate operating scenarios for the boilersin Tables E and F of this permit.Note: Therequirements 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 METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(1) ParticulateMatter EmissionsContinued onNext Page ...1) Emissions may not exceed 0.30pounds of particulate matter from anystack per million BTU of heat input.[s. NR 415.06(1)(b), Wis. Adm. Code]1) The permittee shall perform compliance emissiontesting of particulate matter emissions from Stack S10to demonstrate compliance with the particulate matteremission limit in A(1)(a)1):a) Testing shall be conducted every 24 months aslong as the permit remains valid;b) Each biennial test of particulate matter emissionsshall be performed within 90 days of theanniversary date of the issuance of this permit orwithin 90 days of an alternate date specified bythe Department in writing;Continued on Next Page ...1) Reference Test Method for Particulate Matter Emissions:Whenever particulate matter emission testing is required bythe Department, the permittee shall use U.S. EPA Method 5,including backhalf. [s. NR 439.06(1), Wis. Adm. Code]2) The permittee shall retain copies of the results of thecompliance emission tests specified in condition A(1)(b)1).[s. NR 439.04(1)(a), Wis. Adm. Code]3) The permittee shall keep records of the type and amountof fuel burned in this boiler on a monthly basis. [s. NR439.04(1)(d), Wis. Adm. Code](1) ParticulateMatter Emissions2) The permittee shall only fire:a) Coal as a primary fuel in thisboiler;c) The permittee may request and the Departmentmay approve a waiver from the required biennialtesting provided the results of the most recently4) The permittee shall record the pressure drop across thebaghouse once every eight (8) hours of operation or once perday, whichever yields the greater number of measurements.19The Department recognizes that the emissions from Boilers B23, B24, B25, B26, B27 and B28 discharge through a common stack (S10) and thatit would be difficult to determine the emission rate from a specific boiler unless that boiler were the only one of the six boilers operating. The Departmentalso recognizes that all 6 boilers may not be operating at thetime of the required compliance emissions tests. If the emissions from Stack S10 meet the moststringent limitations and requirements provided in Tables A, B and C of this Part I, then the emissions from each boiler discharging to this common stack willbe deemed to be meeting such limitations and requirements.56POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(continued)b) Petroleum coke and mill-derivedfuel pellets as alternate fuels inthis boiler.See Table E for additionalrequirements that apply while firingpetroleum coke in this boiler. See TableF for additionalrequirements that apply while firingmill-derived fuel pellets in this boiler.[ss. 285.65(3) and 285.63(1)(a), Wis.Stats.]3) The permittee shall operate thebaghouse (C10) to control particulatematter emissions whenever the boileris in operation. [s. NR 415.03, Wis.Adm. Code](a) The permittee shall meet BARTrequirements for particulate matteremissions no later than December 31,2011.(b) The permittee shall meet particulatematter emission requirements forBART by meeting the followingconditions:(i) Conditions A.1.a.(1), A.1.a.(2) andA.1.a.(3);(ii) Conditions for visible emissions inA.2.a.(1) and A.2.a.(2);(iii) The facility malfunction preventionand abatement plan.[ss. NR 433.05, NR 439.11, Wis.Adm. Code]completed biennialtest demonstrate thatparticulatematter emissions are 50 percent or less of theapplicable limitation in condition A(1)(a)1);d) The testing shall be conducted in accordancewith the conditions in DD(4)(a)1).[ss. NR 439.07, 439.075(2)(a), 439.075(3)(b), and439.075(4)(a)1.b., Wis. Adm. Code]2) The permittee shall maintain the pressure dropacross the baghouse between 3.0 and 12.0 inchesof water column. [ss. NR 407.09(4)(a)1., and439.055(1)(a), Wis. Adm. Code]3) The permittee shall take appropriate investigativeand corrective action in accordance with theprocedures in the Malfunction Prevention andAbatement Plan required for this control devicewhenever the pressure drop is outside of theoperating ranges specified in condition A(1)(b)2). [s.NR 407.09(4)(a)1., Wis. Adm. Code]4) The permittee shall perform periodic internalinspections of the baghouse(C10) to ensure that thecontrol equipment is operating properly. The timeinterval 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 forperiodic internal inspections of the boiler. This planshall include the frequency of these inspections andthe items to be inspected. [s. NR 407.09(4)(a)1.,Wis. Adm. Code][s. NR 439.055(2)(b), Wis. Adm. Code]5) The permittee shall keep records of:a) the date, time, and initials of the person performingthe inspections required by condition A(1)(b)4);b) a list of the items inspected; andc) any maintenance or repairs performed as a result ofthese inspections.[s. NR 439.04(1)(d), Wis. Adm. Code]6) The permittee shall keep records of:a) the date, time, and initials of the person performingthe inspections required by condition A(1)(b)5);b) a list of the items inspected; andc) any maintenance or repairs performed as a result ofthese inspections.[s. NR 439.04(1)(d), Wis. Adm. Code](2) VisibleEmissions1) Opacity may not exceed 20% ornumber 1 on the Ringlemann chart.1) The permittee shall calibrate, maintain and operatethe continuous emissions monitoring system required1) Reference Test Method for Visible Emissions: Whenevervisible emission testing is required by the Department, the57POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS[s. NR 431.04(2), Wis. Adm. Code]2) The permittee shall calibrate,maintain and operate a continuousmonitoring systemthat meets theperformance specifications of conditionA(2)(b)1) for the measurement ofopacity. [ss. NR 439.095(1)(a), and439.095(5)(a)1.,Wis. Adm. Code]by condition A(2)(a)2) in accordance with theperformance specifications in PerformanceSpecification 1 in 40 CFR part 60, Appendix B.[s. NR 439.09(1), Wis. Adm. Code]2) The permittee shall follow a quality control andquality assurance plan as approved by the Departmentfor the continuous monitoring system required bycondition A(2)(a)2). [ss. NR 439.09(8), and439.095(6), Wis. Adm. Code]permittee shall use U.S. EPA Method 9.[s. NR 439.06(9)(a)1., Wis. Adm. Code]2) The continuous monitoring system required by conditionA(2)(a)2) shall complete one cycle of sampling and analyzingfor each successive 10-second period and one cycle of datarecording for each successive 6-minute period. [s. NR439.09(9)(a), Wis. Adm. Code]3) Unless otherwise specified by the Department, periods ofexcess visible emissions shall be any 6-minute period duringwhich the average opacity exceeds the limitation in conditionA(2)(a)1). [s. NR 439.09(10)(b)1., Wis. Adm. Code]4) The permittee shall submit quarterly excess emissionreports to the Department within 30 days following the end ofeach calendar quarter. [s. NR439.09(10), Wis.Adm. Code]5) The excess emission reports required by condition A(2)(c)4)shall contain the information identified by conditionDD(3)(a)1)b). [s. NR 439.09(10)(a), Wis. Adm. Code](3) SulfurDioxideContinued onNext Page ...1) Emissions may not exceed 4.45pounds of sulfur dioxide per millionBTU of heat input when Boiler B29is operating.20[ss. 285.65(3) and285.63(1)(a), Wis. Stats. & s. NR404.04(2)(a)2., Wis. Adm. Code]1) Reference Test Method for Sulfur Dioxide Emissions:Whenever sulfur dioxide emission testing is required by theDepartment, the permittee shall use U.S. EPA Method 6, 6A,6B, 6C or 8. [s. NR 439.06(2)(a), Wis. Adm. Code](3) SulfurDioxide2) Emissions may not exceed 4.55pounds of sulfur dioxide per million1) The permittee shall calibrate, maintain and operatethe continuous emissions monitoring system required2) The continuous monitoring system required by conditionA(3)(a)3) shall perform sampling, analyzing, and data20The 4.45 pounds of sulfur dioxide per million BTU of heat input emission limitation comes from Permit No. 88-AJH-031B and ismore restrictivethan the emission limitation from s. NR 418.05(1)(c)1., Wis. Adm. Code (4.55 pounds per million BTU) which appears in conditionA(3)(a)2). The morerestrictive limit is necessary to protect the National Ambient Air Quality Standard for sulfur dioxide when Boiler B29 is operating.58POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(continued)BTU of heat input when Boiler B29 isnot operating. [s. NR 418.05(1)(c)1.,Wis. Adm. Code]3) The permittee shall calibrate,maintain and operate a continuousmonitoring systemthat meets theperformance specifications of conditionA(3)(b)(1) for the measurement ofsulfur 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 BARTrequirements for sulfur dioxideemissions no later than December 31,2015.(b) The permittee shall meet sulfurdioxide emission requirements forBART by meeting one of the followinglimitations:(i) a sulfur dioxide emission ratelimitation of 0.27 pounds per millionBTU of heat input to boiler B26 on thebasis of a 30-day rolling average; or(ii) total emissions of sulfur dioxide notto exceed 254 tons in any 12-monthperiod and 33 tons in any 30-day periodon boiler B26; or(iii) a sulfur dioxide emission ratelimitation of 1.01 pounds per millionby condition A(3)(a)3) in accordance with theperformance specifications in PerformanceSpecification 2 in 40 CFR part 60, Appendix B.[s. NR 439.09(2), Wis. Adm. Code]2) The permittee shall follow a quality control andquality assurance plan as approved by the Departmentfor the continuous monitoring system required bycondition A(3)(a)3). [s. NR 439.09(8), Wis. Adm.Code](3) In determining compliance with emissionlimitations of condition A(3)(a)(4) the permittee shalldetermine sulfur dioxide emissions using emissiondata measured according toconditions A(3)(b)(1) andA(3)(b)(2) and according to the following:(a) For condition A(3)(a)(4)(b)(i):(i) In calculating the 30-dayrolling average emissionrate, in pounds per million BTU, the permittee shallnot exclude emissions for any period of time forwhich flue gas is exiting boiler B26.(ii) The 30-day rolling average emission rate inpounds per million BTU shall be calculated as theaverage of the hourly emissions, in pounds permillion BTU, obtained from the continuous emissionsmonitoring system over the hours boiler B26 operatedduring the averaging period. The 30−day rollingperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day rolling average emission rate shall becalculated 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting boiler B26.recording as follows:a) Complete one cycle of sampling, analyzing, and datarecording for eachsuccessive 15-minute period.b) The values recorded shall be averaged hourly.c) Hourly averages shall be computed from 4 data pointsequally spaced over each 1-hour period, except duringperiods when calibrations, quality assurance ormaintenance activities are being performed. Duringthese periods, a valid hour shall consist of at least 2data points separated by a minimum of 15 minutes.