Public Notice of 

Proposed Best Available Retrofit Technology (BART) Determination 

For Georgia-Pacific Consumer Products, L.P., Green Bay, WI 

for Visibility Protection 

Background 

In response to federal clean air regulations requiring states to develop plans to address the impairment of visibility 

in certain pristine federal areas (Class I areas), the Wisconsin Department of Natural Resources (DNR) developed 

an administrative rule (ch. NR 433, Wis. Adm. Code). The rule requires certain categories of major stationary 

sources to install Best Available Retrofit Technology (BART) for visibility protection. The Georgia-Pacific 

Consumer Products, L.P. (Georgia Pacific) facility at 1919 S. Broadway, Green Bay, Brown County, Wisconsin, 

FED 405032870, was identified as a facility that was subject to BART requirements. Georgia Pacific submitted to 

the Department of Natural Resources (DNR) a best available retrofit technology (BART) analysis to identify 

available control technologies for their units that are subject to BART. After reviewing the BART analysis 

submitted by Georgia Pacific along with other available information DNR has made a preliminary determination of 

the proposed BART requirements for Georgia Pacific. The proposed BART requirements are incorporated into a 

draft revision of Air Pollution Control Permit No. 405032870-P03. 

Availability of Information 

You can review Georgia Pacific's BART analysis, the DNR's preliminary determination, comments received from 

the FLM, and the proposed BART requirements incorporated into the draft revision of the air quality permit 

prepared by the DNR at the Department of Natural Resources Bureau of Air Management Headquarters, Seventh 

Floor, 101 South Webster Street, Madison, Wisconsin, 53703; Northeast Region Headquarters, 2984 Shawano 

Avenue, Green Bay, WI 54313-6727, tel. (920) 662-5495; and at the Brown County Library, 515 Pine St., Green 

Bay, WI 54301-4301, or by contacting Carol V. Crawford, P.E. at (920) 662-5445 or by e-mail at 

Carol.Crawford@Wisconsin.gov. This information is also available for downloading from the Internet at 

http://dnr.wi.gov/air/permits/permitsearch.html. 

Public Comments 

Interested persons wishing to comment on the proposed BART requirements or the draft revisions to the air permit 

should send written comments within 30 days of publication of this notice to: 

Wisconsin Department of Natural Resources, Northeast Region Headquarters, 2984 Shawano Avenue, Green Bay, 

WI 54313-6727. Attn.: Carol V. Crawford, P.E. 

Public Hearing 

Pursuant to s. 285.13 (1), Wis. Stats., the Department will hold a public hearing on the proposed BART 

requirements and the draft revisions to the air permit. The public hearing will be held: 

Thursday, July 29, 2010 at 1:00 PM 

Green Bay City Hall 

100 N. Jefferson Street, Room 207 
Green Bay, WI 

Information on the public comment and public hearing process is available at http://dnr.wi.gov/air/citguide.htm. Reasonable accommodation, including the provision of informational material in an alternative format, will be 

provided for qualified individuals with disabilities upon request. 

After all public comments have been considered, DNR will make a final BART determination and send revised 

permit conditions to the United States Environmental Protection Agency (US EPA) for review and approval. 

STATE OF WISCONSIN 

DEPARTMENT OF NATURAL RESOURCES 

For the Secretary 

Andre 

Permits tionary Source Modeling 

Section Chief 
Mailed to facility by:Carrif-V. Crawford;P7E.- 

-NERIGr-P.P.A-Bay 

Publication to appear in: 

The DNR will publish in: 

Green Bay.Press-Gazette 

PO Box 23430 

Green Bay, WI, 54307-3430 

On Monday, June 28, 2010 

P#41‘,Lftp-A--) 

,• • .• • .• 

Wisconsin State Journal 

1901 Fish Hatchery Rd, B ox 79 

Madison, WI 53708 

On Monday, June 28, 2010 

Location and date of hearing: 

Thursday, July 29, 2010 at 1:00 PM 

Green Bay City Hall 

100 N. Jefferson Street, Room 207 

Green Bay, WI 

Linda Lund, Office Operations Associate 

Bureau of Air Management 

608-264-9206 

Subscribed and sworn to before me 

_asiLi_day 

o this f 3itoki, at) 1 

Notary Pu .1 c, State, of WissQnsin. 

My commission expires: 61-116-q an I ( 
STATE OF WISCONSIN Public Hearing Notice/Permit Number: 

DEPARTMENT OF NATURAL RESOURCES 405032870-P03 Proposed BART requirements 

Public Hearing Notice for Proposed Best Available Retrofit Technology (BART) Determination for 

Visibility Protection at Georgia-Pacific Consumer Products, L.P., 1919 S. Broadway, Green Bay, Brown 

County, Wisconsin. 

Linda Lund, being first duly sworn on oath deposes and says that said person is employed as a Office 

Operations Associate, by the State of Wisconsin Department of Natural Resources; that on the 24th day of 

June, 2010, said person deposited.in'theUnited.States.mail at Madison, Dane County, Wisconsin,•copies of 

the notice for public hearing to the above entitled action, securely enclosed in envelopes, the postage duly 

prepaid and one copy addressed to each of the following at his/her respective last known address: 

Pamela Blakley, Chief - AR-18J 

US EPA - Region 5 

77 West Jackson Boulevard 

Chicago, IL 60604 

Janice Keib 

PO Box 146 

Brokaw, WI 54417 

Michael Huenick 

Env. Tech. & Engineering Corp. 

13020 Bluemound Rd. 

Elm Grove, WI 53122 

• 

James O'Connor 

Kent & O'Connor Incorporated 

1990 M. Street NW 

Ste. 340 

Washington, DC 20036 

Lee Kottke 

Anguil Environmental Consultants 

851 E. Glen Avenue 

Milwaukee, WI 53217 

Gregory Denny 

Environmental Monitoring & Tech. Inc. 

8100 North Austin Ave 

Morton Grove, IL 60053-3203 

Dennis Greil • 

Bay Environmental Strategies 

529 S. Jefferson St. 

Ste. 10 

Green Bay, WI 54301 

Clean Wisconsin 

122 State Street 

Ste. 200 

Madison, WI 53703-2500 

Environmental Law Society, UW Law School 

975 Bascom Mall 

Madison, WI 53706 

Mike Mayan 

RMC Env. 

PO Box 216 

Rosendale, WI 54974 

Bruce Nilles 

Sierra Club 

122 W. Washington St. 

Ste. 830 

Madigon, WI* 53703 

Mark Larson 

2310 Pinehurst Drive 

Middleton, WI 53562-2541 

David C. Bender 

McGillivray Westerberg & Bender LLC 

305 S. Paterson Street 

Madison, WI 53703 

Brown County Library 

515 Pine St. 

Green Bay, WI 54301-5194 

Bay-Lake Regional Planning Commission 

. .441. South Jackson Street 

Green Bay, WI 54301-3909 

Brown County Planning Commission 

305 E. Walnut St. Room 320 

PO Box 23600 

Green Bay, WI 54305/3600 

Chairman, Brown County Board 

PO Box 23600 

Green Bay, WI 54305-3600 
Paul Holtan OC/2 

Mayor, Green Bay 

100 N Jefferson St MS • 

Green Bay, WI 54301-5006 

Clerk, Brown County 

PO Box 23600 

Green Bay, WI 54305-360 

County Executive, Brown County 

PO Box 23600 

Green Bay, WI 54305-360 

Clerk, Green Bay 

100 N. Jefferson Street 

Green Bay, WI 54301 

• •.re. • • .• • • .• 

Ms. Natalene Cummings 

FCPC Natural Resources Dept., EPA - Air 

Resources 

Forest County Potawatomi Community 

PO Box 340 

Crandon, WI 54520 

Forest Co. Potowatomi Tribe 

PO Box 340 

Crandon, WI 54520 

Menominee Tribe 

PO Box 910 

Keshena, WI 54135 

4.11 • • .4 

Oneida Tribe 

PO Box 365 

Oneida (Town of), WI 54155-0365 

Stockbridge-Munsee Tribe 

PO Box 70 

Bowler, WI 54416 

Sue Eley-LS/8 

Tom Steidl — LS/8 

• •••• • • • • • • • 

GLIFW Commission 

P.O. Box 9 

Odanah, WI 54861-0009 

Ashwaubenon Press 

1047 Marvelle Lane 

Green Bay, WI 54304 

De Pere Journal 

PO Box 23430 

Green Bay, WI 54305-3430 

The Green Bay News Chronicle 

PO Box 23430 

'Green' Ray, WI 54305-3430 

WBAY TV 

115 S. Jefferson 

Green Bay, WI 54301 

WDUZ Radio 

810 Victoria Street 

Green Bay, WI 54302 

Rebecca Katers 

2484 Manitowoc Rd. 

Green Bay, WI 54311-5376 

• • • • . 1, • • • -II 

WFRV TV 

Box 19055 

Green Bay, WI 54307-9055 
Mike Scott — LS/8 

Marney Hoefer — LS/8 

Linda Haddix, LS/8 

DNR Hearing and Meeting Calendar 

.•. 

