## 2/9/2009 Updated Ga Pac Bruns Cell to reflect that Wet FGD and combustion controls were identified as technically feasible.

## Updated Ga Pac Bruns Cell to reflect that Wet FGD and combustion controls were identified as technically feasible.**Worksheet H.10-1**



### Four-factor Technical Review **23-Oct-08**

**Facility name: Brunswick Cellulose (GA Pac) Uncontrolled SO** **2 emissions (tons)**  **basis** County: Glynn **Emissions unit: F1 (U700)** AIRS: 1270003 MMBtu/hr capacity 800 2018 VISTAS 1842 fuel: wood waste/bark, No.6 oil, others Facility 4F 1642 2002 CERR % S (fuel oil) 3 output (MW) 70 **Class 1 sulfate impacts** 0.1255 Wolf Is. ACFM stack test 293000 (from VISTAS emissions) 0.0389 Okef. DSCFM stack test 160000 existing control ESP

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCos**

**t/ton Total Cap.** 

**Investment Capital** 

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (kW)**  **Ann.**

**Cost/ACF M**  **Ann.**

**Cost/DSC FM**  **Ann. Cost**

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) (10** **6 $)**  **($10 6** **, 2004) ($10** **6**
**, escalated to**  **2006) (date)** 

**($/kW) ($/ACFM)**  **($/DSCFM )**  95 1560 5449 2.9 0.094 8.5 29.0 53.1 2.88 3.24 0.07 20 2008 543 0 0.0 0 0.0 0.0

70 1.2 0.094 2.74 9.4 17.1 no data 0.07 20 2007

294 0 0 0.42 1.4 2.6 no data no data

2008 731 0.47 2.36 8.1 14.8 no data no data

2008
* tons avoided are incremental over tons avoided with 3% S and 5000 kgal limit; cost/ton uses the incremental tons avoided
(1) Analysis basis (company) wet FGD scaled up from estimate for smaller unit (190,000 acfm); cost of 50 % caustic = $480/ton oil limit use existing S% and transport method (barge); reduce No. 6 oil usage to 5 million gal; based on project that increased boiler efficiency after 2002 oil limit and dry sorbent injection consultant cost estimate, does not include cost of solid waste handling oil limit & fuel switch to 2.2% S use 2.2 S% and existing transport method (barge); oil limit of 5 million gal; tons avoided is incremental over oil limit only oil limit & fuel switch to 1.0% S use 1.0 S% and truck transport; install dedicated storage tank; oil limit of 5 million gal; tons avoided is incremental over oil limit only dry FGD recent installation at like-sized GA Pacific facility; cap. recovery estimated at $7.1 M/yr, too expensive to consider

(2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index) none

none none none 6.0

33.7 facility concern with price variability over time facility concern with price variability over time before 2012

before 2012 insignificant

insignificant none none

Oil limit and fuel switch to S = 1.0%* 1429

3228 Oil limit and fuel switch to S = 2.2%* Oil limit and dry sorbent injection* 769 3562 facility concern with sorbent supply, opacity, and control viability insignificant none none 8000 tons per year Oil Limit, 5000 kgal/yr, S = 3% 13.1 none none none none

39.1 no data for oil-fired uni ts before 2013 0 0.0 before 2012 **Other Environ.**  **Impacts: Solid**  **Waste**

98 MG per year 34 MG

per year did not

address **Other Environ.**  **Impacts: Water**  **Consump. Other** 

**Environ. Impacts:**  **Wastewate**

**r C.R.**  **Factor - CRF**  **- int. rate - life (yrs)**  **Comments**

Wet FGD 31 121.4 did not address before 2013 **Identified and feasible**  **technol. 1**  **Energy Impacts** **BACKUP DATA/CALCS**

**Air Control Net Query** in puts: residual oil, Glynn County, Brunswick MSA

outputs: control FGD (dry) control effic. 90 % annual cost 9.99 mill. $ 1999 dollars boiler cap. 787 MMBtu/hr facility Brunswick Pulp and Paper (Brunswick cellulose)

B. Cellulose emmissions 1642 cost/ton 6760

fuel switching
fuel usage 5 mill. Gal 5 mill. Gal

S content 2.62 % 1.25 % lb S/1000 gal 411.34 lb 196.25 lb S emiss. 1028.35 tons 490.625 tons**Worksheet H.10-2**



### Four-factor Technical Review **9-Feb-09**

**Facility name: Brunswick Cellulose (GA Pac)**  **Uncontrolled SO 2** **emissions (tons) basis**  County: Glynn **Emissions unit: M24 (recov. boiler, non-direct contact evap.)** AIRS: 1270003 MMBtu/hr capacity 2018 VISTAS 193 fuel: black liquor solids, 72 % Facility 4F 193 not addressed in submittal, assume VISTAS % S 2006 stack testing 38 ppmv output (MW) 0 **Class 1 sulfate impacts** 0.0131 Wolf Is. 

### ACFM (from VISTAS emissions) <0.005 Okef. existing control ESP for particulate (threshold = 0.005) <0.005 St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (k**  **W) Ann. Cost** 

**(ACNet) 2**  **Time to**

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6 $)**  **(10 6** **$) (10**  **6 $)**  **($10 6** **, 2004) (date)** 

**($/k W)**  not given #VALUE! #VALUE! no data 0.094 no data 0.07 20 2007

Combustion Controls existing control

Analysis basis (company) Wed FGD or scrubber - GA Pac deemed these technologies to be economically infeasible due to the low SO2 concentration (38 ppm from 2006 stack test)

(2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index) **Other Environ.**  **Impacts: Water**  **Consump. Other** 

**Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)**  **Comments Other**  **Environ. Impacts:**  **Solid Waste** 

no data no data no data Wet FGD no data #VALUE! no data no data **Identified and feasible**  **technol. Energy**  **Impacts**

### Wo**rksheet H.10-3**



### Four-factor Technical Review **3/11/2008**

**Facility name: GA Pac Cedar Springs Uncontrolled SO** **2**

### emissions (tons) **basis** County: Early **Emissions unit: U500** AIRS: 09900001 MMBtu/hr capacity 784 2018 VISTAS 2428 fuel: bitum coal, wood waste, fuel oil Facility 4F 1976 2006 CEMS after 30% control % S (coal) 1 output (MW) 69 **Class 1 sulfate impacts** <0.005 Wolf Is. 

### ACFM 213000 (from VISTAS emissions) <0.005 Okef. existing control venturi scrubber w / water (threshold = 0.005) 0.0108 St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **1** 

### SO**2**



### avoided, **2018 AnnualCo** 

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2** 

### (Ann. **Cost)/ (k**  **W) Ann. Cost** 

**(ACNet) 2**  

### Time to

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6**

### $) **(10 6** 

### $) **(10 6** 

### $) **($10 6** 

### , 2004) **(date)**

**($/k W)**  93 1835 2725 1.8 0.094 5.0 11.9 0.07 20 2007 86 1694 2952 1.8 5.0

79 0.5 0.094 2.6 0.07 20 2007

70 8.8 0.83 0.094 2.3 no data 0.07 20
2007 Coal Washing 15

- - - 3.2 no data

2007 Coal
switching, 0.75 % S 25 494 5668

- - -

2.8 before 2012 did not

address did not

address did not

address did not

address **Comments Other**  **Environ. Impacts:**  **Wastewater C.R.**  **Factor - CRF**  **- int. rate - life (yrs)** 

did not address before 2013 New wet FGD with caustic 18.7 72.9 **Other Environ.**  **Impacts: Solid**  **Waste**

15000 tons/yr did not address did not

address **Identified and feasible**  **technol. Energy**  **Impacts Other** 

**Environ. Impacts:**  **Water Consump.** 

did not address did not

address did not

address 15000

tons/yr Modify existing venturi scrubber, add spray towers and caustic 19.6 before 2012

1553 1675 4.9 37.9 before 2012 did not

address did not

address 15000 tons/yr Modify existing venturi scrubber, add caustic Duct sorbent injection 1663 did not address did not

address did not

address

10796 1383

296 33.5

46.6 did not address

did not address did not

address did not address before 2012

before 2012 did not

address

did not address

### Analysis basis (company)

New wet FGD with caustic - remove exising venturi scrubber, install new wet FGD (95 % effective) Modify existing venturi scrubber - add spray towers and add caustic to existing scrubbant (90 % effective) Modify existing venturi scrubber - add caustic to existing scrubbant (85 % efffective) duct sorbent injection - scaled down from larger unit (70 % effective) coal washing - $15/ton additional cost, 215,000 tpy coal switching - $6/ton additional cost, 215,000 tpy, switch to 0.75% S
1-16-08: update from GA Pacific - revise coal switch cost to $13/ton from $6/ton 2-19-08: update from GA Pacific - increase caustic price by $147/ton, assume 4 tons caustic per ton SO2 removed

(1) Existing venturi scrubber with water is used to control particulate matter and opacity in boiler flue gas. GA Pacific estimates that the scurbber is also removing 30 % of the SO2. Therefore, the control effectiveness of the first three options are calculated in contemplation of replacement of the existing control effectiveness of 30%. The control effectiveness of the fourth option is calculated in contemplation of working in conjuction with the existing control effectiveness of 30%.
(2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index)**Worksheet H.10-4**



### Four-factor Technical Review **24-Oct-07**

**Facility name: GA Pac Cedar Springs Uncontrolled SO** **2 emissions (tons)**  **basis** County: Early **Emissions unit: U501** AIRS: 09900001 MMBtu/hr capacity 784 2018 VISTAS 2533 fuel: bitum coal, wood waste, fuel oil Facility 4F 1976 2006 CEMS for U500 after 30% control; facility may propose 350 lb/hr limit for BART exemption % S (coal) 1 output (MW) 69 **Class 1 sulfate impacts** <0.005 Wolf Is. 