[s. NR 439.09(9)(b), Wis. Adm. Code]3) Excess emissions for sulfur dioxide are any 24-hour rollingaverage during which the average sulfur dioxide emissionsexceed the emission limitations inconditions A(3)(a)1) and 2).[s. NR 439.09(10)(b)2., Wis. Adm. Code]4) For purposes of reporting exceedances on the basis of a 24-hour rolling average, any hourly average may be included inonly one 24-hour period. An exceedance shall be based on atleast 18 and not more than 24 valid recordings of hourlyaverage emission rates in any 24-hour period. [s. NR439.09(10)(c), Wis. Adm. Code]5) The permittee shall submit quarterly excess emissionreports to the Department within 30 days following the end ofeach calendar quarter. [s. NR439.09(10), Wis.Adm. Code]6) The excess emission reports required by condition A(3)(c)5)shall contain the information identified by conditionDD(3)(a)1)b). [s. NR 439.09(10)(a), Wis. Adm. Code](7) The procedures and methods required for compliancedemonstration and for performance testing required byconditions A(3)(b)(3) and A(3)(b)(4) shall be according to theapplicable requirements of ch. NR 439. [ss. NR 433.06(1),NR 439 and NR 440, Wis. Adm. Code]59POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)BTU of heat input to stack S10 on thebasis of a 12-month rolling average and1.53 pounds per million BTU of heatinput to stack S10 on the basis of a 30-day rolling average; or(iv) total emissions of sulfur dioxidenot 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 tradingprogram provided under conditionA(3a)(b)(5), the permittee shall meetthe following emission limitations:(1) the sulfur dioxide emissionlimitations in conditionA(3)(a)(4)(b)(iv), and(2) the sulfur dioxide emissionlimitations specified in conditionA(3a)(a)(1)(b)(v)(2).[s. NR 433.05, Wis. Adm. Code]Note:The sulfur dioxide BART emissionlimitation on boiler B26 is based oneliminating the firing of coke fuels,combined with continuous operation ofa circulating fluidized bed sulfurdioxide scrubber system achieving aminimum 93% sulfur dioxide removal.This technology is noted to establish abasis for determining alternativeemission requirements if constraintsare encountered in implementing these(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that boiler B26 operated during the complianceperiod. The 12-month period shall consist of themonth of monitoring and the previous 11 consecutivecalendar months. A new 12-month total emissionsshall be calculated and recorded at the end of eachmonth. The 30−day period shall consist of the dayof monitoring and the previous 29 consecutivecalendar days. A new 30−day total emissions shallbe 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 and30-day rolling average emission rates, in pounds permillion BTU, the permittee shall not excludeemissions for any period of time for which flue gas isexiting Stack S10.(ii) The 12-month rolling average and 30-day rollingaverage emission rates, in pounds per million BTU,shall be calculated as the average of the hourlyemissions, in pounds per million BTU, obtained fromthe continuous emissions monitoring system over thehours that any of the boilers B25, B26, B27 or B28operated during the averaging period. The 12-monthrolling period shall consist of the month ofmonitoring and the previous 11 consecutive calendarmonths. A new 12-month rolling average emissionlimit shall be calculated and recorded at the end ofeach month. The 30−day rolling period shall consistof the day of monitoring and the previous 29consecutive calendar days. A new 30−day rollingaverage emission rate shall be calculated andrecorded at the end of each day.(d) For condition A(3)(a)(4)(b)(iv):(8) In meeting the procedures and methods required forcompliance demonstration and for performance testingrequired by conditions A(3)(b)(3) and A(3)(b)(4), thepermittee shall determine the heat input, in million BTU,based on records of the amount of fuel burnt, in tons, and theheat content of the fuel, in million BTU per ton of fuel.[ss. NR 433.05 and NR 433.06, Wis. Adm. Code](9) In meeting the compliance demonstration required byconditions A(3)(b)(3)(b), A(3)(b)(3)(d) and A(3)(b)(3)(e), thepermittee shall perform the following calculations:(a) Tons of emissions shall be calculated daily for use incalculating emissions overeach 30-day period.(b) Monthly emissions shall be calculated by adding all dailyemissions in that month. These monthly emissions shall beused to calculate emissions over each 12-month period.[ss. NR 433.05 and NR 433.06, Wis. Adm. Code]60POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)specific technologies which warrant arevision of the individual boilerdetermined control level as allowed forunder s. NR 433.05(5).(i) In calculating the total emissions, in tons per 12-month period and tons per 30-day period, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the compliance period. The 12-month period shall consist of the month of monitoringand the previous 11 consecutive calendar months. Anew 12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−daycompliance period shall consist of the day ofmonitoring and the previous 29 consecutive calendardays. A new 30−day total emissions shall becalculated 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the averaging period. The 12-monthperiod shall consist of the month of monitoring andthe previous 11 consecutive calendar months. A new12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−dayperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day total emissions shall be calculated andrecorded at the end of each day.61POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)(4) In demonstrating compliance with emissionlimitations of condition A(3)(a)(4) the permittee maypropose an emissions trading program if the programachieves an improvement in visibility in themandatory class I federal areas greater than would beachieved through the installation and operation ofBART on each boiler subject to BART. Thepermittee proposing to use an emissions tradingprogram shall submit an emissions trading plan to thedepartment. The plan shall be subject to departmentand administrator approval and meet the followingcriteria:(a) The plan shall contain the proposed controlstrategy and the method of demonstratingcompliance;(b) The plan shall achieve either of the following:(i) For each visibility impairing pollutant for whichcompliance is demonstrated through use of a tradingplan, an emission reduction at least 10% greater thanwould be achieved through the installation andoperation of BART on each boiler subject to BART;(ii) An improvement in visibility in the mandatoryclass I federal areas greater than or equal to thevisibility improvement achieved under conditionA(3)(b)(4)(b)(i). The improvement in visibility shallbe demonstrated by comparing the 20% best days ofvisibility and the 20% worst days of visibility in atleast the 4 mandatory class I federal areas nearest tothe source and for each calendar year 2002, 2003 and2004. The daily visibility shall be determined usingan air quality model approved by the EPA forpredicting visibility impacts from single emissionsources and conducting the air quality modeling62POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)analyses according to the guidelines in 40 CFR part51, Appendix Y, incorporated by reference in s. NR484.04(11m);(c) Trading shall be between all boilers serving asimilar function located on the same property;(d) Boilers participating in the trading shall achievethe required emission reductions on a continuousbasis and shall be subject to continuous emissionmonitoring, which meets the applicable requirementsunder ch. NR 439;(e) The plan shall specify the monitoring devices andprocedures which will be used to provide informationsufficient to assess the performance of the proposedemission control measures and to quantify on anhourly average basis the mass flow of each pollutantin pounds per hour and the emission rate of eachpollutant in pounds per mmBtu heat input for eachboiler participating in the trading. The proceduresand methods required for compliance demonstrationand for performance testingshall be according to theapplicable requirements of ch. NR 439;(f) Excess emission reductions, for the purposes ofmeeting the BART requirements, shall be emissionreductions beyond those required to meet all state andfederal requirements and may not include emissionreductions used in any other banking or tradingprogram. [ss. NR 433.06(1), NR 439, and NR484.04, Wis. Adm. Code](5)If the department approves the emissions tradingplan from condition A(3)(b)(4), the department shallpropose to revise the source’s air quality permit toinclude the requirements of the emissions trading planin lieu of the BART requirements for the boilers63POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)identified in the emissions trading plan. [s. NR433.06(2), Wis. Adm. Code](6)After the department incorporates the emissionstrading plan from condition A(3)(b)(4) into therevised air operation permit, the permittee shallcomply with the requirements of the emissionstrading plan for the boilers identified in the plan. [s.NR 433.06(3), Wis. Adm. Code](7) The permittee shall notify the Department 90 daysprior to selecting a new emission limitation – fromthe emission limitation options under A(3)(a)(4)(b) –to be complied with. [s. NR 433.05, Wis. Adm.Code]3a. NitrogenOxidesrequirements forBoiler B26(1) Best Available Retrofit Technology(BART) applies to boiler B26.(a) The permittee shall meet BARTrequirements for nitrogen oxidesemissions no later than December 31,2015.(b) The permittee shall meet nitrogenoxides emission requirements forBART by meeting one of the followinglimitations:(i) a nitrogen oxides emission ratelimitation of 0.22 pounds per millionBTU of heat input to boiler B26 on thebasis of a 30-day rolling average; or(ii) total nitrogen oxides emissions of207 tons in any 12-month period and 27tons in any 30-day period on boilerB26; or(1) The permittee shall calibrate, maintain andoperate a continuous monitoring system for themeasurement of nitrogenoxides which meets theperformance specificationsof 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 andoperate the continuous emission monitor required bycondition A(3a)(b)(1) in accordance with theperformance 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 bycondition A(3a)(b)(1) shall follow a quality controland quality assurance plan, as approved by theDepartment.