## ATTACHMENT B

ENGINEERING ANALYSIS FOR CONTROL TECHNOLOGY

OPTIONS – GREEN BAY BROADWAY MILLGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

i 1.0 ENGINEERING ANALYSIS METHODOLOGY 1

2.0 BART ENGINEERING ANALYSIS FOR BOILER NO. 6 3

2.1 SOURCE DESCRIPTION 3 2.2 BASELINE EMISSIONS 3 2.3 PARTICULATE MATTER 5 2.4 SULFUR DIOXIDE 7 Wet Spray Tower with Sodium Hydroxide Cost Evaluati on 8 Dry Scrubbing with Hydrated Lime Fluidized Bed Abso rber (FBA) Cost Evaluation 16 Furnace Sorbent Injection (FSI) Cost Evaluation 21 In-Duct Absorption System with Trona Cost Evaluatio n 25 Clean Fuels Cost Evaluation 28 Energy and Environmental Impacts 32 SO 2 Engineering Analysis Summary 32 2.5 NITROGEN OXIDES 33 SCR Cost Evaluation 38 ROFA and Rotamix Cost Evaluation 42 SNCR Cost Evaluation 43 FGR/OFA Cost Evaluation 46 SNCR with FGR and OFA Cost Evaluation 48 Energy and Environmental Impacts 50 NO x Engineering Analysis Summary 51 2.6 SUMMARY OF ENGINEERING ANALYSES FOR BOILER NO. 6 51 3.0 BART ENGINEERING ANALYSIS FOR POWER BOILER NO.7 52

3.1 SOURCE DESCRIPTION 52 3.2 BASELINE EMISSIONS 52 3.3 PARTICULATE MATTER 54 3.4 SULFUR DIOXIDE 56 Wet Spray Tower with Sodium Hydroxide Cost Evaluati on 57 Dry Scrubbing with Hydrated Lime Fluidized Bed Abso rber (FBA) Cost Evaluation 60 Furnace Sorbent Injection (FSI) Cost Evaluation 62 In-Duct Absorption System with Trona Cost Evaluatio n 65 Clean Fuels Cost Evaluation 68 Energy and Environmental Impacts 70 3.5 NITROGEN OXIDES 72 SCR Cost Evaluation 73 ROFA and Rotamix Cost Evaluation 77 SNCR Cost Evaluation 78 OFA Cost Evaluation 81 SNCR with OFA Cost Evaluation 84 Energy and Environmental Impacts 85 3.6 ADDITIONAL MULTI-POLLUTANT CONTROL OPTION FOR B OILER NO. 7 87 Cost Evaluation 87 4.0 BART ENGINEERING ANALYSIS SUMMARY 90

APPENDIX AGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-1 

### 1.0 ENGINEERING ANALYSIS METHODOLOGY

NR 433 Wisconsin Administrative Code requires Best Available Retrofit Technology (BART) engineering analyses for emission units which meet eligibility requirements of source size, type, and date of init ial operation. Wisconsin Department of Natural Resourc es (DNR) notified Georgia-Pacific Consumer Products LP – Green Bay Broadway Mill on July 9, 2008, of it s eligibility for two emission units. As required by NR 433, the Green Bay Broadway Mill has prepared an en gineering analysis for units we agree are eligible for BART. As explained in the July 9, 2008, notice, th e two units are Boiler No. 6 and Boiler No. 7 (sour ce IDs B26 and B27, respectively). The requirements of a BART engineering analysis are summarized in NR 433.

The Best Available Retrofit Technology (BART) engin eering analysis in this application follows the U.S

. EPA’s BART guidelines 1 which reflect a “top-down” approach that is simil ar to analyses required by federal Prevention of Significant Deterioration reg ulations for Best Available Technology (BACT). The BART review is performed on a case-by-case basis, t aking into account energy, environmental, and economic impacts and other costs for technologies d etermined to be technically feasible. The “top-down ” approach starts with an assessment of the most stri ngent control technology. If the technology is sho wn not to be technically or economically effective, then t he analysis provides a basis for rejecting this alt ernative in favor of the next most stringent technology as BART . Following are the basic steps of a “top-down” analysis:

1) Identify all control technologies a) Typically in use or shown to be technically feasibl e by an equipment vendor, b) Determined as BACT and listed in USEPA RACT/BACT/LAER Clearinghouse, c) Already in use at one of Georgia-Pacific’s operatin g facilities. 2) Eliminate technically or economically infeasible op tions. 3) Rank remaining control technologies by control effe ctiveness. 4) Evaluate most effective controls (considering costs , energy and environmental impacts). 5) Select BART control technology.

GP performed the 5 steps for each visibility-affect ing pollutant individually for each affected unit s ubject to

BART. Wisconsin DNR has determined that the releva nt pollutants are: sulfur dioxide (SO 2 ), nitrogen

1 70 Federal Register 39104 July 6, 2005GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-2 oxides (NO x ) and particulate matter (PM 10 ) 2 . For each analysis of control technology costs, GP followed

US EPA’s Cost Control Manual 3 guidance. Generally, the Manual techniques reflec t a “rough order of magnitude” with an accuracy of approximately +/- 30 %. GP prepared site-specific cost estimates that m eet or exceed this level of accuracy.

The following sections provide a detailed engineeri ng analysis for Boiler No. 6 and Boiler No. 7 individually. To determine emission reduction effic iency and operating costs, the analyses used the BART baseline years selected by Wisconsin DNR (2002 -2004). The estimated rates of reduction (efficiencies) reflect the design of control option s. In contrast, the reduction in mass emissions (tp y) reflects the control option as it applies to the ac tual operating rates and actual fuel selections dur ing the baseline period.

2 NR 433.02 (13) 3 EPA Air Pollution Control Cost Manual Sixth Editio n EPA/452/B-02-001 January 2002GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-3 

### 2.0 BART ENGINEERING ANALYSIS FOR BOILER NO. 6

2.1 SOURCE DESCRIPTION Boiler No. 6 is a spreader stoker-fired unit manufa ctured by Babcock and Wilcox installed in 1962. It is a two drum, balanced draft furnace, with a maximum rated heat input capacity of 350 million British Thermal Units per hour (MM Btu/hr). Boiler No. 6 b urns washed coal 4 (eastern high and low fusion and western coals) and petroleum coke. Boiler No. 6 provides steam for process heating and for the production of electrical energy using turbine gener ators. The boiler is designed for steam production at a maximum continuous rating (MCR) of 275,000 (lbs/hr) at 850 psig and 890 o F. The boiler exhaust gases pass through an air heater and then are discharged via the boiler’s induced draft fan into a common du ct connected with the flue gas discharge streams of se veral other boilers at the mill. The common duct i s equipped with a baghouse to remove particulate matt er emissions from the exhaust gases. Figure B-1 presents a side-view drawing of Boiler No. 6.

2.2 BASELINE EMISSIONS The following table presents the actual fuels fired , sulfur content of each fuel combusted, and the BART-regulated emissions generated from Boiler No. 6 during the baseline period of 2002 through

2004. Table B-1. Summary of Baseline Fuels and Emissions , Boiler No. 6

Parameter 2002 2003 2004 3-yr Average Total MMBtu All Fuels 1732160 1917674 1998835 18828 90 Tons High Fusion Coal 45060 18112 894 % S High Fusion Coal 1.01 0.96 0.96 Tons Western Coal 9997 33588 64601 %S Western Coal 0.54 0.49 0.5 Tons Low Fusion Coal 0 8771 5009 % S Low Fusion Coal 2.33 2.36 2.43 Tons Pet Coke 10971 12084 14119 % S Pet Coke 5.89 5.38 5.49 Annual Average SO 2 (lb/MMBtu) 2.22 2.52 2.14 2.29 Actual SO 2 Emissions (tpy) 1926 2413 2141 2160 Actual NO x Emissions (tpy) 375 432 477 428 Actual PM 10 Emissions (tpy) 72 79 50 67

4 Coal is washed prior to arrival at the mill as nee ded to reduce ash and achieve heat content specific ations.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-4 Figure B-1. Side View of Boiler No. 6, Green Bay B roadway MillGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-5 2.3 PARTICULATE MATTER Step 1a-Identification of Control Technologies-Typi cal Technologies in Use in the United States Technology that may be considered for the control o f particulate matter emissions from boilers include s the substitution and use of clean fuels, mechanical /gravity separation devices ( e.g., cyclones, settling chambers), electrostatic precipitators (ESPs), bagh ouses, and high efficiency wet scrubbers.

Step 1b-Identification of Control Technologies-Revi ew of RACT/BACT/LAER Clearinghouse (RBLC) Searches of the RBLC were conducted to identify con trol technologies for the control of PM 10 emissions from stoker-fired boilers. The specific category s earched was External Combustion- -11 The clearinghouse listed multiclones with ESPs, bag houses, good combustion practices and wet

scrubbers as the PM 10 control technologies.

Step 1c-Identification of Control Technologies-Revi ew of Technologies in Use at Georgia-Pacific Corporation Facilities GP operates numerous combination fuel-fired boilers and coal-fired boilers at its operating facilities within

the United States. PM 10 control devices in use at these mills include ESPs , baghouses and wet scrubbers.

Step 2-Technical Feasibility Analysis-Eliminate Tec hnically Infeasible Options All of the control options identified in Step 1 are technically feasible.

Step 3 – Ranking the Technically Feasible Alternati ves to Establish a Control Hierarchy The ranking of technologies for PM 10 control is: 1. Baghouse with greater than 99% removal efficiency 2. ESP with multiclones at greater than 99% removal ef ficiency 3. High efficiency scrubbers with 98%+ removal efficie ncy 4. Wet scrubbers with 50 to 95% removal efficiency 5. High efficiency cyclones with 50-90% removal effici ency

Step 4- Cost Effectiveness Evaluation GP currently operates a high efficiency (above 99%) baghouse to control PM 10 emissions generated by Boiler Nos. 5, 6, 7, and 8. The baghouse design in let particulate loading ranges from 1 to 3.5 grains/actual cubic foot (gr/acf) while the outlet loading is consistently at or below 0.01 gr/acf. T he baghouse design exhaust gas flowrate is 772,000 acf /minute (ACFM) at 365 °F. The existing State limitGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-6 of 0.3 lb PM 10

/MM Btu from NR 415.06(1)(b), (equivalent to 105 lb /hr at Boiler No. 6’s maximum rated capacity), is much greater than the baseline annual emission rate of approximately 17 lbs/hr 5 (equal to 0.07 lb/MM Btu) from Boiler No. 6. As th e Mill presently operates the highest ranked PM 10 control technology, no additional cost effectivenes s evaluation is necessary.

Step 5-Select BART GP is proposing to continue the use of the highest level of control, a baghouse with the current emiss ion

limit of 0.3 lb PM 10

/MM Btu.

5 Estimated with actual reported emissions presented in Table B-1 and the total operating hours for the baseline period (23520 hours). That is, [72 tons + 79 tons + 50 tons] x 2000 lbs/ton / 23,520 hours = 17.1 lbs /hr average.

Using the total MMBtu for the baseline period, the actual emissions are estimated as [72 tons + 79 ton s + 50 tons] x 2000 lbs/ton / 5648669 MMBtu = 0.07 lb/MMBtu. T hese emissions include both filterable and condensi ble particulate matter.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-7 2.4 SULFUR DIOXIDE

Step 1a-Identification of Control Technologies-Typi cal Technologies in Use in the United States Emission control equipment that may be considered t o control sulfur dioxide emissions from coal-fired

boilers includes:

1. Gas absorption using wet and dry scrubbers (90% con trol),

2. Flue gas desulfurization techniques such as sorbent injection (50 to 65% control).

3. The use of clean substitute fuels can also be consi dered as an alternative to add-on controls.

Step 1b-Identification of Control Technologies-Revi ew of RACT/BACT/LAER Clearinghouse (RBLC) Searches of the RBLC were conducted to identify con trol technologies for the control of SO 2 emissions from stoker-fired boilers. The specific category s earched was “External Combustion- -11”. The clearinghouse listed the use of clean fuels, wet an d dry scrubbers, and flue gas desulfurization techniques such as limestone injection and spray dr yer absorbers (SDA) as the control technologies.

Step 1c-Identification of Control Technologies-Revi ew of Technologies installed at Georgia-Pacific Corporation Facilities Georgia-Pacific operates numerous combination fuel- fired boilers and coal-fired boilers within the

United States. SO 2 control technologies include dry scrubbing, limesto ne and sorbent injection on fluidized bed boilers, and the use of clean fuels. However, the company has limited experience with w et scrubbing with caustic on similar types of stoker c oal-fired boilers.

Step 2-Technical Feasibility Analysis-Eliminate Tec hnically Infeasible Options The Green Bay Broadway Mill investigated several ga s absorption technologies: wet scrubbing with caust ic (sodium hydroxide) solutions, semi-dry scrubbing us ing a lime slurry with conventional scrubbers, Spra y Dry Absorbers (SDAs), and circulating fluidized bed scrubbers. Scrubber vendors have indicated to the Mill that spray drying is not technically feasible because the allowable inlet sulfur concentration as sociated with the current fuel mix would be too high and the flue gas temperatures too low to support the water evaporation requirements in the hydrated lime slurr y SDA. As a result, SDA vendors have informed GP th at they cannot provide quotations for this particular application of the technology. All of the other SO 2 control technology options are technically feasible.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-8 Step 3 – Ranking the Technically Feasible Alternati ves to Establish a Control Hierarchy The ranking of the technologies are:

1. Gas absorption with a wet spray tower or semi-dry s crubbing system with hydrated lime at 90%+

SO 2 removal efficiency,

2. In-Furnace Sorbent Injection at 65% removal efficie ncy, 3. In-duct absorption with sodium sesquicarbonate (Tro na) injection with 50% removal efficiency,

4. Fuel substitution: Low SO 2 /MMBtu coal in place of all higher sulfur containin g fuels at 40-62% removal efficiency.

Step 4- Effectiveness Evaluation

Economic Evaluation For each control technology cost estimate, the Gree n Bay Broadway Mill provided several general assumptions to the equipment vendors and engineerin g contractors for their use in determining site-spe cific cost estimates with a target accuracy of +/- 30% or better.

The Title V Permit for the Green Bay Broadway Mill limits the firing of petroleum coke to a rate demonstrated during a compliance stack test. As a r esult of these tests, the current fuel mix is limit ed to approximately 17% by weight petroleum coke and 83% coal, based on the heat content of the fuels curren tly combusted in the boiler. The cost analysis for Boi ler No. 6 considers equipment that has been designe d for

the control to accommodate an SO 2 inlet loading of 760 to 1,300 lb/hr. 6 In instances that pumps are part of the equipment design, the cost estimates include re dundant pumps to allow the control equipment to continue operating while one pump is being repaired or otherwise out-of service. In addition, the ana lysis applied a 15-year life to the capital recovery fact or calculation for scrubber technologies. Other tec hnologies with less equipment ( i.e., in furnace sorbent inject) applied a longer, conse rvative value of 20-year life for the capital recovery factor. The analysis also appl ied 8,400 hours/year and/or actual uncontrolled emi ssions to determine the direct operating costs. This appr oach is conservative in that an analysis using pote ntial emissions would overstate direct operating costs su ch as reagent use.

Wet Spray Tower with Sodium Hydroxide Cost Evaluati on The Green Broadway Bay Mill worked with several con trol equipment vendors to review technical issues and challenges with SO 2 control by using either wet, dry, or semi-dry scru bbing technologies. Based on the

6 Hourly emissions reflect the maximum heat input ra te of 350 MMBtu/hr and a range of fuel mixes repres ented as 2.17 to 3.7 pounds sulfur dioxide per MMBtu. Thoug h the stack is permitted for 4.55 pounds sulfur dio xide per MMBtu, this rate is limited by other permit conditi ons that restrict the amount of petroleum coke burn ed at any time.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-9 technical reviews, the use of a wet spray tower dem onstrates the best overall SO 2 removal efficiency of all the technologies reviewed and that were considered technically feasible. Jacobs Engineering provided the Green Bay Broadway Mill with a +/-30% cost estimate to install and operate a wet spray tower scrubber. The cost estimate for a wet spray tower scrubber as sumed that the scrubber would be located downstream of the existing baghouse. This requirement is necessa ry to maintain low PM 10 emissions entering the scrubber as the scrubber would not function properly if it w as “overloaded” with PM 10 emissions. Additionally, the proposed scrubber is not capable of replacing the b aghouse since it is not capable of reducing PM 10 emissions to the same levels achieved by the existi ng baghouse. For gas absorption, the control equipm ent was designed with a maximum flue gas exhaust gas fl ow rate of 235,000 acf per minute (ACFM). The scrubber was designed with an exhaust gas flow rate greater than the existing rate from Boiler No. 6 o f approximately 140,000 ACFM. This was done to accom modate additional exhaust gases from a slip-stream during periods of lower SO 2 influent conditions. That is, when the fuels burn ed in the boilers yield a lower inlet air concentration of sulfur dioxide, the scru bber may need to treat a larger exhaust gas flowrat e to

achieve the same SO 2 removal efficiency.

The wet spray tower scrubber operates by directing the boiler exhaust gases through an alkaline liquid solution. The flue gas would enter the wet spray t ower scrubber radially at the bottom of the unit fl owing vertically upward through the scrubber vessel, and counter-current to the alkaline solution. The clea n (scrubbed) flue gas would then be passed through a chevron-type mist eliminator for removal of large w ater droplets prior to exiting to the atmosphere through the top of the scrubber vessel. The mist eliminat or would be equipped with an internal water wash header that is activated intermittently to wash away potential

formations of reacted salts. The alkaline solution , by way of contacting the flue gas surface, promot es the absorption of the acid gases and the reduction of S O 2 from the exhaust gas stream. The alkaline solutio n used for this study is a 50% (wt.) solution of sodi um hydroxide. The caustic solution would be introd uced into the top of the scrubber vessel via multiple sp ray nozzles by a metering pump initiated by a pH an alyzer loop located in the recycle reservoir. These nozzl es would be arranged to ensure that the flue gas st ream is in complete contact with the downward flowing caust ic solution. The caustic solution would drain to t he

bottom of the absorber vessel’s reservoir and be re cycled back to the spray headers with recirculation pumps by blowing down some of the liquid based on reservo ir conductivity and adding fresh makeup water as

needed.