### ACFM 213000 (from VISTAS emissions) <0.005 Okef. existing control venturi scrubber w/ water (threshold = 0.005) 0.0113 St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **1 SO** **2**

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (k**  **W) Ann. Cost** 

**(ACNet) 2**  **Time to**

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6 $)**  **(10 6** **$) (10**  **6 $)**  **($10 6** **, 2004) (date)** 

**($/k W)**  93 1835 2725 1.8 0.094 5.0 11.9 0.07 20 2007 86 1694 2952 1.8 5.0

79 0.5 0.094 2.6 0.07 20 2007

70 8.8 0.83 0.094 2.3 no data 0.07 20
2007 Coal Washing 15

- - - 3.2 no data

2007 Coal switching, 0.75 % S 25 494 5668

- - -

2.8 before 2012 did not

address did not

address did not

address did not

address did not address did not

address 10796 1383

296 33.5

46.6 did not address before 2012

before 2012 did not

address

did not address did not

address did not

address 15000

tons/yr Modify existing venturi scrubber, add caustic Duct sorbent injection 1663 did not address did not

address did not

address 15000 tons/yr

1553 1675 4.9 37.9 before 2012 did not

address 15000 tons/yr **Comments**

Modify existing venturi scrubber, add spray towers and caustic 19.6 before 2012 did not

address did not

address did not

address **Identified and feasible**  **technol. 1**  **Energy Impacts**  **Other**

**Environ. Impacts:**  **Water Consump.**  **Other**

**Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)**  **Other Environ.**  **Impacts: Solid**  **Waste**

did not address did not

address New wet FGD with caustic 18.7 72.9 did not address before 2013Analysis basis (company)

New wet FGD with caustic - remove exising venturi scrubber, install new wet FGD (95 % effective) Modify existing venturi scrubber - add spray towers and add caustic to existing scrubbant (90 % effective) Modify existing venturi scrubber - add caustic to existing scrubbant (85 % efffective) duct sorbent injection - scaled down from larger unit (70 % effective) coal washing - $15/ton additional cost, 215,000 tpy coal switching - $6/ton additional cost, 215,000 tpy, switch to 0.75% S
1-16-08: update from GA Pacific - revise coal switch cost to $13/ton from $6/ton 2-19-08: update from GA Pacific - increase caustic price by $147/ton, assume 4 tons caustic per ton SO2 removed

(1) Existing venturi scrubber with water is used to control particulate matter and opacity in boiler flue gas. GA Pacific estimates that the scurbber is also removing 30 % of the SO2. Therefore, the control effectiveness of the first three options are calculated in contemplation of replacement of the existing control effectiveness of 30%. The control effectiveness of the fourth option is calculated in contemplation of working in conjuction with the existing control effectiveness of 30%.
(2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index)

### Worksheet H.10-5



## Four-factor Technical Review **10-Oct-08**

**Facility name: GA Pac Cedar Springs Uncontrolled SO** **2**

### emissions (tons) **basis** County: Early **Emissions unit: R402 (Recov. Boiler No. 3)** AIRS: 09900001 MMBtu/hr capacity 769 2018 VISTAS 1726 fuels 1 

### : bl. liquor solids, 5931 Btu/lb Facility 4F 184 black liquor/oil cofiring in 2006

No. 6 fuel oil, 1.8 % S 571 100 % oil firing in 2007 output (MW) 67 2006 stack testing 51 ppmv 

## ACFM/temp **Class 1 sulfate impacts**

- Wolf Is. existing control ESP (from VISTAS emissions)

- Okef. (threshold = 0.005) 0.0077 St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 



### avoided, **2018 AnnualCo** 

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2** 

### (Ann. **Cost)/ (k**  **W) Ann. Cost** 

**(ACNet) 2**  

### Time to

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6**

### $) **(10 6** 

### $) **(10 6** 

### $) **($10 6** 

### , 2004) **(date)**

**($/k W)**  22 40 148962 4.2 0.094 6.03 0.07 20 2007

Conversion to No. 6 oil, 1 % sulfur 44 251 12060 no data no data 3.03 45.01 no data no data no data no data no data

Conversion to No. 2 oil, 0.5 % sulfur 72 411 22864 no data no data 9.4 139.63 no data no data no data no data no data

(1) two operating modes: (a) black liquor cofiring with supplemental oil (b) 100 % oil firing when black liquor cycle is interrupted

**Notes:** Wed FGD or scrubber - GA Pac deemed these technologies to be economically infeasible due to the low SO2 concentration (51 ppm from 2006 stack test)

**Sources:** Letters from Mark Aguilar dated July 31, 2008, and August 15, 2008 **Comments Other**  **Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)** 

no data 89.6 Conversion to high solids firing 45 no data **Other Environ.**  **Impacts: Solid**  **Waste**

no data no data no data **Identified and feasible**  **technol. Energy**  **Impacts Other** 

**Environ. Impacts:**  **Water Consump.** **Worksheet H.10-6**



### Four-factor Technical Review **7-Mar-08**

**Facility nam e: GA Pacific Savannah River Mill**  **Uncontrolled SO 2** **emissions (tons) basis**  County: Effingham **Emissions unit: B001(No. 3 Boiler)** AIRS: 10300007 MMBtu/hr capacity 422 2018 VISTAS 1844 fuel: petcoke (primary

), bitum coal, others permitted Facility 4F 1659 2005 CEMS data % S (coal 1.55, petcoke 6.1) output (MW) 37 **Class 1 sulfate impacts** 0.0111 Wolf Is. ACFM (from VISTAS emissions)

- Okef. existing control limestone inject. (90 %) (threshold = 0.005)

- St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost**  **(Ann. Cost)/**  **(k W)**  **Ann. Cost**

**(ACNet) Ann. Cost** 

**(ACNet) Tim** **e to**

**im plem.**  **(mos) (%** **) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) ($10** **6 , 2007)**  **($/k W)**  **($10 6** **, 2004) ($10** **6**
**,**

**escalated to 2006)** **2 (date)** 

Wet FGD with caustic 95 1576 2430.13 14.70 1.39 0.0944 3.83 103.68 ND ND after 2012 20 MG per year increased

dissolved solids load Circ. fluidized bed scrubber 95 1576 4504.93 34.40 3.25 0.0944 7.10 192.19 ND ND after 2012

Switch to 100% coal firing 65 1078 4451.24 0.00 NA 4.80 129.93 ND ND after 2012 increased CO2 air emissions

Increased limestone injection 1 15 249 7233.27 0.75 0.07 0.0944 1.80 48.73 ND ND before 2012 24000 to 60000 tpy

Rotating opposed fire air1 30 498 2149.89 8.15 0.77 0.0944 1.07 28.96 ND ND after 2012

Analysis basis (company) wet FGD with caustic - end of pipe control (caustic = approx. $450/ton) circulating fluidized bed scrubber - end of pipe control switch to 100 % coal firing - submittal listed control efficiency as range of 30 to 95 %; coal is 1.5 % S, whereas petcoke is 6.0 %. increased limestone injection - improves SO2 control from 87 to 89 percent (Feb. 08 testing). rotating opposed fire air - this option will improve mixing in combustor and therefore improve the efficiency of the existing limestone injection from 90 to 93 percent
(1) These technologies would provide improvement to the existing 90% SO2 control. Control effectiveness shown is the percent removal of the existing controlled emissions provided by the improvement. (2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index) **Other Environ.**  **Impacts: Solid**  **Waste Comments**  **Identified and feasible**  **technol. Energy**  **Impacts Other** 

**Environ. Impacts:**  **Water Consump.**  **Other**

**Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)** **Worksheet H.10-7**



### Four-factor Technical Review **7-Mar-08**

**Facility name: GA Pacific Savannah River Mill Uncontrolled SO** **2 emissions (tons)**  **basis** County: Effingham **Emissions unit: B002 (No. 4 Boiler)** AIRS: 10300007 MMBtu/hr capacity 422 2018 VISTAS 1415 fuel: petcoke (primary), others permitted Facility 4F 1195 2005 CEMS data % S (coal 1.55, petcoke 6.1) output (MW) 37 **Class 1 sulfate impacts** 0.0086 Wolf Is. ACFM (from VISTAS emissions)