[ss. NR 439.09(8) and NR439.095(6), Wis. Adm. Code](4) In determining compliance with emissionlimitations of condition A(3a)(a)(1) the permitteeshall determine nitrogen oxides emissions using(1) The procedures andmethods required forcompliancedemonstration and for performance testing required bycondition A(3a)(b)(4) and A(3a)(b)(5) shall be according to theapplicable requirements of ch. NR 439. [ss. NR 433.06(1),NR 439 and NR 440, Wis. Adm. Code](2) In meeting the procedures and methods required forcompliance demonstration and for performance testingrequired by conditions A(3a)(b)(4) and A(3a)(b)(5), thepermittee shall determine the heat input, in million BTU,based on records of the amount of fuel burnt, in tons, and theheat content of the fuel, in million BTU per ton of fuel.[ss. NR 433.05 and NR 433.06, Wis. Adm. Code](3) In meeting the compliance demonstration required byconditions A(3a)(b)(3)(b), A(3a)(b)(3)(d) and A(3a)(b)(3)(e),the permittee shall perform the following calculations:(a) Tons of emissions shall be calculated daily for use incalculating emissions overeach 30-day period.(b) Monthly emissions shall be calculated by adding all dailyemissions in that month. These monthly emissions shall be64POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) NitrogenOxides(continued)(iii) nitrogen oxides emission ratelimitations of 0.21 pounds per millionBTU of heat input to stack S10 on thebasis of a 12-month rolling average,and 0.28 pounds per million BTU ofheat input to stack S10 on the basis of a30-day rolling average; or(iv) total nitrogen oxides emissions of1,200 tons in any 12-month period and141 tons in any 30-day period on stackS10; or(v) under the emissions tradingprogram provided for under conditionA(3a)(b)(5), the permittee shall meetthe following emission limitations:(1) total nitrogen oxides emissionlimitation of 1,080 tons in any 12-month consecutive period and 127 tonsin any 30-day consecutive period onstack S10;(2) The emission limitation on nitrogenoxides in condition A(3a)(a)(1)(b)(v)(1)shall be met when:(a) total actual sulfur dioxide emissionsdo not exceed [5,800 - (N1*T)] tons forany 12-month consecutive period onstack S10, and(b) total actual sulfur dioxide emissionsdo not exceed [761 - (N2*T)] tonssulfur dioxide for any 30-dayconsecutive periodon stack S10,whereemission data measuredaccording to conditionsA(3a)(b)(1), A(3a)(b)(2), and A(3a)(b)(3) andaccording to the following requirements:(a) For condition A(3a)(a)(1)(b)(i):(i) In calculating the 30-dayrolling average emissionrate, in pounds per million BTU, the permittee shallnot exclude emissions for any period of time forwhich flue gas is exiting boiler B26.(ii) The 30-day rolling average emission rate inpounds per million BTU shall be calculated as theaverage of the hourly emissions, in pounds permillion BTU, obtained from the continuous emissionsmonitoring system over the hours boiler B26 operatedduring the averaging period. The 30−day rollingperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day rolling average emission rate shall becalculated 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting boiler B26.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that boiler B26 operated during the complianceperiod. The 12-month period shall consist of themonth of monitoring and the previous 11 consecutivecalendar months. A new 12-month total emissionsshall be calculated and recorded at the end of eachmonth. The 30−day period shall consist of the dayof monitoring and the previous 29 consecutivecalendar days. A new 30−day total emissions shallbe calculated and recorded at the end of each day.used to calculate emissions over each 12-month period.[ss. NR 433.05 and NR 433.06, Wis. Adm. Code]65POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) NitrogenOxides(continued)N1= the difference between (actualtotal tons nitrogen oxides) and (1,080tons nitrogen oxides) per consecutive12-month period on stack S10,N2= the difference between (actualtotal tons nitrogen oxides) and (127tons nitrogen oxides) per consecutive30-day period,T = 2.0 = the ratio of (sulfur dioxidetons reduced from 5,800 tons) to(nitrogen oxides tons increased from1,080 tons) over any consecutive 12-month period, and the ratio of (sulfurdioxide tons reduced from 761 tons) to(nitrogen oxides tons increased from127 tons) over any consecutive 30-dayperiod.[s. NR 433.05, Wis. Adm. Code]Note:The nitrogen oxides BART emissionlimitation on boiler B26 is based oncontinuous operation of over-fire airand flue gas recirculation controldesigned specifically for NOx controland continuous operation of selectivenon-catalytic reduction. Thistechnology is noted to establish a basisfor determining alternative emissionrequirements if constraints inimplementing these specifictechnologies are encountered asallowed for under s. NR 433.05(5)warrant a revision of the individualboiler determined control level.(c) For condition A(3a)(a)(1)(b)(iii):(i) In calculating the 30-dayrolling average emissionrate, in pounds per million BTU, the permittee shallnot exclude emissions for any period of time forwhich flue gas is exiting Stack S10.(ii) The 30-day rolling average emission rate inpounds per million BTU shall be calculated as theaverage of the hourly emissions, in pounds permillion BTU, obtained from the continuous emissionsmonitoring system over the hours that any of theboilers B25, B26, B27 or B28 operated during theaveraging period. The 30−day rolling period shallconsist of the day of monitoring and the previous 29consecutive calendar days. A new 30−day rollingaverage emission rate shall be calculated andrecorded 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the compliance period. The 12-month period shall consist of the month of monitoringand the previous 11 consecutive calendar months. Anew 12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−daycompliance period shall consist of the day ofmonitoring and the previous 29 consecutive calendardays. A new 30−day total emissions shall becalculated and recorded at the end of each day.66POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) NitrogenOxides(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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the averaging period. The 12-monthperiod shall consist of the month of monitoring andthe previous 11 consecutive calendar months. A new12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−dayperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day total emissions shall be calculated andrecorded at the end of each day.(5) In demonstrating compliance with emissionlimitations of condition A(3a)(a)(1) the permittee maypropose an emissions trading program if the programachieves an improvement in visibility in themandatory class I federal areas greater than would beachieved through the installation and operation ofBART on each boiler subject to BART. The permitteeproposing to use an emissions trading program shallsubmit an emissions trading plan to the department.The plan shall be subject to department andadministrator approvaland meet the followingcriteria:(a) The plan shall contain the proposed controlstrategy and the method of demonstratingcompliance;(b) The plan shall achieve either of the following:(i) For each visibility impairing pollutant for whichcompliance is demonstrated through use of a trading67POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) NitrogenOxides(continued)plan, an emission reduction at least 10% greater thanwould be achieved through the installation andoperation of BART on each boiler subject to BART;(ii) An improvement in visibility in the mandatoryclass I federal areas greater than or equal to thevisibility improvement achieved under conditionA(3a)(b)(5)(b)(i).The improvement in visibility shallbe demonstrated by comparing the 20% best days ofvisibility and the 20% worst days of visibility in atleast the 4 mandatory class I federal areas nearest tothe source and for each calendar year 2002, 2003 and2004. The daily visibility shall be determined usingan air quality model approved by the EPA forpredicting visibility impacts from single emissionsources and conducting the air quality modelinganalyses according to the guidelines in 40 CFR part51, Appendix Y, incorporated by reference in s. NR484.04(11m);(c) Trading shall be between all boilers serving asimilar function located on the same property;(d) Boilers participating in the trading shall achievethe required emission reductions on a continuousbasis and shall be subject to continuous emissionmonitoring, which meets the applicable requirementsunder ch. NR 439;(e) The plan shall specify the monitoring devices andprocedures which will be used to provide informationsufficient to assess the performance of the proposedemission control measures and to quantify on anhourly average basis the mass flow of each pollutantin pounds per hour and the emission rate of eachpollutant in pounds per mmBtu heat input for eachboiler participating in the trading. The proceduresand methods required for compliance demonstrationand for performance testingshall be according to theapplicable requirements of ch. NR 439;(f) Excess emission reductions, for the purposes ofmeeting the BART requirements, shall be emission68POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) NitrogenOxides(continued)reductions beyond those required to meet all state andfederal requirements and may not include emissionreductions used in any other banking or tradingprogram. [ss. NR 433.06(1), NR 439, and NR484.04, Wis. Adm. Code](6)If the department approves the emissions tradingplan from condition A(3a)(b)(5), the department shallpropose to revise the source’s air quality permit toinclude the requirements of the emissions trading planin lieuof the BART requirements for the boilers identified inthe emissions trading plan. [s. NR 433.06(2), Wis.Adm. Code](7)After the department incorporates the emissionstrading plan from condition A(3a)(b)(5) into therevised air operation permit, the permittee shallcomply with the requirements of the emissionstrading plan for the boilers identified in the plan. [s.NR 433.06(3), Wis. Adm. Code](8 The permittee shall notify the Department 90 daysprior to selecting a new emission limitation – fromthe emission limitation options under A(3a)(a)(1)(b) –to be complied with. [s. NR 433.05, Wis. Adm.Code]69B. Stack S10; Control C10; Boiler B27- This is a cyclone furnace type boiler that burns coal as itsprimary fuel, natural gas anddistillate fuel oil as supplementalfuels, and petroleum coke as an alternatefuel. The boiler has a heat input rating of615 million BTU per hour and was installed in 1969.21This boiler has the capacity to fire petroleum coke as an alternate fuel. Please see the additional requirements that relate to this alternate operating scenario for the boiler inTable E of this permit.Note: The requirements and emission limitations outlined in thissection apply to the boiler regardless of the fuel being fired.POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(1) ParticulateMatter EmissionsContinued onNext Page ...1) Emissions may not exceed 0.30pounds of particulate matter from anystack per million BTU of heat input.