• 
RECEIVED 

JUN 3 0 2010 

AIR MANAGEMENT 

"PT OF NATURAL RESOURCES 

Ken Behm 

Mail to: 

-7921 

PWSJ Wisconsin State Journal 

as), th, 

trative 

The 

A 

Arlene Staff 

SS. 

being duly sworn, doth depose and say that 

he (she) is an authorized representative of 

Capital Newspapers, publishers of 

a newspaper, at Madison, the seat of government of said State, 

and that an advertisement of which the annexed is a true 

copy, taken from said paper, was published therein on 

June 28th, 2010 

Principal Clerk 

Subscribed and sworn to before me on 

Notary Public, Dane County, Wiscon in 

My Commission expires May 24th, 2013 SERVED MGM 

Capital Newspapers Proof of Publication Affidavit 

Ad #: 1610916 Price: $100.11 Ad ID: AMU-727; Georgia Pacific 

Retain this portion for your records. 

Please do not remit payment until you receive your advertising invoice. 

BEFORE THE 

DEPARTMENT OF NATURAL RESOURCES 

Notice of Public Hearing 

State Implementation Plan (SIP) to Address Requirements of the Federal Regional Haze Rule 

NOTICE IS HEREBY GIVEN that pursuant to s. 285.13(1), Wis. Stats., the Department of Natural 

Resources will hold a public hearing on the proposed Regional Haze SIP for the State of Wisconsin. 

Background 

The Regional Haze Rule was adopted on July 1, 1999 (64 FR 35714) and incorporated under 40 

CFR part 51.308 as part of Subpart P — Protection of Visibility. The Clean Air Act (CAA) under 

section 169A(b)(2) requires each state with a residing listed Class I area — and any state from 

which emissions are reasonably anticipated to cause or contribute to any impairment of visibility 

of such a Class I area — to make reasonable progress towards remedying impairment from manmade air pollution. Wisconsin, being identified as a contributing state, is specifically subject to 

requirements under the regional haze program, 40 CFR Part 51.308. 

In accordance with 40 CFR Part 51.308, the Department has developed a draft Regional Haze SIP 

based on the requirements of the Regional Haze Rule. This document describes Wisconsin's 

fulfillment of SIP requirements established by the rule for purposes of remedying and protecting 

visibility in designated federal Class I areas. The document includes Wisconsin's strategy for 

meeting reasonable progress goals by 2018 for Class I areas — which relies primarily on existing 

control programs across different source categories — and implementation of Best Available 

Retrofit Technology (BART) for affected major sources. 

NOTICE IS HEREBY FURTHER GIVEN that the public hearing will be held on: 

Tuesday, September 13, 2011 at 10:00 a.m. 

Wisconsin Department of Natural Resources, Room 713 

101 S. Webster Street 

Madison, WI 53707-7921 

NOTICE IS HEREBY FURTHER GIVEN that pursuant to the Americans with Disabilities Act, 

reasonable accommodations, including the provision of informational material in an alternative format, 

will be provided for qualified individuals with disabilities upon request. Please call Jonathan Loftus at 

(608) 264 - 8868 with specific information on your request at least 10 days before the date of the 

scheduled hearing. 

Written Comments and Copies of Documents 

Written comments on the proposed Regional Haze SIP may be submitted to Mr. Jonathan Loftus, 

Bureau of Air Management AM/7, P.O. Box 7921, Madison, WI 53707 no later than September 16, 

2011. Comments may be submitted electronically to jonathan.loflus@wisconsin.gov . Written comments 

will have the same weight and effect as oral statements presented at the hearing. 
A copy of the documents for the proposed Regional Haze SIP may be downloaded from 

http://dnr.wi.gov/air/aq/particles/vishaze.htm or a hard copy may be obtained from: 

Jonathan Loftus AM/7 

Bureau of Air Management 

P.O. Box 7921 

Madison, WI 53707 

.Jonathan.Loftus(a)wisconsin.gov 

Phone: (608) 264-8868 

FAX: (608) 267-0560 

Dated at Madison, Wisconsin 

STATE OF WISCONSIN 

DEPARTMENJ' OF NA RESOURCES 

in Cathy St - p, Secretary 
STATE OF WISCONSIN Notice/Permit Number: 

DEPARTMENT OF NATURAL RESOURCES Hearing Notice 

Proposed Ozone Redesignation Request and Maintenance Plan Supplement for the Milwaukee-Racine 

Nonattainment Area and the Sheboygan County Nonattainment Area 

State Implementation Plan (SIP) to Address Requirements of the Federal Regional Haze Rule 

Linda Lund, being first duly sworn on oath deposes and says that said person is employed as a Office 

Operations Associate, by the State of Wisconsin Department of Natural Resources; that on the 8th day of 

August, 2011, said person deposited in the United States mail at Madison, Dane County, Wisconsin, copies 

of the notice for public hearing to the above entitled action, securely enclosed in envelopes, the postage duly 

prepaid and one copy addressed to each of the following at his/her respective last known address; and emailed the same to the interested parties who have requested to receive the public notices via e-mail: 

Susan Kraj (e-mailed) 

US EPA - Region 5 

Kraj.Susan@epamail.epa.gov 

Janice Kelb 

PO Box 146 

Brokaw, WI 54417 

Michael Huenick 

Env. Tech. & Engineering Corp. 

13020 Bluemound Rd. 

Elm Grove, WI 53122 

Lee Kottke (e-mailed) 

Anguil Environmental Consultants 

lkottke118 @aol.com 

Gregory Denny (e-mailed) 

Environmental Monitoring & Tech. Inc. 

dkrueger@emt.com 

Dennis Greil (e-mailed) 

Bay Environmental Strategies 

dcgreil@bayenvironmental.com 

Clean Wisconsin 

122 State Street 

Ste. 200 

Madison, WI 53703-2500 

Environmental Law Society, UW Law School 

975 Bascom Mall 

Madison, WI 53706 

Mike Mayan 

RMC Env. 

PO Box 216 

Rosendale, WI 54974 

Jennifer Feyerherm (e-mailed) 

Sierra Club 

Jennifer.Feyerherm@sierraclub.org 

Mark Larson (e-mailed) 

mlarson@prefinishing.com 

David C. Bender (e-mailed) 

McGillivray Westerberg & Bender LLC 

Bender@mwbattomeys.com 

Danny Marcus (e-mailed) 

US EPA - Region 5 

Marcus.Danny@epamail.epa.gov 

Rosemary Thorne (e-mailed) 

Badger Laboratories & Engineering, Inc. 

rthome@badgerlabs.com 

Marney Hoefer - LS/8 
<NYV1/411`0 

Notary Public, State of Wisconsin 

My commission expires: 

AReARA * 

Publication to appear in:, 

The DNR will publish in: 

Wisconsin State Journal 

PO Box 8056 

Madison, WI, 53708-8056 

On Thursday, August 11, 2011 

Public Hearing Contact: 

Jonathan Loftus —AM/7 

Bureau of Air Management 

Phone: (608) 264-8868 

Location and date of hearing: 

Tuesday, September 13, 2011 at 1:00 p.m. 