The clean flue gas would exit the wet spray tower s crubber and enter a new 16’-4” diameter, 316L stain less steel stack mounted on top of the new spray tower s crubber outlet. The stack would terminate at an elevation of 199 feet above grade. The stack would be sized for a flue gas velocity of approximately 34GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-10 ft/sec of saturated flue gas. The lower velocity i n the stack is critical to prevent water carry-over from stack sidewalls (as would occur when operating at higher velocities) or what is referred to as “raining” fro m the

stack exit. Stainless steel material was chosen fo r the stack to allow for good resistance to acid at tack that is possible due to contact with the saturated flue gas . Acid attack occurs mainly in the wet-to-dry inte rface in a stack. Therefore, the stack would be designed on top of the scrubber to ensure any water formation on the

internal stack wall will drain back to the scrubber

.

The existing induced draft (ID) fan on the baghouse outlet and associated drive would be reused as pre sently installed. The existing fan curves and motor horse power were reviewed and found to be adequately designed to account for the increased pressure drop created by the additional ductwork (4” w.c. drop through ductwork) and the spray tower scrubber (3” w.c. drop through scrubber). The incremental cost of the fan horsepower required for the additional scru bber and associated ductwork pressure drop is inclu ded in the operating cost for the spray tower scrubber. M oney is included in the estimate as an allowance to evaluate and seal any air infiltration due to leaka ge from Boiler No. 6’s physical structure and assoc iated

ductwork.

The cost estimate considered additional site-specif ic design conditions which have a significant impac t on the control system design and cost:

• Mill process water would be used for scrubber make- up due to evaporation during operation and for supply of water to the mist eliminator wash water h eader. However, mill process water is not available at the required pressure (greater than 65 psi) in the new scrubber area, therefore, make-up water booster pumps would also be required as part of the new scrubber system .

• While no capital has been specifically identified f or rerouting of underground lines, there are funds available in the cost estimate for “site improvemen ts”. Money for the labor and material cost for relocating process, sewer, and fire water lines wou ld come from this estimate; however, without detailed information regarding the underground line s in the installation site this may not be

sufficient. The funds included in the cost estimat e are based on the typical amount of rerouting required for an installation such as this, based on experience Jacobs Engineering (working under contract for GP) has gained from other projects.

• The existing electrical control infrastructure is n ot adequate for the additional equipment in this option. Thus, a new Motor Control Center/Rack Room was also included in the factored estimate in order to provide an area to house the electrical eq uipment for the ID Fan new pump drives.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-11 • The scrubber would be completely field-welded in pl ace due to its large size. Lower-cost shopwelded scrubber vessels cannot be used for this pro ject as they do not have the flow rate capacity required for this project.

• The 50% caustic solution storage tank would be equi pped with in-tank electric heaters and caustic metering pumps. At this level of design, the resid ence time of delivered caustic is expected to be less than one day and the estimate does not include permanent buildings for the storage tank.

To prevent the buildup of sulfur compounds in the s crubber, a waste bleed stream would be required to

remove concentrated solids. This waste stream woul d be rich in sodium and sulfur-bearing compounds created from the reaction of sulfur dioxide gases w ith the caustic solution. The waste bleed stream f rom the scrubber would be nominally comprised of 10% dissol ved sodium salts including sodium sulfate, sodium sulfite, and sodium bi-sulfite. The Green Bay Broa dway Mill has no allowance in their NPDES wastewate r discharge permit for the additional dissolved ions present in the scrubber’s wastewater stream, and therefore, simply combining the scrubber’s wastewat er with the mill’s wastewater would exceed the mill ’s NPDES permit limit for conductivity. Furthermore, w hile the Mill’s wastewater treatment system may remove most of the sulfate bearing compounds, Jacob s’ analysis has determined that the plant’s wastewa ter effluent will have the potential to discharge mercu ry above the current NPDES Permit limit. The Fox R iver is the receiving water for the wastewater plant eff luent. GP believes the ongoing study to establish a total maximum daily limit (TMDL) of mercury discharges in to the Fox River disqualifies the discharge of wet scrubber blow down into the plant’s wastewater trea tment system. To eliminate the mercury discharge issue, Jacobs’ cost estimate has included a dedicat ed, separate wastewater treatment process to remove solids (including mercury and other metals) using c oncentration and evaporation methodology.

The preferred alternative for managing scrubber was tewater is the use of a recirculating evaporator/ condenser/ccentrifuge system. In this design, the wastewater bleed from the scrubber would enter a se ries of preheated steam condensing exchangers, and then move on to the evaporator crystallizer vvessels. B y evaporating water, the salt solution would be conce ntrated past its solubility point, resulting in the formation of solid crystals. The wastewater stream from the evaporator crystallizer vvessel would be taken to a centrifuge, where any solid crystals present would be separated to form a solid waste stream. The sol id waste stream would drop into a truck that will then be transported to a landfill. The evaporated wate r would be condensed with mill process cooling water. The condensed water would be the then used as a clean water stream for potential use at the mill.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-12 The spray tower scrubber evaluated has a 24’ by 30’ footprint and the scrubber absorber vessel is 19’- 3” in diameter and stands approximately 58’ tall. The bo ttom of the absorber would be raised several feet a bove grade to allow for access to auxiliary equipment lo cated underneath at grade. The steel structure wou ld terminate at the stack testing platform level. N ew 10’ x 10’ ductwork would be added to transfer fl ue gas from the existing roof-mounted dual chamber baghous e ID fans outlets to the spray tower scrubber’s inl et. Figure B-2 presents a simplified general equipment arrangement.

Table B-2 summarizes the estimated capital costs to install a complete wet spray tower scrubber system

. The total installed cost is estimated to be equal t o $33,062,714.GP Consumer Products Green Bay MillBest Available Retrofit Technology AnalysisMarch 2009B-13Figure B-2. General Arrangement of Wet Spray TowerSystem, Green Bay Broadway MillGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-14 Table B-2. Summary of Capital Cost for Installatio n of Wet Spray Tower Scrubber System, Boiler No. 6 Green Bay Broadway Mill Description 7 Total Cost (2007$) 8

Direct Costs Major Equipment 8,971,255 Demolition 14,522 Site Improvements 448,563 Piling, Caissons 627,988 Buildings 502,180 Concrete 741,100 Structural Steel 1,644,865 Piping 2,496,353 Insulation - Pipe, Equipment & Ductwork 643,899 Instrumentation 715,662 Electrical 1,088,346 Painting, Protective Coatings 89,713 Construction Indirect Costs Construction Support Labor 778,526 Premium Time 229,937 Craft Per Diem ($7/Hour On 100 % Of Time) 493,602 Non-Payroll Tax, Insurance & Permits 775,873 Craft Start-Up Assistance 32,717 Contractor's Construction Fee 1,441,756 Project Indirect Costs Construction Management 1,493,050 Engineering Professional Services 3,315,140 Study Cost 50,000 Outside Consultant Services 100,000 Owner's Cost 993,118 Spare Parts 343,840 Non-Craft Start-Up Assistance 89,306 Allowance For Unforeseen 2,804,624 Escalation 2,036,801 Air Infiltration Allowance 9 $100,000 Total Installed Cost (TIC)(+/- 30%) $33,062,714

7 See Appendix for further description of estimator’ s cost categories 8 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 9 Modifications to the exhaust system are expected t o require studies and upgrades to eliminate air inf iltration.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-15 To determine estimated operating costs for the scru bber, this cost analysis used the templates provide d by EPA in their Cost Control Manual. Determining ann ual operating costs is sensitive to the amount of s ulfur dioxide removed and the amount of scrubbant require d to maintain the desired SO 2 removal efficiency. The 2002-2004 actual emissions are significantly lower than permitted emissions ( i.e.., 2.29 lbs SO 2 /MMBtu in 2002-2004 compared to permit limit of 4.55 lb SO 2 /MMBtu) and thus represent a conservatively lower annualized cost estimate. Table B-3 presents opera ting costs for the spray tower technology.

Table B-3. Annual Operating Cost Calculations, Wet Spray Tower for Boiler No. 6, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($)

Direct Costs Operating labor : 1 hours per shift x 1095 shifts/y r @ $40/hr 43,800 Supervisor Labor 15% of Operator costs 6,570 Maintenance labor: 0.5 hours per shift x 1095 shift s/yr @ $40/hr 21,900 Maintenance material 100% of Maintenance Labor 21,900

Electricity 0.059$/kWhr x 11,160,688 kWhr/yr 658,481

Caustic Solution 10 $1,050/dry ton NaOH x 3,375 ton NaOH 3,543,750 Process water: $0.06/kgal x 976,039 kgal 58,562 Landfill Scrubber system solids $ 9.50/ton x 24,878 tons 236,341 Additional Process Steam $2.45/klb steam x 186,588 klbs 457,141

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 56,502 Taxes, insurance, admin. factor: 4% of TIC (Table B -2) 1,322,509 Capital recovery factor (system): 0.1098 x TIC 11 3,630,108

Total Annual Cost 10,057,563

10 2002-2004 actual SO 2 tons = 2,160 emitted; consumption is 2.5 lb-mol Na OH per lb mol of SO 2 emitted; 2008 average unit cost of caustic as delivered to Mill = $1,050/dry t on NaOH;

2,160 tons SO 2 x 2,000 lbs/ton x lbmol SO 2 /64 lbs SO 2 x 2.5 lb-mol NaOH/lb-mol SO 2 x 40 lbs NaOH/lb-mol NaOH / 2,000 lbs/ton =3,375 tons dry NaOH

11 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: (0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

The cost effectiveness of this technology is equal to the Annual Operating Costs/ Annual Quantity of S O 2 Removed.

The estimated cost effectiveness is: $ 10,057,563 / (90% x 2,160 tons) = $5,174/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-16 Dry Scrubbing with Hydrated Lime Fluidized Bed Abso rber (FBA) Cost Evaluation

Dry scrubbers have significantly lower capital and annual operating costs than wet systems because the y are simpler, demand less water, and waste disposal is l ess complex. Dry injection systems are easier to i nstall and use less space; therefore, they are good candid ates for retrofit applications, such as the one at the Green Bay Broadway Mill. In contrast to a wet spray towe r, FBAs use a reactor vessel with a closely control led temperature. Both an even distribution of sorbent across the reactor and adequate residence time at t he proper temperature are critical for the best SO 2 removal rates 12

.

Flue gas from the boiler would enter the bottom of the fluid bed absorber. Water would be first spraye d into the gas stream to cool the flue gas to near adiabat ic conditions to improve adsorption. Once the flue gas stream is cooled, hydrated lime would be added to t he reactor at a rate of approximately 5,000 lbs per hour.

The SO 2 would react with the hydrated lime to form calcium sulfate. The unreacted hydrated lime, fly ash, spent lime, and calcium sulfate would then be captu red in the fabric filter and then recirculated back to the inlet of the fluidized bed absorber. Fresh hydrated lime would be added to the circuit to maintain abs orber

SO 2 removal efficiency. The system would bleed out exc ess spent material for disposal using the same methods presently used for boiler ash disposal. Be cause the original design of the baghouse is much l arger than the flue gas volume from the current boilers, the mill expects that the existing baghouse will co llect the additional particulate loading and maintain its hig h removal efficiency from an FBA without significan t

modification.

ESI Inc. of Tennessee provided the Green Bay Broadw ay Mill with a +/-20% cost estimate to install an FBA system.

The FBA cost estimate reflects the installation and operation of the following new equipment:

• new fluidizing bed reactor 18' diameter x 100' over all height,

• solids recirculation systems,

• pre-piped lime slurry pump skids,

• booster fans,

• 210-ton powdered hydrated lime silos with fabric fi lter to collect dust from silo loading,

• a hydrated lime bulk pneumatic truck unloading stat ion,

• rotary hydrated lime volumetric hydrated lime feede rs,

• shutoff dampers (double sealing) with purge air blo wers for safe access to confined spaces.

12 Srivastava, 2001. Srivastava R. K., and W. Josew icz.. “Flue Gas Desulfurization: The State of the A rt”. Air and Waste Management Assoc., 51:1676-1688, 2001.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-17 Table B-4 summarizes the total cost for installatio n of the FBA system.

Table B-4. Summary of Capital Cost for Installatio n of Fluidized Bed Absorber System, Boiler No. 6 Green Bay Broadway Mill Description Total Cost (2008$) 13

Scrubber systems installation and duct modification s 10,158,367 Footings and foundation work 405,000 Electrical and controls 929,094 Structural steel 285,000 Engineering and commissioning 1,228,922 Construction management 829,523 General contractor overhead and mark-up 1,013,861 Contingency 1,536,153 Emission Monitoring systems 180,000 Piping 61,760 Freight 591,961 Miscellaneous 270,000 Total Installed Cost (TIC) (+/-20%) 17,489,639

13 BART Preliminary Engineering Study (ESI Inc. of Te nnessee March 2008)

Figure B-3 represents a simplified flow diagram of the required equipment for a generic case of any on e of

several boilers at the mill. In contrast to the we t spray tower scrubber technology, most of the equi pment will be located within the existing buildings at a point upstream of the baghouse. Figure B-4 present s a footprint diagram.GP Consumer Products Green Bay MillBest Available Retrofit Technology AnalysisMarch 2009B-18Figure B-3. Schematic of Process Equipment for Fluidized Bed Absorber, Generic CaseGP Consumer Products Green Bay MillBest Available Retrofit Technology AnalysisMarch 2009B-19Figure B-4. Equipment Arrangement for Fluidized Bed Absorber, Generic CaseGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-20 To determine annual operating costs, the analysis f ollowed US EPA’s Cost Control Manual templates 14 with some equipment-specific adjustments. Table B -5 presents the annual operating costs for the FBA technology.

Table B-5. Annual Operating Cost Calculations, Flu idized Bed Absorber for Boiler No. 6, Based on Actu al 2002-2004 Emissions and Operating Conditions Parameter Methodology Annual Cost ($) 

### Direct Costs Operating labor : 3 hour per shift x 1095 shifts/yr @ $40/hr 131,400 Supervisor Labor 15% of Operator Costs 19,710 Maintenance labor & equipment: Vendor Estimate 10% of Equipment Costs 910,000

Electricity- direct 0.059$/kWhr x 6,864,000 kWhr/yr 404,976 Electricity- fan make-up 8 inches w.c 201,680 Hydrated Lime $90/ ton hy. lime x 8,932 ton hy. Lim e/yr 15 803,853 Process water: $0.06/kgal x 8,400 kgal 504 Landfill Scrubber system solids $ 9.50/ton x 29,601 tons 276,080



### Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 636,666 Taxes, insurance, admin. factor: 4% of TIC (Table B-4) 699,586 Capital recovery factor (system): 0.1098 x TIC 16 (Table B-4) 1,920,268

Total Annual Cost 6,004,723

14 EPA Air Pollution Control Cost Manual Sixth Editio n EPA/452/B-02-001 January 2002

15 2002-2004 actual SO 2 tons = 2,160; consumption is 3.25 lb-mol hydrated lime per lb mol of SO 2 removed; 2008 average unit cost = $275 dry ton hydrated lime

2,160 tons SO 2 x 2,000 lbs/ton x lb-mol SO 2 /64 lbs SO 2 x 3.25 lb-mol hydrated lime/lb-mol SO 2 x 74.1 lbs hydrated lime / lbmol hydrated lime / 2,000 lbs/ton x 1ton pure CaCO3 /0.91 ton hydrated lime = 8,932 tons hydrated lime

16 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: (0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and scrubbant required. The 2002-2004 emission rates are signifi cantly lower than permitted emissions and thus repr esent a conservatively lower annual cost (and operation) estimate. The cost effectiveness of this technology is equal to Annual Costs/ Annual SO 2 Removed. The estimated cost effectiveness is: $6,004,273/ ( 90% x 2,160 tons) = 3,089 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-21 Furnace Sorbent Injection (FSI) Cost Evaluation As an alternative to “back-end” controls, the Green Bay Broadway Mill assessed control technologies further upstream. One such technique involves inje cting a sorbent into the combustion chamber of the

boiler with the fuel. As additional material in th e boiler can significantly affect boiler performanc e, this technology is coupled with improving the air distri bution system within the boiler. The technology ha s been demonstrated on stoker-fired boilers, however, an u nknown risk to operations is the potential erosion of

boiler furnace tubes due to the additional sorbent material injected into the combustion chamber of th e boiler. The FSI technology is similar to the dry s crubbing system in that it eliminates management of wet streams and has a small equipment footprint relativ e to wet scrubbing systems. Limestone with a high

CaCO 3 content would absorb SO 2 as the fuel sulfur is oxidized in the furnace. Th e resultant particulate would be carried out with the boiler flue gas and t hen captured in the existing baghouse. As mentioned earlier, the mill expects that the existing baghous e would collect the additional particulate and main tain its high removal efficiency from an FBA without signifi cant modification, and the same expectation holds f or any additional particulate resulting from FSI.

The Green Bay Broadway Mill selected Mobotec USA as a vendor to develop an equipment cost estimate for a Furnace Sorbent Injection (FSI) system. Mobo tec USA would supply the injection equipment, mixin g nozzles (ROTAMIX), and rotating overfire air fans ( ROFA) for such a system, which would also be considered a technically feasible NOx control techn ology. Installation of the ROFA system includes a new overfire air fan that will take suction from the ho t combustion air side of the boiler’s existing air preheater, a new ductwork system, and multiple ROFA boxes instal led on the furnace walls. A detailed study for appropriate placement of the FSI system nozzles and injection locations was not conducted for Boiler N o. 6; however, the cost estimate includes a one time stud y cost of $50,000.

The installed equipment required for the FSI system includes a:

• Limestone storage silo with truck unloading connect ions, a baghouse to control loading emissions, feed hoppers, screw feeders and rotary valves, puls e system and isolation valves;

• A new blower with the pneumatic limestone feed pipi ng system and injection devices mounted on the furnace wall, and;

• Additional fans, ductwork and controls for ROFA box es.