[s. NR 415.06(1)(b), Wis. Adm. Code]1) The permittee shall perform compliance emissiontesting of particulate matter emissions from Stack S10to demonstrate compliance with the particulate matteremission limit in B(1)(a)1):a) Testing shall be conducted every 24 months aslong as the permit remains valid;b) Each biennial test of particulate matter emissionsshall be performed within 90 days of theanniversary date of the issuance of this permit orwithin 90 days of an alternate date specified bythe Department in writing;c) The permittee may request and the Departmentmay approve a waiver from the required biennialtesting provided the results of the most recentlycompleted biennialtest demonstrate thatparticulatematter emissions are 50 percent or less of theapplicable limitation in condition B(1)(a)1);d) The testing shall be conducted in accordancewith the conditions in DD(4)(a)1).[ss. NR 439.07, 439.075(2)(a), 439.075(3)(b), and439.075(4)(a)1.b., Wis. Adm. Code]1) Reference Test Method for Particulate Matter Emissions:Whenever particulate matter emission testing is required bythe Department, the permittee shall use U.S. EPA Method 5,including backhalf. [s. NR 439.06(1), Wis. Adm. Code]2) The permittee shall retain copies of the results of thecompliance emission tests specified in condition B(1)(b)1).[s. NR 439.04(1)(a), Wis. Adm. Code]3) The permittee shall keep records of the type and amountof fuel burned in this boiler on a monthly basis. [s. NR439.04(1)(d), Wis. Adm. Code]21The Department recognizes that the emissions from Boilers B23, B24, B25, B26, B27 and B28 discharge through a common stack (S10) and thatit would be difficult to determine the emission rate from a specific boiler unless that boiler were the only one of the six boilers operating. The Departmentalso recognizes that all 6 boilers may not be operating at thetime of the required compliance emissions tests. If the emissions from Stack S10 meet the moststringent limitations and requirements provided in Tables A, B and C of this Part I, then the emissions from each boiler discharging to this common stack willbe deemed to be meeting such limitations and requirements.70POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(1) ParticulateMatter Emissions(continued)2) The permittee shall only fire:a) Coal as a primary fuel in thisboiler;b) Natural gas and distillate fuel oil(#1 and #2) as supplemental fuelsin this boiler; andc) Petroleum coke as an alternatefuel in this boiler.See Table E for additionalrequirements that apply while firingpetroleum coke in the boiler.[ss.285.65(3) and 285.63(1)(a), Wis.Stats.]3) The permittee shall operate thebaghouse (C10) to control particulatematter emissions whenever the boileris in operation. [s. NR 415.03, Wis.Adm. Code](4) Best Available Retrofit Technology(BART) applies to boiler B27.(a) The permittee shall meet BARTrequirements for particulate matteremissions no later than December 31,2011.(b) The permittee shall meet particulatematter emission requirements forBART by meeting the followingconditions:(i) Conditions B.1.a.(1), B.1.a.(2) andB.1.a.(3);(ii) Conditions for visible emissions inB.2.a.(1) and B.2.a.(2);2) The permittee shall maintain the pressure dropacross the baghouse between 3.0 and 12.0 inchesof water column. [ss. NR 407.09(4)(a)1., and439.055(1)(a), Wis. Adm. Code]3) The permittee shall take appropriate investigativeand corrective action in accordance with theprocedures in the Malfunction Prevention andAbatement Plan required for this control devicewhenever the pressure drop is outside of theoperating range specified in condition B(1)(b)2). [s.NR 407.09(4)(a)1., Wis. Adm. Code]4) The permittee shall perform periodic internalinspections of the baghouse(C10) to ensure that thecontrol equipment is operating properly. The timeinterval 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 forperiodic internal inspections of the boiler. This planshall include the frequency of these inspections andthe items to be inspected. [s. NR 407.09(4)(a)1.,Wis. Adm. Code]4) The permittee shall record the pressure drop across thebaghouse once every eight (8) hours of operation or once perday, whichever yields the greater number of measurements.[s. NR 439.055(2)(b), Wis. Adm. Code]5) The permittee shall keep records of:a) the date, time, and initials of the person performingthe inspections required by condition B(1)(b)4);b) a list of the items inspected; andc) any maintenance or repairs performed as a result ofthese inspections.[s. NR 439.04(1)(d), Wis. Adm. Code]6) The permittee shall keep records of:a) the date, time, and initials of the person performingthe inspections required by condition B(1)(b)5);b) a list of the items inspected; andc) any maintenance or repairs performed as a result ofthese inspections.[s. NR 439.04(1)(d), Wis. Adm. Code]71POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(iii) The facility malfunction preventionand abatement plan.[ss. NR 433.05, NR 439.11, Wis.Adm. Code](2) VisibleEmissions1) Opacity may not exceed 20% ornumber 1 on the Ringlemann chart.[s. NR 431.04(2), Wis. Adm. Code]2) The permittee shall calibrate,maintain and operate a continuousmonitoring systemthat meets theperformance specifications of conditionB(2)(b)1) for the measurement ofopacity. [s. NR 439.095(1)(a), Wis.Adm. Code]1) The permittee shall calibrate, maintain and operatethe continuous emissions monitoring system requiredby condition B(2)(a)2) in accordance with theperformance specifications in PerformanceSpecification 1 in 40 CFR part 60, Appendix B.[s. NR 439.09(1), Wis. Adm. Code]2) The permittee shall follow a quality control andquality assurance plan as approved by the Departmentfor the continuous monitoring system required bycondition B(2)(a)2). [ss. NR 439.09(8), and439.095(6), Wis. Adm. Code]1) Reference Test Method for Visible Emissions: Whenevervisible emission testing is required by the Department, thepermittee shall use U.S. EPA Method 9.[s. NR 439.06(9)(a)1., Wis. Adm. Code]2) The continuous monitoring system required by conditionB(2)(a)2) shall complete one cycle of sampling and analyzingfor each successive 10-second period and one cycle of datarecording for each successive 6-minute period. [s. NR439.09(9)(a), Wis. Adm. Code]3) Unless otherwise specified by the Department, periods ofexcess visible emissions shall be any 6-minute period duringwhich the average opacity exceeds the limitation in conditionB(2)(a)1). [s. NR 439.09(10)(b)1., Wis. Adm. Code]4) The permittee shall submit quarterly excess emissionreports to the Department within 30 days following the end ofeach calendar quarter. [s. NR439.09(10), Wis.Adm. Code]5) The excess emission reports required by condition B(2)(c)4)shall contain the information identified by conditionDD(3)(a)1)b). [s. NR 439.09(10)(a), Wis. Adm. Code]72POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxideContinued onNext Page ...1) Emissions may not exceed 4.45pounds of sulfur dioxide per millionBTU of heat input when Boiler B29is operating.22[ss. 285.65(3) and285.63(1)(a), Wis. Stats. & s. NR404.04(2)(a)2., Wis. Adm. Code]1) Reference Test Method for Sulfur Dioxide Emissions:Whenever sulfur dioxide emission testing is required by theDepartment, the permittee shall use U.S. EPA Method 6, 6A,6B, 6C or 8. [s. NR 439.06(2)(a), Wis. Adm. Code](3) SulfurDioxide(continued)2) Emissions may not exceed 4.55pounds of sulfur dioxide per millionBTU of heat input when Boiler B29 isnot operating. [s. NR 418.05(1)(c)1.,Wis. Adm. Code]3) The permittee shall calibrate,maintain and operate a continuousmonitoring systemthat meets theperformance specifications of conditionB(3)(b)1) for the measurement of sulfurdioxide. [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 BARTrequirements for sulfur dioxideemissions no later than December 31,2015.1) The permittee shall calibrate, maintain and operatethe continuous emissions monitoring system requiredby condition B(3)(a)3) in accordance with theperformance specifications in PerformanceSpecification 2 in 40 CFR part 60, Appendix B.[s. NR 439.09(2), Wis. Adm. Code]2) The permittee shall follow a quality control andquality assurance plan as approved by the Departmentfor the continuous monitoring system required bycondition B(3)(a)3). [s. NR 439.09(8), Wis. Adm.Code](3) In determining compliance with emissionlimitations of condition B(3)(a)(4) the permittee shalldetermine sulfur dioxide emissions using emissiondata measured according toconditions B(3)(b)(1) andB(3)(b)(2) and according to the following:(a) For condition B(3)(a)(4)(b)(i):(i) In calculating the 30-dayrolling average emissionrate, in pounds per million BTU, the permittee shall2) The continuous monitoring system required by conditionB(3)(a)3) shall perform sampling, analyzing, and datarecording as follows:a) Complete one cycle of sampling, analyzing, and datarecording for eachsuccessive 15-minute period.b) The values recorded shall be averaged hourly.c) Hourly averages shall be computed from 4 data pointsequally spaced over each 1-hour period, except duringperiods when calibrations, quality assurance ormaintenance activities are being performed. Duringthese periods, a valid hour shall consist of at least 2data points separated by a minimum of 15 minutes.[s. NR 439.09(9)(b), Wis. Adm. Code]3) Excess emissions for sulfur dioxide are any 24-hour rollingaverage during which the average sulfur dioxide emissionsexceed the emission limitations inconditions B(3)(a)1) and 2).