Wisconsin Department of Natural Resources. 

Room 713 

101 S. Webster Street 

Madison, WI 53707-7921 

inda Lund, Office Operations Associate 

Bureau of Air Management 

608-264-9206 

Subscribed and sworn to before me 

this CiA./:■_, day of axiivo, ap 
ONSIN 

SS. 

} ;ounty 

i\6 1. 6 20 

My Commission expires April 15th, 2015 

(Signed) 

(Title) Principal Clerk 

Subscribed and sworn to before me on 

3- la.‘ ■ ( 

Notary Public, Dane County, Wisconsin 

Capital Newspapers Proof of Publication Affidavit 

Ad #: 1802836 Price: $93.37 Ad ID: AMLL-863 

Retain this portion for your records. 

Please do not remit payment until you receive your advertising invoice. 

Mail to: 

DEPT OF NATURAL RESOURCES 

Sharon Reeve 

P.O. Box 7921 

MADISON, WI 53707 

BEFORi THE 

OF NATURAL 

Notice of Public 

State ImplementationPIsn 'SIP) to A.4 

dress Requirements of. AN Federal Regional Haze Rule NOTICE is wow *at Pursuant 

to s. 285.13(1), WI. , the Department of Natural' Resoi0ea will hold a 

public heating on the prOposedRegional 

e SIP tor the State of Wisconsin. 

The &COO& Heize.Rule waip adopted on 

July 1, 1999 (64 FR 35714) and Incorp6- 

rated 1.ft 40 'CFR part-11,908 as part 

of Subpart P ProtectioA of Visibility. 

' ttnder section 

With a restate 

anto any irna Class I area 

ess towards 

man-Made 

identified 

citify subregional 

air poll 

?loco 

to 

The Clean Air •Act 

169A(b)(2)* * 

siding listed 

from 

ticipat 

pas 

- to 

SHARON SCALLON 

being duly sworn, doth depose and say that 

he (she) is an authorized representative of 

Capital Newspapers, publishers of 

In ac 6.308, 

the a draft 

Regional Haze SIP based on the requirements of the Regional Haze Rule. Thia 

document WiscOnsin's 'fulfillment of SIP requirements established by 

the rule for of remedying and 

Mass 

protecting ,federal 

I areas. includes 

able 

Wisconsin's strategy rrsoni 

progress goals 

areas which relies existing 

source 

ectitiology 

. GIVEN 

that the public hearing will be held on: 

Tuesday, September 13, 2011 at 10:00 

Nisaltisin DepArtment of. Natural RelourCes, Room 713 

101 S. Webster Street 

vtadiiion, WI 53707-7921 

FURTHER 

a

GiVEN 

American with 

noble SICC01117 

the provision of 

I in an alteThative 

for qualified inupon request. 

Loftus at (608) 264 

on your 

before the date 

loNring. 

Ond Copses of Documeat on the proposed Rebe submitted to Mr. 

u of Air Manage921, Madison; WI 

tember 16, 2011. 

itted eleCtronfa@wisconsin.gov. 

will have the same 

*oral statements pre- 

) 

nts for the proSIP may be down- 

' 

/eq/partIcles/viscopy may be ob- 

, 

Bilreau of Air 

x 7921. Madison, 

nathan.Loftua@wisconsin.gov 

one: (608) 264-8868 

X:' (608) 207-0660 

ted at Madison, Wisconsin : 8/1/11 

ATE OF WISCONSIN 

:PARTMENT QF 

;WAAL RESOURCES 

: 

• Matt Moroney • for 

thy StOpp, Secretary . 

PUB. WSJ: August 11, 2011 

#1802836 WNAXLP 

Var 

Best Available 

:Nn for a isaffaln; 

PWSJ Wisconsin State Journal 

a newspaper, at Madison, the seat of government of said State, 

and that an advertisement of which the annexed is a true 

copy, taken from said paper, was published therein on 

August 11th, 2011 

0• 
1

BART Requirements for Wisconsin Sources – Response to Public Comment

Wisconsin is required to implement a Best Available Retrofit Control program according 

to 40 CFR part 51.308(e) of the Federal Regional Haze Rule. The Department initially 

proposed BART requirements for public comment in June of 2010. Based on received 

comment and analysis, the Department re-proposed BART requirements in July of 2010 

for public comment. On the re-proposed BART the Department received comment from 

Georgia Pacific, U.S. Forest Service, National Parks Service, U. S EPA, and joint 

comment from Sierra Club and the Midwest Environment Defense Center. This 

document comprises the Department's response to specific and identified areas of 

comment to the BART determination for the Georgia Pacific Broadway Mill, Green Bay 

Wisconsin and for the Electric Utility Sector. 

Herein the U.S. Forest Service and National Parks Service when addressed in common 

are referred to as the Federal Land Managers (FLMs). The Wisconsin Department of 

Natural Resources is referred to as the Department. 

I. Georgia Pacific BART Requirements 

1.0 Baseline Emissions

Comment 1.1: The baseline emissions used in calculating baseline emissions should 

reflect boilers “shut down” of boilers B24 and B25 with zero emissions. 

Response: The Department agrees that boiler B24 should not be included in calculating 

a mass cap requirement. Georgia Pacific began curtailing operation of this boiler during 

the BART baseline years with no operation by 2005 and after. 

The Department maintains that boiler B25 baseline emissions should be included in 

calculating a mass cap requirement for the stack S10 boiler system. Boiler B25 

operated continuously during and since the BART baseline years until 2009 when the 

boiler potentially became subject to the Clean Air Interstate Rule (CAIR). Georgia 

Pacific elected to not operate the boiler pending a review by U.S. EPA for determining 

CAIR applicability. In May 2, 2011, U.S. EPA provided a determination, appendix A, 

that boiler B25 is not subject to CAIR. Therefore this boiler is no longer restricted in 

operation. 

The Department believes using operation during the BART baseline years is 

representative of boiler B25 returned status to full allowable operation. This is 

supported by looking at the total heat input for the stack S10 boiler system. Before and 

after boiler B25 operation was halted the total stack heat input remains relatively 

constant. This indicates that boiler B25 load was simply switched to the other boilers. 

Therefore non-operation of boiler B25 was not due to a reduced need of load or 

necessarily reflect the normal dispatch of the stack S10 boiler system. Therefore the 
2

consistent approach for reflecting operation of all affected boilers, including B25, is the 

use of the baseline years emission and operation data. 

Comment 1.2: The U.S. EPA, Federal Land Managers, and Sierra Club commented that 

baseline SO2 emissions should not be calculated using a design fuel but rather reflect 

actual historic emission levels. 

Response: The Department agrees. The finalized baseline emissions reflect actual 

historic emission levels during the BART baseline years of 2002 to 2004. Specifically, 

the 12 month rolling mass cap is calculated using the three year average of SO2 emitted 

during 2002 to 2004 for each boiler, except B24, in the stack S10 system. The 30 day 

rolling average emission cap is calculated using the SO2 average emission rate for each 

boiler during the baseline years applied to the boiler's heat input demonstrated during 

the 30 day heat input of maximum heat input during baseline years for the total stack 

S10 system. 

Comment 1.3: The Department, in proposing BART, evaluated appropriate fuels for 

purposes of calculating adjusted baseline emissions; i.e. determining a boiler design fuel. 

The U.S. EPA states that fuel switching is a control option and should be evaluated in the 

context of actual historic fuels and operation. 

Response: The Department concurs and evaluated fuel switching as a control option. 

