2/9/2009 Updated Ga Pac Bruns Cell to reflect that Wet FGD and combustion controls were identified as technically feasible
were identified as technically feasible.
Worksheet H.10-1

Four-factor Technical Review

23-Oct-08

Facility name: Brunswick Cellulose (GA Pac) Uncontrolled SO2 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.

SO2 

avoided, 

2018

AnnualCos

t/ton

Total Cap. 

Investment

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. 

Cost/ACF

M

Ann. 

Cost/DSC

FM

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 2004) ($106, 

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

insignificantnone 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 

units

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

inputs: 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 SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)2

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 2004) (date)

($/kW)

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)

Other Comments

Environ. 

Impacts: 

Solid 

Waste

Wet FGD no data #VALUE! no data no data no data no data no data

Identified 

and feasible 

technol.

Energy 

Impacts
Worksheet H.10-3

Four-factor Technical Review

3/11/2008

Facility name: GA Pac Cedar Springs Uncontrolled SO2 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

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)2

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 2004) (date)

($/kW)

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

Other Comments

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 SO2 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

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)2

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 2004) (date)

($/kW)

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 

2013
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.10-5

Four-factor Technical Review

10-Oct-08

Facility name: GA Pac Cedar Springs Uncontrolled SO2 emissions (tons) basis County: Early

Emissions unit: R402 (Recov. Boiler No. 3) AIRS: 09900001

MMBtu/hr capacity 769 2018 VISTAS 1726

fuels1: 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)2

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 2004) (date)

($/kW)

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

Other Comments

Environ. 

Impacts: 

Wastewat

er

C.R. 

Factor 

- CRF 

- int. rate 

- life (yrs)

Conversion to 89.6 no data

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 name: GA Pacific Savannah River Mill Uncontrolled SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost (Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106, 2007) 

($/kW)

($106, 2004) ($106, 

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 

injection1

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

Identified and Comments

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 SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investment

Capital 

Recovery

Ann. Cost (Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106, 2007) 

($/kW)

($106, 2004) ($106, 

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 

injection1

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

Identified and Comments

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 SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investment

Capital 

Recovery

Ann. Cost (Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106, 2007) 

($/kW)

($106, 2004) ($106, 

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 

injection1

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

Identified and Comments

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 SO2 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.

SO2 

avoided, 

2018

AnnualCos

t/ton

Total Cap. 

Investment

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106, 2007) 

($/kW)

($106, 2004) ($106, 

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

Other Comments

Environ. 

Impacts: 

Solid 

Waste

90 gal per 

MWh

30 gal per 

MWh

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 

5.67 Jan. 2016
Worksheet H.10-10

Four-factor Technical Review

28-Sep-07

Facility name: GPC Plant Kraft Uncontrolled SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106, 2007) 

($/kW)

($106, 2004) ($106, 

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

Other Comments

Environ. 

Impacts: 

Wastewat

er

C.R. 

Factor 

- CRF 

- int. rate 

- life (yrs)

2 % of 

generatio

n (1000 

Wet FGD 5.67 Jan. 2016

(LSFO)

37.3 102.0

Other 

Environ. 

Impacts: 

Solid 

Waste

90 gal per 

MWh

30 gal per 

MWh

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
BACKUP DATA/CALCS

Air 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 SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106, 2007) 

($/kW)

($106, 2004) ($106, 

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 

MWh

30 gal per 

MWh

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 

7.89 Jan. 2016
BACKUP DATA/CALCS

Air 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 SO2 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.

SO2 

avoided, 

2018

AnnualCost/

ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. Cost)/ 

(kW)

Ann. 

Cost/ACFM

Ann. 

Cost/DSCFM

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 

2004)

($106, 

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 name: GPC Plant Mitchell Uncontrolled SO2 emissions (tons) basis County: Dougherty

Emissions 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.

SO2 

avoided, 

2018

AnnualCost/

ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) (106 $) ($106, 

2004)

($106, 

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 

Impacts

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 

Comments

not 

addressed

not 

addressed

not 

addressed

Other 

Environ. 

Impacts: 

Water 

Consump.

reduced heat input 

expected 2008 - 2010

Other 

Environ. 

Impacts: 

Wastewater

Other 

Environ. 

Impacts: 

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 Wolf 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investment3

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) (106

$) (106$) (106 $) ($106, 

2004)

($106, 

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 & 

SOG2

Identified and 

feasible technol.1

2010 to 

2012

Other Comments

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 & SOG2 

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 SO2 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.

SO2 

avoided, 

2018

AnnualCo

st/ton

Total Cap. 

Investmen

t

Capital 

Recovery

Ann. Cost2

(Ann. 