The BART estimate includes additional (above those normally factored) allowances for demolition and relocation inside of the building around Boiler No. 6 due to the extensive amount of ductwork and inje ctionGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-22 piping required for the FSI system. Extensive layo ut and engineering planning would be required at th e time of design to make the installation of this sys tem functional in regards to good maintenance acces s and basic boiler walk-around access. The physical loca tion of Boiler No. 6 is a congested area that is immediately adjacent to other boilers which in turn may limit the ability to locate ROFA boxes and inj ection lances in the optimum positions predicted by the st udy. The total installed cost (TIC) for the FSI sys tem is $26,827,507. Table B-6 presents the total install ed costs for an FSI system for Boiler No. 6.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-23 Table B-6. Summary Of Capital Cost For Installatio n Of FSI System, Boiler No. 6 Green Bay Broadway Mill Description 17 Total Cost (2007$) 18 Major Equipment 5,926,151 Demolition 811,138 Site Improvements 491,316 Piling, Caissons 631,692 Buildings 330,000 Concrete 828,031 Structural Steel 1,497,449 Piping 1,886,064 Insulation - Pipe, Equipment & Ductwork 296,308 Instrumentation 658,012 Electrical 1,014,583 Painting, Protective Coatings 59,262 Construction Indirect Costs Construction Support Labor 711,432 Premium Time 209,454 Craft Per Diem ($7/Hour On 100 % Of Time) 451,063 Non-Payroll Tax, Insurance & Permits 504,113 Craft Start-Up Assistance 43,650 Contractor's Construction Fee 1,242,334 Project Indirect Costs Construction Management 1,209,000 Engineering Professional Services 2,683,000 Study Cost 50,000 Outside Consultant Services 100,000 Owner's Cost 804,000 Spare Parts 245,193 Non-Craft Start-Up Assistance 119,150 Allowance For Unforeseen 2,275,240 Escalation 1,649,872 Air Infiltration Allowance 100,000 TOTAL INSTALLED COST (TIC) (+/-30%) 26,827,507

17 See Appendix for further description of estimator’ s cost categories 18 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs EngineeringGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-24 Table B-7 presents annual operating costs for the F SI system. Without a site-specific study by Mobotec , the economic analysis could not estimate what, if any, loss of steaming capacity would occur with the significant amount of “dead load” material ( i.e., sorbent) added into the furnace. The operating cos ts also do not include lost steam production due to increased wear on boiler tubes. Though the increased rate of tube erosion cannot yet be determined, the operation of the boiler will be affected by a significant increa se in tube wall inspections following startup with an FSI system.

Table B-7. Annual Operating Cost Calculations, FSI for Boiler No. 6, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hour/shift x 1,095 shifts/year @ $40/hr 43,800 Supervisor Labor 15% of Operator costs 6,570 Maintenance labor: 0.5 hrs/shift x 1,095 shifts/yea r @ $40/hr 21,900 Maintenance material 100% of Maintenance Labor 21,9 00

Electricity- direct 0.059$/kWhr x 3,437,500 kWhr 20 2,813 Limestone $40/ton limestone x 10,978 tons 19 439,189 Landfill Additional system solids $ 9.50/ton x 10,9 78 tons 104,291

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 56,502 Taxes, insurance, admin. factor: 4% of TIC (Table B -6) 1,073,100 Capital recovery factor (system): 0.0944 x TIC 20 (Table B-6) 2,532,327

Total Annual Cost 4,502,391

19 2002-2004 actual SO 2 tons = 2,160; consumption is 3.25 lb-mol limestone per lb mol of SO 2 ; Average unit cost is $40/ton delivered.

2,160 tons SO 2 x 2,000 lbs/ton x lb-mol SO 2 /64 lbs SO 2 x 3.25 lb-mol limestone /lb-mol SO 2 x 100.1 lbs limestone (CaCO 3 )/ lb-mol limestone / 2,000 lbs/ton = 10,978 tons lime stone

20 7% interest for the cost of capital and an equipme nt life of 20 years using Equation 2.8a of USEPA Co st Control Manual yields: (0.07*(1+0.07)^20)/((1+0.07)^20-1) = 0.094 4

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent required. The 2002-2004 actual emissions are signi ficantly lower than permitted emissions and thus represent a conservatively lower annual cost (and o peration) estimate.

The cost effectiveness of this technology is equal to Annual Costs/ Annual SO 2 Removed. The estimated cost effectiveness is: $4,502,391/ ( 50% x 2,160 tons) = 4,169 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-25 In-Duct Absorption System with Trona Cost Evaluatio n In contrast to injecting sorbent into the boiler or using a wet spray tower scrubber vessel, in-duct a bsorption is an alternative capable of obtaining a 50% reduct ion in SO 2 emissions from Boiler No. 6. Unlike the other

SO 2 removal technologies described above, this technol ogy does not have many similar applications in commercial operation. With the use of this technol ogy, offered by O’Brien and Gere, the sorbent is fe d into the flue gas as a dry powder. The sorbent (sodium sesquicarbonate, or Trona) undergoes thermal decomposition and reacts with sulfur dioxide in the flue gases to form a particulate. Approximately o nethird of the sorbent mass forms carbon dioxide and exhausts to the atmosphere while the other two-thir ds of the particulate mass is captured in the existing ba ghouse. The supply market for this sorbent is lim ited to a

few active mines in western United States. Without multiple sources for Trona, deliveries to the mill are at higher risk of supply interruptions ( e.g., natural or other external events) than sorbents wi th many suppliers.

For Boiler No. 6, Trona would be injected between i nto the flue gas stream between the boiler’s econom izer outlet and the air preheater inlet where the flue g as exhaust temperature is approximately 700°F. Ven dor experience indicates that this is the optimum tempe rature for SO 2 removal for this sorbent application and type of boiler. The thermal decomposition at this t emperature increases the amount of surface area on the Trona particle, and increases its SO 2 capture efficiency. The chemical reaction taking pl ace in the flue gas stream with Trona injection is shown below:



### 2(Na 2 

### CO 3 

### • NaHCO 3 

### • 2H 2 

### O) + 3SO 2 

### → 3Na 2 

### SO 3 

### + 4CO 2 

### + 5H 2 

### O

As shown, the use of Trona will result in the relea se of 4 moles of CO 2 for every 2 moles of Trona.

The particle size specification for Trona injection is a minimum of 90% by weight shall be no larger t han 10 microns in diameter. If the Trona particles are not ground properly, the consumption of Trona in the f lue gas stream will be significantly higher, thereby result ing in higher operating costs.

Jacobs Engineering provided the Mill with a +/-30% cost estimate to install a Trona injection system. The capital cost estimate includes the following eq uipment: • 2 Trona silos (approximately 16' diameter and 40' high), • 3 Trona pulverizers, particle size classifiers, f eeders and blowers, and • Trona pneumatic truck unloading station with a ba ghouse for PM control.

Table B-8 presents a summary of installation the in stalled costs for the In-Duct Absorption System.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-26 21 See Appendix for further description of estimator’ s cost categories 22 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 23 Modifications to the exhaust system are expected t o require studies and upgrades to eliminate air inf iltration. Table B-8. Summary of Capital Cost for Installatio n of In-Duct Absorption System, Boiler No. 6 Green Bay Broadway Mill Description 21 Total Cost (2007$) 22

Direct Costs Major Equipment $5,400,000 Demolition $250,000 Site Improvements $135,000 Piling, Caissons $250,000 Buildings $120,000 Concrete $121,500 Structural Steel $486,000 Piping $459,000 Insulation - Pipe, Equipment & Ductwork $243,000 Instrumentation $135,000 Electrical $297,000 Painting, Protective Coatings $27,000 Construction Indirect Costs Construction Support Labor $164,232 Premium Time $47,350 Craft Per Diem ($7/Hour On 100 % Of Time) $104,126 Non-Payroll Tax, Insurance & Permits $223,644 Craft Start-Up Assistance $43,650 Contractor's Construction Fee $323,046 Project Indirect Costs Construction Management $322,000 Engineering Professional Services $715,000 Outside Consultant Services $100,000 Owner's Cost $378,000 Spare Parts $279,450 Non-Craft Start-Up Assistance $119,150 Allowance For Unforeseen $1,074,315 Escalation $603,026 Air Infiltration Allowance 23 $100,000

Total Installed Cost (+/- 30%) (TIC) $12,520,489GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-27 The total installed cost (TIC) is $12,520,489. Ta ble B-9 presents the annual operating costs for the In-Duct Absorption System.

Table B-9. Annual Operating Cost Calculations, In- Duct Absorption System for Boiler No. 6, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hr/shift x 1,025 shifts/yr @ $4 0/hr 41,000 Supervisor Labor 15% of Operator 6,150 Maintenance labor: 0.5 hrs per day x 350 days/yr @ $40/hr 7,000 Maintenance material 100% of Maintenance Labor 7,00 0

Electricity 0.059$/kWhr x 2,534,375 kWhr 149,528 Trona consumption $150/ton Trona x 1.8 tons Trona/h r 24 x 8,400 hr/yr 2,268,000 Landfill Additional Baghouse solids $ 9.50/ton x 1. 5 tons solids/hr x 8,400 hrs/yr 119,700

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 36,690 Taxes, insurance, admin. factor: 4% of TIC (Table B -8) 500,820 Capital recovery factor (system): 0.0944 x TIC (Tab le B-8) 1,181,846

Total Annual Cost 4,317,733

24 Reagent usage of 3600 lbs/hr estimated by vendor

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent required. The 2002-2004 actual emissions are signi ficantly lower than permitted emissions and thus represent a conservatively lower annualized cost (a nd operation) estimate.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of S O 2 Removed. The estimated cost effectiveness is: $4,317,733/ ( 50% x 2,160 tons) = 3,998 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-28 Clean Fuels Cost Evaluation

As mentioned above, Boiler No. 6 combusts several f uels with the existing equipment: eastern coal (hig h / low fusion), western coal and petroleum coke. The o nly fuel limited by the air permit is the amount of petroleum coke to approximately 17-21% by weight of total fuel. All solid fuels are stored outdoors i n a common area. Table B-10 presents the range of heat content, as well as ash and sulfur content of the

various fuels combusted in the boiler.

Determining marginal costs of fuel with different s ulfur concentrations is reasonably certain when usi ng short-term “future” forecasts. As the period for f uel forecasting is extended, uncertainty rapidly in creases. Therefore, the unit costs below are presented as a range where estimated. Subsequent calculations use the average of the high and low end of the range.

Table B-10. Comparison of Various Fuels Fired in B oiler No. 6, Green Bay Broadway Mill

Fuel Sulfur % MMBtu/ton $/MMBtu 2007-2009 25 Petroleum Coke 5 to 6.5 27.6-28.4 1.71 Eastern Low-fusion Coal 2.5-2.7 25.4-27.0 3.35 Western Coal 0.4-0.7 20.6-23.6 4.55 Eastern High-fusion Coal 0.9 – 1.5 24-25.5 3.60

25 Prices reflect cost from source delivered to the M ill between 2007 and 2009. Year-to-year prices are volatile.

An additional difference between the fuels is the e stimated CO 2 emissions. CO 2 Emissions from petroleum coke combustion is approximately 10 to 15% above co al combustion (on a lb/MMBtu basis). The cost evaluation compared the following three op tions with increasing emission reduction:

1. Switch 100% of petroleum coke to eastern high fusio n coal

2. Switch 100% of petroleum coke to western coal

3. Switch 100% of all fuel to western coal

Table B-11 presents a summary of the sulfur dioxide emission estimates and fuel costs for each case.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-29 Table B-11. Clean Fuel SO 2 Emission Calculations, Boiler No. 6, Green Bay Bro adway Mill

Eastern Coal Parameter High Fusion Low

Fusion Western

Coal Petroleum

Coke Total

2002-2004 MMBtu Estimate (annual) 528,545 120,345 796,970 346957 1,792,817 2002-2004 Tons (annual) 21,355 4,593 36,062 12391 74,402 Sulfur into the Boiler (tpy) 213 109.6 184 694 1200 Percent of total SO 2 Emissions 18% 9% 15% 58% SO 2 Emission Estimate (tpy) 383 197 331 1249 2160 Fuel Cost (MM$) 1.903 0.40 3.63 0.59 6.53

Case 1 : Switch from Petroleum Coke to Eastern High Fusion MMBtu 875,502 120,345 796,970 -- 1,792,817 Tons Fuel 35,374 4,593 36,062 -- 76,029 Sulfur into the Boiler (tpy) 352 109.6 184 -- SO 2 Emission Estimate (tpy) 704 219 368 -- 1291 Fuel Cost (MM$) 3.15 0.40 3.63 -- 7.18

Case 2 : Switch from Petroleum Coke to Western Coal MMBtu 528,545 120,345 1143928 -- 1,792,817 Tons Fuel 20,251 4,593 51761 -- 76,606 Sulfur into the Boiler (tpy) 251 110 264 -- SO 2 Emission Estimate (tpy) 502 219 528 -- 1,249 Fuel Cost (MM$) 1.90 0.40 5.20 -- 7.51

Case 3 Switch All Fuels to Western Coal MMBtu Fuel -- -- 1,792,817 -- 1,792,817 Tons Fuel -- -- 81,123 -- 81,123 Sulfur into the Boiler (tpy) -- -- 414 -- SO 2 Emission Estimate (tpy) -- -- 827 -- 827 Fuel Cost (MM$) -- -- 8.16 0 8.16

Table B-12 summarizes the annual marginal fuel cost s and emissions reductions relative to 2002-2004

actual emissions for these cases.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-30 Table B-12. Summary of Fuel Cost Increases for Vari ous Fuel Switch Cases, Green Bay Broadway Mill Case Parameter 2002-2004 1 2 3

Average $/MMBtu $3.64 $4.01 $4.19 $4.55

SO 2 Emissions (tpy) 2,160 1291 1249 827 Emission Change (tpy) NA 869 911 1,333 Reduction Efficiency (%) 40% 42% 62% Fuel Cost ($/yr) $6,525,429 $7,181,178 $7,510,787 $ 8,157,319 Fuel Cost Increase ($/yr) NA $655,749 $985,359 $1,6 31,891 Cost Effectiveness Fuel Price Only ($/ton) NA 755 1 ,082 1,225

Though Boiler No. 6 is equipped to handle the vario us fuel selections of the three cases above, the ac tual operating costs for ash hauling and disposal will i ncrease. Petroleum coke ash content is near 0.5% compared to 12 % for western coal. Based on using the Mill’s current unit cost for ash disposal of $9 .50 per ton, additional operating costs of approximately 0. 03 to 0.05 $/MMBtu will be incurred, or, an increas e of approximately $90,00 per year.

Summary of Economic Evaluation, SO 2 Controls for Power Boiler No. 6 The economic evaluation determined a range of cost effectiveness values for the following levels of co ntrol: Less than 50%, 50%, 62%, and 90%. Figure B-5 prese nts a marginal cost curve for the cost estimates presented in Table B-2 through B-12.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-31 Figure B-5 Marginal Cost Curve for SO 2 Control Options, Green Bay Broadway Mill Boiler No . 6

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions Control options: 42% removal by Clean Fuels (case 2); 50% removal by FSI or in-duct sorbent injection ; 62% removal by Clean Fuels (case 3); 90% removal by wet or dry scrubber

Incremental Costs In addition to marginal cost effectiveness, the inc remental cost effectiveness can be used to compare the additional cost for a higher level of control. USE PA guidance indicates that “the incremental cost

effectiveness should be examined in combination wit h the average cost effectiveness in order to justif y elimination of a control option.” 26 The incremental cost effectiveness formula is as follows:



## ( Annual Costs ($/yr) 

## | Control Option – Annual Cost ($/yr) 

## | Next Control Option 

## ) / Change in Controlled Emissions (tpy)

26 New Source Review Workshop Manual Draft (USEPA, 19 80) 

### 0 1000 2000 3000 4000 5000 6000

500 1000 1500 2000 2500

Actual Tons Removed Per Year (tpy)Cost Effectiveness ($/ton)



### Low Cost High Cost 90%

62% 50%

40-42%GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-32 Figure B-5 graphically shows a large increment in c ost effectiveness is between the 62% control option (clean fuels) and the 90% control option (scrubber) . The incremental cost effectiveness between the t wo options is:

($8,031,143/yr for scrubbers (average of either wet or dry) – $1,631,891/yr for Clean Fuels) / ((1-62% x 2,160 tons) – (1-90% x 2160 tons)) = $6,399,253 additional annual cost/ 605 additional tons SO 2 removed = $10,581 /ton for additional reductions in SO 2 emissions beyond the clean fuel option.

Energy and Environmental Impacts Throughout the economic analysis, the cost estimate s documented, where possible, the actual costs for additional energy consumption, additional water dem and, and addition solid waste generated. Also in e ach technology discussion, the analysis discussed envir onmental impacts. Table B-13 summarized a comparison of energy and environmental impacts for each option.

Table B-13. Summary of Additional Impacts for SO 2 Control Technologies, Boiler No. 6

Technology Impacts Scrubber FSI/ Induct Injection Clean Fuels Additional Energy (kWhr/yr) up to 11,160,688 3,437, 500 None Additional Water (million gal) up to 976 None None Additional Solid Waste (tons) 29,601 10,978 up to 7 ,900 Environmental Impacts Treatment of metals in waste stream Higher PM 10 Loading to Baghouse Higher PM 10 Loading

to Baghouse

Other Impacts Wet Plume Additional CO 2 from Trona decomposition; FSI may reduce NOx Less CO 2 emissions

SO 2 Engineering Analysis Summary Through a detailed comparison of many site specific issues and costs, the Mill believes a 62% level of

control of SO 2 is economically feasible for Boiler No. 6. The in cremental cost effectiveness for options greater than 62% control ( i.e., a scrubber) is greater than $10,000/ton and is eco nomically infeasible. The expected annual cost to meet an SO 2 removal efficiency of 62%, compared to the baselin e period of 2002 through 2004, is $1.63 million per year.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-33 2.5 NITROGEN OXIDES Step 1a-Identification of Control Technologies-Typi cal Technologies in Use in the United States The following sections discuss the technologies typ ically available for multi-fuel stoker-fired boiler s including reduction of nitrogen content in fuels wi th the use of clean fuels, chemical selective catalytic/noncatalytic reduction, combustion air im provements, reducing the residence time at peak combustion operating temperature, and reducing the peak combustion temperature inside of the boiler.

Removal of Nitrogen Ultra-Low Nitrogen Fuel –The range of fuels typically combusted in stoker- fired boilers can range from wood/bark to coal and pet-coke. The combustion of fuel with lower nitrogen content may result in slightly lower emissions of NO x . However, this relationship is not well understood 27 . The variety of solid fuels normally combusted in Boiler No. 6 ( i.e., petroleum coke and coal) are comparable in nitrogen content. A fuel substitution from convent ional fuels to wood or bark would introduce lower levels of nitrogen, but a much higher moisture cont ent. The high moisture content of bark results in lower combustion temperatures than that of petroleu m coke or coal that may result in less thermal NO x formation. However, fuel substitution using wood wo uld result in a loss of heat from nearly 24

MMBtu/ton for coal to less than 10 MMBtu/ton for wo od. Substituting wood for coal and/or pet coke

would derate the boiler to less than 50% of its des ign capacity. Additionally, the boiler is not desi gned

to accommodate bark as the lower heat release rate does not match the design of other boiler internal elements ( e.g., tube sections, economizer). Though lower in fuel nitrogen, the use of wood in the boiler would require an evaluation of the existing baghous e and may require additional equipment to continue

to meet the current PM emission limits.