[s. NR 439.09(10)(b)2., Wis. Adm. Code]4) For purposes of reporting exceedances on the basis of a 24-hour rolling average, any hourly average may be included inonly one 24-hour period. An exceedance shall be based on at22The 4.45 pounds of sulfur dioxide per million BTU of heat input emission limitation comes from Permit No. 88-AJH-031B and ismore restrictivethan the emission limitation from s. NR 418.05(1)(c)1., Wis. Adm. Code (4.55 pounds per million BTU) which appears in conditionB(3)(a)2). The morerestrictive limit is necessary to protect the National Ambient Air Quality Standard for sulfur dioxide when Boiler B29 is operating.73POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)(b) The permittee shall meet sulfurdioxide emission requirements forBART by meeting one of the followinglimitations:(i) a sulfur dioxide emission ratelimitation of 0.23 pounds per millionBTU of heat input to boiler B27 on thebasis of a 30-day rolling average; or(ii) total sulfur dioxide emissions of502 tons in any 12-month period and 47tons in any 30-day period on boilerB27; or(iii) a sulfur dioxide emission ratelimitation of 1.01 pounds per millionBTU of heat input to stack S10 on thebasis of a 12-month rolling average and1.53 pounds per million BTU of heatinput to stack S10 on the basis of a 30-day rolling average; or(iv) total sulfur dioxide emissions of5,800 tons in any 12-month period and761 tons in any 30-day period on stackS10; or(v) under the emissions tradingprogram provided under conditionB(3a)(b)(5), the permittee shall meetthe following emission limitations:(1) the sulfur dioxide emissionlimitations in conditionB(3)(a)(4)(b)(iv), and(2) the sulfur dioxide emissionnot exclude emissions for any period of time forwhich flue gas is exiting boiler B27.(ii) The 30-day rolling average emission rate inpounds per million BTU shall be calculated as theaverage of the hourly emissions, in pounds permillion BTU, obtained from the continuous emissionsmonitoring system over the hours boiler B27 operatedduring the averaging period. The 30−day rollingperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day rolling average emission rate shall becalculated 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting boiler B27.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that boiler B27 operated during the complianceperiod. The 12-month period shall consist of themonth of monitoring and the previous 11 consecutivecalendar months. A new 12-month total emissionsshall be calculated and recorded at the end of eachmonth. The 30−day period shall consist of the dayof monitoring and the previous 29 consecutivecalendar days. A new 30−day total emissions shallbe 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 and30-day rolling average emission rates, in pounds permillion BTU, the permittee shall not excludeemissions for any period of time for which flue gas isleast 18 and not more than 24 valid recordings of hourlyaverage emission rates in any 24-hour period. [s. NR439.09(10)(c), Wis. Adm. Code]5) The permittee shall submit quarterly excess emissionreports to the Department within 30 days following the end ofeach calendar quarter. [s. NR439.09(10), Wis.Adm. Code]6) The excess emission reports required by condition B(3)(c)5)shall contain the information identified by conditionDD(3)(a)1)b). [s. NR 439.09(10)(a), Wis. Adm. Code](7) The procedures and methods required for compliancedemonstration and for performance testing required bycondition B(3)(b)(3) and B(3)(b)(4) shallbe according to theapplicable requirements of ch. NR 439. [ss. NR 433.06(1),NR 439 and NR 440, Wis. Adm. Code](8) In meeting the procedures and methods required forcompliance demonstration and for performance testingrequired by conditions B(3)(b)(3)and B(3)(b)(4), the permitteeshall determine the heat input, in million BTU, based onrecords of the amountof fuel burnt, intons, and the heatcontent of the fuel, in million BTU per ton of fuel.[ss. NR 433.05 and NR 433.06, Wis. Adm. Code]74POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)limitations specified in conditionB(3a)(a)(1)(b)(v)(2).[s. NR 433.05, Wis. Adm. Code]Note:The sulfur dioxide BART emissionlimitation on boiler B27 is based oneliminating the firing of coke fuels,combined with continuous operation ofa circulating fluidized bed sulfurdioxide scrubber system achieving aminimum 93% sulfur dioxide removal.This technology is noted to establish abasis for determining alternativeemission requirements if constraintsare encountered in implementing thesespecific technologies which warrant arevision of the individual boilerdetermined control level as allowed forunder s. NR 433.05(5).exiting Stack S10.(ii) The 12-month rolling average and 30-day rollingaverage emission rates, in pounds per million BTU,shall be calculated as the average of the hourlyemissions, in pounds per million BTU, obtained fromthe continuous emissions monitoring system over thehours that any of the boilers B25, B26, B27 or B28operated during the averaging period. The 12-monthrolling period shall consist of the month ofmonitoring and the previous 11 consecutive calendarmonths. A new 12-month rolling average emissionlimit shall be calculated and recorded at the end ofeach month. The 30−day rolling period shall consistof the day of monitoring and the previous 29consecutive calendar days. A new 30−day rollingaverage emission rate shall be calculated andrecorded 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the compliance period. The 12-month period shall consist of the month of monitoringand the previous 11 consecutive calendar months. Anew 12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−daycompliance period shall consist of the day ofmonitoring and the previous 29 consecutive calendardays. A new 30−day total emissions shall becalculated and recorded at the end of each day.75POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the averaging period. The 12-monthperiod shall consist of the month of monitoring andthe previous 11 consecutive calendar months. A new12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−dayperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day total emissions shall be calculated andrecorded at the end of each day.(4) In demonstrating compliance with emissionlimitations of condition B(3)(a)(4) the permittee maypropose an emissions trading program if the programachieves an improvement in visibility in themandatory class I federal areas greater than would beachieved through the installation and operation ofBART on each boiler subject to BART. The permitteeproposing to use an emissions trading program shallsubmit an emissions trading plan to the department.The plan shall be subject to department andadministrator approvaland meet the followingcriteria:(a) The plan shall contain the proposed controlstrategy and the method of demonstratingcompliance;(b) The plan shall achieve either of the following:76POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)(i) For each visibility impairing pollutant for whichcompliance is demonstrated through use of a tradingplan, an emission reduction at least 10% greater thanwould be achieved through the installation andoperation of BART on each boiler subject to BART;(ii) An improvement in visibility in the mandatoryclass I federal areas greater than or equal to thevisibility improvement achieved under conditionB(3)(b)(4)(b)(i). The improvement in visibility shallbe demonstrated by comparing the 20% best days ofvisibility and the 20% worst days of visibility in atleast the 4 mandatory class I federal areas nearest tothe source and for each calendar year 2002, 2003 and2004. The daily visibility shall be determined usingan air quality model approved by the EPA forpredicting visibility impacts from single emissionsources and conducting the air quality modelinganalyses according to the guidelines in 40 CFR part51, Appendix Y, incorporated by reference in s. NR484.04(11m);(c) Trading shall be between all boilers serving asimilar function located on the same property;(d) Boilers participating in the trading shall achievethe required emission reductions on a continuousbasis and shall be subject to continuous emissionmonitoring, which meets the applicable requirementsunder ch. NR 439;(e) The plan shall specify the monitoring devices andprocedures which will be used to provide informationsufficient to assess the performance of the proposedemission control measures and to quantify on anhourly average basis the mass flow of each pollutantin pounds per hour and the emission rate of eachpollutant in pounds per mmBtu heat input for eachboiler participating in the trading. The proceduresand methods required for compliance demonstrationand for performance testingshall be according to the77POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3) SulfurDioxide(continued)applicable requirements of ch. NR 439;(f) Excess emission reductions, for the purposes ofmeeting the BART requirements, shall be emissionreductions beyond those required to meet all state andfederal requirements and may not include emissionreductions used in any other banking or tradingprogram. [ss. NR 433.06(1), NR 439, and NR484.04, Wis. Adm. Code](5)If the department approves the emissions tradingplan from condition B(3)(b)(4)(b), the departmentshall propose to revise the source’s air quality permitto include the requirements of the emissions tradingplan in lieu of the BART requirements for the boilersidentified in the emissions trading plan. [s. NR433.06(2), Wis. Adm. Code](6)After the department incorporates the emissionstrading plan from condition B(3)(b)(4)(b) into therevised air operation permit, the permittee shallcomply with the requirements of the emissionstrading plan for the boilers identified in the plan. [s.NR 433.06(3), Wis. Adm. Code](7) The permittee shall notify the Department 90 daysprior to selecting a new emission limitation – fromthe emission limitation options under B(3)(a)(4)(b) –to be complied with. [s. NR 433.05, Wis. Adm.Code]3a. NitrogenOxidesrequirements(1) Best Available Retrofit Technology(BART) applies to boiler B27.(a) The permittee shall meet BARTrequirements for nitrogen oxidesemissions no later than December 31,2015.(1) The permittee shall calibrate, maintain andoperate a continuous monitoring system for themeasurement of nitrogenoxides which meets theperformance 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 methods required for compliancedemonstration and for performance testing required bycondition B(3a)(b)(4) and B(3a)(b)(5) shall be according to theapplicable requirements of ch. NR 439. [ss. NR 433.06(1),NR 439 and NR 440, Wis. Adm. Code](2) In meeting the procedures and methods required for78POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) Nitrogenoxides(continued)(b) The permittee shall meet nitrogenoxides emission requirements forBART by meeting one of the followinglimitations:(i) a nitrogen oxides emission ratelimitation of 0.20 pounds per millionBTU of heat input to boiler B27 on thebasis of a 30-day rolling average; or(ii) total nitrogen oxides emissions of437 tons in any 12-month period and 41tons per 30-day rolling average onboiler B27; or(iii) nitrogen oxides emission ratelimitations of 0.21 pounds per millionBTU of heat input to stack S10 on thebasis of a 12-month rolling average,and 0.28 pounds per million BTU ofheat input to stack S10 on the basis of a30-day rolling average; or(iv) total nitrogen oxides emissions of1,200 tons in any 12-month period and141 tons in any 30-day period on stackS10; or(v) under the emissions tradingprogram provided for under conditionB(3a)(b)(5), the permittee shall meetthe following emission limitations:(1) total nitrogen oxides emissionlimitation of 1,080 tons in any 12-month period and 127 tons in any 30-(2) The permittee shall calibrate, maintain andoperate the continuous emission monitor required bycondition B(3a)(b)(1) in accordance with theperformance 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 bycondition B(3a)(b)(1) shall follow a quality controland quality assurance plan, as approved by theDepartment.