The information developed for fuel switching cost and visibility improvement provided 

in the July 2011 proposed BART determination, section 3 page 12, is applicable to this 

evaluation. Based on this information, the Department determined that the control 

measure of switching petroleum coke fuels to the baseline fired bituminous coals is 

appropriate for both B26 and B27 boilers. For boiler B27, the fuel switching beyond 

the current low fusion coal can negatively affect the combustion and necessary slagging 

characteristics of the cyclone furnace. Therefore, switching petroleum coke to low 

fusion coal is the only option evaluated and was determined cost-effective at 1,505 

$/ton. For boiler B26 a stoker boiler, options are considered for switching fuels from 

petroleum coke to the baseline bituminous coal and to low sulfur bituminous coals. 

The switch to low sulfur bituminous coal is eliminated based on marginal costs at 1.5 to 

almost 2 times the switch to baseline bituminous coals. 

Comment 1.4: The Department proposed a 30 day rolling mass cap compliance 

requirement that reflects heat input equivalent to 90% capacity utilization of the stack 

S10 boiler system. The U.S. EPA commented that full utilization is greater than past 

actual operations and will result, on average, in less than BART control under a mass cap. 

The U.S. EPA also recommended that the 30-day average mass cap be calculated using 

historic operating levels which occurred during the BART baseline years. 

Response: The Department agrees and is amending the 30 day rolling mass cap 

calculation to reflect historic operating levels. The mass cap now reflects the maximum 

30 day heat input demonstrated for stack S10 system (excluding boiler B24) during the 

BART baseline years. This maximum 30 day heat input is then multiplied by the 
3

average baseline year emission rates for each boiler after applying BART controls. 

This approach establishes a mass cap which is used to represents the allowed maximum 

30 day emissions after BART. It is important to note that this level of emissions is less 

than taking the maximum 30 day heat input multiplied by the maximum demonstrated 

emission rates of each boiler and then applying BART control levels. The proposed 30 

day mass cap is also less than would occur when if using the maximum of single day 

emissions demonstrated during the baseline years. This maximum single day value was 

used in modeling visibility impact for assessing BART control options. Therefore the 

currently proposed 30 day mass cap results is a requirement more protective, on the 

whole, of visibility than predicted by the modeled results for BART controls. 

The Department also points out that the 30 day rolling mass cap is meant to work 

together with the more restrictive 12 month rolling mass cap. The 12 month rolling cap 

is the driver for meeting the BART controls on a long-term basis while the 30 day 

rolling mass cap ensures visibility impacts do not exceed modeling visibility 

improvements for BART. Refer to response to comment 5.2. 

2.0 SO2 Controls

Comment 2.1: The U.S. EPA and Federal Land Managers commented that 95% control 

efficiency for the flue gas desulfurization equipment accounts for necessary variability in 

control levels and the Department applying a 2% compliance margin in determining a 

93% control compliance requirement double counts any needed adjustment for control 

variability. Sierra Club commented that a SO2 control level of at least 95 % should be 

reflected in the BART compliance requirement. 

Response: The U.S. EPA and FLM recommendations are based on a particular 

technology (Turbosorp), under a spray dryer sub-category (CFB). In evaluating BART 

for SO2 at Georgia-Pacific, Department maintains that it is necessary to consider the 

weight of evidence for the spray-dryer category as a whole, not limiting the evaluation 

to just CFB or Turbosorp in particular. The Department emphasizes that the Turbosorp 

technology has very limited demonstration. Greenidge Unit 4 – the primary reference 

for Turbosorp application at Georgia-Pacific – has not operated since the end of testing 

in 2008, as far as the Department is aware. The Deerhaven testing for 95+ % control 

was for a duration of 12 hours and is not appropriate for establishing a long-term 

control level at Georgia-Pacific. Further, with taking coke out, the inlet at GP becomes 

3.0 Lb/mmBtu, whereas the testing at Greenidge Unit 4 was 3.6 Lb/mmBtu on average. 

For these reasons, it is questionable to use Turbosorp technology as the sole basis for a 

BART control level. 

Under this approach, the Department is proposing a (conservative) starting control 

efficiency of 95% based on SDA, along with a sufficient compliance margin, for an SO2

control level of 93% on boilers B26 and B27 combined with removal of coke. The total 

control level on boilers B26 and B27 from the baseline is 94.2%. The 93% control level 

is higher than any other proposed BART control for a non-EGU, as far as the 
4

Department is aware. North Dakota dismissed CFB at 93% control in its BART 

analysis in part specifically because of its limited demonstration. The highest BART 

control proposed using SDA technology is 92% control, and the other BART proposals 

using SDA technology are at 90% control or less. It seems that many BART proposals 

used a default control level of 90% based on information from EPA’s SO2 Control 

Manual. Also, the Cross-State Air Pollution Rule (which is proposed as equivalent to 

BART for BART-subject utilities) applies an SO2 control of only 92%. 

3.0 NOx Controls

Comment 3.1: The U.S. EPA requested additional justification for reducing the NOx 

control efficiency of RSCR control equipment from 80% to 70%. 

Response: In the July 2011 draft BART finding the Department proposed an operating 

NOx control efficiency of 75% for RSCR and applied a 70% reduction in allowing for a 

compliance margin and determining final compliance requirements. The Department 

continues to believe these control levels are appropriate in making the BART 

determination. Refer to response to comment 5.3 for discussion of compliance 

margins. 

The Department originally proposed 75 to 80% control efficiency for RSCR in June of 

2010 as a basis for further investigation. At that time, initial discussions with the 

vendor, Babcock Power Inc., indicated the higher range of RSCR control efficiencies 

may result in ammonia slip of up to 13 ppmdv. The RSCR system is comprised of 

multiple canisters containing single layers of catalyst and operates with flue gas being 

treated by alternating canisters while the non-treating canisters are reheating. As flue 

gas is switched between canisters, small amounts of flue gas may exit the common 

header system without first passing through the catalyst beds – therefore momentary 

puffs of untreated flue gas and un-utilized ammonia occur. Traditional SCRs are 

designed for a maximum ammonia slip of 5 ppmdv or less. Assuming slip at the same 

rates as a traditional SCR and along with the momentary puffs a RSCR more total 

ammonia than a normal SCR. This consequence of the RSCR needs to be considered 

further in setting final control levels. 

Since the initial BART assessment, Babcock Power provided a ROM equipment 

estimate for applying RSCR to the Georgia Pacific stack S10 boiler system. In that 

estimate Babcock Power stated a design control efficiency of 75% with a maximum 10 

ppmdv ammonia slip. Although less than 13 piped, the total RSCR ammonia slip is 

still expected to be more than a traditional SCR. The Department acknowledges that 

with lower control efficiency less ammonia slip is likely to occur. Because ammonia 

can contribute to particulate and visibility issues allowing for further minimization of 

ammonia slip closer to traditional SCR levels may be warranted. The Department 

considers this a secondary factor in evaluating appropriate compliance margins. Actual 

operation in meeting the current proposed 70% compliance requirement is assumed to 
5

be 75%, but being able to achieve control consistently below 75% will further reduce 

puffs of uncontrolled NOx and ammonia slip. 

As stated Babcock Power's equipment quote specifies a 75% control efficiency level 

which the Department further confirmed with Babcock Power as an appropriate long 

term control level for RSCR applied to a coal fired unit1. The Department then applied 

a compliance margin in determining the final compliance requirement. In this case the 

compliance margin may allow for further reduced ammonia slip if Georgia Pacific can 

trim closely to a 70% control level. However, the compliance margin mainly addresses 

that an RSCR is a new configuration and operating approach to SCR control 

technology. The RSCR is operating successfully on biomass fired boilers which in 

some cases is more difficult, but to date the RSCR has not been applied to the higher 

NOx levels of coal fired boilers. Therefore, without actual operating data on similar 

sources the Department believes allowing for a 5% compliance margin is appropriate 

under the Georgia Pacific BART determination. 

Comment 3.2 The Department proposed in the July 2011 Draft BART finding that 

regenerative selective catalytic reduction (RSCR) is applicable to boiler B27, but not to 

boiler B26. The U.S. EPA and Federal Land Managers requested justification for this 

determination when both boilers exhaust to a common stack where the RSCR technology 

is typically applied. 