Chemical Reduction of NO x Selective Catalytic Reduction – Selective Catalytic Reduction (SCR) uses a catal yst to react with injected ammonia to chemically reduce NO x to elemental nitrogen, carbon dioxide and water vap or. The catalyst has a finite life in the flue gas, and som e ammonia slips through the boiler without reacting

. SCR has historically used precious metal catalysts, which are quite expensive, but can now also use le ss costly base metal and zeolite catalyst materials. Important considerations in the design, operation a nd maintenance of an SCR application include physical access, flue gas temperature, flue gas velocity, sulfur content, and particulate matter loading. If a conventional catalyst system is used, the SCR rea ctor must be located at a point where the flue gas tempe rature is no greater than 780 degrees Fahrenheit ( o F)

27 Fortune, D. "Influence of nitrogen content of coal on NOx emissions from pulverised fuel systems", In ternal Shell Coal Report No. LMD03068.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-34 and no lower than approximately 570 o F. Other options are available for using catalysts - higher temperature and lower temperature – but both of the se options are more expensive.

If the SCR reactor can be located in a position whe re the flue gas temperature ranges between 570 to

780 o F (nominal), then no preheating of the flue gas is required. There are high-temperature (>800 o F) and low-temperature (250 to 650 o F) catalysts, however, the high-temperature catalys ts are more

effective at NOx removal and can accommodate a broa der range of fuel characteristics, higher sulfur levels in the fuel, and trace metals in the flue ga s. However, the selection of a high temperature ca talyst usually means reheating the flue gas which is rarel y a cost-effective approach since a large quantity of fuel must be used to heat the flue gas stream to th e proper temperature for the catalyst to work effectively.

Another important consideration is the flue gas vel ocity through the SCR catalyst bed. For most applications, the flue gas velocity exiting the boi ler is too high to provide sufficient residence tim e for the catalyst to provide the level of reaction requi red to reduce NO x emissions. For this reason, the exhaust ductwork must be expanded to allow for a re duction in the flue gas velocity dictated by the catalyst vendor, which will be approximately 20 fee t per second (ft/s) depending on the fuel.

Another key consideration is the additional pressur e drop across the SCR reactor bed. The pressure drop due to the use of a catalyst bed is approximat ely 1 to 1.5 inches water (H 2 O), but there will be additional pressure drop due to the expanded ductwo rk and the addition of a static mixing device to maintain a uniform flow across the catalyst bed.

The SCR catalyst design, and therefore life expecta ncy, is based on the particulate matter loading and sulfur content of the flue gas stream. The catalys t design takes into account the particulate matter loading and the expected contaminants in the flue g as – more difficult fuels are typically handled usi ng a larger pitch ( e.g., pore size) which translates into an increase in tre atment length and additional pressure drop. GP did receive one quotation for a “ tail-end” SCR installation behind the current baghouse. Application of SCR is technically feasi ble in a “back-end” system approach with a typical removal efficiency of 70% to 80% for a retrofit ins tallation.

Selective Non-Catalytic Reduction – In a SNCR system, ammonia or urea is injected in the combustion chamber of a boiler or in ductwork in a region wher e the temperature ranges between 1,600 and 2,000oF. This technology is based on high temperat ure ionization of the ammonia or urea instead of using a catalyst. The temperature window for SNCR is very important because if the temperature is too low, there may be more ammonia slip through the sys tem or, if the temperature is too high, more NO x isGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-35 generated than is being chemically reduced. SNCR h as been demonstrated as a feasible technology for

stoker-fired boilers and can achieve variable reduc tions of 25 to 50 percent. Site-specific assessmen ts are required by SNCR vendors for each application.

Based on the above discussion, SNCR is considered t o be technically feasible for Boiler No. 6.

Reducing Residence Time at Peak Operating Temperatu re

Air Staging of Combustion – An overfire air (OFA) system modifies the combus tion air system through the installation of air ports and potentially new f ans. Air ports are designed to inject air at the p roper velocity to complete combustion prior to the furnac e exit. Combustion air inside of a boiler is divide d

into two streams. The first stream is mixed with fuel in a ratio that produces a flame in an oxygendeprived zone. The second stream is injected downs tream of the flame and creates an oxygen-rich zone where combustion is completed. OFA modifications l ower the flame temperature, reducing thermal

NO x and reducing the amount of oxygen available in the flame zone for conversion of fuel nitrogen species to NO x , reducing fuel NO x . A sub-specialized application of this technology is rotating opposed fire air (ROFA) by Mobotec USA. The technology op timizes mixing with the use of air ports and fans. The OFA technology for this boiler is believed to r educe NO x by up to 15% while the ROFA technology may reduce NO x up to 66%.

Steam Injection - Steam injection causes the stoichiometry of the mixture to be changed and dilutes the heat generated by the combustion process. These ac tions cause the combustion temperature to be lower,

and in turn reduces the amount of thermal NO x formed. However, air staging accomplishes a very

similar result.

Each of the techniques described above to reduce re sidence time at peak temperature are considered technically feasible.

Reducing Peak Temperature

Flue Gas Recirculation (FGR) – Recirculation of flue gas for use as combustion air reduces the combustion temperature by diluting the oxygen conte nt of the combustion air and causing heat generated by combustion to be diluted in a greater mass of flue gas. For Boiler No. 6, FGR involves taking flue gas from the outlet of the economizer a nd injecting it in a number of locations in the sto kerfired boiler. The recirculated flue gas would be mi xed with the under-grate combustion air to replace some of the air used to maintain grate velocities a nd to reduce the flame temperature on the grate. Th e recirculated flue gas will also be used to reduce e xcess oxygen in the combustion process in general t oGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-36 minimize overall NO x formation. Injection of the recirculated flue gas will require additional boilerspecific evaluation. This reduction of temperature lowers the thermal NO x generated but can adversely

increase CO emissions. A NO x reduction of 15 percent is estimated with a flue g as recirculation (FGR)

system.

Reburn – In a boiler outfitted with reburn technology, a set of natural gas burners is installed above the primary combustion zone. Natural gas is injected t o form a fuel-rich, oxygen-deficient combustion zon e above the main firing zone. NO x emissions created by the combustion process in the main portion of the boiler drift upward into the reburn zone and ar e converted to elemental nitrogen by combustion of the natural gas. The technology requires no cataly sts, chemical reagents, or changes to any existing burners. Typical reburn systems also incorporate r edesign of the combustion air system along with the water-cooled, pinhole grate to provide less excess air (LEA). Natural gas reburn is a feasible technology for stoker-fired boilers. However, the reduction efficiency is generally less than 15%.

Low-NO x Burners (LNB) – A LNB system provides a stable flame that has se veral different zones. For example, the first zone can be primary combustion. The second zone can be fuel reburning (FR) with fuel added to chemically reduce NO x . The third zone can be the final combustion in lo w excess air to limit the combustion temperature. LNB is not an op tion for stoker-fired systems where solid fuel is injected into the furnace above a traveling grate. In a stoker-fired traveling grate system, lighter particles burn in suspension and fuel not combustin g in suspension falls to the grate where the combustion process is completed. Low-NO x burners can only be used for supplemental gas or l iquid

fuels.

Step 1b-Identification of Control Technologies-Revi ew of RACT/BACT/LAER Clearinghouse (RBLC)

Searches of the RBLC were conducted to identify con trol technologies for the control of emissions from stoker-fired boilers. The specific category search ed was

• External Combustion- -11

GP reviewed previous BACT NO x determinations for utility and non-utility coal-fi red boilers. The RBLC database contains over 30 utility boiler NO x determinations, and several non-utility boilers NO x determinations, two of which are based on new circu lating-fluidizied bed designs. The following table summarizes the technologies and emission limits fro m the RBLC database and recent permit rates for

industrial coal and coal/combination fuel boilers:GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-37 Summary of RBLC and Recent NO x Emission Limits for Various Coal Boilers NO x

Emissions Source Technology (lb/MMBtu) Utility Boilers SCR/SCR+LNB 0.07 - 0.09 Utility Boilers LNB+SNCR 0.1 Utility Boilers SNCR 0.08 - 0.15

Industrial Boilers Circulating Fluid Bed SNCR 0.08 Stoker/Other None Economically Feasible 0.246 - 0.7

Recent Permits with Add On Technologies Temple Inland -Rome, GA LNB 0.5 Smurfit-Stone (Maritime) Jacksonville, FL SNCR 0.5

Step 1c-Identification of Control Technologies-Revi ew of Technologies in Use at Georgia-Pacific Corporation Facilities For several coal boilers at various facilities, GP uses a variety of NO x reduction measures, including overfire air, FGR, and combustion controls. GP use s ammonia injection for NO x control for one

combination fuel fluidized bed boiler and one de-in ked wastewater sludge-fired boiler.

Step 2-Technical Feasibility Analysis-Eliminate Tec hnically Infeasible Options All of the options identified above are technically feasible except for two options: First, fuel substitution cannot be accommodated by the boiler due to its design and fuel properties. Secondly, as this boiler does not employ burners, t he use of Low NO x burners is not feasible. After eliminating the technically infeasible option s, GP added a combination of SNCR and FGR or OFA as a control system to include in the evaluation.

Step 3 – Ranking the Technically Feasible Alternati ves to Establish a Control Hierarchy The ranking for NOx control is: 1. Tail-end SCR at 80% removal efficiency

2. ROFA and Rotamix at 66% removal efficiency

3. SNCR with FGR and OFA at 56% removal efficiency

4. SNCR alone at 25% removal efficiency (site-specific vendor estimate)

5. OFA or FGR alone at 15% to 20% removal efficiencyGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-38 Step 4- Effectiveness Evaluation Economic Effectiveness For each cost estimate, the Green Bay Broadway Mill provided several general assumptions to equipment vendors and engineering contractors to determine si te-specific cost estimates with a target accuracy o f +/-

30% or better. The Title V Permit for the site limi ts the firing of petroleum coke to a rate demonstra ted during a compliance stack test. As a result of thes e tests, the current fuel mix is limited to approxi mately 17% by weight of petroleum coke and 83% coal, based on the heat content of the fuels currently combust ed

in Boiler No. 6.

SCR Cost Evaluation The NO x removal technology with the highest removal effici ency studied is SCR. SCR technology is a post process NO x control option used to remove NO x after the combustion process rather than limit NO x development at the source. In this case, a reactor filled with an application-specific catalyst is pl aced in the boiler outlet flue gas stream. The catalyst in the se reactions is only effective in a narrow elevated temperature range. In this case, the flue gas need s to be between 600oF and 650oF in order to maximiz e the effectiveness of the catalyst without causing therm al damage. Two (2) SCR reactor installation locati ons that allow for the appropriate flue gas temperature were evaluated. The first option would be to modi fy the boiler’s flue gas outlet path to accommodate placem ent of the SCR reactor prior to the boiler’s existi ng air preheater. The second available reactor installati on location is downstream of the existing baghouse.

Locating the SCR reactor between the boiler flue ga s outlet and the existing air preheater provides th e necessary flue gas temperatures; however, it also p resents several key obstacles. These obstacles inc lude high flue gas velocities, reduced residence time fo r the flue gas to pass through the catalyst bed, da mage to the catalyst, and blinding of catalyst pores due to high particulate loading. Because of these factor s as well as constructability issues, the Slip Stream SCR was estimated as a tail-end unit. Figure B-6 presents a general arrangement.

In this estimate, one of the existing Standard Have ns Baghouse chambers would be disconnected from the existing Stack 10 and instead sent across a plant r oad to the old Building 66 area where a new Slip St ream SCR reactor would be located. The reactor would co ntain two layers of catalyst. Duct burners would b e installed in the top inlet of the SCR reactor to re heat the flue gas to 625oF in order to allow the ca talyst to be as effective as possible. An ammonia injection gri d would be installed between the duct burners and t he top row of catalyst and be used to inject atomized ammo nia across the entire plan area of the Slip Stream SCR reactor. A new aqueous ammonia system include a ta nk and a heated building for pumps and air blowers.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-39 Figure B-6. General Arrangement of SCR Slip-Stream System, Green Bay Broadway MillGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-40 The SCR Slip-Stream System reactor outlet would feed to a n ew free-standing 14’-0” diameter, 199’ tall

carbon steel insulated stack. Stack 10 would conti nue to serve one chamber of the Standard Havens baghouse. Table B-14 presents the cost estimate for a SCR for Boiler No. 6.

Table B-14. Summary of Capital Cost for Installati on of SCR Slip-Stream System, Boiler No. 6 Green Bay Broadway Mill Description 2009 Costs ($) Direct Costs Major Equipment 6,125,967

Demolition 17,776 Site Improvements 459,447 Piling, Caissons 643,227 Buildings 21,494 Concrete 825,819 Structural Steel 1,684,872 Piping 1,704,620 Insulation - Pipe, Equipment & Ductwork 1,612,124 Instrumentation 689,171 Electrical 720,352 Painting, Protective Coatings 91,890 Construction Indirect Costs

Construction Support Labor 697,539 Premium Time 208,332 Craft Per Diem 426,485 Non-Payroll Tax, Insurance & Permits 579,468 Craft Start-Up Assistance 43,650 Contractor's Construction Fee 1,345,967 Project Indirect Costs

Construction Management 1,299,178 Engineering Professional Services 4,330,343 Study Cost 50,000 Outside Consultant Services 100,000 Owner's Cost 817,255 Spare Parts 217,099 Non-Craft Start-Up Assistance 71,139 Allowance For Unforeseen 2,467,524 Escalation 1,621,194 Air Infiltration Allowance 100,000

Total Installed Cost (+/- 30%) (TIC) 28,971,933GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-41 Table B-15 presents the annual operating costs for the SCR system.

Table B-15. Annual Operating Cost Calculations, SC R for Boiler No. 6, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 2 hours per shift x 1,025 shifts/yr @ $40/hr 82,000 Supervisor Labor 15% of Operator 12,300 Maintenance labor: 0.5 hours per day x 365 days/yr @ $40/hr 7,300 Maintenance material 100% of Maintenance Labor 7,30 0

Electricity 0.059$/kWhr x 3464778 kWhr 204,422 Ammonia consumption $160/ton aq NH 3 x 6619 tons aq NH 3 /yr 1,059,040 Natural Gas-duct burners $10/MMBtu x 429,040 MMBtu/ yr 4,290,400 Catalyst $750,000/ 3 years 250,000

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 65,340 Taxes, insurance, admin. factor: 4% of TIC (Table B -14) 1,158,877 Capital recovery factor (system): 0.0944 x TIC 28 (Table B-14) 2,734,746

Total Annual Cost 9,871,725

28 7% interest for the cost of capital and an equipme nt life of 20 years using Equation 2.8a of USEPA Co st Control Manual yields: (0.07*(1+0.07)^20)/((1+0.07)^20-1) = 0.094 4

Determining annual operating costs is sensitive to the amount of NOx removed and ammonia required. Th e 2002-2004 actual emissions are significantly lower than permitted emissions and thus represent a conservatively lower annual cost (and operation) es timate.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $9,871,725/ ( 80% x 428 tons) = 28,831 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-42 ROFA and Rotamix Cost Evaluation Section 2.4 presented the application of Mobotec’s ROFA and Rotamix costs within its FSI technology. The total installed cost for targeting NO x control only is estimated to be approximately $1.9 MM lower by removing the limestone injection, handling, and storage equipment specifically needed for SO 2 removal. Thus, the expected total installed cost i s $25,000,000. Table B-16 presents the annual operating costs without the limestone use or landfi lling charges.

Table B-16. Annual Operating Cost Calculations, RO FA/ROTAMIX for Boiler No. 6, Actual 2002- 2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per shift x 1,025 shifts/ yr @ $40/hr 41,000 Supervisor Labor 15% of Operator 6,150 Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 Maintenance material 100% of Maintenance Labor 7,000

Electricity- direct 0.059$/kWhr x 3437500 kWhr 202,813

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 36,690 Taxes, insurance, admin. factor: 4% of TIC 1,000 ,000 Capital recovery factor (system): 0.0944 x TIC 29 2,359,823

Total Annual Cost 3,660,476

29 7% interest for the cost of capital and an equipme nt life of 20 years using Equation 2.8a of USEPA Co st Control Manual yields: (0.07*(1+0.07)^20)/((1+0.07)^20-1) = 0.094 4

Determining annual operating costs is only sensitiv e to the number of hours the air mixing system is operated. The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $3,660,476/ ( 66% x 428 tons) = 12,958 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-43 SNCR Cost Evaluation SNCR systems are most efficient in a single tempera ture window; therefore, in order to properly operat e an SNCR system, a boiler study is required to map t he gas temperatures at several locations during varying boiler operating points. A detailed SNCR s tudy was not conducted for Boiler No. 6; however, the SNCR supplier requires such a study and the SNC R estimate includes a one-time cost of $50,000 to accomplish this task.

This system would consist of a new urea storage tan k equipped with skid-mounted metering, circulating and booster pumps within a diked containment area. The new tank will be electrically heat-traced and insulated. The existing Boiler No. 6 furnace front wall would be modified to accept the new spray nozzles, and distribution module skids would be pla ced near the spray nozzles of the two (2) levels. For Boiler No. 6, tilting injectors would be installed at a single level. A pump would be used to circula te a steady stream of concentrated urea to a metering sk id. The metering skid would then pump the diluted urea solution up to the distribution modules locate d at the boiler’s injection nozzles.

Other than the addition of a diked containment area and the need to modify the existing boiler walls, there are few installation complications to conside r in this system. Extra steel is considered in the factored installation cost to allow for reworking o f platforms to accept control skids, and demolition

dollars are included in the factored estimate for r emoval of items that may be in the way of the new platforms.

The only additional operational concern with a urea -based SNCR system is ammonia slip. Unreacted urea can degrade to nitrogen, carbon dioxide and am monia in the boiler. This ammonia slip can be controlled with careful monitoring. Urea-based SNC R systems often operate at 1 ppm ammonia slip or less and are usually guaranteed at a 5 ppm ammonia slip rate. The most important factor in reducing ammonia carryover in these systems is proper distri bution based on the boiler temperature gradient study. In this case, the preliminary data from the vendor indicates that ammonia slip is expected to be 2 ppm at the exit of the existing baghouse and 5 ppm exiting the boiler. These values would be revised once a boiler-specific study is completed.