- Okef. existing control limestone inject. (90 %) (threshold = 0.005)

- St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investment Capital** 

**Recovery Ann. Cost**  **(Ann. Cost)/**  **(k W)**  **Ann. Cost**

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6 $)**  **(10 6** **$) ($10**  **6 , 2007)**  **($/kW) ($10**  **6 , 2004)**  **($10 6** 
**, escalated to**  **2006) 2**  **(date)**

Wet FGD with caustic 95 1135 3171.11 15.0 1.42 0.0944 3.60 97.45 ND ND after 2012 20 MG per year increased

dissolved solids load Circ. fluidized bed scrubber 95 1135 6166.04 35.4 3.34 0.0944 7.00 189.49 ND ND after 2012

Switch to 100% coal firing 65 777 7467.01 2.0 NA 5.80 157.00 ND ND after 2012 increased CO2 air emissions

Increased limestone injection 1 10 120 5020.92 0.8 0.07 0.0944 0.60 16.24 ND ND before 2012 24000 to 60000 tpy

Rotating opposed fire air1 30 359 2370.99 8.2 0.77 0.0944 0.85 23.01 ND ND after 2012

Analysis basis (company) wet FGD with caustic - end of pipe control (caustic = approx. $450/ton) circulating fluidized bed scrubber - end of pipe control switch to 100 % coal firing - submittal listed control efficiency as range of 30 to 95 %; coal is 1.5 % S, whereas petcoke is 6.0 %.; new feed system required. increased limestone injection - improves SO2 control from 91 to 92 percent (Feb. 08 testing). rotating opposed fire air - this option will improve mixing in combustor and therefore improve the efficiency of the existing limestone injection from 90 to 93 percent

(1) These technologies would provide improvement to the existing 90% SO2 control. Control effectiveness shown is the margin of improved control on existing controlled emissions. (2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index) **Other Environ.**  **Impacts: Solid**  **Waste Comments**  **Identified and feasible**  **technol. Energy**  **Impacts Other** 

**Environ. Impacts:**  **Water Consump.**  **Other**

**Environ. Impacts:**  **Wastewate**

**r C.R.**  **Factor - CRF**  **- int. rate - life (yrs)** **Worksheet H.10-8**



### Four-factor Technical Review **7-Mar-08**

**Facility name: GA Pacific Savannah River Mill Uncontrolled SO** **2 emissions (tons)**  **basis** County: Effingham **Emissions unit: B003 (No. 5 Boiler)** AIRS: 10300007 MMBtu/hr capacity 422 2018 VISTAS 1282 fuel: petcoke (primary), bitum coal, others permitted Facility 4F 1190 2005 CEMS data % S (coal 1.55, petcoke 6.1) output (MW) 37 **Class 1 sulfate impacts** 0.0077 Wolf Is. ACFM (from VISTAS emissions)

- Okef. existing control limestone inject. (90 %) (threshold = 0.005)

- St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investment Capital** 

**Recovery Ann. Cost**  **(Ann. Cost)/**  **(k W)**  **Ann. Cost**

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6 $)**  **(10 6** **$) ($10**  **6 , 2007)**  **($/kW) ($10**  **6 , 2004)**  **($10 6** 
**, escalated to**  **2006) 2**  **(date)**

Wet FGD with caustic 95 1131 3095.98 15.6 1.5 0.0944 3.5 94.74 ND ND after 2012 20 MG per year increased

dissolved solids load Circ. fluidized bed scrubber 95 1131 5926.58 35.1 3.3 0.0944 6.7 181.37 ND ND after 2012

Switch to 100% coal firing 65 774 7369.10 1.9 NA 5.7 154.30 ND ND after 2012 increased CO2 air emissions

Increased limestone injection 1 10 119 6722.69 0.8 0.1 0.0944 0.8 21.66 ND ND before 2012 24000 to 60000 tpy

Rotating opposed fire air1 30 357 2380.95 8.2 0.77 0.0944 0.85 23.01 ND ND after 2012

Analysis basis (company) wet FGD with caustic - end of pipe control (caustic = approx. $450/ton) circulating fluidized bed scrubber - end of pipe control switch to 100 % coal firing - submittal listed control efficiency as range of 30 to 95 %; coal is 1.5 % S, whereas petcoke is 6.0 %; new baghouse required. increased limestone injection - improves SO2 control from 91 to 92 percent (Feb. 08 testing). rotating opposed fire air - this option will improve mixing in combustor and therefore improve the efficiency of the existing limestone injection from 90 to 93 percent

(1) These technologies would provide improvement to the existing 90% SO2 control. Control effectiveness shown is the margin of improved control on existing controlled emissions. (2) Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index) **Other Environ.**  **Impacts: Solid**  **Waste Comments**  **Identified and feasible**  **technol. Energy**  **Impacts Other** 

**Environ. Impacts:**  **Water Consump.**  **Other**

**Environ. Impacts:**  **Wastewate**

**r C.R.**  **Factor - CRF**  **- int. rate - life (yrs)** **Worksheet H.10-9**



### Four-factor Technical Review **28-Sep-07**

**Facility name: GPC Plant Kraft Uncontrolled SO** **2 emissions (tons)**  **basis** County: Chatham **Emissions unit:** SG01 AIRS: 04-13-051-00006 MMBtu/hr capacity 647 2018 VISTAS 691 fuel: bitum. coal, Colombian, 11700 Btu/lb Facility 4F 632 23% capacity in 2018 % S 0.62 output (MW) 50 **Class 1 sulfate impacts** 0.0051 Wolf Is. ACFM (from VISTAS emissions)

- Okef. existing control ESP (threshold = 0.005)

- St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCos**

**t/ton Total Cap.** 

**Investment Capital** 

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (kW)**  **Ann. Cost**

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) ($10** **6 , 2007)**  **($/kW) ($10** **6 , 2004)**  **($10 6** 
**, escalated to**  **2006) (date)** 

95 600 8161 4.1 0.110 4.9 6.38 0.07 15 39 245 4041 0.99

6 0.04 0.110 0.070 0.22 0.07 15

Analysis basis (company) wet FGD - Southern Co. Services historical data and industry curve fit (submittal also included EPA published cost factors and bounds on curve fit) coal switching - Annual cost for fuel switch is delta between existing Colombian coal and Russian coal, 0.38 % S coal washing - based on vendor estimates, includes addition of washing facility, assumes 6 % removal reduced uncontrolled emissions by 2018 - plants without required scrubbers (multipollutant rule) will operate less

**BACKUP DATA/CALCS**
**Air Control Net Query Inputs** 1999 dollars state county SCC: ext. combust. Boilers, electrical generation, bitum/subbitum coal, all pollutant: SO2 0.199 not addressed low capital high removal case; Tables 3-7 and 3-8 appear to have
errors power for coal washing machinery 4400 gal

per day acidic

WW needs treatment coal

refuse, approx. 5 % of total coal - -

Coal Washing low capital and high removal estimate 38 1839 0.33 1.4 Coal switching 19.8 not addressed ND possible boiler efficiency reduction **Comments Other**  **Environ. Impacts:**  **Solid Waste** 

90 gal per MW h 30 gal per

MW h 2.7 ton

gypsum/ ton SO2 **Identified and feasible**  **technol. 1**  **Energy Impacts**  **Other**

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewate**

**r C.R.**  **Factor - CRF**  **- int. rate - life (yrs)**  **Selected Technolog**  **y?**

Wet FGD (LSFO) 37.3 98.0 2 % of generatio n (1000 Jan. 2016 5.67**Worksheet H.10-10**



### Four-factor Technical Review **28-Sep-07**

**Facility name: GPC Plant Kraft Uncontrolled SO** **2 emissions (tons)**  **basis** County: Chatham **Emissions unit:** SG02 AIRS: 04-13-051-00006 MMBtu/hr capacity 690 2018 VISTAS 704 fuel: bitum. coal, Colombian, 11700 Btu/lb Facility 4F 889 34.5% capacity in 2018 % S 0.62 output (MW) 50 **Class 1 sulfate impacts** 0.0052 Wolf Is. ACFM (from VISTAS emissions)

- Okef. existing control ESP (threshold = 0.005)

- St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (k**  **W) Ann. Cost** 

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) ($10**  **6 , 2007)**  **($/k W)**  **($10 6** **, 2004) ($10**  **6**
**,**