[ss. NR 439.09(8) and NR439.095(6), Wis. Adm. Code](4) In determining compliance with emissionlimitations of condition B(3a)(a)(1) the permittee shalldetermine nitrogen oxides emissions using emissiondata measured according toconditions B(3a)(b)(1),B(3a)(b)(2), and B(3a)(b)(3) and according to thefollowing requirements:(a) For condition B(3a)(a)(1)(b)(i):(i) In calculating the 30-dayrolling average emissionrate, in pounds per million BTU, the permittee shallnot exclude emissions for any period of time forwhich flue gas is exiting boiler B27.(ii) The 30-day rolling average emission rate inpounds per million BTU shall be calculated as theaverage of the hourly emissions, in pounds permillion BTU, obtained from the continuous emissionsmonitoring system over the hours boiler B27 operatedduring the averaging period. The 30−day rollingperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day rolling average emission rate shall becalculated and recorded at the end of each day.(b) For condition B(3a)(a)(1)(b)(ii):compliance demonstration and for performance testingrequired by conditions B(3a)(b)(4) and B(3a)(b)(5), thepermittee shall determine the heat input, in million BTU,based on records of the amount of fuel burnt, in tons, and theheat content of the fuel, in million BTU per ton of fuel.[ss. NR 433.05 and NR 433.06, Wis. Adm. Code]79POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) Nitrogenoxides(continued)day period on stack S10;(2) The emission limitation on nitrogenoxides in condition B(3a)(a)(1)(b)(v)(1)shall be met when:(a) total actual sulfur dioxide emissionsdo not exceed [5,800 - (N1*T)] tons forany consecutive 12-month period onstack S10, and(b) total actual sulfur dioxide emissionsdo not exceed [761 - (N2*T)] tonssulfur dioxide for any consecutive 30-day period on stack S10,whereN1= the difference between (actualtotal tons nitrogen oxides) and (1,080tons nitrogen oxides) per consecutive12-month period on stack S10,N2= the difference between (actualtotal tons nitrogen oxides) and (127tons nitrogen oxides) per consecutive30-day period,T = 2.0 = the ratio of (sulfur dioxidetons reduced from 5,800 tons) to(nitrogen oxides tons increased from1,080 tons) over any consecutive 12-month period, and the ratio of (sulfurdioxide tons reduced from 761 tons) to(nitrogen oxides tons increased from127 tons) over any consecutive 30-dayperiod.[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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting boiler B27.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that boiler B27 operated during the complianceperiod. The 12-month period shall consist of themonth of monitoring and the previous 11 consecutivecalendar months. A new 12-month total emissionsshall be calculated and recorded at the end of eachmonth. The 30−day period shall consist of the dayof monitoring and the previous 29 consecutivecalendar days. A new 30−day total emissions shallbe calculated and recorded at the end of each day.(c) For condition B(3a)(a)(1)(b)(iii):(i) In calculating the 30-dayrolling average emissionrate, in pounds per million BTU, the permittee shallnot exclude emissions for any period of time forwhich flue gas is exiting Stack S10.(ii) The 30-day rolling average emission rate inpounds per million BTU shall be calculated as theaverage of the hourly emissions, in pounds permillion BTU, obtained from the continuous emissionsmonitoring system over the hours that any of theboilers B25, B26, B27 or B28 operated during theaveraging period. The 30−day rolling period shallconsist of the day of monitoring and the previous 29consecutive calendar days. A new 30−day rollingaverage emission rate shall be calculated andrecorded at the end of each day.(d) For condition B(3a)(a)(1)(b)(iv):(i) In calculating the total emissions, in tons per 12-80POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) Nitrogenoxides(continued)Note:The nitrogen oxides BART emissionlimitation on boiler B27 is based oncontinuous operation of over-fire airdesigned specifically for NOx controland in combination with one or more ofthe following equipment configurationsto achieve additional 60 – 70% controlof nitrogen oxides beyond the over-fireair: selective catalytic reduction,selective non-catalytic reduction, andrich reagent injection. This technologyis noted to establish a basis fordetermining alternative emissionrequirements if constraints inimplementing these specifictechnologies are encountered asallowed for under s. NR 433.05(5)warrant a revision of the individualboiler determined control level.month period and tons per 30-day period, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the compliance period. The 12-month period shall consist of the month of monitoringand the previous 11 consecutive calendar months. Anew 12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−daycompliance period shall consist of the day ofmonitoring and the previous 29 consecutive calendardays. A new 30−day total emissions shall becalculated 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, thepermittee shall not exclude emissions for any periodof time for which flue gas is exiting Stack S10.(ii) The total emissions, in tons per 12-month periodand tons per 30-day period,shall be calculated as thesum of the daily emissions, in tons, obtained from thecontinuous emissions monitoring system over thedays that any of the boilers B25, B26, B27 or B28operated during the averaging period. The 12-monthperiod shall consist of the month of monitoring andthe previous 11 consecutive calendar months. A new12-month total emissions shall be calculated andrecorded at the end ofeach month. The 30−dayperiod shall consist of the day of monitoring and theprevious 29 consecutive calendar days. A new30−day total emissions shall be calculated andrecorded at the end of each day.81POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) Nitrogenoxides(continued)(5) In demonstrating compliance with emissionlimitations of condition B(3a)(a)(1) the permittee maypropose an emissions trading program if the programachieves an improvement in visibility in themandatory class I federal areas greater than would beachieved through the installation and operation ofBART on each boiler subject to BART. The permitteeproposing to use an emissions trading program shallsubmit an emissions trading plan to the department.The plan shall be subject to department andadministrator approvaland meet the followingcriteria:(a) The plan shall contain the proposed controlstrategy and the method of demonstratingcompliance;(b) The plan shall achieve either of the following:(i) For each visibility impairing pollutant for whichcompliance is demonstrated through use of a tradingplan, an emission reduction at least 10% greater thanwould be achieved through the installation andoperation of BART on each boiler subject to BART;(ii) An improvement in visibility in the mandatoryclass I federal areas greater than or equal to thevisibility improvement achieved under conditionB(3a)(b)(5)(b)(i). The improvement in visibility shallbe demonstrated by comparing the 20% best days ofvisibility and the 20% worst days of visibility in atleast the 4 mandatory class I federal areas nearest tothe source and for each calendar year 2002, 2003 and2004. The daily visibility shall be determined usingan air quality model approved by the EPA forpredicting visibility impacts from single emissionsources and conducting the air quality modelinganalyses according to the guidelines in 40 CFR part51, Appendix Y, incorporated by reference in s. NR484.04(11m);82POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTS(3a) Nitrogenoxides(continued)(c) Trading shall be between all boilers serving asimilar function located on the same property;(d) Boilers participating in the trading shall achievethe required emission reductions on a continuousbasis and shall be subject to continuous emissionmonitoring, which meets the applicable requirementsunder ch. NR 439;(e) The plan shall specify the monitoring devices andprocedures which will be used to provide informationsufficient to assess the performance of the proposedemission control measures and to quantify on anhourly average basis the mass flow of each pollutantin pounds per hour and the emission rate of eachpollutant in pounds per mmBtu heat input for eachboiler participating in the trading. The proceduresand methods required for compliance demonstrationand for performance testingshall be according to theapplicable requirements of ch. NR 439;(f) Excess emission reductions, for the purposes ofmeeting the BART requirements, shall be emissionreductions beyond those required to meet all state andfederal requirements and may not include emissionreductions used in any other banking or tradingprogram. [ss. NR 433.06(1), NR 439, and NR484.04, Wis. Adm. Code](6)If the department approves the emissions tradingplan from condition B(3a)(b)(5), the department shallpropose to revise the source’s air quality permit toinclude the requirements of the emissions trading planin lieuof the BART requirements for the boilers identified inthe emissions trading plan. [s. NR 433.06(2), Wis.Adm. Code](7)After the department incorporates the emissionstrading plan from condition B(3a)(b)(5) into the83POLLUTANT(a) LIMITATIONS & REQUIREMENTS(b) COMPLIANCE DEMONSTRATION(c) REFERENCE TEST METHODS, RECORDKEEPINGAND MONITORING REQUIREMENTSrevised air operation permit, the permittee shallcomply with the requirements of the emissionstrading plan for the boilers identified in the plan. [s.NR 433.06(3), Wis. Adm. Code](7) The permittee shall notify the Department 90 daysprior to selecting a new emission limitation – fromthe emission limitation optionsunder 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 SO 2 