Table B-17 presents the total installed cost estima te for an SNCR system alone.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-44 Table B-17. Summary of Capital Cost for Installati on of SNCR System, Boiler No. 6 Green Bay Broadway Mill Description TOTAL COST (2007$) Direct Costs Major Equipment 1,531,501

Demolition 34,459 Site Improvements 76,575 Piling, Caissons 107,205 Buildings 270,000 Concrete 68,918 Structural Steel 275,670 Piping 260,355 Insulation - Pipe, Equipment & Ductwork 137,835 Instrumentation 38,288 Electrical 213,048 Painting, Protective Coatings 15,315 Construction Indirect Costs

Construction Support Labor 125,805 Premium Time 36,854 Craft Per Diem ($7/Hour On 100 % Of Time) 79,763 Non-Payroll Tax, Insurance & Permits 113,499 Craft Start-Up Assistance 45,000 Contractor's Construction Fee 223,604 Project Indirect Costs

Construction Management 268,000 Engineering Professional Services 594,000 Study Cost 50,000 Outside Consultant Services 100,000 Owner's Cost 179,000 Spare Parts 67,188 Non-Craft Start-Up Assistance 119,150 Allowance For Unforeseen 498,103 Escalation 350,665 Air Infiltration Allowance 100,000

Total Installed Cost (+/- 30%) (TIC) 5,979,799

Table B-18 presents the annual operating costs for the SNCR system.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-45 Table B-18. Annual Operating Cost Calculations, SN CR for Boiler No. 6, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per shift x 1,025 shifts/ yr @ $40/hr 41,000

Supervisor Labor 15% of Operator 6,150 Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 Maintenance material 100% of Maintenance Labor 7,00 0

Electricity 0.059$/kWhr x 821763 kWhr 48,484 Urea Consumption $1.35/gal x 10 gph x 8400 hr/yr 11 3,400 Mill Water $0.06/kgal x 7,884 kgal/yr 473

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 36,690 Taxes, insurance, admin. factor: 4% of TIC (Table B -17) 239,192 Capital recovery factor (system): 0.094 x TIC (Tabl e B-17) 562,101

Total Annual Cost 1,061,490

Determining annual operating costs is sensitive to the amount of NOx removed and the amount of urea required. The 2002-2004 actual emissions are lower than permitted emissions and thus represent a conservatively lower annual cost (and operation) es timate.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $1,061,490/ ( 25% x 428 tons) = 9,920 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-46 FGR/OFA Cost Evaluation An additional NOx control case that was studied and estimated for Boiler No. 6 was Flue Gas Recirculat ion (FGR) and Overfire Air (OFA). Both of these techno logies are expected to provide the same approximate level of control and have similar costs. In FGR, flue gas would be taken from the outlet of the boil er’s economizer section and directed to several injectio n locations in the stoker-fired boiler using ductwo rk. The exact location for the injection points of recircul ated flue gas would be determined by boiler modelin g. The price for this model is included in the cost estima te. Three main locations proposed for injection of the flue gas are (1) at the coal feeder level, (2) through t he nozzles under the fuel feeder, and (3) at the un der-grate air system. Other potential injection sites such a s the fly ash reinjection ports would be evaluated during the study. The injected flue gas under the grate would replace some of the air used for over-fire air to maintain grate velocities and reduce flame temperatures on t he grate. Feeding recirculated flue gas to the coa l feeders

and to the nozzles under the coal feeders would con trol the high temperatures at the air/coal interfac e above the grate. Reducing excess oxygen and flame tempera ture at or above the grate would help prevent the

formation of thermal and fuel bound NOx.

The new FGR system would include an FGR fan located inside of the boiler house, ductwork from the economizer outlet to each point of injection, expan sion joints, dampers and operators, flow indicators to major injection locations, boiler tube bends and in jection wall boxes, and undergrate air mixing sparg ers. Money is included in the cost estimate for minor re location and demolition to allow for installation o f the FGR system ductwork. Table B-19 presents the total installed cost estimate for an FGR system alone.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-47 Table B-19. Summary of Capital Cost for Installati on of FGR System, Boiler No. 6 Green Bay Broadway Mill Description TOTAL COST (2007$) Direct Costs Major Equipment 

### $1,256,014

Demolition 

### $43,454 Piling, Caissons 

### $87,921 Buildings 

### $270,000 Concrete 

### $41,448 Structural Steel 

### $91,061 Insulation - Pipe, Equipment & Ductwork 

### $192,418 Instrumentation 

### $17,270 Electrical 

### $45,216 Construction Indirect Costs

Construction Support Labor 

### $85,575 Premium Time 

### $25,563 Craft Per Diem 

### $54,256 Non-Payroll Tax, Insurance & Permits 

### $68,363 Craft Start-Up Assistance 

### $10,400 Contractor's Construction Fee 

### $159,898 Project Indirect Costs

Construction Management 

### $174,000 Engineering Professional Services 

### $387,000 Study Cost 

### $50,000 Outside Consultant Services 

### $50,000 Owner's Cost 

### $117,000 Spare Parts 

### $40,279 Non-Craft Start-Up Assistance 

### $57,288 Allowance For Unforeseen 

### $327,442 Escalation 

### $207,164

Total Installed Cost (+/- 30%) (TIC) 

### $3,859,031

Table B-20 presents the annual operating costs for the FGR system.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-48 Table B-20. Annual Operating Cost Calculations, FG R for Boiler No. 6, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per day x 350 days/yr @ $ 40/hr 14,000 Supervisor Labor 15% of Operator costs 2,100 Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 Maintenance material 100% of Maintenance Labor cost s 7,000

Electricity 0.059$/kWhr x 927593 kWhr 54,728

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 18,060 Taxes, insurance, admin. factor: 4% of TIC (Table B -19) 154,361 Capital recovery factor (system): 0.094 x TIC (Tabl e B-19) 362,749

Total Annual Cost 619,998

Determining annual operating costs for FGR is sensi tive only to the number of hours the fan is used. The operating costs reflect a typical annual operation of 8,400 hours/year.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $619,998/ (20 % x 428 tons) = 7,242 $/ton.

SNCR with FGR and OFA Cost Evaluation In an attempt to design a more successful combustio n modification technology with urea injection, the Mill developed a cost estimate for the combination of FGR, OFA and SNCR. This combination is different than the ROFA/ROTAMIX option though the a ddition of urea injection. Table B-21 tabulates the cost estimate for this combination of technolog ies.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-49 Table B-21. Summary of Capital Cost for Installati on of FGR/OFA/SNCR System, Boiler No. 6 Green Bay Broadway Mill Description TOTAL COST

FGR FAN System (Table B-19) 3,859,031 OFA System (estimated by a ratio of equipment) 30 2,371,174 SNCR System (Table B-17) 5,979,799

Total Installed Cost (+/- 30%) (TIC) 12,210,004

30 OFA System Installation Cost = FGR Fan Installatio n x OFA Equipment Cost / FGR Equipment Cost; $3,859,031 x $757,000 / $1,232,000 = $ 2,371,174

Table B-22 presents the annual operating costs.

Table B-22. Annual Operating Cost Calculations, FG R+OFA+SNCR for Boiler No. 6, Actual 2002-2004 Conditions Parameter Annual Cost ($)

Direct Costs FGR OFA SNCR Total Operating labor : 14000 0 41000 Supervisor Labor 2100 0 6150 Maintenance labor: 7000 7000 7000 Maintenance material 7000 7000 7000

Electricity 54728 54728 48484 Urea and Water 0 0 113873 Indirect Costs Overhead rate (fractional): 18060 8400 36690 Taxes, insurance, admin. factor: 154361 94847 239192 Capital recovery factor (system): 364749 223839 562101

Total Annual Cost 619998 395814 1061490 $ 2,077,302

Determining annual operating costs for the combinat ion is sensitive to the number of hours the fan is used as well as the urea consumption requirement. The cost effectiveness of this technology is equal to the T otal Annualized Costs/ Annual Quantity of NOx Removed. The estimated cost effectiveness is: $2,077,302/ ( 56% x 428 tons) = 8,666 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-50 Summary of Economic Evaluation, NOx Controls for Po wer Boiler No. 6 The economic evaluation determined a range of cost effectiveness values for the following levels of co ntrol: 20%, 25%, 56%, 66%, and 80%. Figure B-7 presents a marginal cost curve for all the cost estimates presented in Table B-14 through B-22.

Figure B-7 Marginal Cost Curve for NO x Control Options, Green Bay Broadway Mill Boiler No .6

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions Control options: 20% removal by FGR or OFA; 25% re moval by SNCR alone; 56% removal by a combination of FGR/OFA and SNCR; 80% removal by SCR

Energy and Environmental Impacts Throughout the economic analysis, the cost estimate s documented, where possible, the actual costs for additional energy consumption, additional water dem and, and addition solid waste generated. Also in e ach technology discussion, the analysis discussed envir onmental impacts. Table B-23 summarizes a comparis on of energy and environmental impacts for each option

.



### 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

0 100 200 300 400

Actual Annual Tons Removed Per Year (tpy)Cost Effectiveness ($/ton)



### Average $/ton 80%

66%

56% 25%

20%GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-51 Table B-23. Summary of Additional Impacts for NO x Control Technologies, Boiler No. 6

Technology Impacts SNCR Options Combustion Modifications SCR Additional Energy (kWhr/yr) 2,676,949 1,855,186 3,4 64,778 Additional Water (million gal/yr) 7.884 0 0 Additional Natural Gas (MMcf/yr) 0 0 429.04 Environmental Impacts NH 3 Emissions None NH 3 Emissions Other Impacts NH 3 Handling None NH 3 Handling

NO x Engineering Analysis Summary Through a detailed comparison of many site specific issues and costs, the Mill believes no additional controls meets the BART requirement for Boiler No. 6. While technologies do exist for stoker-fired

boilers to reduce NO x , the site-specific cost estimates indicate the ret rofit nature of the installations proves to be economically infeasible. The cost eff ectiveness for the lowest cost option (OFA/FGR) is $7,242/ton removed for a reduction of 86 tons per y ear.

2.6 SUMMARY OF ENGINEERING ANALYSES FOR BOILER NO. 6 Using a “top-down” procedure, the engineering analy sis determined that 62% SO 2 reduction technology is technically and economically feasible for Boiler No. 6. The analysis determined that no additional

controls are feasible for PM 10 and NO x . Boiler No. 6 will continue to use the existing ba ghouse to

remove PM.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-52 

### 3.0 BART ENGINEERING ANALYSIS FOR POWER BOILER NO.7

3.1 SOURCE DESCRIPTION

Boiler No. 7 is a two (2) drum cyclone-type boiler manufactured by Babcock and Wilcox and installed in 1969. The boiler has a heat input rating of 615 MM Btu/hr with a maximum continuous rated (MCR) steam flow of 500,000 lbs/hr and an ultimate maxim um steam flow of 550,000 lb/hr for a one (1) - hour period over 24 hours of operation. The boiler’s st eam superheater outlet condition is 850 psig at 890 o F. Boiler No. 7 is permitted to burn coal, petroleum c oke, natural gas, and No. 2 fuel oil. Natural gas is normally used for startup and maintaining stability . Boiler No. 7 typically operates in a swing-loade d mode and fires low fusion eastern coal with up to 2 5% petroleum coke

. The Boiler’s exhaust gases are discharged into a common duct connected with the fl ue gas discharge streams from several other boilers at the mill. The common duct is equipped with a ba ghouse to remove particulate matter emissions from the exhaust gases. Figure B-8 presents a side-view drawing of Boiler No. 7.

3.2 BASELINE EMISSIONS The following table presents the actual fuels fired , sulfur content of each fuel combusted, and the BART-regulated emissions generated from Boiler No. 7 during the baseline period of 2002 through

2004. Table B-24. Summary of Baseline Solid Fuels and Em issions, Boiler No. 7

Parameter 2002 2003 2004 3-yr Average Total MMBtu All Solid Fuels 4550267 4298870 4251026 4366721 Tons Low Fusion Coal 132187 126175 131213 129858 %S Low Fusion Coal 2.33 2.37 2.43 2.38 Tons Pet Coke 32961 29212 30262 30812 %S Pet Coke 5.89 5.38 5.49 5.59 Annual Average SO 2 (lb/MMBtu) 3.87 4.10 4.01 3.99 Actual SO 2 Emissions (tpy) 8807 8810 8527 8715 Actual NOx Emissions (tpy) 2812 2673 2735 2740 Actual PM 10 Emissions (tpy) 199 187 112 166GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-53 Figure B-8. Side View of Boiler No. 7, Green Bay B roadway MillGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-54 3.3 PARTICULATE MATTER Step 1a-Identification of Control Technologies-Typi cal Technologies in Use in the United States Technology that may be considered for the control o f particulate matter emissions from boilers include s the substitution and use of clean fuels, mechanical /gravity separation devices ( e.g., cyclones, settling chambers), electrostatic precipitators (ESPs), bagh ouses, and high efficiency wet scrubbers.

Step 1b-Identification of Control Technologies-Revi ew of RACT/BACT/LAER Clearinghouse (RBLC) Searches of the RBLC were conducted to identify con trol technologies for the control of PM 10 emissions from cyclone boilers. The specific category searche d was External Combustion- -11 The clearinghouse listed multiclones with ESPs, bag houses, good combustion practices, and wet

scrubbers as the PM 10 control technologies.

Step 1c-Identification of Control Technologies-Revi ew of Technologies in Use at Georgia-Pacific Corporation Facilities GP operates numerous combination fuel-fired boilers and coal-fired boilers at its operating facilities within

the United States. PM 10 control devices in use at these mills include ESPs , baghouses and wet scrubbers.

Step 2-Technical Feasibility Analysis-Eliminate Tec hnically Infeasible Options All of the control options identified in Step 1 are technically feasible.

Step 3 – Ranking the Technically Feasible Alternati ves to Establish a Control Hierarchy The ranking of technologies for PM 10 control is: 1. Baghouse with greater than 99% removal efficiency 2. ESP with multiclones at greater than 99% removal ef ficiency 3. High efficiency scrubbers with 98%+ removal efficie ncy 4. Wet scrubbers with 50 to 95% removal efficiency 5. High efficiency cyclones with 50-90% removal effici ency

Step 4- Effectiveness Evaluation GP currently operates a high efficiency (above 99%) baghouse to control PM 10 emissions generated by Boiler Nos. 5, 6, 7, and 8. The baghouse design in let particulate loading ranges from 1 to 3.5 gr/acf

, while the outlet loading is consistently at or belo w 0.01 gr/acf. The baghouse design exhaust gas flowrate is 772,000 acf/minute (ACFM) at 365 °F. T he baghouse meets the existing State limit of 0.3 l bGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-55 PM 10 /MM Btu from NR415.06(1)(b), (equivalent to 184.5 l b/hr at Boiler No. 7’s maximum rated capacity), is much greater than the baseline annual emissions rate of approximately 40 lbs/hr 31 (equal to 0.08 lb/MM Btu) from Boiler No. 7. As the Mill pr esently operates the highest ranked PM 10 control technology, no additional cost effectiveness evalua tion is necessary.

Step 5-Select BART GP is proposing to continue the use of the highest level of control, a baghouse with the current emiss ion

limit of 0.3 lb PM 10

/MM Btu.

31 [199 tons (2002) + 187 tons (2003) + 112 tons (200 4)] x 2000 lbs/ton / 25,104 hours = 40 lbs/hr. [(199 tons (2002) + 187 tons (2003) + 112 tons (200 4))*2000 lb/ton] / 13,100,163 MMBTU total = 0.08 lb/MMBtu including both filterable and condensible.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-56 3.4 SULFUR DIOXIDE

Step 1a-Identification of Control Technologies-Typi cal Technologies in Use in the United States Emission control equipment that may be considered t o control sulfur dioxide emissions from coal-fired boilers includes gas absorption using wet and dry s crubbers, and flue gas desulfurization techniques such as sorbent injection. The use of clean substi tute fuels can also be considered as an alternative to

add-on controls.

Step 1b-Identification of Control Technologies-Revi ew of RACT/BACT/LAER Clearinghouse (RBLC) Searches of the RBLC were conducted to identify con trol technologies for the control of SO 2 emissions from cyclone boilers. The specific category search ed was “External Combustion- -11”. The clearinghouse listed the use of clean fuels, wet an d dry scrubbers, and flue gas desulfurization techniques such as limestone injection and spray dr yer absorbers (SDA) as the control technologies.

Step 1c-Identification of Control Technologies-Revi ew of Technologies installed at Georgia-Pacific Corporation Facilities Georgia-Pacific operates numerous combination fuel- fired boilers and coal-fired boilers within the

United States. SO 2 control technologies include dry scrubbing, limesto ne and sorbent injection on fluidized bed boilers, and the use of clean fuels. However, the company has limited experience with we t scrubbing with caustic on similar cyclone boilers.

Step 2-Technical Feasibility Analysis-Eliminate Tec hnically Infeasible Options The Green Bay Broadway Mill investigated several ga s absorption technologies: wet scrubbing with caust ic (sodium hydroxide) solution, semi-dry scrubbing usi ng a lime slurry with conventional scrubbers, Spray Dry Absorbers (SDAs) and circulating fluidized bed scru bbers. Scrubber vendors have indicated to the Mill that spray drying is not technically feasible because th e allowable inlet sulfur concentration associated w ith the current fuel mix would be too high and the flue gas temperatures too low to support the water evaporat ion requirements in the hydrated lime slurry SDA. As a result, SDA vendors have informed GP that they can not provide quotations for this particular application of the technology. All of the other SO 2 control technology options are technically feasible.

Step 3 – Ranking the Technically Feasible Alternati ves to Establish a Control HierarchyGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-57 The ranking of the technologies are:

1. Gas absorption with a wet spray tower or semi-dry s crubbing system with hydrated lime at 90%+

SO 2 removal efficiency,

2. In-Furnace Sorbent Injection at 50% removal efficie ncy, 3. In-duct absorption with sodium sesquicarbonate (Tro na) injection with 50% removal efficiency,

4. Fuel substitution: Low SO 2 /MMBtu coal in place of all higher sulfur containin g fuels at 11% removal efficiency

Step 4- Cost Effectiveness Evaluation

Economic Evaluation For each control technology cost estimate, the Gree n Bay Broadway Mill provided several general assumptions to the equipment vendors and engineerin g contractors for their use in determining site-spe cific cost estimates with a target accuracy of +/- 30% or better. The cost analysis for Boiler No. 7 follo ws the conventions presented above for Boiler No. 6.