Cost)/ 

(kW)

Ann. Cost 

(ACNet)

Ann. Cost 

(ACNet)

Time to 

implem. 

(mos)

 (%) (tons) ($/ton) (106

$) (106$) ($106 2007) ($106, 2004) ($106, 

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

Other Comments

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

Wet FGD 450 kW 37 MG/yr

(MEL)

32.4 141.5 36 mos

Wet FGD 

(LSFO)

32.4 141.5
Escalation 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 

VISTAS 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 SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm-1)

(ton SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

(ton SO2)/ 

(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 WOLF* 

.0389 OKEF*

ESP Oil limit, 5 

Mgal/yr, 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

insignificantnone 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 switch 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 switch 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 WOLF* 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)

Add 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

Add 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 switching 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

Annual 

cost, 

company 

($106, 2007)

Annual 

cost, 

ACNet 

($106, 

2006 )

Page 1 of 7
Facility Emiss. 

unit 

VISTAS 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 SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm-1)

(ton SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

(ton SO2)/ 

(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)

Add 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

Add 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 switching 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

Annual 

cost, 

company 

($106, 2007 )

Annual 

cost, 

ACNet 

($106, 

2006 )

Page 2 of 7
Facility Emiss. 

unit 

VISTAS 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 SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm-1)

(ton SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

(ton SO2)/ 

(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 WOLF* limestone 

injection 

(87% eff,)

Switch 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 WOLF* limestone 

injection 

(90% eff,)

Switch 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 WOLF* limestone 

injection 

(90% eff,)

Switch 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

Annual 

cost, 

company 

($106, 2007 )

Annual 

cost, 

ACNet 

($106, 

2006 )

Page 3 of 7
Facility Emiss. 

unit 

VISTAS 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 SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm-1)

(ton SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

(ton SO2)/ 

(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 

MWh

30 gal per 

MWh

2.7 ton 

gypsum/ 

ton SO2

17700 144.5 0.03392 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold

.0051 WOLF* Coal switching 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 

MWh

30 gal per 

MWh

2.7 ton 

gypsum/ 

ton SO2

17700 106.9 0.04772 below thresthold below thresthold below thresthold below thresthold below thresthold below thresthold

.0052 WOLF* Coal switching 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 

MWh

30 gal per 

MWh

2.7 ton 

gypsum/ 

ton SO2

17700 56.9 0.13177 18112 58.2 0.12877 below thresthold below thresthold below thresthold

.0330 WOLF* 

.0085 OKEF* 

.0081 ROMA

Coal switching 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)

Annual 

cost, 

company 

($106, 2007 )

Annual 

cost, 

ACNet 

($106, 

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 

VISTAS 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 SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm-1)

(ton SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

(ton SO2)/ 

(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/MWh

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 WOLF* 

.0120 OKEF* 

.0055 SAMA* 

.0135 ROMA 

.0072 SWAN

Coal switching 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 switching 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 WOLF* 

.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 switching, 

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

Annual 

cost, 

company 

($106, 2007 )

Annual 

cost, 

ACNet 

($106, 

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 

VISTAS 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 SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm-1)

(ton SO2)/ 

(Mm-1)

106 $/ 

(Mm-1) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

(ton SO2)/ 

(Mm

-1

)

10

6

 $/ 

(Mm

-1

) 

company

cost

Control 

extinction 

reduction 

(Mm

-1

)

Southern 

States 

Phosphate 

and Fert.

SA02 

(Sulfuric 

Acid 

Plant 2) 

#REF! #REF! Increase acid 

capture with 

Cs-promoted 

catalyst

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

.0064 WOLF* 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

Abbreviations: Class I Areas:

ACNet Air Control Net (EPA cost database) WOLF* 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)

Annual 

cost, 

company 

($106, 2007 )

Annual 

cost, 

ACNet 

($106, 

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 

VISTAS SO2 

(tons)

4F Baseline 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 SO2)/ 

(Mm-1)

106 $/ 

(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, 

multiclone, 

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

Abbreviations: Class I Areas:

ACNet Air Control Net (EPA cost database) COHU Cohutta estimated implementation date earlier than Jan. 1, 2012 

Mm megameter JOKI Joyce Kilmer

MG million gallons extinction reduction (visibility improvement) > 0.100

ND no data

0 not addressed in 4-factor submittal 0.010 < extinction reduction < 0.100

Cohutta Visibility - Sensitivity to 

emissions reductions

TempleInland 

Rome LB 

Mill

Annual 

cost, 

company 

($106, 2007 

)

Annual 

cost, 

ACNet 

($106, 

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 ROMA1 SAMA1 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 POWER 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 BRUNSWICK 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 BRUNSWICK 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) ACFM 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