### 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 solid s 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 base d on Babcock Power quote received by GP in 2010 1



### . The cost included B28, making the cost estimate co nservative for the B 26/B27 combined flue

alone.

b 

### Dry FGD operating cost and wet FGD capital/operating costs ar e estimated from the BART analysis submitted by GP 2



### .

### 87 NOx

Boiler B27 - Overfire Air

Boiler Capacity 50 MW Tons/Year grams/sec

Emissions 2,729 103

Existing Control Efficiency 0%

Control Efficiency 50% OFA

Controlled Emissions 1,365 52

Emitted 1,365 52 Visibility Improvement - Seney 0.005 dv per gr/sec 0.25 deciview

OFA Cost:

Reference
Total Direct Cost (TDC) 693,980 4
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 2,729 103

Existing Control Efficiency 0%

Control Efficiency 70% RSCR

Controlled Emissions 1,910 72

Emitted 819 31 Visibility Improvement - Seney 0.005 dv per gr/sec 0.35 deciview

RSCR Cost:

Reference
Total Direct Cost (TDC) 6,100,000 1

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 2,729 103

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 409 15
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 2,729 103

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 437 17
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: 9.4 4% 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 2,729 103

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 405 15
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 rat e 855,360 4

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 640 27

Existing Control Efficiency 0%

Control Efficiency 35% OFA

Controlled Emissions 224 9

Emitted 416 17 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 640 27

Existing Control Efficiency 0%

Control Efficiency 50% SNCR

Controlled Emissions 320 13

Emitted 320 13 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

urea a l/hr (double CAA r 337,245 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 252,854 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 640 27

Existing Control Efficiency 0%
Control Efficiency 1 35% OFA/FGR 224 9
Control Efficiency 2 50% SNCR 208 9

Controlled Emissions 432 18

Emitted 208 9
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 640 27

Existing Control Efficiency 0%
Control Efficiency 1 70% RSCR 448 19
Control Efficiency 2 0 0

Controlled Emissions 448 19

Emitted 192 8
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) 6,100,000 1

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 640 27

Existing Control Efficiency 0%
Control Efficiency 1 35% OFA/FGR 224 9
Control Efficiency 2 70% RSCR 291 12

Controlled Emissions 515 22

Emitted 125 5
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) 6,100,000 1

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 Environmen tal, 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 submitt ed to WDNR April, 2009.

3) USEPA, 2002, EPA Air Pollution Control Cost Manual – 6 th 

### 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 Tec hnology At Non-EGU Facilities , Note 5, page 62, Wisconsin Department of Na tural Resources, Madison, Wi.

### 100 APPENDIX C

Fuel Switching Analysis

for

Base SO 2 

### Emissions

WDNR, July 2011

### 101 Table C.1 Analysis for Adjusted B24 Base SO 2 

### 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 Hi gh 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 repl acing one ton Western coal is

assumed at 1.14.

Table C.2 Analysis for Adjusted B25 Base SO 2 

### 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 Hi gh 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 repl acing one ton Western coal is

assumed at 1.14.

### 102 Table C.3 Analysis for Adjusted B26 Base SO 2 

### 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 Hi gh 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 repl acing one ton Western coal is

assumed at 1.14.

2 

### Ratio of coal heat content fo r one ton High Fusion coal replaci ng one ton Coke is assumed at

0.89.

Table C.4 Analysis for Adjusted B27 Base SO 2 

### 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 fo r one ton Low Fusion coal replaci ng one ton Coke is assumed at

0.93.

### 103 Table C.5 Analysis for Adjusted B28 Base SO 2 

### 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 Hi gh 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 repl acing 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 draf t BART determination from the Class I area Federal Land Managers, from Georgia Pacific – Green Bay, and from McGillivray, Westerberg

& Bender LLC on behalf of Sier ra Club of Wisconsin. The De partment'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 dete rmination and emission requirement.

2. Georgia Pacific – Green Bay

The Draft Permit should clearly identify th at the BART-derived St ack 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 emi ssions 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 boile r limits. The common stack emi ssion limitations are applicable only if Georgia Pacific elects to dem onstrate compliance on this basis.

Under this consideration however, Georgia Paci fic 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 compli ance 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 Georgi a Pacific to notify the Department 90 days prior to first establishing or when ch anging the election of emission limitation requirements for demonstrating compliance.

Best Available Retrofit Technol ogy 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 Depa rtment cannot presume any SO 2 

### reductions resulting from

BART in the technical feas ibility and operation of NOx controls, specifically RSCR.

Response :

### 106 The Department does not agree that individual pollutant cont rols should be evaluated one pollutant at a time in separate context. First, the evaluation of visibility improvement is synergistic between the pollutant s with the emission reduction requirements to be implemented concurrently. Further, BART guidance is to evaluate controls in context of the existing equipment configurations and know n conditions. Therefore the De partment's approach is to evaluate controls accounting for actual existing or projected equipment co nfigurations 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 SO 2 

### emission reductions required under BA RT 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 SO 2 

### emissions. However, the Department also concludes that it is appropriate to consider the various SO 2 

### reduction approaches, under the existing equipment configuration, and their potential efficienci es for achievi ng the overall control requirement. As such, the evaluation of the RSCR tec hnology applied to the GP boiler system also considers that the co mmon flue duct splits prior to th e existing fabric filter. Under

this condition the most efficient approach may be to a pply FGD and RSCR technology to one side of the split duct system (r efer to the Section II.4).

Further, the Department considers different SO 2 

### control approaches in evaluating NOx controls

based on solutions considered viab le under the five factor analysis . For this reason, if a control approach such as shutting down one boiler significantly reduces total SO 2 

### emissions and but still results in high SO 2 

### flue gas concentrations from the remain ing boilers then this condition will be considered in evaluating NOx BART controls. However, if other SO 2 

### control options are available and are equal under the fi ve factors then these control op tions are used as the basis for evaluating NOx controls.

o Georgia Pacific considers that the cost of SO 2 

### controls as a pre-requisite for NOx control

should be included in the cost of the NOx control system.

Response: The department agrees that al l costs should be counted in ev aluating BART co ntrols. Any portion of cost for SO 2 

### control incurred beyond the SO 2 

### BART requirement shou ld be applied to evaluating the cost of NOx control. However, the full benefit of visibility improvement associated with any required SO 2 

### control, whether for SO 2 

### 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 SO 2 

### beyond that of

the SO 2 

### BART is assumed as a pre-requisite to implementing NOx emission reductions. Conversely, the NOx BART dete rmination looked at how SO 2 

### controls can be configured, in meeting the same SO 2 

### BART, in order to provide the most efficient use of RSCR NOx control equipment on one flue gas stream exiting the existi ng fabric filter system. In this manner the Department looked at how cont rols can be best integrated for the highest available NOx reduction, in context of the five factor analysis, in a manner which does no t require reductions beyond SO 2 

### BART.

### 107 o Georgia Pacific concluded that the draft BART determination and default application of surrogate control equipment can preclude the technical feasibili ty 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 tr ading program must demonstrate visibility improvement equivalent to that achieved through the BART level of cont rols. This approach clearly requires that the BART level of controls is establis hed first and independently of emissions trading. Then the De partment must set appropriate criteria for emissions trading which maintains visibility improvement garner ed 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 BA RT Determination and emission trading criteria allow Georgia Pacific to structure the best pos sible control approach meeting the BART dete rmined requirements.