Response: The Department maintains that RSCR is applicable to boiler B27 and not to 

boiler B26 in determining BART requirements. This finding is based on both the 

physical equipment configuration and resulting high cost of applying RSCR to boiler 

B26. As a note - one of the original concerns described in the 2011 BART finding for 

applying RSCR to boiler B26 was the potential for high SO2 concentrations in the flue 

gas which could result in SO3 plume. This concern is no longer applicable based on the 

finalized BART SO2 requirements. 

This point first clarifies the discussion in the 2011 finding concerning RSCR and the 

existing equipment configuration. All of the boilers B25 to B28 exhaust into a common 

flue duct. However, this duct then splits evenly before entering two parallel fabric filter 

units housed inside of a building. A flue duct exits from each fabric filter out of the 

building and enter opposite sides of the flue stack. The flue ducts then rejoin only once 

inside the stack. The default placement of the RSCR is between the fabric filter system 

and the stack where there are still two separate ducts. Therefore the default 

configuration is to place two separate RSCR units – one on each flue duct. The 

previous discussion further identified that under this configuration one duct 

corresponds to the flow rate and emissions equivalent of boiler B27. Therefore this 

RSCR system and cost is attributed to boiler B27. This RSCR placement is deemed 

cost-effective for BART purposes. 

Under this configuration the control of boiler B26 requires a RSCR be placed on the 

second flue duct between the fabric filter and stack. The cost of this unit is then placed 

 

1

 Babcock Power, personal communication 
6

against the flow rate and emissions equivalent of boiler B262. In looking the RSCR 

based control options the highest control level is achieved by overfire air and flue gas 

recirculation on the boiler followed by the RSCR control (OFA/FGR/RSCR). This 

configuration results in a 0.11 deciview improvement at a cost of approximately 15.6 

million dollars per deciview improvement (M$/dv). The next lower control option of 

OFA/FGR/SNCR achieves a 0.09 deciview improvement at 9.1 M$/dv. Also 

significant is that the capital cost of the RSCR based system is 9.9 M$ and the SNCR 

based system is 4.4 $M. This shows the RSCR system will achieve only 0.02 deciview 

improvements while incurring significant additional cost compared to the SNCR based 

system. In this case the RSCR based system is not considered BART. 

Comment 3.3 U.S. EPA requested additional justification for reducing the control 

efficiency of overfire air NOx control as applied to boiler B27 from 60% to 50%. 

Response: In the July 2011 draft BART finding the Department proposed an 

estimated operating NOx control efficiency of 52% for overfire air and applied a 50% 

reduction in allowing a compliance margin and determining final compliance 

requirements. The Department maintains these control levels are appropriate in 

making the BART determination. Refer to response to comment 5.3 for discussion of 

compliance margins. To note is that the overfire air achieves higher NOx control 

efficiency for the B27 cyclone boiler than can be achieved on the B26 stoker boiler. 

The quoted 60% control was originally proposed in the June 2010 Draft BART 

finding for purposes of obtaining comment and further information. Since that time 

the Department evaluated historic emissions data before and after operation of 

overfire air on cyclone boilers of similar size and fuel operated at the Wisconsin 

Nelson Dewey electric utility plant. The overfire air of this boiler is operated with 

neural network type of system which is believed to represent best operational levels 

for reducing NOx emissions while under optimal combustion efficiency conditions. 

Although, 60% control efficiency is technically achievable it may come at the 

expense of poor combustion characteristics and increased emissions of incomplete 

combustion such as carbon monoxide, dioxins and furans. Under the currently 

proposed ICI MACT regulation, these hazardous pollutants are to be controlled 

through good combustion practices. The Department believes an overfire air control 

efficiency should not be set that potentially works against the MACT requirement and 

good combustion efficiency. Further the Department believes the Nelson Dewey 

plant's well operated overfire air system is an appropriate basis for overfire air control 

levels applied to cyclone boilers under these constraints. Reviewing emissions data 

for Nelson Dewey's two cyclone boilers demonstrates 52% NOx control due to the 

overfire air system on an annual basis. Because this is a demonstrated control level 

the final compliance requirement can be set using a small compliance margin. A 2% 

compliance margin is allowed resulting in an overall 50% compliance control 

efficiency. Refer to response to comment 5.3 for discussion concerning the use of 

compliance margins. 

 

2

 WDNR, 2011, BART Determination – Amended July 2011, Georgia Pacific Broadway Mill, Green Bay 

Wisconsin, section 4, page 26, Table 4.3 July 1, 2011. 
7

4.0 Particulate Controls

Comment 4.1: The National Parks Service commented that the proposed particulate 

emission limit, 0.30 lbs/mmBtu for stack S10, does not reflect achievable emission levels 

with the existing fabric filter control system. Further, if this emission limit is maintained, 

then the Department needs to demonstrate this level of emissions results in no significant 

impact to visibility. 

Response: In meeting SO2 mass caps the emissions from the stack S10 boilers, if 

continuing to burn coal fuels, must be controlled by some level of lime injection. In this 

case, particulate loading to the fabric filter system will increase substantially. Therefore 

restricting the system to lower particulate emission levels is likely contrary to visibility 

improvement gained from the SO2 reduction. At a minimum the exact design point for 

particulate loading and emissions versus SO2 control is still to be determined in final 

equipment design. Therefore the Department has concluded it is not appropriate to 

restrict particulate emissions based on actual emissions when particulate loading will be 

changing as a result of another portion of the BART requirement. 

In determining controls for particulate and SO2 emissions, Georgia Pacific will also have 

to consider the pending ICI Boiler MACT emission limitations. Currently the ICI boiler 

MACT is proposing filterable particulate emission limits for coal boilers ranging from 

0.028 to 0.088 lbs/mmbtu. This suggests that the final MACT limits will be more 

stringent than the previously adopted 0.3 lbs/mmbtu total particulate emission limit. 

Because the design load of particulate to the fabric filter related if SO2 control is pending 

and because the MACT particulate requirement is also pending the Department is not 

proposing to further restrict particulate control below the current permitted level. 

5.0 BART Control Levels and Compliance Requirements

Comment 5.1: The Federal Land Managers and Sierra Club commented that a mass cap 

does not represent BART level of control; i.e. the BART control levels are may not be 

achieved while the boilers are operating at low loads. 

Response: The Department maintains that a mass cap is an appropriate mechanism for 

implementing continuous control compliance requirements. Using a mass cap approach 

in meeting continuous emission limit requirements, such as RACT, is established under 

the U.S. EPA policy for economic incentive programs (EIP). The applicability of the 

EIP policy is discussed in the response to comment 6.2. However, the methods used in 

establishing BART mass cap requirements inherently ensure that BART control levels 

or better visibility improvement is achieved in all cases as discussed below. Further, if 

exceeding normal high operating levels, Georgia Pacific must implement higher control 

levels than determined for BART. Also to note here is that the mass cap acts to ensure 

emissions are not simply switched to non-BART boilers. This is compared to an 
8

emission rate approach where total capacity utilization and emissions can exceed the 

proposed BART mass caps. 

 

Establishing mass caps from the baseline year average emissions will ensure ongoing 

overall control levels consistent with BART control. For both SO2 and NOx, emission 

levels for stack S10 remain fairly constant from 2002 to 2010, summarized in the table 

below. This information shows that there has been no extended period of low load 

operation significantly affecting overall operations from year to year. In looking at the 

baseline year average emissions the BART controls result in an average 81% and 72% 

control of SO2 and NOx emissions, respectively. Based actual historic emissions the 

average SO2 control will potentially range from 79% to 82%. A further case is looked 

at where the baseline year average emission rates are multiplied by the low and high 

heat inputs demonstrated for the stack S10 system to further check control sensitivity – 

using the baseline year emission rate would be the same basis as evaluating control 

levels under an emission rate limitation. Here potential control levels range from only 

78% to 82%. This evaluation shows that overall control levels based on normal historic 

operation are likely to be greater as much as less than the BART determined control 

efficiencies. In fact, Georgia Pacific will have to pursue greater reductions they 

increase facility production and steam requirements. These same conclusions hold true 

for the NOx BART control levels. These same conclusions are supported by the most 

recently available data for 2010 which shows required control levels for both SO2 and 

NOx are substantially the same as for BART. 