**escalated to 2006)**  **(date)**

95 845 6039 4.1 0.110 5.1 6.38 0.07 15 39 344 4041 1.39

6 0.05 0.110 0.099 0.26 0.07 15

Analysis basis (company) wet FGD - Southern Co. Services historical data and industry curve fit (submittal also included EPA published cost factors and bounds on curve fit) coal switching - Annual cost for fuel switch is delta between existing Colombian coal and Russian coal, 0.38 % S coal washing - based on vendor estimates, includes addition of washing facility, assumes 6 % removal reduced uncontrolled emissions by 2018 - plants without required scrubbers (multipollutant rule) will operate less **Comments Other**  **Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)** 

2 % of generatio n (1000 Jan. 2016 5.67 Wet FGD (LSFO) 37.3 102.0 **Other Environ.**  **Impacts: Solid**  **Waste**

90 gal per MW h 30 gal per

MW h 2.7 ton

gypsum/ ton SO2 **Identified and feasible**  **technol. 1**  **Energy Impacts**  **Other**

**Environ. Impacts:**  **Water Consump.** 

not addresse d possible

boiler efficiency - - Coal switching 27.8 not addresse d Coal Washing low capital and high removal estimate 53 1847 0.46 2.0 0.23 power for coal washing machinery 4600 gal

per day acidic

WW needs treatment coal

refuse, approx. 5 % of total coal**BA CKUP DA**  **TA /CA** **LCS**

**Ai r Control Net Query Inputs**  1999 dollars state county SCC: ext. combust. Boilers, electrical generation, bitum/subbitum coal, all pollutant: SO2**Worksheet H.10-11**



### Four-factor Technical Review **28-Sep-07**

**Facility name: GPC Plant Kraft Uncontrolled SO** **2 emissions (tons)**  **basis** County: Chatham **Emissions unit: SG03** AIRS: 04-13-051-00006 MMBtu/hr capacity 1274 2018 VISTAS 4474 fuel: bitum. coal, Colombian, 11700 Btu/lb Facility 4F 2455 50% capacity in 2018 % S 0.62 output (MW) 103 **Class 1 sulfate impacts** 0.0330 Wolf Is. ACFM (from VISTAS emissions) 0.0085 Okef. existing control ESP (threshold = 0.005)

- St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (k**  **W) Ann. Cost** 

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) ($10**  **6 , 2007)**  **($/k W)**  **($10 6** **, 2004) ($10**  **6**
**,**

**escalated to 2006)**  **(date)**

95 2332 3216 5.6 0.110 7.5 8.88 0.07 15 39 950 4042 3.84

6 0.14 0.110 0.272 0.53 0.07 15

Analysis basis (company) wet FGD - Southern Co. Services historical data and industry curve fit (submittal also included EPA published cost factors and bounds on curve fit) coal switching - Annual cost for fuel switch is delta between existing Colombian coal and Russian coal, 0.38 % S coal washing - based on vendor estimates, includes addition of washing facility, assumes 6 % removal reduced uncontrolled emissions by 2018 - plants without required scrubbers (multipollutant rule) will operate less Coal Washing low capital and high removal estimate 147 1845 1.27 2.6 0.47 not addresse d power for

coal washing machinery 7500 gal

per day acidic

WW needs treatment coal

refuse, approx. 5 % of total coal possible boiler efficiency - - **Other Environ.**  **Impacts: Solid**  **Waste**

90 gal per MW h 30 gal per

MW h 2.7 ton

gypsum/ ton SO2 Coal switching 37.3 not addresse d ND **Identified and feasible**  **technol. 1**  **Energy Impacts**  **Other**

**Environ. Impacts:**  **Water Consump.**  **Other**

**Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)**  **Comments**

50.8 72.8 2 % of generatio n (2000 Jan. 2016 7.89**BA CKUP DA**  **TA /CA** **LCS**

**Ai r Control Net Query Inputs**  1999 dollars state county SCC: ext. combust. Boilers, electrical generation, bitum/subbitum coal, all pollutant: SO2**Worksheet H.10-12**

**Four-factor Technical Review 20-Nov-07** 

**Facility name: GPC Plant McIntosh Uncontrolled SO** **2 emissions (tons)**  **basis** County: Effingham **Emissions unit: SG01** AIRS: 041310300003 MMBtu/hr capacity 1862 2018 VISTAS 7015 fuel: bitum. coal, Colombian Facility 4F 1860 at 24% capacity factor % S 0.62 output (MW) 163 **Class 1 sulfate impacts** 0.0413 Wolf Is. ACFM stack test 591333 (from VISTAS emissions) 0.012 Okef. DSCFM stack test 392333 0.0055 St. Marks existing control ESP

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCost/**

**ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2 (Ann. Cost)/**  **(kW) Ann.** 

**Cost/ACFM Ann.** 

**Cost/DSCFM Ann. Cost** 

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10**  **6 $)**  **(10 6** **$) (10**  **6 $)**  **($10 6** 
**, 2004)**  **($10 6** 
**,**

**escalated to 2006)**  **(date)**

**($/kW) ($/ACFM)**  **($/DSCFM)** 95 1767 7131 9.1 0.110 12.6 21.3 32.1 10.3 11.59 Jan. 2016 0.07 15 2007

.

39 720 4306 na na 3.1 5.2 7.9 no data

2007

6 0.11 0.110 0.2 0.3 0.5 0.75 0.84 0.07 15 2007

.

Analysis basis (company) wet FGD - Southern Co. Services historical data and industry curve fit (submittal also included EPA published cost factors and bounds on curve fit) coal switching - Annual cost for fuel switch is delta between existing Colombian coal and Russian coal, 0.38 % S coal washing - based on vendor estimates, includes addition of washing facility, assumes 6 % removal reduced uncontrolled emissions by 2018 - plants without required scrubbers (multipollutant rule) will operate less Cost of low removal case may be 20x higher than high removal case. not addressed other coals evaluated have higher cost/ton SO2 removed **Comments**

80 - 110 gal/MWh treatment of

scrubber blowdown 2.7 tons

gypsum/ton SO2 removed - landfill **Other Environ.**  **Impacts: Water**  **Consump.**

reduced heat input expected 2014/2015 83 77.3 1 - 2 % of generation

19.0 possible boiler efficiency reduction

1.2 **Other Environ.**  **Impacts: Wastewater**  **Other**

**Environ. Impacts:**  **Solid Waste**

not addressed not addressed not addressed

acidic wastewater 81.5 tons

coal refuse/day at full load - landfill not addressed not

addressed

16,300 gal/day Coal Washing low capital and high removal estimate 37 **Identified and feasible**  **technol. 1**  **Energy Impacts**  **C.R. Factor - CRF**  **- int. rate - life (yrs)** 

Coal Switching na

5534 0.96 Wet FGD**Worksheet H.10-13**



### Four-factor Technical Review **27-Sep-07**

**Facility nam e: GPC Plant Mitchell**  **Uncontrolled SO 2** **emissions (tons) basis**  County: Dougherty **Em issions unit: SG03 (Unit 3)**  AIRS: 04-13-095-00002 MMBtu/hr capacity 1814 2018 VISTAS 4930 fuel: bitum. coal, Colombian Facility 4F 1189 at 11% capacity factor % S 1 output (MW) 125 **Class 1 sulfate impacts** <0.005 Wolf Is. ACFM (from VISTAS emissions) 0.0077 Okef. existing control ESP 0.0274 St. Marks

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCost/**

**ton Total Cap.** 

**Investm en**  **t Capital** 

**Recovery Ann. Cost** **2 (Ann. Cost)/**  **(kW) Ann. Cost** 

**(ACNet) Ann. Cost** 

**(ACNet) Tim** **e to**

**im plem** 

**. (m** **os) (%)**  **(tons) ($/ton)**  **(10 6** **$) (10**  **6 $)**  **(10 6** **$) ($10**  **6**
**, 2004)**  **($10 6** 
**,**

**escalated to 200.67)**  **(date)**

**($/kW)** 95 1130 9119 7.1 0.101 10.3 9.71 10.92 Jan. 2016 0.07 15 2007

.