Wet Spray Tower with Sodium Hydroxide Cost Evaluati on The Green Broadway Bay Mill worked with several con trol equipment vendors to review technical issues and challenges with SO 2 control by using wet, dry, or semi-dry scrubbing t echnologies. Based on the technical reviews, the use of a wet spray tower dem onstrates the best overall SO 2 removal efficiency of all the technologies reviewed and that were considered technically feasible. Jacobs Engineering provided the Green Bay Broadway Mill with a +/-30% cost estimate to install and operate a wet spray tower scrubber. The cost estimate for a wet spray tower scrubber pr esented in Table B-25 assumed that the scrubber wil l be located downstream of the existing baghouse and is parallel to the estimates presented for Boiler No. 6. The key design differences are:

1. The clean flue gas exits the Scrubber and enters a new 16’ diameter, 316L stainless steel Stack mounte d on top of the new Spray Tower Scrubber outlet. The Stack will terminate at an elevation of 199 feet above grade. The Stack is sized for a flue gas vel ocity of approximately 34 ft/sec with 395,000 cubic feet/minute of scrubbed and saturated flue gas.

2. The Spray Tower Scrubber has a 38’ by 30’ footprint and the Scrubber absorber vessel is 25’-0” in diameter and stands approximately 58’ tall.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-58 Table B-25. Summary of Capital Cost for Installati on of Wet Spray Tower Scrubber System, Boiler No. 7 Green Bay Broadway Mill Description 32 Total Cost (2007$) 33

Direct Costs Major Equipment $11,969,285 Demolition $19,375 Site Improvements $598,464 Piling, Caissons $837,850 Buildings $670,000 Concrete $988,762 Structural Steel $2,194,549 Piping $3,330,589 Insulation - Pipe, Equipment & Ductwork $859,079 Instrumentation $954,823 Electrical $1,452,051 Painting, Protective Coatings $119,693 Construction Indirect Costs Construction Support Labor $1,038,695 Premium Time $306,778 Craft Per Diem $658,555 Non-Payroll Tax, Insurance & Permits $1,035,129 Craft Start-Up Assistance $43,650 Contractor's Construction Fee $1,923,564 Project Indirect Costs Construction Management $1,992,000 Engineering Professional Services $4,423,000 Study Cost $50,000 Outside Consultant Services $100,000 Owner's Cost $1,325,000 Spare Parts $458,745 Non-Craft Start-Up Assistance $119,150 Allowance For Unforeseen $3,741,878 Escalation $2,717,463 Air Infiltration Allowance 34 $100,000 Total Installed Cost (TIC)(+/- 30%) $44,028,127

32 See Appendix for further description of estimator’ s cost categories 33 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 34 Modifications to the exhaust system are expected t o require studies and upgrades to eliminate air inf iltration.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-59 To determine estimated operating costs for the scru bber, this cost analysis used the templates provide d by EPA in their Cost Control Manual. Determining ann ual operating costs is sensitive to the amount of s ulfur dioxide removed and the amount of scrubbant require d to maintain the desired SO 2 removal efficiency. The 2002-2004 actual emissions are significantly lower than permitted emissions ( i.e.., 3.99 lbs SO 2 /MMBtu in 2002-2004 compared to permit limit of 4.55 lb SO 2 /MMBtu) and thus represent a conservatively lower annualized cost estimate. Table B-26 presents oper ating costs for the spray tower technology.

Table B-26. Annual Operating Cost Calculations, We t Spray Tower for Boiler No. 7, Actual 2002- 2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per shift @ $40/hr $ 43,800 Supervisor Labor 15% of Operator $ 6 ,570 Maintenance labor: 0.5 hours per shift @ $40/hr $ 21,900 Maintenance material 100% of Maintenance Labor $ 21,900

Electricity 0.059$/kWhr x 11963492 kWhr $ 705,846 Caustic Solution 35 $1050/dry ton NaOH x 13,617 ton NaOH $ 14,29 8,047 Process water: $0.06/kgal x 4518951 kgal $ 271,137 Landfill Scrubber system solids $ 9.50 /ton x 100,3 77 tons $ 953,582 Additional Process Steam $2.45/klb steam x 752,831 klbs $ 1,844,436

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs $ 56,502 Taxes, insurance, admin. factor: 4% of TIC (Table B -25) $ 1,761,125 Capital recovery factor (system): 0.1098 x TIC 36 (Table B-25) $ 4,834,052

Total Annual Cost $ 24,818,896

35 2002-2004 actual SO 2 tons emitted = 8715 emitted; consumption is 2.5 lb -mol NaOH per lb mol of SO 2 removed; 2008 average unit cost of caustic as delivered to Mill = $1,050/dry ton NaOH;

8715 tons SO 2 x 2,000 lbs/ton x lbmol SO 2 /64 lbs SO 2 x 2.5 lb-mol NaOH/lb-mol SO 2 x 40 lbs NaOH/lb-mol NaOH / 2,000 lbs/ton =13,617 tons dry NaOH

36 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: (0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

The cost effectiveness of this technology is equal to the Annual Operating Costs/ Annual Quantity of S O 2 Removed. The estimated cost effectiveness is: $24,818,896 / (90% x 8,715 tons) = $3,164 /ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-60 Dry Scrubbing with Hydrated Lime Fluidized Bed Abso rber (FBA) Cost Evaluation

Dry scrubbers have significantly lower capital and annual operating costs than wet systems because the y are simpler, demand less water, and waste disposal is l ess complex. Dry injection systems are easier to i nstall and use less space; therefore, they are good candid ates for retrofit applications, such as the one at the Green Bay Broadway Mill. In contrast to a wet spray towe r, FBAs use a reactor vessel with a closely control led

temperature.

The cost estimate for a FBA scrubber assumes that t he scrubber will be located downstream of the exist ing baghouse and is comparable to the estimates present ed for Boiler No. 6 although equipment size is scal ed for the higher airflow rate.

Table B-27 summarizes the total cost for installati on of the FBA system.

Table B-27. Summary of Capital Cost for Installati on of Fluidized Bed Absorber System, Boiler No. 7 Green Bay Broadway Mi ll Description TOTAL COST (2008$) Scrubber systems installation and duct modification s 15,357,754 Footings and foundation work 684,809 Electrical and controls 1,680,120 Structural steel 536,569 Engineering and commissioning 2,370,307 Construction management 1,623,336 General contractor overhead and mark-up 2,001,420 Contingency 3,048,333 CEM systems 358,312 Piping 123,172 Miscellaneous 539,087 Freight 919,121 Total Installed Cost 29,242,339

Figure B-3 represents a simplified flow diagram of the required equipment for a generic case of any on e of

several boilers at the mill. In contrast to the we t spray tower scrubber technology, most of the equi pment will be located within the existing buildings at a point upstream of the baghouse. Figure B-4 present s a footprint diagram. Table B-28 presents the operati ng costs for the FBA specific to Boiler No. 7.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-61 Table B-28. Annual Operating Cost Calculations, Fl uidized Circulating Absorber for Boiler No. 7, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 3 hour per shift @ $40/hr 131,400 Supervisor Labor 15% of Operator 19,710 Maintenance labor & equipment: Vendor Estimate 10% of Equipment Costs 1,838,242

Electricity- direct 0.059$/kWhr x 6864000 kWhr 404,976 Electricity- fan make-up 8 inches w.c 201,680 Hydrated Lime $90/ton hy lime x 36,037 tons hy lime /yr 37 3,243,322 Process water: $0.06/kgal x 36,600 kgal 2,196 Landfill Scrubber system solids $ 9.50 /ton x 58,57 5 tons 556,458

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 1,193,611 Taxes, insurance, admin. factor: 4% of TIC (Table B -27) 1,169,694 Capital recovery factor (system): 0.1098 x TIC 38 (Table B-27) 3,210,652

Total Annual Cost 11,971,942

37 2002-2004 actual SO 2 tons = 8,715; consumption is 3.25 lb-mol hydrated lime per lb mol of SO 2 removed; 2008 average unit cost = $90/ ton hydrated lime (91% active)

8,715 tons SO 2 x 2,000 lbs/ton x lb-mol SO 2 /64 lbs SO 2 x 3.25 lb-mol hydrated lime/lb-mol SO 2 x 74.1 lbs hydrated lime / lbmol hydrated lime / 2,000 lbs/ton 1ton pure CaCO3/ 0.91 ton hydrated lime = 36,037 tons hydrated lime

38 7% interest for the cost of capital and a scrubber life of 15 years using Equation 2.8a of USEPA Cost Control Manual yields: (0.07*(1+0.07)^15)/((1+0.07)^15-1) = 0.1098

The cost effectiveness of this technology is equal to the Annual Operating Costs/ Annual Quantity of S O 2 Removed. The estimated cost effectiveness is: $11,971,942/ (90% x 8,715 tons) = $1,526 /ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-62 Furnace Sorbent Injection (FSI) Cost Evaluation As an alternative to “back-end” controls, the Green Bay Broadway Mill assessed control technologies further upstream. One such technique involves inje cting a sorbent into the combustion chamber of the

boiler with the fuel. As additional material in th e boiler can significantly affect boiler performanc e, this technology is coupled with improving the air distri bution system within the boiler. The technology ha s been demonstrated on stoker-fired boilers (further demon stration on cyclone boilers is expected in 2009), however, an unknown risk to operations is the poten tial erosion of boiler furnace tubes due to the add itional sorbent material injected into the combustion chamb er of the boiler. The FSI technology is similar to the dry scrubbing system in that it eliminates manageme nt of wet streams and has a small equipment footpri nt relative to wet scrubbing systems. Limestone with a high CaCO 3 content would absorb SO 2 as the fuel sulfur is oxidized in the furnace. The resultant p articulate would be carried out with the boiler flu e gas and then captured in the existing baghouse. As mentione d earlier, the mill expects that the existing bagho use would collect the additional particulate and mainta in its high removal efficiency from an FSI without significant modification.

The cost estimate for an FSI system is comparable t o the estimates presented for Boiler No. 6, though equipment size is scaled for the higher airflow rat e. However, Mobotec has very little experience wit h this type of system on cyclone boilers at this time.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-63 Table B-29. Summary Of Capital Cost For Installati on Of FSI System, Boiler No. 7 Green Bay Broadway Mill Description 39 Total Cost (2007$) 40 Major Equipment $7,018,799 Demolition $661,504 Site Improvements $491,316 Piling, Caissons $631,692 Buildings $330,000 Concrete $828,031 Structural Steel $1,497,449 Piping $2,233,812 Insulation - Pipe, Equipment & Ductwork $350,940 Instrumentation $658,012 Electrical $1,035,904 Painting, Protective Coatings $70,188 Construction Indirect Costs Construction Support Labor $758,232 Premium Time $223,596 Craft Per Diem $480,735 Non-Payroll Tax, Insurance & Permits $564,881 Craft Start-Up Assistance $43,650 Contractor's Construction Fee $1,315,374 Project Indirect Costs Construction Management $1,320,000 Engineering Professional Services $2,931,000 Study Cost $50,000 Outside Consultant Services $100,000 Owner's Cost $878,000 Spare Parts $288,461 Non-Craft Start-Up Assistance $119,150 Allowance For Unforeseen $2,485,548 Escalation $1,814,693 Air Infiltration Allowance $100,000 TOTAL INSTALLED COST (TIC) (+/- 30%) $29,280,967

39 See Appendix for further description of estimator’ s cost categories 40 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs EngineeringGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-64 Table B-30 presents annual operating costs for the FSI system. Without a site-specific study by Mobote c, the economic analysis could not estimate what, if a ny, loss of steaming capacity would occur with the significant amount of “dead load” material ( i.e., sorbent) added into the furnace. The operating cos ts also do not include lost steam production due to increased wear on boiler tubes. Though the increased rate of tube erosion cannot yet be determined, the operation of the boiler will be affected by a significant increa se in tube wall inspections following startup with an FSI system.

Table B-30. Annual Operating Cost Calculations, FS I for Boiler No. 7, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hour/shift x 1,095 shifts/year @ $40/hr 43,800 Supervisor Labor 15% of Operator costs 6,570 Maintenance labor: 0.5 hrs/shift x 1,095 shifts/yea r @ $40/hr 21,900 Maintenance material 100% of Maintenance Labor 21,9 00

Electricity- direct 0.059$/kWhr x 3,801,797 kWhr 22 4,306 Limestone $40/ton limestone x 44,300 tons 41 1,772,005 Landfill Additional system solids $ 9.50/ton x 44,3 00 tons 420,850

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 56,502 Taxes, insurance, admin. factor: 4% of TIC (Table B -29) 1,171,239 Capital recovery factor (system): 0.1098 x TIC (Tab le B-29) 3,214,893

Total Annual Cost 6,953,964

41 2002-2004 actual SO 2 tons = 8,715; consumption is 3.25 lb-mol limestone per lb mol of SO 2 ; Average unit cost is $40/ton delivered.

8,715 tons SO 2 x 2,000 lbs/ton x lb-mol SO 2 /64 lbs SO 2 x 3.25 lb-mol limestone /lb-mol SO 2 x 100.1 lbs limestone (CaCO 3 )/ lb-mol limestone / 2,000 lbs/ton = 44,300 tons lime stone

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent required. The 2002-2004 actual emissions are signi ficantly lower than permitted emissions and thus represent a conservatively lower annual cost (and o peration) estimate.

The cost effectiveness of this technology is equal to Annual Costs/ Annual SO 2 Removed. The estimated cost effectiveness is: $6,953,964 / (50% x 8,715 tons) = 1,596 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-65 In-Duct Absorption System with Trona Cost Evaluatio n In contrast to injecting sorbent into the boiler or using a wet spray tower scrubber vessel, in-duct a bsorption is an alternative capable of obtaining a 50% reduct ion in SO 2 emissions from Boiler No. 7. Unlike the other

SO 2 technologies described above, this technology does not have many similar applications in commercial operation. With the use of this technology, offere d by O’Brien and Gere, the sorbent is fed into the flue gas as a dry powder. The sorbent (sodium sesquicarbona te, or Trona) undergoes thermal decomposition and reacts with sulfur dioxide in the flue gases to for m a particulate. Approximately one-third of the so rbent

mass forms carbon dioxide and exhausts to the atmos phere while the other two-thirds of the particulate mass is captured in the existing baghouse. The use of T rona will result in the release of 4 moles of carbo n dioxide for every 2 moles of Trona. The supply market for this sorbent is very limited to a few active mines in the western United States. Without multiple sources fo r the sorbent, deliveries to the mill are at higher risk of supply interruptions ( e.g., natural or other external events) than other techn ologies with many suppliers.

The cost estimate for an In-Duct Absorbtion System is comparable to the estimates presented for Boiler No. 6, although equipment size is designed for the high er airflow rate. Table B-31 presents a summary of

installation the installed costs for the In-Duct Ab sorption System for Boiler No. 7.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-66 42 See Appendix for further description of estimator’ s cost categories 43 Green Bay, WI BART Feasibility Study and Estimate, June 2007 Jacobs Engineering 44 Modifications to the exhaust system are expected t o require studies and upgrades to eliminate air inf iltration. Table B-31. Summary of Capital Cost for Installati on of In-Duct Sorbent System, Boiler No. 7 Green Bay Broadway Mill Description 42 Total Cost (2007$) 43

Direct Costs Major Equipment 12,600,000 Demolition 250,000 Site Improvements 157,500 Piling, Caissons 450,000 Buildings 120,000 Concrete 141,750 Structural Steel 567,000 Piping 535,500 Insulation - Pipe, Equipment & Ductwork 283,500 Instrumentation 157,500 Electrical 346,500 Painting, Protective Coatings 47,250 Construction Indirect Costs Construction Support Labor 184,480 Premium Time 53,062 Craft Per Diem 116,965 Non-Payroll Tax, Insurance & Permits 438,838 Craft Start-Up Assistance 43,650 Contractor's Construction Fee 406,796 Project Indirect Costs Construction Management 478,000 Engineering Professional Services 1,058,000 Outside Consultant Services 100,000 Owner's Cost 700,000 Spare Parts 641,025 Non-Craft Start-Up Assistance 119,150 Allowance For Unforeseen 1,999,647 Escalation 1,044,328 Air Infiltration Allowance 44 100,000

Total Installed Cost (+/- 30%) (TIC) 23 ,140,441GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-67 Table B-32 presents the annual operating costs for the In-Duct Absorption system.

Table B-32. Annual Operating Cost Calculations, In -Duct Absorption System for Boiler No. 7, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 0.5 hrs/shift x 1,095 shifts/yr @ $40/hr 21,900 Supervisor Labor 15% of Operator 3,285 Maintenance labor: 0.5 hrs per day x 365 days/yr @ $40/hr 7,300 Maintenance material 100% of Maintenance Labor 7,300

Electricity 0.059$/kWhr x 2,534,375 kWhr 149,528 Trona consumption $150/ton Trona x 5.2 tons Trona/h r 45 x 8,400 hr/yr 6,552,000 Landfill Additional Baghouse solids $ 9.50/ton x 4. 4 tons solids/hr x 8,400 hrs/yr 351,120

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 23,871 Taxes, insurance, admin. factor: 4% of TIC (Table B -31) 925,618 Capital recovery factor (system): 0.1098 x TIC (Tab le B-31) 2,540,696

Total Annual Cost 10,582,618

45 Based on vendor estimate

Determining annual operating costs is sensitive to the amount of sulfur dioxide removed and sorbent required. The 2002-2004 actual emissions are signi ficantly lower than permitted emissions and thus represent a conservatively lower annualized cost (a nd operation) estimate.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of S O 2 Removed. The estimated cost effectiveness is: $10,582,618 / (50% x 8,715 tons) = 2,428 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-68 Clean Fuels Cost Evaluation

As mentioned above, Boiler No. 7 combusts eastern l ow fusion coal and petroleum coke. The only fuel limited by the air permit is the amount of petroleu m coke to approximately 24% by weight of total fuel

. Table B-33 presents the range of heat value, ash an d sulfur content of the various fuels.

Determining marginal costs of fuel with different s ulfur concentrations is reasonably certain for a sh ort “future”. As the period for a fuel forecast is ext ended, uncertainty rapidly increases. Therefore, t he unit cost is presented as a range where estimated. Subs equent calculations use the average of the high and low end of the range.