On a daily basis, Georgia Pacific will have to meet control levels consistent with the 

BART control levels. A chart of stack S10 steam load for stack S10 shows the range 

between high and low loads are very consistent and that daily cycling is consistent as 

well. This supports that there is not one or a few types of load situations where Georgia 

Pacific can significantly curtail load. Basically, the boiler normal operations are 

consistent and therefore reflected by the long term average operations. Therefore the 

mass cap based on average operating levels accounts for the range of demonstrated load 

swings over short periods. Further because of the frequency of operating at both low 

and high loads Georgia Pacific cannot target the curtailment of control equipment 

operation at any one specific level without significant impact. This information 

supports the conclusion that Georgia Pacific will not be able to substantially alter the 

actual efficiency of control equipment or curtail emission reduction measures 

responding to BART on a prolonged basis. 

Ultimately, it is prudent for Georgia Pacific to control at both high and low loads to 

ensure that unplanned or higher production levels than normal can be accommodated as 

needed. However, it is worth evaluating the impact to visibility in the event control 

levels are less than BART. If Georgia Pacific decides to reduce control levels at lower 

loads then reductions must be made up at higher load levels. Since high loads are the 

periods of higher emissions increasing the control efficiency during these periods will 

have the greatest benefit in reducing visibility impacts. At lower loads, the emissions 

have a lower initial visibility impact than at the higher loads. Therefore this potential 

approach to BART controls has greater overall benefit to reducing visibility impacts. 
9

For these reasons combined, the Department maintains that a mass cap ensures a BART 

level of control overall and potentially a higher level of control at the times of greatest 

visibility impact. 

Table. Comparison of Emission Levels and Control Required in Meeting the 12 Month 

Mass Cap. 

12 Month Rolling 

Mass Cap (tons) = 2,340 977

Annual Emissions 

Case During 2002 - 

2010

Tons

Required 

Reduction from 

Mass Cap

Tons

Required 

Reduction from 

Mass Cap

Baseline Year Avg 12,644 81% 3,510 72%

Lowest Actual 11,406 79% 3,273 70%

Highest Actual 13,125 82% 3,656 73%

2010 Actual 12,420 81% 3,406 71%

Low Heat Input 10,731 78% 3,338 71%

High Heat Input 13,262 82% 3,680 73%

SO2 Emissions NOx Emissions

Georgia Pacific Broadway Mill Stack 10

September 2010

300

400

500

600

700

800

900

1

21416181

101121141161181201221241261281301321341361381401421441461481501521541561581601621641661681701

Hour in Month

S10 Boilers Steam K#/HR

Load K#/HR
10

Comment 5.2: U.S. EPA commented that averaging emissions over extended periods, 30 

day and 12 month periods, allows for more stringent emission limits. It is inappropriate 

to allow a 30 day emission limit which is less stringent the BART level of control and 

increased averaging periods typically allow for more stringent emission requirements. 

Response: The control levels used in evaluating BART control options are based on 

long term average reduction levels and not maximum design levels. Further, in several 

cases compliance margins are appropriate for ensuring long term performance and 

appropriate compliance requirements (refer to comment 5.3 for discussion of 

compliance margins). In calculating emission requirements the control efficiencies are 

then placed against the activity level consistent with that averaging period. This 

maintains the stringency of the requirement for each averaging period. Therefore the 

approach used by the Department in identifying control levels and evaluating control 

equipment options is consistent with setting emission limits over 30 day and 12 month 

averaging periods. 

Also in considering emissions averaging periods, the requirement must be measured 

against the targeted purpose in determining if it reflects BART control levels. For 

Georgia Pacific the emission limits are specifically structured to reduce visibility 

impacts at the most critical time (30 day limit) while achieving BART control level on 

an overall basis (12 month). The 30 day rolling mass caps are set to protect visibility at 

times of maximum operation. With the annual mass cap requirement in place the stack 

S10 boiler system cannot be operated for any duration at the level of the 30 day rolling 

mass cap. The table below shows the 12 month rolling mass caps prorated to 30 days. 

Clearly the 12 month requirement is the short-term and long-term driver for overall 

continuous control levels. The 30 day allowable emissions sets at a maximum control 

level that is less than could occur if the operated at maximum capacity even while 

continuously operating BART control equipment. For these reasons the two limitations 

together ensure the implementation of a BART level of control and visibility 

improvement at the most critical times below that which would occur based on an 

emission rate limitation approach. 

Comparison of Mass Cap Requirements on a 30 Day Basis. 

12 month rolling 

mass cap 

12 month mass cap 

prorated to 30 days 

30 day rolling mass 

cap 

SO2 (tons) 2,340 192 268 

NOx (tons) 977 110 80 

Comment 5.3 U.S. EPA questions the use of a compliance margin in determining 

compliance requirements for several control equipment options. The specific control 

options are turbosorp flue gas desulfurization and overfire air (OFA) and regenerative 

selective catalytic reduction (RSCR) as applied to boiler B27. Sierra Club also questions 

the use of any compliance margin in determining compliance requirements. 
11

Response: The Department maintains that consideration of a compliance margin is 

appropriate on a case-by-case basis for the specific control equipment. Specifically, if 

long operating levels are clearly demonstrated by actual emissions data then this 

information can be translated directly into a final control requirement. However, where 

there is some variability to final optimal control levels associated with characteristics of 

each source then some level of compliance margin should be assessed. The 

Department took this approach in applying a low 2% compliance margin for overfire air 

installed to boiler B27 based on actual operating data. Similarly, a 2% compliance 

margin is applied to turbosorp based on variability of actual emissions data. For the 

RSCR, where actual operating data on similar sources is not available, a higher 5% 

compliance margin is applied. Another type of case is where some variability may 

occur in control levels during normal operation of the source. 

Applying a compliance margin is appropriate in these identified cases. As Georgia 

Pacific identified in earlier comment to the Department, the Courts have agreed that 

emission limits cannot be set at the level of reasonably expected control levels. This 

invariably sets a requirement with which the source will be out of compliance based on 

normal variability. 

The compliance margins in the identified cases are equally or more restrictive than 

normally expected compliance margins. U.S. EPA economic incentive program (EIP) 

guidance discusses a 10% compliance margin as a default assumption in accounting 

where sources will operate in meeting an emission requirement. Also a 10% 

compliance margin was applied where appropriate in determining Wisconsin's SIP 

approved NOx RACT emission requirements. The table below shows the percent 

overall compliance margin resulting from applying the individual control. In all cases 

where compliance margins are applied, the overall resulting compliance margins are 

well below 10%. 

Control 

Technology

Operating 

Control

Compliance 

Requirement

Real 

Compliance 

Margin

OFA 52% 50%

RSCR 75% 70%

OFA/RSCR 88% 85% 3%

Turbosorb 95% 93% 2%
12

6.0 SO2 and NOx Emissions Averaging and Trading

Comment 6.1: U.S. EPA commented that setting a compliance requirement for stack S10 

constitutes emissions averaging over both BART and non-BART boilers. Because the 

Regional Haze Rule only addresses emissions averaging between boilers subject to 

BART, emission averaging with non-BART boilers is subject to the Economic Incentive 

Program (EIP) policy and accordingly must demonstrate an environmental benefit (EB). 

The U.S. EPA recommends limiting emissions to 10 percent below the level that would 

be required with unit-by-unit limits. 

Response: The Department agrees that the stack S10 compliance requirement is subject 

to an environmental benefit (EB). The EB is comprised of the mass cap to the stack 

S10 boiler system including a 10% additional reduction applied to the BART boilers. 

The EIP states that a default environmental benefit is the reduction of emissions 10% 

below that level which would result from directly meeting the applicable standards. 