47 554 2347 na na 1.3 no data

2007

Analysis basis (company) wet FGD - Southern Co. Services historical data and industry curve fit (submittal also included EPA published cost factors and bounds on curve fit) coal switching - Annual cost for fuel switch is delta between existing central Appalachian coal (1.5 % S, 12500 Btu/lb) and Colorado coal (0.5 % S, 11700 Btu/lb) reduced uncontrolled emissions forecast to occur 2008 - 2010; plants without required scrubbers (multipollutant rule) will operate less Wet FGD

Coal Washing not addressed **Identified and feasible**  **technol. 1**  **Energy Im**  **pacts C.R. Factor**  **- CRF - int. rate**  **- life (yrs)**

Coal Switching na 70.2 82.4 1 - 2 % of generation (1250 to 2500 kW )

10.4 possible reduced generation efficiency with some coals **Com me** **nts**

not addressed not

addressed not

addressed **Other Environ.**  **Im pacts:**  **Water Consum**  **p.**

reduced heat input expected 2008 - 2010 **Other Environ.**  **Im pacts:**  **Wastewater Other** 

**Environ. Im**  **pacts: Solid Waste** 

Already implemented. not addressed other coals evaluated have higher cost/ton SO2 removed not addressed not addressed**Worksheet H.10-14**

**Four-factor Technical Review 21-Feb-08** 

**Facility name: International Paper - Savannah Mill Uncontrolled emissions**  **basis** County: Chatham **Emissions unit: PB13** AIRS: 5100007 MMBtu/hr capacity 1280 2018 VISTAS 8578 includes pulping S emissions fuel: bitum coal (primary), bark, others Facility 4F 8578 includes pulping S emissions % S 0.69 output (MW) 112 **Class 1 sulfate impacts** 0.0664 Wo lf Is. ACFM stack test 377000 (from VISTAS emissions) 0.0166 Okef. DSCFM stack test 221000 (threshold = 0.005) 0.007 St. Marks existing control ESP service life 2022+ O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investment 3**  **Capital**

**Recovery Ann. Cost**  **(Ann. Cost)/**  **(kW) Ann.** 

**Cost/ACFM Ann.** 

**Cost/DSCFM Ann. Cost** 

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) (10** **6 $)**  **($10 6** 
**, 2004)**  **($10 6** 
**,**

**escalated to 2006)**  **(date)**

**($/kW) ($/ACFM)**  **($/DSCFM)** 95 8149 4896 16.3 0.117 39.9 105.8 180.5 11.4 12.825 0.08 15 90 7720 4391 10.8 0.117 33.9 89.9 153.4 4.05 0.08 15 85 8.3 0.117 35.5 94.2 160.6 3.15 0.08 15 65 24 2.8 0.117 53 140.6 239.8 0 0.08 15

25 22.1 2.6 0.117 11.2 29.7 50.7 1.7 1.91 2010 to 2012 280 kW 7900 tpy 0.08 15

95 314 5223 3.7 1.64 - not applicable not

applicable not

applicable not

applicable 2010 to

2012 422 kW

95 1533 1826 4.4 2.8 - not applicable not

applicable not

applicable not

applicable 2010 to

2012 357 kW

95 1847 2057 6.9 3.8 - not applicable not

applicable not

applicable not

applicable 2010 to

2012 601 kW

(1) Coal switching was determined to be ineffective because the sulfur content of the existing coal is low already (2) These are controls on emissions from the pulping process only - they do not control combustion emissions (3) Used retrofit factor of 1.6 rather than standard 1.3 due to equipment space constraints
Analysis basis (company) LVHC = low volume high concentration noncondensable gases from pulping process packed tower with caustic - Coal Utility Environmental Cost (CUECost) model; $39.9 M includes $11.2 M for stack gas reheat (probably unnecessary) HVLC = high volume low concentration noncondensable gases from pulping process - did not do line item estimate for capital costs; used multiplier of 1.5 on lime spray estimate
wet limestone spray tower - Coal Utility Environmental Cost (CUECost) model SOG = stripper off-gases Semi-dry lime spray tower - Coal Utility Environmental Cost (CUECost) model RTO = regenerative thermal oxidizer fuel switching to natural gas - includes $21 million in TCI for lost production sorbent injection - includes $42 million in TCI for lost production; Coal Utility Environmental Cost (CUECost) model

Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index) **Energy Impacts**  **Other**

**Environ. Impacts:**  **Water Consump.** 

212 MG per year Wet FGD (packed tower) **C.R. Factor**  **- CRF - int. rate**  **- life (yrs)**

139 356.1 2010 to 2012

RTO, packed tower scrubber, WESP, and 2nd scrubber: control HVLC, LVHC & SOG 2 **Identified and feasible technol.**  **1**

2010 to 2012 **Comments Other**  **Environ. Impacts:**  **Solid Waste**  **Other Environ.**  **Impacts: Wastewate** 

**r Selected**  **Technolog y?** 

161 MG per year 2210 kW

Semi-dry lime spray
tower 7291 4869 70.7 316.8 2.8 FGD, wet limestone spray tower 92.4 302.5 3.6 2010 to 2012 2210 kW

114 MG per year 19300 tpy

22000 tpy

17 MG per year Fuel switching, nat. gas, S = % 9506 473.0 780 kW

5576

2145

RTO, packed tower scrubber, WESP, and 2nd scrubber: control LVHC & SOG 2 Dry sorbent injection 5223 100.0

RTO & packed tower scrubber: control HVLC2

81 MG per year

98 MG per year 6 MG per

year

31 MG per year

37 MG per year**Worksheet H.10-15**



### Four-factor Technical Review **2-Dec-08**

**Facility name: Temple-Inland Rome Linerboard Mill Uncontrolled SO** **2 emissions (tons)**  **basis** County: Floyd **Emissions unit: : No. 4 Power Boiler** AIRS: 04-13-115-00021 MMBtu/hr capacity 565 2018 VISTAS 3696 fuel: bituminous coal, fuel oil Facility 4F 3837 permit limit % S (1.29 coal, 0.5 fuel oil) output (MW) 49 **Class 1 sulfate impacts** 0.0442 Cohutta ACFM (from VISTAS emissions) existing control ESP, multiclone, LNB (threshold = 0.005)

A B C D E F G H I J K L M N O

**Control effect.**  **SO 2** 

**avoided, 2018**  **AnnualCo**

**st/ton Total Cap.** 

**Investmen t**  **Capital**

**Recovery Ann. Cost** **2 (Ann.**  **Cost)/ (kW)**  **Ann. Cost**

**(ACNet) Ann. Cost** 

**(ACNet) Time to** 

**implem. (mos)**  **(%) (tons)**  **($/ton) (10** **6 $)**  **(10 6** **$) ($10** **6 2007)**  **($10 6** **, 2004) ($10** **6**
**, escalated to**  **2006) (date)** 

**($/kW)** 90 3453 2027 3.6 0.110 7.0 3.1 3.5 0.09 20

90 3453 2027 3.6 0.110 7.0 3.1 3.5 0.09 20 

### 80 3.2 0.117 5.7 13.4 0.10 20

65 2494 7.0 no data

55 2110 19.0 2.2 0.117 4.1 1.3 1.5 0.10 20

Analysis basis (company) wet FGD (limestone forced oxidation, BE&K estimate) - this is a site-specific estimate submitted by an engineering company and dated September 18, 2008; the total capital estimate includes $5 MM for demolition of 2 boilers and $3.7 MM for project escalation (installed costs) wet FGD (magnesium enhanced lime, BE&K estimate) - Section 3.1 of BE&K's submittal states that a MEL wet scrubber system would have the same operating and capital costs as the LSFO system; no specific data were presented dry FGD sorbent injection fuel switching - switch to PRB coal (0.24 % S, 8800 Btu/lb) from existing coal (1.29 % S, 12900Btu/lb) 10,000 ton/yr gypsum Used 1990 to 2007 escalation of 60 %, may be too high 12 mos

36 mos 650 kW

650 kW increase ash by 30% 10,000 ton/yr gypsum

Fuel Switching

Duct sorbent injection 2807

1943 141.5

82.9 Dry FGD (lime absorbent) 3070 1857 27.0 115.2 11.9 36 mos 36 mos 450 kW 37 MG/yr 16,000 ton/yr gypsum **Comments Other**  **Environ. Impacts:**  **Solid Waste** 

16,000 ton/yr gypsum **Identified and feasible**  **technol. 1**  **Energy Impacts**  **Other**

**Environ. Impacts:**  **Water Consump.**  **Other**

**Environ. Impacts:**  **Wastewat**

**er C.R.**  **Factor - CRF**  **- int. rate - life (yrs)**  **Selected Technolog**  **y?**

650 kW 450 kW 37 MG/yr Wet FGD (MEL) 32.4 141.5 36 mos

Wet FGD (LSFO) 32.4 141.5Escalation factor, 2004 dollars to 2006 dollars = 1.125 (based on Chemical Engineering Plant Cost Index)

**BACKUP DATA/CALCS**
**Air Control Net Query Inputs**  2004 dollars state county SCC: ext. combust. Boilers, industrial, bitum/subbitum coal, all pollutant: SO2

fuel switching
fuel usage

S content lb S/1000 gal S emiss.