The Department has incorporated a default emissions trading co mpliance option under the BART compliance requirements. The Department conc luded, based on analysis of technologies and cost, that the most likely emissions tr ading approach is to over-control SO 2 

### emissions from nonBART boilers at a lower cost rather than fully controlling NOx to the BA RT 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 th e 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 on ly factor to consider in determining a BART level of control. Th e Department's approach considered vendor information, control levels demonstrated by other operating units, a nd 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 SO 2 

### flue gas concentrations.

Response: The Department re-examined the applicability of RSCR in cont ext of the existing flue duct configuration and potential flue gas SO 2 

### concentrations. The RSCR vendor provided a quote to Georgia Pacific for the Stack S10 system and further confirmed wi th the Department that RSCR is applicable to coal fired units . The vendor further identified implications for operating RSCR

at different SO 2 

### flue gas concentrations. The Department finds that control strategies can be

### 108 implemented for reducing SO 2 

### concentrations under the SO 2 

### BART requirement which allows operating RSCR for control of boiler B27's portion of NOx emissions in th e flue gas. This approach is based on the common fl ue 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 SO 2 

### concentrations in the sec ond 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 RS CR was eliminated as a cont rol option for boiler B26.

Operating variability must also be considered in determining BART.

The emission requirement set fo r BART needs to incorporate th e operating variability into a compliance margin, i.e. an enfo rceable operating perm it limit should provid e the permittee an appropriate level of operating flexibility to allo w the facility to achiev e continuous compliance with all permit limits.

Response: The Department agrees that the long-term pe rformance of control equipment and operating variability must be considered in establishing a reasonably achievable control level and emission limitation. In this context, th e Department believes the emissi on limitations set for the Georgia Pacific boilers on a 30 day and 12 month rolling ba sis address normal operating variability (refer to Section II.6).

The Department addressed control levels and compliance margins as follows for SO 2 

### and NOx.

SO 2 

### The draft BART determination pr oposed control levels of 95 % removal based on circulating fluidized bed technology as represented by Tur boSorb. The Department reviewed emissions data for operating Turbosorb units and engineering assessmen ts for CFB technology. The Department adjusted the SO 2 

### BART control efficiency from 95% to 93% removal in setting BART compliance requirements. Refer to Section II.2 for the determination of SO 2 

### BART

control levels

NOx The draft BART determination pr oposed control levels of 84 % for boiler B26 and 92% for

Boiler B27. Under the amended determination the BART compli ance requirement is based on

NOx control levels of 68% and 84% for boilers B26 and B27, respectiv ely. 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 be nefits is the change in days above a 0.5 deciview impact. To completely evaluate the difference s between options, the

determination needs to incl ude this info rmation.

### 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 deci view threshold is achieved. The amount of deciview impact for the Georgi a Pacific boilers and the amount of improvement resulting from

the BART controls is estimated in the BART determination. Th e maximum day visibility impact from uncontrolled emissions to the Seney Cla ss 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 a nd that days are reduced.

o Georgia Pacific requests, consiste nt with BART guideli nes, that the Department not consider imperceptible visibility changes (i n evaluating controls for BART).

Response: The Department assessed small ch anges in visibility when evalua ting control technologies. The CALPUFF model used in estimating visibility impacts fo r a source defines deciview changes in 0.01 increments. The Department ag rees 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 t op-down BART approach co ntrol technologies are evaluated based on the resulting total visibility improvement. Th e amended BART requiremen t is estimated to yield visibility improvement for Seney of 0.52 deci view from NOx reduction and 1.23 deciview from

SO 2 

### reductions (average of 3 year maximum daily impact). Therefore the control technologies

and associated emission reducti ons yield significant changes th at contribute to perceptible visibility improvement.

The Department did evaluate the increment of vi sibility improvement be tween two technologies when the control envelope define s a significant cost increase be tween the top-available control and the next tier down. For example, the Depa rtment determined wet-FGD could cost on the

order of two times the cost of dry-FGD with little additional SO 2 

### control. Wet FGD produced only a maximum 0.09 improvement versus dry-FGD in visibility for the Sene y Class I area. The dry-FGD garners a maximum 1.23 dv improvement. Therefore we t-FGD is eliminated as a BART control option because dry-FGD produced n early equivalent visibility improvement. Similar approaches are used in comparing SCR, RSCR, and SNCR based co ntrol options in the

NOx BART determination.

o Additional Particulate Matter requirements are unnecessary.

Response: The Department agrees that no additional require ment for particulate matt er 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 vi sibility improvement. In co ntext that this visibility improvement is the entire resu lt of a control measure the De partment deems this level of visibility improvement as marg inal in contribution to a pe rceptible visibility change.

Allowable emissions for both BART and non-BA RT boilers should be used to establish proposed Stack 10 permit limits.

Response : The Department does not agree that permit limits for BART a nd non-BART boiler s 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 SO 2 

### base emissions). On this basis the Department determined a base fu el for adjusting uncontrolled SO 2 

### emission baseline. The base

fuel assumes sulfur content refl ecting bituminous coals. The SO 2 

### emission requirement is then calculated using this adjusted SO 2 

### base emissions. The settin g of the NOx emission limit is

based on current actual emission ra tes. These rates are related to boiler combustion parameters and therefore reflect expected ongoing uncontrolle d emissions.

WDNR needs to calculate incremental cost ef fectiveness of proposed control analysis.

Response : The Department staff performed a top-down analys is of the available co ntrol technologies and control levels. As part of this analysis, the Department staff pr ovided the costs associated with each control technology and control level. The Department evaluated incremental costs and visibility impacts when the co ntrol envelope of control optio ns demonstrated a significant

increase in cost versus the resu lting visibility improvement.

3. Sierra Club of Wisconsin

DNR must also establish BART limits for EGUs.

Response: The Department established BA RT limits for EGUs. The stat e BART rule, ch. NR 433, Wis. Adm. Code, establishes that EGUs satisfy SO 2 

### and NOx BART if comp lying with the federal Clean Air Interstate Rule (CAI R). The Wisconsin EGUs elected this compliance option. With the implementation of th e Clean Air Transport Rule (CATR) to replace CAIR the Department will have to evaluate if EGUs still satisfy the SO 2 

### 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 to p-down approach required unde r BART in evaluating control options. Under this approach, contribution to visibility impr ovement 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. Howe ver, the BART guidelines also provide that marginal or increm ental cost should be considered and that a control envelope should be developed representing th e 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 applie d this method in dete rmine controls representing BART. In addition the BART guidance requ ires consideration of non-cost factors in making a BART determination. The Department applied these criteria in esta blishing BART. Addressing both factors eliminated several top-tier co ntrol options as th e basis for BART.

Wet Scrubber Technology is available at low er 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 improv ement 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 co st to refute the cost s presented by WDNR.

Wet FGD above 98% control rema ins inappropriate in terms of cost-effectiveness and energy and environmental impacts compared to dry FGD.

The Department needs to consider fuel switchin g to low sulfur coal and natural gas as a control option.

Response: In the final determination for GP, the Department ut ilizes a base coal to replace the historical use of petroleum coke. This base fuel is a bitu minous 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 leve ls of fuel switching including th e use of low sulfur bituminous

coal and subbituminous coal. Th e low sulfur bituminous coal doe s not yield additional benefit compared to the use of stan dard bituminous coal when a pplying the dry FGD 93% control efficiency. The Department co nsidered switching to subbitumi nous 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 in stead 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 se veral years creates a less stringent requirement.

Response: The Department has determined th at including B24 and B25 historic operati on levels in setting emission requirements for stack S10 is appr opriate. The BART gui delines specify using emissions from the baseline years, 2002 to 2004, as the default basis fo r establishing BART. During this baseline period these bo ilers operated as part of the st ack S10 boiler system. Even as these boilers have not recently operated the Stack S10 system ha s demonstrated the use of this capacity. The Department finds that applying the h eat input from boilers B24 and B25 to the operating levels of the remaining boilers during baseline year op eration does not exceed their capacity. Therefore, the Depart ment uses the average operati ng level (heat i nput) during the baseline years as the basis for establishing Stack S10 requirements . The Departme nt also finds adjusting SO 2 

### base emissions to re flect an assumed "base" fuel fo r each boiler is appropriate to account for variability of fuel sulfur content and fuel switching contro l options. (Section II.3)

o Potential future control requ irements for B24, B25 and B 28 may create a less stringent requirement for the BART boilers . The Department must ensu re that boilers B26 and B27 are meeting BART-level em ission reductions during al l operating scenarios.

Response: The Department cannot antici pate or regulate based on future potential requirements. As the BART guidelines establish the BART determination should cons ider the existing equipment configuration and operations. Under this considerat ion, the emissions exi ting from stack S10 cannot be distinguished as or iginating from BART or non-BART boilers. Therefore allowing compliance with either the individual boiler requirements or common stack requirements is appropriate and reflects a reducti on of total emissions versus the baseline year emissions. In fact, establishing the al ternative Stack S10 requirements establishes a baseline for BART and non-BART boiler operation. This compliance approach, if utili zed, addresses the appropriate benchmark against simply shif ting load between boilers.

The Department has not shown that the prop osed limits will protect air quality (increased increments and NAAQS for NO 2 

### , SO 2 

### and PM2.5).

Response: The BART requirement is a requi rement for visibility improvemen t under the federal Regional Haze rule. The air protection standards referenced by Sierra Club are not applicable to the BART determination. However, th e Department agrees that comp liance with these requirements

must be demonstrated under the applicable regul atory programs.

### 113 The Department must clarify the seque nce of permits for Georgia Pacific.

Response: The Department is in the process of renewing th e permit for Georgia Paci fic. The process for incorporating BART requirements is separate from the renewa l process but subject to public comment as well. Both proces ses for modifying the permit will proceed separately with requirements effective as each revision is finalized.