The EIP also states that in cases where the source is not in an area needing and lacking 

an approved attainment demonstration (NALD), the trading program may meet the 

environmental benefit in a variety of ways including an emissions mass cap for single 

source trading3. Because the Georgia Pacific facility is not in a NALD area the 

environmental benefit can be met through either the additional 10% reduction or a mass 

cap. 

The Department agrees that setting a compliance requirement for total stack S10 

emissions is a form of emissions averaging across the BART and non-BART boilers for 

each pollutant. Initially the Department proposed that Georgia Pacific could meet 

BART requirements by demonstrating compliance with only the BART boiler emission 

rate limits or boiler mass caps. The BART requirements are amended where Georgia 

Pacific is required to comply with a mass cap limitation applied to all stack S10 boilers. 

As described in the EIP, a mass cap meets the minimum criteria for a single source 

emissions trading program. However, an additional 10% reduction is applied to the 

residual emissions for boilers B26 and B27 after BART controls. This step is taken to 

meet the State's BART rule trading requirements and in applying a more stringent 

standard for addressing the increased flexibility allowed via inter-pollutant trading (SO2

for NOx) under the alternative compliance option. The application of 10% 

environmental benefit to residual emissions follows the calculations established in the 

EIP, section 7.3(b). 

The EIP considers the mass cap approach an environmental benefit because it 

eliminates any future growth of emissions from all boilers including those with a BART 

limitation. Realistically, for Georgia Pacific to fully utilize boiler capacity under the 

stack S10 system, emission controls will have to exceed those applied in determining 

the NOx and SO2 BART requirements. The EIP states that the mass cap also acts to 

eliminate switching load and emissions to other boilers at a facility. 

 

3

 USEPA, 2001, Improving Air Quality with Economic Incentive Programs, section 4.3 page 51, EPA452/R-01-001, January 2001. 
13

The Department acknowledges that the mass cap is also a measure which contributes to 

meeting haze reasonable progress goals (RPG) for this planning period. Therefore an 

argument may be made that the mass cap should not be counted as an environmental 

benefit if it is counted as a RPG measure or visa versa. The Department maintains that 

the mass cap works to meet both requirements. The mass cap implements the 10% 

added reduction without load switching and acts to limit overall emissions from all 

boilers towards meeting RPG. 

Comment 6.2: U.S. EPA, FLM, and Sierra Club comments assert that a mass cap 

compliance approach will not ensure continuous operation of BART controls. The 

concern is that controls will not have to operate at the BART control efficiencies when 

boilers are operating at low loads. 

Response: The Department maintains that a mass cap is a continuous control 

requirement meeting the test for continuous BART control. First, as previous discussed 

in response to comment 5.1, the control efficiencies and visibility improvement under a 

mass cap will be equivalent to or greater than the result of implementing an emission 

rate requirement for the BART boilers. Second, as discussed here, the EIP policy 

establishes that a mass cap is an acceptable control approach for emission limit 

requirements. In fact, the EIP considers a mass cap to constitute an overall 

environmental benefit compared to an emission rate requirement. 

Under the EIP policy, U.S. EPA clearly encourages use of economic incentive 

programs (emissions averaging, trading, etc...) in meeting Clean Air Act requirements 

for criteria pollutants. EPA also states that the EIP policy applies to programs used by 

states in meeting regional haze requirements – as such the EIP policy applies to 

implementation of BART requirements.4

 

The EIP establishes that a mass cap approach is an appropriate alternative and 

constitutes an environmental benefit in meeting source specific and continuous 

emission rate requirements. The test EPA applies is whether a mass cap will result in 

emission reductions equivalent to those reasonably expected when meeting the 

emission limitation or operating the control equipment continuously. The best example 

of this position is where EPA discusses meeting RACT requirements through an EIP 

program. 

"Your EIP may allow sources subject to RACT to avoid direct application of 

RACT technology [ ]. In doing so, it is important to note that these sources are 

not avoiding the RACT requirements; they are avoiding the direct application of 

RACT technology. The reductions called for by the RACT requirements are 

satisfied through other means.[ ] If your EIP allows sources to avoid the direct 

application of RACT technology, your EIP must ensure that the level of emission 

 

4

 USEPA, 2001, Improving Air Quality with Economic Incentive Programs, section 1.1 page 4, EPA452/R-01-001, January 2001. 
14

reductions resulting from the EIP will be equal to those reductions expected from 

the direct application of RACT"5 

The Department believes that BART is directly comparable to implementing a RACT 

technology program under EIP guidance. 

7.0 SO2 and NOx Inter-Pollutant Trading

Comment 7.1: U.S. EPA and the Federal Land Managers commented that the Haze Rule 

may not support inter-pollutant trading of visibility pre-cursors. 

Response: The Department maintains that inter-pollutant trading is allowed and 

supported by the Haze Rule and other EPA policy documents. Further, that no rule 

provision or Haze Rule supporting document, including the preamble, precludes interpollutant emissions trading. 

In the basic form, the Haze Rule supports the use of emissions averaging and 

alternative compliance options. Under 40 CFR Part 51, Appendix Y, section V, U.S. 

EPA encourages states to allow for emissions averaging on a facility basis: 

"You should consider allowing sources to 'average' emissions across any set of 

BART of BART-eligible emission units within a fenceline, so long as the emission 

reductions from each pollutant being controlled for BART would be equal to those 

reductions that would be obtained by simply controlling each of the BARTeligible units that constitute the BART-eligible source"

This provision clearly addresses the simple case where one pollutant such as NOx is 

being averaged over multiple boilers at the Georgia Pacific facility. To the other end of 

the spectrum, the Haze Rule under 40 CFR part 51.308(e)(2) allows for broader multifacility emissions trading: 

"A State may opt to implement an emissions trading program or alternative 

measure rather than to require sources subject to BART to install, operate, and 

maintain BART. To do so, the State must demonstrate that this emissions trading 

program or other alternative measure will achieve greater reasonable than would 

be achieved through the installation and operation of BART."

This provision describes a program which can be implemented over the entire state and 

can encompass all sources within one or multiple source categories. The primary 

emission requirement of this provision is that any trading program will achieve greater 

reasonable progress in visibility improvement versus meeting BART alone for the 

affected Class I areas. EPA further indicates that visibility improvement should be 

tested for the worst and best 20 percent of days if the geographic distribution of 

 

5

 USEPA, 2001, Improving Air Quality with Economic Incentive Programs, section 16.7 page 239, EPA452/R-01-001, January 2001. 
15

emissions is significantly different than under BART. This modeling would 

demonstrate "greater reasonable progress" if two criteria are met: 

1) Visibility does not decline in any Class I area. 

2) There is an overall improvement in visibility, determined by comparing the 

average differences between BART and the alternative over all Class I areas. 

The Department believes that inter-pollutant trading represents a significant difference 

in the distribution of emissions and therefore subject to these methods for evaluating 

visibility. However, the main point to consider is that none of the Haze Rule trading or 

alternative option criteria directly state or infer a restriction of inter-pollutant visibility 

precursor pollutants. In the contrary, the criteria specifically point to testing overall 

visibility improvement only. Further, the overall provision allows for a trading 

program with significant flexibilities and inherently significant variability in visibility 

impacts at any one time or place. The Department believes that the Georgia Pacific 

inter-pollutant trading / alternative compliance option falls between single pollutant 

emissions averaging and the broad trading program allowed under the Haze Rule. 

Once again at minimum, the Haze Rule does not prohibit inter-pollutant trading co 

The Department believes the U.S. EPA policies for economic incentive programs (EIP) 

and new source emission offsets for particulate matter support the inter-pollutant 

program proposed for Georgia Pacific. Under the EIP policy, EPA encourages the use 

of emissions averaging and trading where it is not otherwise prohibited or addressed 

through the specific applicable pollutant rule. The EIP also specifically states that the 

guidance applies to haze regulations6

. Lastly, the EIP establishes that inter-pollutant 

trading of precursor emissions is allowable7

. The policy is developed with ozone 

precursor trading (NOx and VOC) as the example. Since ozone is regulated to 

primarily address health related impacts this example seems to set the most stringent 

criteria for trading. The Department believes that meeting this ozone trading criteria 

meets all possible constraints of inter-pollutant trading, outside of the haze rule, for 

pollutants regulated for visibility and haze impacts. The EIP indicates in this case that 

air quality modeling must be conducted to establish the correct ratio for inter-precursor 

trades of ozone. Such an analysis and resulting trading ratio has been established for 

the Georgia Pacific inter-pollutant trading / alternative compliance option. 