Cost Recovery Factor (CRF) calculation
interest (i) 0.10 lfie (n), yrs 20

CRF 0.11746

### SUMMARY - REGIONAL HAZE FOUR-FACTOR ANALYSES - SOUTH GEORGIA FACILITIES updated 10-10-08 see abbreviations and color codes on last page

**Facility Emiss.** 

**unit VISTA** 

**S SO2 (tons)**  **4F Base-line**

**SO2 (tons) Control** 

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Fuel**  **Class 1**

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut.** 

**factor statut.** 

**factor (ton SO** **2**

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) F1 P.B. No.4 1842 1642 **Wet FGD** 1560 8.5 5449 3.24 before 2013 did not

address 98 MG per

year 34 MG per

year did not

address 5813 31.7 0.26836 6557 35.7 0.23790 below thresthold below thresthold below thresthold



### bark, wood waste, No.6 oil, TDF, sludge .1255 W OLF*

.0389 OKEF* ESP **Oil limit, 5 Mgal/y** **r, S = 3% (existing %)**  543 0 0 ND before 2012 none none none none 5813 0.0 0.09342 6557 0.0 0.08281 below thresthold below thresthold below thresthold



### In duct sorbent **injection** 769 2.7 3562 ND before 2013 insignificant none none 8000 tons per year 5813 20.7 0.13235 6557 23.4 0.11733 below thresthold below thresthold below thresthold



### Oil limit and **fuel sw itch to**  **S = 2.2%** 294 0.4 1429 ND before 2012 0 0 0 #REF! 5813 8.3 0.05058 6557 9.4 0.04484 below thresthold below thresthold below thresthold



### Oil limit and **fuel sw itch to**  **S = 1.0%** 731 2.4 3228 ND before 2012 0 0 0 #REF! 5813 18.8 0.12576 6557 21.2 0.11149 below thresthold below thresthold below thresthold



### M24 RB No. 6 193 193 **Increase black liquor solids** 

**conc.** 5813 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### blk. liquor .0131 W OLF* ESP

**GA Pac -**  **Cedar Springs**  U500

power boiler 2428 1976 **Wet FGD with caustic**  1835 5.0 2725 11.9 before 2013 did not

address did not

address did not

address 15000

tons/yr below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 1381.9 0.00362

bitum. coal, wood waste, fuel oil .0108 SAMA* venturi scrubber (water) **Ad d spray** 

**towers and caustic to**  **existing venturi**  1694 5.0 2952 ND before 2012 did not

address did not

address did not

address 15000

tons/yr below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 1497.0 0.00334

**Ad d caustic to**  **existing venturi**  1553 2.6 1675 ND before 2012 did not

address did not

address did not

address 15000

tons/yr below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 849.2 0.00306

**Duct sorbent injection**  1383 2.3 1663 ND before 2012 did not

address did not

address did not

address did not

address below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 843.2 0.00273
**Coal washing** 296 3.2 10796 ND before 2012 did not

address did not

address did not

address did not

address below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 5474.8 0.00058

**Coal sw itching**  494 2.8 5668 ND before 2012 did not

address did not

address did not

address did not

address below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 2874.3 0.00097 **Reduct. from 4F**  **baseline (tons)** 

**Brunswick Cellulose**  **(GA Pac)**  **St. Marks Visibility**  **- Sensitivity to emissions reductions**  **Wolf Island Visibility** 

**- Sensitivity to emissions reductions**  **Okefenokee Visibility**  **- Sensitivity to emissions reductions**  **An nual**  **cost, company**  **($10 6** 

### , 2007) **An nual**  **cost, AC**  **Net ($10**  **6**



### , **2006 )**

Page 1 of 7

### Facility **Emiss.**

**unit VISTA** 

**S SO2 (tons)**  **4F Base-line**

**SO2 (tons) Control** 

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Waste**  **Fuel Class 1** 

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut.** 

**factor statut.** 

**factor (ton SO** **2**

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **GA Pac -**  **Cedar Springs**  U501

power boiler 2533 1976 **Wet FGD with caustic**  1835 5.0 2725 11.9 before 2013 did not

address did not

address did not

address 15000

tons/yr below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 1381.9 0.00362

bitum. coal, wood waste, fuel oil .0113 SAMA* venturi scrubber (water) **Ad d spray** 

**towers and caustic to**  **existing venturi**  1694 5.0 2952 ND before 2012 did not

address did not

address did not

address 15000

tons/yr below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 1497.0 0.00334

**Ad d caustic to**  **existing venturi**  1553 2.6 1675 ND before 2012 did not

address did not

address did not

address 15000

tons/yr below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 849.2 0.00306

**Duct sorbent injection**  1383 2.3 1663 ND before 2012 did not

address did not

address did not

address did not

address below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 843.2 0.00273
**Coal washing** 296 3.2 10796 ND before 2012 0 0 0 0 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 5474.8 0.00058

**Coal sw itching**  494 2.8 5668 ND before 2012 0 0 0 0 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 2874.3 0.00097

R402 recovery boiler 1726 184 **Conversion to high solids**  **firing** 40 6.0 148962.5 ND ND ND ND ND ND below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 75539.2 0.00008

.0077 SAMA* 571 **Conversion to No. 6 oil, 1 %**  **sulfur** 251 3.0 12060.2 ND ND ND ND ND ND below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 6115.7 0.00050

571 **Conversion to No. 2 oil, 0.5%**  **sulfur** 411 9.4 22864.4 ND ND ND ND ND ND below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### 507102 11594.6 0.00081

ESP **Reduct. from 4F**  **baseline (tons)**  **Wolf Island Visibility**  **- Sensitivity to emissions reductions**  **Okefenokee Visibility**  **- Sensitivity to emissions reductions**  **St. Marks Visibility**  **- Sensitivity to emissions reductions**  **An nual**  **cost, company**  **($10 6** 

### , 2007 ) **An nual**  **cost, AC**  **Net ($10**  **6**



### , **2006 )**

Page 2 of 7

### Facility **Emiss.**

**unit VISTA** 

**S SO2 (tons)**  **4F Base-line**

**SO2 (tons) Control** 

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Waste**  **Fuel Class 1** 

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut.** 

**factor statut.** 

**factor (ton SO** **2**

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **GA Pac -**  **Savannah River**  **B001**

No. 3 Boiler 1844 1659 **Wet FGD with caustic**  1576 3.83

2430.13 ND

after 2012 0 20 MG per year increased

dissolved solids load 0 247801 602.2 0.00636 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Circ. fluidized **bed scrubber** 1576 7.10 4504.93 ND after 2012 0 0 0 0 247801 1116.3 0.00636 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### .0111 W OLF* limestone

injection (87% eff,) **Sw itch to 100%** 

**coal firing** 1078 4.80

4451.24 ND

after 2012 0 0 0 0 247801 1103.0 0.00435 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Increased **limestone injection**  249 1.80

7233.27 ND before 2012 0 0 0 24000 to 60000 tpy 247801 1792.4 0.00100 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Rotating **opposed fire air**  498 1.07

2149.89 ND

after 2012 0 0 0 0 247801 532.7 0.00201 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### B002 No. 4 Boiler 1415 1195 **Wet FGD with caustic**  1135 3.60

3171.11 ND

after 2012 0 20 MG per year increased

dissolved solids load 0 247801 785.8 0.00458 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Circ. fluidized **bed scrubber** 1135 7.00 6166.04 ND after 2012 0 0 0 0 247801 1528.0 0.00458 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### .0086 W OLF* limestone

injection (90% eff,) **Sw itch to 100%** 

**coal firing** 777 5.80

7467.01 ND

after 2012 0 0 0 0 247801 1850.3 0.00313 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Increased **limestone injection**  120 0.60

5020.92 ND before 2012 0 0 0 24000 to 60000 tpy 247801 1244.2 0.00048 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Rotating **opposed fire air**  359 0.85

2370.99 ND

after 2012 0 0 0 0 247801 587.5 0.00145 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### B003 No. 5 Boiler 1282 1190 **Wet FGD with caustic**  1131 3.50

3095.98 ND

after 2012 0 20 MG per year increased

dissolved solids load 0 247801 767.2 0.00456 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Circ. fluidized **bed scrubber** 1131 6.70 5926.58 ND after 2012 0 0 0 0 247801 1468.6 0.00456 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### .0077 W OLF* limestone

injection (90% eff,) **Sw itch to 100%** 

**coal firing** 774 5.70

7369.10 ND

after 2012 0 0 0 0 247801 1826.1 0.00312 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Increased **limestone injection**  119 0.80

6722.69 ND before 2012 0 0 0 24000 to 60000 tpy 247801 1665.9 0.00048 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Rotating **opposed fire air**  357 0.85

2380.95 ND

after 2012 0 0 0 0 247801 590.0 0.00144 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold 

### petcoke, bitum. coal, others permitted **Reduct. from 4F**  **baseline (tons)** 

petcoke, bitum. coal, others permitted

petcoke, others permitted **Wolf Island Visibility**  **- Sensitivity to emissions reductions**  **Okefenokee Visibility**  **- Sensitivity to emissions reductions**  **St. Marks Visibility**  **- Sensitivity to emissions reductions**  **An nual**  **cost, company**  **($10 6** 

### , 2007 ) **An nual**  **cost, AC**  **Net ($10**  **6**



### , **2006 )**

Page 3 of 7

### Facility **Emiss.**

**unit VISTA** 

**S SO2 (tons)**  **4F Base-line**

**SO2 (tons) Control** 

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Waste**  **Fuel Class 1** 

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut.** 

**factor statut.** 

**factor (ton SO** **2**

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **SG01** 691 632 **Wet FGD** 600 4.90 8161 6.38 Jan. 2016 2 % of generation (1000 kW ) 90 gal per