Table B-33 Unit Costs for Various Fuels Fired in Bo iler No. 7, Green Bay Broadway Mill

Fuel Sulfur % MMBtu/ton $/MMBtu 2009-2013 Petroleum Coke 5 to 6.5 27.6-28.4 1.71 Eastern Low-fusion Coal 2.5-2.7 25.4-27.0 3.35

The cost evaluation determined the costs of substit uting all petroleum coke with eastern low-fusion co al.

Table B-34 presents a summary of the sulfur dioxide emission estimates for this case.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-69 Table B-34. Clean Fuel Emission Calculations, Boil er No. 7, Green Bay Broadway Mill

Low Fusion Petroleum

Coke Total

2002-2004 MMBtu Estimate (annual) 3402280 871980 4274259 2002-2004 Tons (annual) 129858 30812 160670 Sulfur into the Boiler (tpy) 3091 1722 4813 Percent of Emissions 64% 36% SO 2 Emission Estimate (tpy) 5596 3119 8715 Fuel Cost (MM$) 11.4 1.5 12.9

Case 1 : Switch Petroleum Coke to Eastern Low Fusio n MMBtu 4274259 -- 4274259 Tons Fuel 163140 -- 163140 Sulfur into the Boiler (tpy) 3883 -- SO 2 Emission Estimate (tpy) 7765 -- 7765 Fuel Cost (MM$) 14.3 -- 14.3

Table B-35 summarizes the annual marginal fuel cost s and emissions reductions relative to 2002-2004

actual emissions for these cases.

Table B-35. Summary of Fuel Cost Increases for Vari ous Fuel Switch Cases, Green Bay Broadway Mill

Case 2002-2004 1

Average $/MMBtu $3.02 $3.35 SO2 Emissions 8,715 7765 Emission Change (tpy) NA 950 % Reduction 11% Fuel Cost ($/yr) $12,888,722 $14,318,768 Fuel Cost Increase ($/yr) NA $1,430,047 Cost Effectiveness Fuel Price Only ($/ton) NA 1,506

Summary of Economic Evaluation, SO 2 Controls for Power Boiler No. 7GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-70 The economic evaluation determined a range of cost effectiveness values for the following levels of co ntrol: Less than 50%, 50%, and 90%. Figure B-9 presents a marginal cost curve for all the cost estimates presented in Table B-25 through B-35.

Figure B-9. Marginal Cost Curve for SO 2 Control Options, Green Bay Broadway Mill Boiler No .7

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions Control options: 11% removal by Clean Fuels; 50% r emoval by FSI or In Dusct Sorbent Injectionremoval by gas absorption (scrubber)

Energy and Environmental Impacts Throughout the economic analysis, the cost estimate s documented, where possible, the actual costs for additional energy consumption, additional water dem and, and addition solid waste generated. Also in e ach technology discussion, the analysis discussed envir onmental impacts. Table B-36 summarizes a comparis on of energy and environmental impacts for each option

. 

### 500 1000 1500 2000 2500 3000 3500

0 2000 4000 6000 8000 10000

Actual Annual Tons SO2 Removed (tpy)Cost Effectiveness ($/ton)



### Low Cost High Cost 11% 50% 90%GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-71 Table B-36. Summary of Additional Impacts for SO 2 Control Technologies, Boiler No. 7

Technology Impacts Scrubber FSI/ Induct Injection Clean Fuels Additional Energy (kWhr/yr) 11,963,492 3,801,797 No ne Additional Water (million gal) 4,519 None None

Additional Solid Waste (tons) 100,377 44,300 None Environmental Impacts Treatment of metals in waste stream Higher PM 10 Loading to Baghouse Higher PM 10 Loading

to Baghouse

Other Impacts Wet Plume Additional CO 2 from Trona decomposition; FSI may reduce NOx Less CO 2 emissionsGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-72 3.5 NITROGEN OXIDES Step 1a-Identification of Control Technologies-Typi cal Technologies in Use in the United States The technologies typically available for multi-fuel cyclone boilers are equivalent to the technologies presented in Section 2.5 for Boiler No. 6. These t echnologies are:

• Low Nitrogen Fuel

• Selective Catalytic Reduction

• Selective Non-Catalytic Reduction

• Air Staging of Combustion

• Flue Gas Recirculation

• Low-NOx Burners

Step 1b-Identification of Control Technologies-Revi ew of RACT/BACT/LAER Clearinghouse (RBLC)

Searches of the RBLC were conducted to identify con trol technologies for the control of emissions from cyclone power boilers. The specific category searc hed was External Combustion- 11. Table B-37 summarizes recent retrofit technologies determinati ons.

Table B-37. Summary of RBLC and Recent NO x Emission Limits for Various Coal Boilers NO x Emissions Source Technology (lb/MMBtu) Utility Boilers SCR/SCR+LNB 0.07 - 0.09 Utility Boilers LNB+SNCR 0.1 Utility Boilers SNCR 0.08 - 0.15

Industrial Boilers Circulating Fluid Bed SNCR 0.08 Stoker/Other None 0.246 - 0.7

Recent Permits with Add On Technologies Temple Inland -Rome, GA LNB 0.5 Smurfit-Stone (Maritime) Jacksonville, FL SNCR 0.5GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-73 Step 1c-Identification of Control Technologies-Revi ew of Technologies in Use at Georgia-Pacific Corporation Facilities For several coal boilers at various facilities, GP uses a variety of NO x reduction measures, including overfire air, FGR, and combustion controls. GP use s ammonia injection for NO x control for one

combination fuel fluidized bed boiler and one deink ed wastewater sludge-fired boiler.

Step 2-Technical Feasibility Analysis-Eliminate Tec hnically Infeasible Options All of the options identified above are technically feasible except for low-Nitrogen fuel substitution and

the use of low NO x burners.

Step 3 – Ranking the Technically Feasible Alternati ves to Establish a Control Hierarchy The ranking for NO x control is:

1. Tail-end SCR at 80% removal efficiency

2. SNCR with OFA at 70% removal efficiency

3. ROFA and Rotamix at 66% removal efficiency

4. OFA at 60% removal efficiency

5. SNCR alone at 35% removal efficiency

Step 4- Effectiveness Evaluation Economic Effectiveness For each cost estimate, the Green Bay Broadway Mill provided several general assumptions to equipment vendors and engineering contractors to determine si te-specific cost estimates with a target accuracy o f +/-

30% or better.

SCR Cost Evaluation The NO x removal technology with the highest removal effici ency studied is SCR. SCR technology is a post-process NO x control option used to remove NO x after the combustion process rather than limit NO x development at the source. In this case, a reactor filled with an application-specific catalyst is pl aced in the boiler outlet flue gas stream. The catalyst in the se reactions is only effective in a narrow elevated temperature range. In this case, the flue gas need s to be between 600oF and 650oF in order to maximiz e the effectiveness of the catalyst without causing therm al damage. Two (2) SCR reactor installation locati ons that allow for the appropriate flue gas temperature were evaluated. The first option would be to modi fy the boiler’s flue gas outlet path to accommodate placem ent of the SCR reactor prior to the boiler’s existi ng air preheater. The second available reactor installati on location is downstream of the existing baghouse.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-74 Locating the SCR reactor between the boiler flue ga s outlet and the existing air preheater provides th e necessary flue gas temperatures; however, it also p resents several key obstacles. These obstacles inc lude high flue gas velocities, reduced residence time fo r the flue gas to pass through the catalyst bed, da mage to the catalyst, and blinding of catalyst pores due to high particulate loading. Because of these factor s as well as constructability issues, the Slip Stream SCR was estimated as a tail-end unit. Figure B-6 presents a general arrangement.

The estimate for Boiler No. 7 follows a similar met hodology as Boiler No. 6 with a re-design of equipm ent

due to size of the boiler and its level of emission s. Stack 10 will continue to serve one chamber of the Standard Havens baghouse. Table B-38 presents the capital cost estimate for a tail-end SCR for Boiler No.

7.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-75 Table B-38. Summary of Capital Cost for Installati on of SCR Slip-Stream System, Boiler No. 7 Green Bay Broadway Mill Description 2009 Costs ($) Direct Costs Major Equipment 9,158,122

Demolition 20,773 Site Improvements 686,859 Piling, Caissons 961,603 Buildings 36,000 Concrete 1,249,240 Structural Steel 2,518,690 Piping 2,548,351 Insulation - Pipe, Equipment & Ductwork 2,447,224 Instrumentation 1,030,289 Electrical 1,076,904 Painting, Protective Coatings 137,372 Construction Indirect Costs

Construction Support Labor 1,044,553 Premium Time 311,917 Craft Per Diem ($7/Hour On 100 % Of Time) 638,654 Non-Payroll Tax, Insurance & Permits 864,094 Craft Start-Up Assistance 43,650 Contractor's Construction Fee 2,029,476 Project Indirect Costs

Construction Management 1,949,000 Engineering Professional Services 6,500,000 Study Cost 50,000

Outside Consultant Services 100,000 Owner's Cost 1,225,000 Spare Parts 319,000 Non-Craft Start-Up Assistance 119,150 Allowance For Unforeseen 3,701,594 Escalation 2,422,800 Air Infiltration Allowance 100,000

Total Installed Cost (+/- 30%) (TIC) 43,290,315GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-76 Table B-39 presents the annual operating costs for the SCR system.

Table B-39. Annual Operating Cost Calculations, SC R for Boiler No. 7, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 2 hours per shift x 1,025 shifts/ yr @ $40/hr 82,000 Supervisor Labor 15% of Operator 12,300 Maintenance labor: 0.5 hours per day x 365 days/yr @ $40/hr 7,300 Maintenance material 100% of Maintenance Labor 7,30 0

Electricity 0.059$/kWhr x 6737068 kWhr 397,487 Ammonia consumption $160/ton aq NH 3 x 33899 tons aq NH 3 /yr 5,423,840 Natural Gas $10/MMBtu x 822,326 MMBtu/yr 8,223,260 Catalyst $936,224/ 3 years 312,075

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 65,340 Taxes, insurance, admin. factor: 4% of TIC (Table B -38) 1,731,613 Capital recovery factor (system): 0.094 x TIC (Tabl e B-38) 4,086,299

Total Annual Cost 20,348,814

Determining annual operating costs is sensitive to the amount of NO x removed and ammonia required.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $20,348,814/ (80% x 2,740 tons) = 9,283 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-77 ROFA and Rotamix Cost Evaluation Section 3.4 presented the application of Mobotec’s ROFA and Rotamix costs within its FSI technology. The total installed cost for targeting NO x contol only is estimated to be approximately $1.9M M lower by removing the limestone injection, handling, and storage equipment specifically needed for SO 2 removal. Thus, the expected total installed cost i s $27,000,000. Table B-40 presents the annual operating costs without the limestone use or landfi lling charges.

Table B-40. Annual Operating Cost Calculations, R OFA/ROTAMIX for Boiler No. 7, Actual 2002- 2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per shift x 1,025 shifts/ yr @ $40/hr 41,000 Supervisor Labor 15% of Operator 6,150 Maintenance labor: 0.5 hours per day x 365 days/yr @ $40/hr 7,300 Maintenance material 100% of Maintenance Labor 7,300

Electricity- direct 0.059$/kWhr x 3801797 kWhr 224,306

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 37,050 Taxes, insurance, admin. factor: 4% of TIC 1,080 ,000 Capital recovery factor (system): 0.094 x TIC ($27M M) 2,548,609

Total Annual Cost 3,951,715

Determining annual operating costs is only sensitiv e to the number of hours the air mixing system is operated. The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $3,951,715/ ( 66% x 2,740 tons) = 2,185 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-78 SNCR Cost Evaluation SNCR systems are most efficient in a single tempera ture window; therefore, in order to properly operat e an SNCR system, a boiler study is required to map t he gas temperatures at several locations during varying boiler operating points. A detailed SNCR s tudy was not conducted for Power Boiler No. 7; however, the SNCR supplier requires such a study an d the SNCR estimate includes a one-time cost of $50,000 to accomplish this task.

The estimate for Boiler No. 7 follows a similar met hodology as Boiler No. 6 with a re-design of equipment due to size of the boiler and its level o f emissions. The vendor has indicated that an SNCR system on a cyclone boiler can achieve 35% reductio n. Table B-41 presents the total installed cost estimate for an SNCR system alone.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-79 Table B-41. Summary of Capital Cost for Installati on of SNCR System, Boiler No. 7 Green Bay Broadway Mill Description TOTAL COST (2007$) Direct Costs Major Equipment 1,704,630

Demolition 38,354 Site Improvements 85,232 Piling, Caissons 119,324 Buildings 270,000 Concrete 76,708 Structural Steel 306,833 Piping 289,787 Insulation - Pipe, Equipment & Ductwork 153,417 Instrumentation 42,616 Electrical 232,092 Painting, Protective Coatings 17,046 Construction Indirect Costs

Construction Support Labor 140,891 Premium Time 41,289 Craft Per Diem 89,328 Non-Payroll Tax, Insurance & Permits 124,932 Craft Start-Up Assistance 45,000 Contractor's Construction Fee 245,577 Project Indirect Costs

Construction Management 295,000 Engineering Professional Services 652,000 Outside Consultant Services 100,000 Owner's Cost 197,000 Spare Parts 74,279 Non-Craft Start-Up Assistance 119,150 Allowance For Unforeseen 546,048 Escalation 386,091 Air Infiltration Allowance 100,000

Total Installed Cost (+/- 30%) (TIC) 6,492,624

Table B-42 presents the annual operating costs for the SNCR system.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-80 Table B-42. Annual Operating Cost Calculations, SN CR for Boiler No. 7, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per shift x 1,025 shifts/yr @ $40/hr 41,000 Supervisor Labor 15% of Operator 6,150 Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 Maintenance material 100% of Maintenance Labor 7,00 0

Electricity 0.059$/kWhr x 821763 kWhr 48,484 Urea Consumption $1.35/gal x 34.4 gph x 8400 hr/yr 390,096 Mill Water $0.06/kgal x 7,884 kgal/yr 473

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 36,690 Taxes, insurance, admin. factor: 4% of TIC (Table B -41) 259,705 Capital recovery factor (system): 0.094 x TIC (Tabl e B-41) 610,307

Total Annual Cost 1,406,905

Determining annual operating costs is sensitive to the amount of NOx removed and urea required.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $1,406,905/ ( 35% x 2740 tons) = 1,467 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-81 OFA Cost Evaluation An additional NOx control case that was studied and estimated for Power Boiler No. 7 was Overfire Air.

The installation of OFA reduces the formation of NO x by staging combustion into two zones. The first combustion stage created by this process control sy stem redistributes some of the combustion air away from the cyclone burners allowing the burners to operate fuel rich. The subsequent fuel rich zone prevents the

formation of thermal NO x by providing a low oxygen concentration in the cyc lone burner. Thermal NO x is caused by the reaction of nitrogen and oxygen in ar eas of high flame temperatures. In the fuel-rich s tage,

the formation of NO x is low but the formation of CO and combustibles is high. The second stage of the OFA system allows for the completion of combustion by adding combustion air to the furnace downstream of the cyclone burners. The second stage combustio n in the furnace occurs at a lower temperature with subsequent reduction in formation of thermal and fu el bound NO x . Fuel bound NO x is the result of the oxidation of fuel bound nitrogen.

The new OFA system would include ductwork from the existing high pressure forced draft (FD) fans’ outl et to each port location; expansion joints, dampers an d operators, annubars for delta-P measurement to ma jor port locations, as well as boiler tube bends and in jection wall boxes. Due to the cyclone boiler’s hi gh pressure FD Fans, no booster OFA fan would be requi red for the system. Combustion air port design wou ld be dependent on the supplier. Several different de signs are available in the market place to ensure t hat the appropriate amount of air and air penetration could be achieved during boiler swings. Money is includ ed in the BART estimate for the supplier to perform a stu dy to determine the appropriate location for the OF A ports. Money is included in the BART estimate for minor relocation and demolition to allow for the OF A system ductwork installation.

Table B-43 presents the total installed cost estima te for an OFA system alone.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-82 Table B-43. Summary of Capital Cost for Installati on of OFA System, Boiler No. 7 Green Bay Broadway Mill Description TOTAL COST (2007$) Direct Costs Major Equipment 992,465 Demolition 38,749 Site Improvements 49,623 Buildings 270,000 Concrete 29,774 Structural Steel 148,870 Insulation - Pipe, Equipment & Ductwork 45,021 Instrumentation 24,812 Electrical 99,168 Painting, Protective Coatings 9,925 Construction Indirect Costs Construction Support Labor 86,960 Premium Time 25,969 Craft Per Diem 55,135 Non-Payroll Tax, Insurance & Permits 56,507 Craft Start-Up Assistance 45,000 Contractor's Construction Fee 143,014 Project Indirect Costs Construction Management 162,000 Engineering Professional Services 358,000 Study Cost 50,000 Outside Consultant Services 100,000 Owner's Cost 108,000 Spare Parts 32,742 Non-Craft Start-Up Assistance 59,575 Allowance For Unforeseen 294,131 Escalation 190,808 Air Infiltration Allowance 100,000 Total Installed Cost (+/- 30%) (TIC) 3,576,246

Table B-44 presents the annual operating costs for the OFA system.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-83 Table B-44. Annual Operating Cost Calculations, OF A for Boiler No. 7, Actual 2002-2004 Conditions Parameter Methodology Annual Cost ($) Direct Costs Operating labor : 1 hours per day x 350 days/yr @ $40/hr 14,000 Supervisor Labor 15% of Operator 2,100 Maintenance labor: 0.5 hours per day x 350 days/yr @ $40/hr 7,000 Maintenance material 100% of Maintenance Labor 7,00 0

Electricity 0.059$/kWhr x 890,491 kWhr 52,539

Indirect Costs Overhead rate (fractional): 60% of total labor and material costs 18,060 Taxes, insurance, admin. factor: 4% of TIC (Table B -43) 143,050 Capital recovery factor (system): 0.094 x TIC (Tabl e B-43) 336,167

Total Annual Cost 579,916

Determining annual operating costs for OFA is sensi tive only to the number of hours the fan is used. The operating costs reflect a typical annual operation of 8,400 hours/year (350 days/yr).

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed. The estimated cost effectiveness is: $579,916/ (60 % x 2,740 tons) = 353 $/ton.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-84 SNCR with OFA Cost Evaluation In an attempt to design a more successful combustio n modification technology with urea injection, the Mill developed a cost estimate for the combination of both OFA and SNCR. Table B-45 tabulates the cost estimate for this combination of technologies.