MW h 30 gal per

MW h 2.7 ton

gypsum/ ton SO2 17700 144.5 0.03392 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### .0051 W OLF* **Coal sw itching**  245 0.99 4041 ND not addressed possible

boiler efficiency reduction - - 0 17700 71.5 0.01384 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Coal washing 38 0.07 1839 0.22 not addressed power for

coal washing machinery 4400 gal

per day acidic WW

needs treatment coal

refuse, approx. 5 % of total coal 17700 32.5 0.00214 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### SG02 704 889 **Wet FGD** 845 5.10 6039 6.38 Jan. 2016 2 % of generation (1000 kW ) 90 gal per

MW h 30 gal per

MW h 2.7 ton

gypsum/ ton SO2 17700 106.9 0.04772 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### .0052 W OLF* **Coal sw itching**  344 1.39 4041 ND not addressed possible

boiler efficiency reduction - - 0 17700 71.5 0.01944 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Coal washing 53 0.10 1847 0.26 not addressed power for

coal washing machinery 4600 gal

per day acidic WW

needs treatment coal

refuse, approx. 5 % of total coal 17700 32.7 0.00301 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### SG03 4474 2455 **Wet FGD** 2332 7.50 3216 8.88 Jan. 2016 '2 % of generation (2000 kW ) 90 gal per

MW h 30 gal per

MW h 2.7 ton

gypsum/ ton SO2 17700 56.9 0.13177 18112 58.2 0.12877 below thresthold below thresthold below thresthold



### .0330 W OLF* .0085 OKEF* .0081 ROMA **Coal sw itching**  950 3.84 4042 ND not addressed possible

boiler efficiency reduction - - 0 17700 71.5 0.05367 18112 73.2 0.05245 below thresthold below thresthold below thresthold



### Coal washing 147 0.27 1845 0.53 not addressed power for

coal washing machinery 7500 gal

per day acidic WW

needs treatment coal

refuse, approx. 5 % of total coal 17700 32.7 0.00832 18112 33.4 0.00813 below thresthold below thresthold below thresthold 

### Reduct. **from 4F baseline**  **(tons) An**  **nual**

**cost, company**  **($10 6** 

### , 2007 ) **An nual**  **cost, AC**  **Net ($10**  **6**



### , **2006 )**

**GPC – Plant Kraft**  **Wolf Island Visibility**  **- Sensitivity to emissions reductions**  **Okefenokee Visibility**  **- Sensitivity to emissions reductions**  **St. Marks Visibility**  **- Sensitivity to emissions reductions** 

Page 4 of 7

### Facility **Emiss.**

**unit VISTA** 

**S SO2 (tons)**  **4F Base-line**

**SO2 (tons) Control** 

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Waste**  **Fuel Class 1** 

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut.** 

**factor statut.** 

**factor (ton SO** **2**

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **SG01** 7015 1860 **Wet FGD** 1767 12.6 7131 11.59 Jan. 2016 1 - 2 % of generation 80 - 110

gal/MW h treatment of

scrubber blowdown 2.7 tons

gypsum/to n SO2 removed - landfill 16615 118.5 0.10635 18602 132.6 0.09499 57639 411.0 0.03066

.0413 W OLF* .0120 OKEF* .0055 SAMA* .0135 ROMA .0072 SWAN **Coal sw itching**  720 3.1 4306 ND not addressed possible

boiler efficiency reduction not

addressed not

addressed not

addressed 16615 71.5 0.04333 18602 80.1 0.03870 57639 248.2 0.01249

**Coal washing** 37 0.2 5534 0.84 not addressed not

addressed 16,300

gal/day acidic

wastewater 81.5 tons

coal refuse/day at full load - landfill 16615 91.9 0.00223 18602 102.9 0.00199 57639 319.0 0.00064

**SG03** 4930 1189 **Wet FGD** 1130 10.3 9119 10.92 Jan. 2016 1 - 2 % of generation (1250 to 2500 kW ) not

addressed not

addressed not

addressed below thresthold below thresthold below thresthold 

### 16283 148.5 0.06937 32836 299.4 0.03440

.0274 SAMA* .0077 OKEF* **Coal sw itching**  554 1.3 2347 ND not addressed possible

reduced generation efficiency with some coals not

addressed not

addressed not

addressed below thresthold below thresthold below thresthold 

### 16283 38.2 0.03402 32836 77.1 0.01687

**Internat. Paper**  **PB13** 8578.00 8578.00 **Wet FGD (packed tower)**  8149.10 39.90 4896.25 12.83 2010 to 2012 2210 kW 212 MG per year 161 MG per

year 0 14766.80 72.3 0.55185 16334 80.0 0.49891 66949 327.8 0.12172

bitum. coal, bark, others .0664 W OLF*

.0166 OKEF* .0070 SAMA* .0155 ROMA ESP **FGD, wet limestone**  **spray tower**  7720.20 33.90 4391.08 4.05 2010 to 2012 2210 kW 0 0 22000 tpy 14766.80 64.8 0.52281 16334 71.7 0.47265 66949 294.0 0.11531

.0086 SWAN **Semi-dry lime**  **spray tower**  7291.30 35.50 4868.82 3.15 2010 to 2012 780 kW 0 114 MG per year 19300 tpy 14766.80 71.9 0.49376 16334 79.5 0.44639 66949 326.0 0.10891

**Fuel sw itching,**  **nat. gas** 5575.70 53.00 9505.53 0 0 0 0 0 14766.80 140.4 0.37758 16334 155.3 0.34136 66949 636.4 0.08328

**Dry sorbent**  **injection** 2144.50 11.20 5222.66 1.91 2010 to 2012 280 kW 0 0 7900 tpy 14766.80 77.1 0.14522 16334 85.3 0.13129 66949 349.7 0.03203

**RTO/scrubbing opt. 1: control**  **HVLC** 314.00 1.64 5222.93 2010 to 2012 422 kW 17 MG per year 6 MG per

year 0 14766.80 77.1 0.02126 16334 85.3 0.01922 66949 349.7 0.00469

**RTO/scrubbing opt. 2: control**  **LVHC & SOG** 1533.00 2.80 1826.48 2010 to 2012 357 kW 81 MG per year 31 MG per

year 0 14766.80 27.0 0.10381 16334 29.8 0.09385 66949 122.3 0.02290 **An nual**  **cost, company**  **($10 6** 

### , 2007 ) **An nual**  **cost, AC**  **Net ($10**  **6**



### , **2006 )**

**GPC – Plant McIntosh** 

**GPC - Plant Mitchell**  **Reduct. from 4F**  **baseline (tons)**  **St. Marks Visibility**  **- Sensitivity to emissions reductions**  **Wolf Island Visibility** 

**- Sensitivity to emissions reductions**  **Okefenokee Visibility**  **- Sensitivity to emissions reductions** 

Page 5 of 7

### RTO/scrubbing **opt. 3: control HVLC, LVHC &**  **SOG** 1847.00 3.80 2057.39 2010 to 2012 601 kW 98 MG per year 37 MG per

year 0 14766.80 30.4 0.12508 16334 33.6 0.11308 66949 137.7 0.02759

Page 6 of 7

### Facility **Emiss.**

**unit VISTA** 

**S SO2 (tons)**  **4F Base-line**

**SO2 (tons) Control** 

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Waste**  **Fuel Class 1** 

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut.** 

**factor statut.** 

**factor (ton SO** **2**

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **(ton SO 2** 

### )/

**(Mm -1**  

### ) **10 6** 

### $/

**(Mm -1**  

### ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

### ) **Southern States**  **Phosphate and Fert.**  **SA 02** 

**(Sulfuric Ac** **id Plant 2)**  #REF! #REF! **Increase acid capture w** **ith Cs-promoted**  **cataly st**  14766.80 #REF! below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### .0064 W OLF* mist

eliminator **#REF!** 14766.80 #REF! below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### #REF! 14766.80 #REF! below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold



### Ab **breviations: Class I A** **reas:**

ACNet Air Control Net (EPA cost database) WO LF* Wolf Is. estimated implementation date earlier than Jan. 1, 2012 Mm megameter OKEF* Okefenokee MG million gallons SAMA* St. Marks extinction reduction (visibility improvement) > 0.100 ND no data ROMA Romain 0 not addressed in 4-factor submittal SWAN Swan Quarter 0.010 < extinction reduction < 0.100
* Class I area is currently behind the glide path schedule for attaining reasonable progress by 2018