Table B-45. Summary of Capital Cost for Installati on of OFA/SNCR System, Boiler No. 7 Green Bay Broadway Mill Description TOTAL COST

OFA System (Table B-43) 3,576,246 SNCR System (Table B-41) 6,492,624

Total Installed Cost (+/- 30%) (TIC) 10,068,870

Table B-46 presents the operating costs for a combi nation of OFA and SNCR.

Table B-46. Annual Operating Cost Calculations, OF A+SNCR for Boiler No. 7, Actual 2002-2004 Conditions Parameter Annual Cost ($)

Direct Costs OFA SNCR Total Operating labor : 14,000 41,000 Supervisor Labor 2,100 6,150 Maintenance labor: 7,000 7,000 Maintenance material 7,000 7,000

Electricity 52,539 48,484 Urea and Water 0 390,569 Indirect Costs Overhead rate (fractional): 18,060 36,690 Taxes, insurance, admin. factor: 143,050 259,705 Capital recovery factor (system): 336,167 610,307

Total Annual Cost 579,916 1,406,905 1,986,821

Determining annual operating costs for the combinat ion is sensitive to the number of hours the fan is used as well as the urea consumption requirement.

The cost effectiveness of this technology is equal to the Total Annualized Costs/ Annual Quantity of N Ox

Removed.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-85 The estimated cost effectiveness is: $1,986,821/ ( 70% x 2,740 tons) = 1,036 $/ton.

Summary of Economic Evaluation, NOx Controls for Po wer Boiler No. 7 The economic evaluation determined a range of cost effectiveness values for the following levels of co ntrol: 35%, 60%, 66%, 70%, and 80%. Figure B-10 presents a marginal cost curve for all the cost estimates presented in above.

Figure B-10 Marginal Cost Curve for NOx Control O ptions, Green Bay Broadway Mill Boiler No. 7

Note: Annual Actual tons removed shown is relative to 2002-2004 actual emissions Control options: 35% by SNCR; 60% by OFA; 66% by R OFA/ROTAMIX; 70% by SNCR and OFA; 80% by SCR

Energy and Environmental Impacts Throughout the economic analysis, the cost estimate s documented, where possible, the actual costs for additional energy consumption, additional water dem and, and addition solid waste generated. Also in e ach technology discussion, the analysis discussed envir onmental impacts. Table B-47 summarizes a comparis on of energy and environmental impacts for each option

.

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

750 1250 1750 2250 2750

Acutal Annual Ton NOX Removed (tpy)Cost Effectiveness ($/ton)

Average $/ton 80%

70% 66%

60% 35%GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-86 Table B-47. Summary of Additional Impacts for NOx Control Technologies, Boiler No. 7

Technology Impacts SNCR Options Combustion Modifications SCR Additional Energy (kWhr/yr) 82,1763 1,712,254 6,737 ,068 Additional Water (million gal/yr) 7.884 0 0 Additional Natural Gas (MMcf/yr) 0 0 822 Environmental Impacts NH 3 Emissions None NH 3 Emissions Other Impacts NH 3 Handling None NH 3 HandlingGP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-87 3.6 ADDITIONAL MULTI-POLLUTANT CONTROL OPTION FOR B OILER NO. 7 As mentioned above, Boiler No. 7 provides significa nt energy to the Mill. The steam that Boiler No. 7 produces can be viewed as being directly used for e lectricity generation through condensing this steam

in the mill’s steam turbine condensers. Boiler No. 7 has the capacity to produce 550,000 lbs steam pe r hour and, by passing this steam through the mill’s turbines to its condensers, can yield an output of approximately 55 megawatts (MW) for use in the plan t. An additional multi-pollutant option for Boiler No. 7 is to replace the electrical generation with purchased electricity while reserving its steam production capacity for intermittent operation ( i.e., scheduled downtime of other steam-producing units at the Mill). Increasing the use of purchased elec tricity will require a one-time upgrade to electric al infrastructure. The Electrical Infrastructure Upgr ade option is technically feasible. The cost evalu ation is provided for comparison purposes. This option i s not a conventional control technology as it drastically reduces the ability for the source to o perate as it does presently.

Cost Evaluation Through its current arrangement with Wisconsin Publ ic Service Corporation (WPS), (the mill’s utility service provider), two potential electrical infrast ructure upgrades could be considered for the mill. One upgrade would involve the installation of a new tra nsmission level (138 Kilovolt) connection to the utility with the substation being located on the mi ll property. The other upgrade would involve the installation of one or two additional primary volta ge level (13.8 Kilovolt) connections to the mill property from existing or new WPS substations. Bot h solutions have distinct advantages and disadvantages which need to be further evaluated be fore a solution is chosen. The estimated total

installed cost for either one of these solutions is $5 million.

The annual operating cost of the Electrical Infrast ructure Upgrade is limited to the marginal cost of purchased electricity and indirect costs. Direct o perating costs associated with the electrical equip ment

is shared with WPS.

The average steam production across the 2002-2004 b aseline period was 3,441,735 klbs/steam per year. Assuming all of the steam from Boiler No. 7 was use d to generate electricity through condensing in the mill’s turbine generators, the mill would convert t his amount of steam into approximately 344,173 MW for an annual period, and 39.29MW/hr (annual averag e). The incremental unit cost of purchased electricity from WPS above the cost for Boiler No. 7 to produce the power is $25/MW-hr for on-peak hours. The incremental cost of purchased electrici ty from WPS is approximately equal to the Boiler No

. 7 generation cost during off-peak hours. The annua l average incremental unit cost is:GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-88 $25/MW-hr x 3900 on-peak hr/yr + $0.00/MW-hr x 4860 off peak hr/yr / (8,760 hours/yr) = = $11.13/MW-hr (annual average)

The electrical infrastructure upgrade option would require the mill to operate Boiler No. 7 as a steam

source when another boiler is down. Based on the n umber of boilers at the mill, their steam usage and scheduled outage durations, the mill estimates that Boiler No. 7 would operate up to 60 days or 16.4% of the year. This would result in an 83.6% emissio ns reduction for all pollutants on a pollutant-bypollutant basis, including those not subject to BAR T.

The direct annual operating cost associated with el ectrical energy charges is estimated to be: 39.29 MW-hr/hr x (83.6%) x 8760 hr/yr x $11.13/MW-h r = $3,202,488/yr ($2009).

In addition to the electrical energy charges detail ed above, the mill would also incur electrical dema ndrelated charges. Electrical demand charges from WP S are billed monthly and consist of an annual demand-related charge and a monthly demand-related charge. The annual (customer) demand charge would be largely unchanged. However, monthly (syst em) demand charges would be affected for approximately 10 months of the year.

Based on a 4 MW firm demand nomination, the additio nal demand-related costs resulting from reducing the operation of Boiler No. 7 to 60 days per year a re: [39.29 MW – 4 MW] x 10-months x $3,139/MW = $1,107, 753/yr ($2009)

The estimated indirect annual cost is the capital r ecovery for the installed equipment. For this opti on, the analysis used a capital recovery factor of 7% i nterest over 20 years. As described above, the capi tal recovery factor is 0.0944. Thus the indirect annua l cost for capital recovery is: 0.0944 x $5,000,000 = $472,000/yr.

The total annual cost is $3,202,488/yr + $1,107,753 + $472,000 = $4,782,241/yr. ($2009)

In addition to the limited operating schedule, the option will include the exclusive use of low fusion eastern coal. As presented above, the reduction in actual emissions from this fuel switch is approximately 11%. When combined with the 83.6% re duction, the total annual average reduction is: 83.6% + (1-83.6%) x 11% = 85% for SO 2 .GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-89 The cost effectiveness is equal to the Annual Cost per Ton removed. Though this is a multi-pollutant option, the analysis calculated cost effectiveness for each pollutant individually for direct comparis on to other technologies.

The cost effectiveness for SO 2 is: $4,782,241/ (85% x 8,715 tons SO 2 ) = $646

The cost effectiveness for NO x is: $4,782,241/ (83.6% x 2,740 tons NO x ) = $2,088

The actual cost effectiveness is lower than these c alculated values as the total annual cost is only s pent once and achieves the reduction of both pollutants simul taneously.GP Consumer Products Green Bay Mill Best Available Retrofit Technology Analysis March 2009

B-90 

### 4.0 BART ENGINEERING ANALYSIS SUMMARY

Table B-48 presents the summary of the technically feasible options for the BART eligible emission

units.

* Technologies which are not economically feasible due to marginal or incremental cost effectiveness. Table B-48. Summary of BART Engineering Analysis G reen Bay Broadway Mill

Emission Unit Pollutant Technology Maximum Reduction (%) Annual Operating

Cost ($) Effectiveness

($/ton) Boiler No. 6 SO 2 Wet Scrubber 90 10,057,563 5,174* Boiler No. 6 SO 2 Semi Dry Scrubber 90 6,004,723 3,089*

Boiler No. 6 SO 2 Clean Fuels 62 $1,631,891 1,082

Boiler No. 6 SO 2 Furnace Sorbent Injection 50 4,502,391 4,169

Boiler No. 6 SO 2 In Duct Sorbent Injection 50 4,317,733 3,998

Boiler No. 6 NOx SCR 80 9,871,725 28,831* Boiler No. 6 NOx ROFA - ROTAMIX 66 3,660,476 12,958 * Boiler No. 6 NOx SNCR+ OFA +FGR 56 2,077,302 8,667* Boiler No. 6 NOx SNCR 25 1,061,490 9,920* Boiler No. 6 NOx OFA/FGR 20 619,998 7,243*

Boiler No. 7 SO 2 Wet Scrubber 90 24,818,896 3,164*

Boiler No. 7 SO 2 Semi Dry Scrubber 90 11,971,942 1,526*

Boiler No. 7 SO 2 Electrical Upgrades + Fuel Switch 85 4,782,241 646

Boiler No. 7 SO 2 Furnace Sorbent Injection 50 6,953,964 2,429

Boiler No. 7 SO 2 In Duct Sorbent Injection 50 10,582,618 1,596

Boiler No. 7 SO 2 Clean Fuels 11 1,430,047 1,506

Boiler No. 7 NOx Electrical Upgrades + Fuel Switch 83.6 4,782,24 1 2,088

Boiler No. 7 NOx SCR 80 20,348,814 9,283*

Boiler No. 7 NOx SNCR+ OFA 70 1,986,821 1,036

Boiler No. 7 NOx ROFA - ROTAMIX 66 3,951,715 2,185

Boiler No. 7 NOx OFA 60 579,916 353

Boiler No. 7 NOx SNCR 35 1,406,905 1,467Georgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708



# Appendix A: Basis of Estimated CostsGeorgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708

GENERAL

The purpose of these cost estimates is to provide Georgia Pacific with a Feasibility Study Level Report in 2007 dollars with an accuracy range of ± 30 % for the Regional Haze/ Boiler BART Program at the Greenbay, Wisconsin Mill.

Estimates were prepared by Jacobs for various SO 2 and NO X control technologies for the boilers which where put in place or under construction between August 7, 1962 and August 7, 1977. These cost estimates were prepared in such a manner to ensure that each boiler proposed control technology and related cost estimate would stand alone on its own merit. This approach was selected to better address the uncertainty that will exist between which project or combination of projects might ultimately be implemented to meet the emissions targets established for the EPA Regional Haze / Boiler BART 2013 compliance date. Certain site specific conditions and / or the presence of alternate control technologies in the future may ultimately impact the overall project costs and feasibility of these projects if several of these projects are implemented concurrently on any given site.

In addition, the numbers used in this estimate for equipment cost do not always reflect the exact dollar amount that was provided by a vendor and reported in Appendix D. In many cases, Jacobs has used their sound engineering judgment and previous experience to change these prices. These changes may be for many reasons including but not limited to: adding or removing installation costs, adjusting for construction with a more expensive material, adding or removing options, increasing the controls included, etc. In order to allow for air in-leakage in the existing Boilers, $100,000 has been added to each estimate to locate and repair any areas where excessive air infiltration may be occurring. This is required to ensure that any control technologies installed operate as they were designed.

GP plans to utilize the results from this feasibility study report and cost estimate(s) to support the Regional Haze / Boiler BART documentation submittal requirements to the individual States. This will establish the viability for installing the Boiler BART Control Technologies on these respective site boilers or whether to de-rate or decommission them to a capacity level below BART-eligibility.

At the time of issue, this estimate reflects the fair market value for construction costs, based upon 2007 dollars, in the Greenbay, Wisconsin area.

ESTIMATE APPROACH

The estimate is based on Jacobs providing Engineering, Construction Management and Procurement Services.Georgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708

For the basis of the cost estimate, detailed engineering, procurement and construction activities are assumed be completed by December 31, 2007.

WAGE RATES

The wage rates used in this estimate are composite, union all-in rates. The base journeyman rate ranges from $25.53 to $29.11. Jacobs established a crew mix for each craft, ranging from 97.98 % to 99.89 % of the base journeyman rate - see the All-In Wage Rate Sheet in the Estimate Detail Printout. Included in the wage rates are the following:

• 81 - PAYROLL TAXES AND INSURANCE

Payroll Taxes and Insurance are included at 33.6 % of bare craft labor.

• 79 - CRAFT FRINGE BENEFITS

Craft Fringe Benefits are included and range from 37.95 % to 62.01 % of bare craft labor.

• 76 - TEMPORARY CONSTRUCTION FACILITIES

Temporary Construction Facilities include Contractor’s office supplies, PC’s, copiers, postage, phones, Fed Ex, temporary sanitary facilities, mobilization, trash removal and temporary lights. These items are calculated at 7.5% of bare craft labor.

• 83 & 84 - SMALL TOOLS AND CONSUMABLES

Small tools are included in the estimate at 7.5 % of bare craft labor. Construction consumables are included in the estimate at 7.5 % of bare craft labor.

• 87 - CONTRACTORS FIELD STAFF

Field staff includes all contractors’ field support staff except for craft foremen which are included in the crew mix calculations. Contractors Field Staff is calculated at 25 % to 35 % of bare craft labor based on the type of work being performed.

• 85 - CONSTRUCTION EQUIPMENT RENTAL

Construction equipment rental includes the contractors’ automotive equipment, general equipment and small cranes. This construction equipment cost is calculated at 25 % to 40 % of bare craft labor based on the discipline - concrete, steel, pipe, electrical, etc. - being supported - see the All-In Wage Rate Sheet in the Estimate Detail Printout for the percent used for each discipline. If required, a line item is listed in the estimate for situations that require large cranes not covered by the allowance carried in the rate.

• 93 – CONTRACTOR’S HOME OFFICEGeorgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708

Contractor’s Home Office cost includes time for Project Manager, accounting, safety, quality control, etc. is included in the Contractor’s Fee.

• 99 - CONTRACTOR’S FEE

Contractor’s fee is included in the estimate at 10 % of contractor’s construction cost.

• 75 - CONTRUCTION SUPPORT LABOR

Construction Support Labor includes drug testing, safety training, fire watch, final cleanup, yard crews, etc. This cost is calculated as 20 % of bare craft labor.

DIRECT COSTS

50 - MAJOR EQUIPMENT

Vendor budget quotes were received for the Major Equipment.

Pump and motor installation hours are from Jacobs Standards. Other equipment installation cost items are based on historical experience.

Freight cost is included at 6 % of equipment cost.

51 – DEMOLITION AND RELOCATION

Demolition cost is factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

53 - SITE IMPROVEMENTS

Site Improvement costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

54 – PILING

Piling costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

56 – CONCRETE

Concrete costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

58 – STRUCTURAL STEEL

Structural Steel costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.Georgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708

62 – PIPING

Piping costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

63 – INSULATION

Insulation costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

64 – INSTRUMENTATION

Instrumentation costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

65 – ELECTRICAL

Electrical Costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

66 – PAINTING

Painting costs are factored from installed process equipment cost but have been adjusted, as required, to reflect specific site requirements.

INDIRECT COSTS

70 – SPARE PARTS

An allowance for Spare Parts of 5 % of the process equipment cost is included.

78 - PREMIUM TIME

Premium Time is included based on the assumption that 100 % of the craft labor hours will be worked on a 50-hour week.

XX - CRAFT PER DIEM

Craft Per Diem is included at $7.00 per craft hour for all workers.

81 - NON-PAYROLL TAXES, INSURANCE AND PERMITS

Sales Tax is included at 6.5 % on equipment, materials and 6.5 % on 50 % of subcontract costs.

88 - CONSTRUCTION MANAGEMENTGeorgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708

Construction Management is estimated at 4.5 % of Total Installed Cost.

90 – ENGINEERING PR OFESSIONAL SERVICES

Detail Design Engineering is estimated at 10 % of Total Installed Cost.

91 – OWNER’S COST

Owner’s Cost is included at approximately 3 % of Total Installed Cost.

96 – OUTSIDE CONSULTANT SERVICES

An allowance of $100,000 is carried in the estimates for Outside Consultant Services.

98 – CONTINGENCY

Contingency is included in the estimate at 10 % of labor, equipment, material and subcontract costs.

This Contingency is part of the estimated project cost and is to cover unusual weather conditions, productivity issues, increases in co sts not covered by contractual provisions, delays in delivery of equipment or materials, etc. It does not cover cost of additional work or scope changes after the definition of the project has been frozen for the estimate.

98 – ESCALATION

Escalation is based on the assumption that all work will be completed by December 31, 2007. Escalation is included at 7 % on labor, 10 % on equipment, 10 % on all material except for concrete, steel, pipe, instrumentation and electrical material which is included at 15 % and 5 % on subcontract cost

.Georgia Pacific – Green Bay, WI December 12, 2008 Regional Haze/Boiler BART Program Rev. 2 Feasibility Study Report and Estimate Jacobs Job No. 71BN3708

ITEMS NOT INCLUDED

The following is a list of items not included in this estimate:

Cost of Land Cost of borrowing money Cost of operating supplies Property taxes Hazardous materials handling or disposal All Risk Insurance Payment and Performance Bond Permits, Fees and Licenses

ITEMS AFFECTING THE COST ESTIMATE

Items, which may change the estimated construction cost, include, but are not limited to:

Modifications to the scope of work included in this estimate Above normal escalation in material costs due to market availability and demands Special phasing requirements Restrictive technical specifications Volume discounts on National agreements Sole source specifications of materials or products Bids delayed beyond the projected schedule Sales and Use Tax exemptions Labor disputes or difficulties