**Reduct. from 4F**  **baseline (tons)**  **An nual** 

**cost, company**  **($10 6** 

### , 2007 ) **An nual**  **cost, AC**  **Net ($10**  **6**



### , **2006 )**

**Status:**Cs-promoted catalyst proposed but insufficient. Company wants to take a 580 ton/yr limit, **effective in Jan. 2014**  , by doing 502(b)10 (see 12-7-07 letter). This would drop the unit below the 0.5 % sulfate threshold. **St. Marks Visibility**  **- Sensitivity to emissions reductions**  **Wolf Island Visibility** 

**- Sensitivity to emissions reductions**  **Okefenokee Visibility**  **- Sensitivity to emissions reductions** 

Page 7 of 7

## SUMMARY - REGIONAL HAZE FOUR-FACTOR ANALYSES - NORTH GEORGIA FACILITIES updated 12-2-08

**Facility Emiss.** 

**unit VISTA** **S SO2**

**(tons) 4F Base** 

**line SO2 (tons)**  **Control**

**Technology $/ton SO2**  **Time to implem.**  **Energy**

**Impacts Other** 

**Environ. Impacts:**  **Water Use Other** 

**Environ. Impacts:**  **Wastewater Other** 

**Environ. Impacts:**  **Solid Waste Fuels**  **Class 1**

**sulfate impact**  **fractions Existing** 

**Controls statut.**  **factor statut.**  **factor statut.** 

**factor statut.** 

**factor statut. factor**  **statut. factor (ton SO** **2**

## )/ **(Mm -1**  

## ) **10 6** 

## $/

**(Mm -1**  

## ) **company cost**  **Control**

**extinction reduction**  **(Mm -1**  

## ) **No. 4 Power**  **Boiler** 3696 3837 **Wet FGD (MEL)** 3453 7 2027 3.4875 before 2012 450 kW 37 MG/yr 0 16,000 ton/yr gypsum 19468 39.5 0.17738

**Wet FGD (LSFO)**  3453 7 2027 3.4875 before 2012 450 kW 37 MG/yr 0 16,000 ton/yr gypsum 19468 39.5 0.17738

bit. coal, fuel oil .0442 COHU

.0099 JOKI ESP,

mu lticlone, LNB **Dry FGD (lime**

**absorbent)** 3070 5.7 1857 13.3875 before 2012 650 kW 0 0 10,000 ton/yr gypsum 19468 36.2 0.15767

**Fuel Switching** 2494 7 2807 ND before 2010 650 kW 0 0 increase ash by 30% 19468 54.6 0.12811

**Duct sorbent injection**  2110 4.1 1943 1.4625 before 2012 650 kW 0 0 10,000 ton/yr gypsum 19468 37.8 0.10840

**Ab breviations:**  **Class I A reas:** 

ACNet Air Control Net (EPA cost database) COHU Cohutta estimated implementation date earlier than Jan. 1, 2012 Mm megam eter JOKI Joyce Kilm er MG mi llion gallons extinction reduction (visibility im provement) > 0.100 ND no data 0 not addressed in 4-factor submittal 0.010 < extinction reduction < 0.100 **Cohutta Visibility - Sensitivity to**  **emissions reductions**

**Temple Inland**  **Rome LB Mill**  **An nual**  **cost, company**  **($10 6** 

## , 2007 **) An**  **nual cost,**  **AC Net**  **($10 6** 



## , **2006 ) Reduct.**  **from 4F baseline**  **(tons)**

### Normalized SO2 impacts, from Jim Boylan VISTAS emissions tons SO2/inverse megameter, ton/Mm-1 Updated 11-08-07

**Facility Unit**  **2018 SO2 TPY COHU1**  **GRSM1 OKEF1**  **ROMA 1**  **SA MA** **1 SIPS1**  **WOLF1** GEORGIA PACIFIC CORPORATION, CEDAR SPRIN R402 1,726 30,006.52 75,127.79 256,346.98 262,105.85 507,102.18 268,457.33 445,023.59 GEORGIA PACIFIC CORPORATION, CEDAR SPRIN U500 2,428 30,006.52 75,127.79 256,346.98 262,105.85 507,102.18 268,457.33 445,023.59 GEORGIA PACIFIC CORPORATION, CEDAR SPRIN U501 2,533 30,006.52 75,127.79 256,346.98 262,105.85 507,102.18 268,457.33 445,023.59 GEORGIA POW ER COMPANY, MITCHELL STEAM-EL SG03 4,930 81,621.63 87,176.25 16,282.85 123,456.10 32,836.11 51,121.25 33,051.80 GEORGIA-PACIFIC BRUNSW ICK OPERATIONS F1 1,842 144,991.65 139,940.38 6,556.82 12,564.52 50,876.19 84,653.35 5,812.70 GEORGIA-PACIFIC BRUNSW ICK OPERATIONS M24 193 144,991.65 139,940.38 6,556.82 12,564.52 50,876.19 84,653.35 5,812.70 GEORGIA-PACIFIC CORP SAVANNAH RIVER MILL BO01 1,844 540,902.89 1,450,446.49 300,982.95 89,957.69 934,882.16 926,619.48 247,800.80 GEORGIA-PACIFIC CORP SAVANNAH RIVER MILL BO02 1,415 540,902.89 1,450,446.49 300,982.95 89,957.69 934,882.16 926,619.48 247,800.80 GEORGIA-PACIFIC CORP SAVANNAH RIVER MILL BO03 1,282 540,902.89 1,450,446.49 300,982.95 89,957.69 934,882.16 926,619.48 247,800.80

INLAND PAPERBOARD & PACKAGING, INC. -LIN F4 3,696 19,468.06 29,876.43 70,278.60 62,902.15 86,516.20 52,226.90 93,003.00 INTERNATIONAL PAPER - SAVANNAH MILL PB13 8,578 60,770.78 144,198.38 16,333.87 7,650.04 66,949.15 90,245.22 14,766.80 INTERSTATE PAPER LLC F1 188 67,002.42 185,239.29 11,897.30 7,189.89 52,933.54 97,326.78 13,243.50 JESUP MILL, RAYONIER PERFORMANCE FIBERS PB03 1,597 107,421.39 144,998.18 10,991.02 10,606.28 67,960.85 69,862.76 11,110.47 JESUP MILL, RAYONIER PERFORMANCE FIBERS PB02 624 107,421.39 144,998.18 10,991.02 10,606.28 67,960.85 69,862.76 11,110.47 JESUP MILL, RAYONIER PERFORMANCE FIBERS RF01 333 107,421.39 144,998.18 10,991.02 10,606.28 67,960.85 69,862.76 11,110.47 JESUP MILL, RAYONIER PERFORMANCE FIBERS RF04 334 107,421.39 144,998.18 10,991.02 10,606.28 67,960.85 69,862.76 11,110.47 PACKAGING CORPORATION OF AMERICA - VALDO 1017 653 122,880.11 103,853.24 5,107.49 21,872.91 19,151.22 68,147.97 14,006.81 SAVANNAH ELECTRIC: KRAFT STEAM - ELECTRI SG01 691 62,609.86 171,971.46 18,111.53 9,165.68 78,268.39 110,253.12 17,699.86 SAVANNAH ELECTRIC: KRAFT STEAM - ELECTRI SG02 704 62,609.86 171,971.46 18,111.53 9,165.68 78,268.39 110,253.12 17,699.86 SAVANNAH ELECTRIC: KRAFT STEAM - ELECTRI SG03 4,474 62,609.86 171,971.46 18,111.53 9,165.68 78,268.39 110,253.12 17,699.86 SAVANNAH ELECTRIC: MCINTOSH STEAM - ELEC SG01 7,015 38,864.30 106,498.54 18,602.27 5,338.97 57,638.59 73,603.43 16,614.78 SAVANNAH SUGAR REFINERY U161 997 60,770.78 144,198.38 16,333.87 7,650.04 66,949.15 90,245.22 14,766.80 SOUTHERN STATES PHOSPHATE & FERTILIZER C SA02 808 60,770.78 144,198.38 16,333.87 7,650.04 66,949.15 90,245.22 14,766.80

INLAND PAPERBOARD & PACKAGING, INC. -LIN F2 1,148 19,468.06 29,876.43 70,278.60 62,902.15 86,516.20 52,226.90 93,003.00

## CFM calculations from stack tests

**updated 11-20-07**

**Facility Unit**  **test date fuel**  **approx. temp**  **(deg F) rated heat** 

**input (MMBtu/hr)**  **test heat**

**input (MMBtu/hr)**  **AC FM**  **DSCFM dscfm/acfm** 

IP Savannah Mill PB13 5/15/2007 coal 360 1280 1109 378000 221000 375000 221000 378000 221000

AVG 377000 221000 0.59

GPC Plant McIntosh SG01 2/8/2007 coal 270 1862 1568 589000 393000 592000 392000 593000 392000

AVG 591333 392333 0.66

GA Pac Bruns. Cell. F1 (U700) 4/27/2006 0.6 bark 354 800 707 288000 160000 0.4 oil 290000 160000 301000 160000

AVG 293000 160000 0.55