The U.S. EPA established that inter-pollutant trading is appropriate in netting PM2.5 

offsets for new source review (NSR) requirements8. The guidance directly addresses 

trading SO2 and NOx as precursors for PM2.5 which clearly establishes that EPA 

supports inter-pollutant precursor trading for the same pollutants and particulate 

outcomes which affect visibility. EPA in establishing this policy provided the expected 

 

6

 USEPA, 2001, Improving Air Quality with Economic Incentive Programs, section 1.1 page 4, EPA452/R-01-001, January 2001. 

7

 USEPA, 2001, Improving Air Quality with Economic Incentive Programs, sections 6.2, page 82 and 16.9 

page 243, EPA-452/R-01-001, January 2001. 

8

 U.S. EPA, 2011, Revised Policy to Address Reconsideration of Interpollutant Trading Provisions Fine 

Particles (PM2.5), July 21, 2011, http://www.epa.gov/region07/air/nsr/nsrmemos/pm25trade.pdf.
16

methodology for developing inter-pollutant precursor trading based air quality 

modeling for a specific geographic area and then establishing pollutant trading ratios. 

The Department believes the approach used in establishing inter-pollutant trading for 

Georgia Pacific follows the same methodology outlined by the U.S. EPA for PM2.5 

inter-pollutant trading. 

In conclusion, the Department finds that the exchange of visibility precursor emissions 

through either an inter-pollutant trading program or alternative compliance option is 

allowed and supported for Georgia Pacific in meeting BART requirements. The 

program must, however, meet all applicable criteria under the haze rule and EIP policy. 

As discussed in response to comments the Department believes all EIP criteria are met. 

Comment 7.2: U.S. EPA questions whether any inter-pollutant alternative compliance 

option can allow levels of SO2 and NOx to vary over time; i.e. can Georgia Pacific 

change the amount of SO2 excess emissions traded in lieu of NOx reductions anytime 

into the future. 

Response: The Department believes varying SO2 and NOx levels according to 

constraints which ensure greater visibility improvement than BART is allowable. 

However, the proposed alternative compliance option has been amended such that 

traded emissions will be chosen and fixed into the future. The Department does 

request, however, that U.S. EPA consider allowing an inter-pollutant trading program 

which allows varying SO2 and NOx emission levels tied to the BART mass caps based 

on a 2:1 trading ratio. 

Comment 7.3: U.S. EPA commented that the proposed inter-pollutant trading option 

needs to account for future SO2 requirements because the EIP policy requires emission 

reductions used for emissions averaging or trading to be "surplus" to other federal 

requirements. 

Response: The Haze Rule specifically identifies "surplus" reductions under 40 CFR 

part 52.308(e)(2)(iv) for purposes of a BART emissions trading program or alternative 

compliance option. The provision states: 

"emission reductions resulting from the emissions trading program or other 

alternative measure will be surplus to those reductions resulting from measures 

adopted to meet requirements of the CAA as of the baseline date of the SIP."

In the case of the Haze Rule and BART the "baseline date of the SIP" is the BART 

baseline years 2002 to 2003. 

The Departments understanding of the EIP guidance is that it does not supercede 

specific requirements or criteria specifically addressed by another regulation. Therefore 

emission requirements effective after this time and into the future do not affect the 

identification of "surplus" emissions for purposes of BART. Because the BART 

requirements will reduce both SO2 and NOx to levels below any previous requirement, 
17

including those implemented since the baseline years, the BART mass caps for each 

pollutant set the basis for determining surplus emissions for purposes of the BART 

alternative compliance option. The Departments understanding is that this basis will 

not change into the future based on surplus being defined under the Haze Rule instead 

of the EIP policy. A fixed basis for counting surplus emissions is similar to what occurs 

under the federally implemented programs such as CAIR and CSAPR. 

Comment 7.4: The concern of whether continuous BART control under a mass cap will 

be achieved is further extended to inter-pollutant compliance option where SO2 can be 

traded for NOx. Basically, there is concern that SO2 reductions can be generated such 

that all NOx reduction can be avoided. 

Response: The Department believes that the test for a BART inter-pollutant trading 

program is whether it achieves equivalent visibility improvement whereas SO2 and 

NOx are both visibility precursors. Therefore under the Haze rule, the measure of 

continuous BART control is not the net tons reduction of either SO2 or NOx but rather 

the continuous level of visibility improvement. The Department's analysis shows that a 

preferred alternative for the greatest visibility improvement is to allow minimal NOx 

reductions in lieu of greater SO2 reductions at a trading ratio of 2 SO22 for 1 NOx (refer 

to comment 7.6). 

However, the Department acknowledges the NOx emission reductions have direct 

visibility improvement and for any one day the best visibility improvement may be 

obtained through reducing both NOx and SO2 emissions together. Therefore, the 

alternate compliance option based on inter-pollutant trading includes a minimum NOx 

emission reduction requirement. Accordingly, a NOx emission cap of 1,522 tons on a 

12-month rolling basis and 172 tons on a 30-day rolling basis applies to the stack S10 

system. The mass cap level corresponds to approximately 50% reduction of NOx 

compared to the average baseline year emissions 

7.5 Comment: U.S. EPA questions the validity of modeling versus baseline year 

emissions because it does not account for emission reductions from future regulations and 

resulting atmospheric chemistry conditions. 

Response: The Department believes modeling future unknown regulations for 

evaluating BART or BART alternative compliance options is not appropriate. The 

Haze Rule clearly identifies the BART baseline years of 2002 to 2004 as the basis for 

evaluating BART controls and visibility impacts. Further, in providing for alternative 

compliance options the Haze Rule, 40 CFR part 51.308(e)(2)(iv) establishes that excess 

emissions are to be determined based on regulations or requirements in place during the 

BART baseline years. This further supports that BART is a determination made in time 

which carries forward as is. The requirements do not alter due to other regulations. 

Rather if further emission reductions are needed for visibility improvement this issue is 

addressed in meeting each step of Reasonable Progress Goals (RPG). 
18

In direct response to this comment the Department has found, based on visibility 

modeling for evaluated control options, as emissions are removed from the atmosphere 

the average visibility improvement from BART controls will increase. The Department 

has not identified a scenario where future regulations and the finalized BART 

requirements will result in a negative visibility impact versus the BART level of 

visibility improvement. 

7.6 Comment: U.S. EPA commented that a trading ratio of 2.2:1 (SO2:NOx) is reflected 

in the analysis of visibility equivalency supporting inter-pollutant trading. 

Response: The Department acknowledges an actual trading ratio of 2.2 tons SO2 to 1 

ton was modeled in establishing the inter-pollutant compliance option. This slightly 

higher ratio was an inherent result of the modeling data preparation. Even with this 

difference the Department maintains, based on information discussed below, that a 

trading ratio of 2 SO2 for 1 NOx is appropriate for inter-pollutant compliance 

alternatives at the Georgia Pacific facility. However to support this ratio the 

Department is conducting visibility modeling for the finalized BART compliance 

requirements and trading SO2 for NOx in a 2:1 ratio. The results will be submitted to 

U.S. EPA as supplemental support information the Haze SIP submittal. 

The 2:1 trading ratio is supported by existing modeling results by assessing the 

visibility impact of the 0.2 ratio differential. To do this, the incremental visibility is 

first interpolated based on the results for the model results at trading ratios of 1.1, 2.2, 

and 3.3 SO2 to 1 NOx. These results were initially presented in Table 7.4 of the July 

2011 draft BART determination as Cases 2, 4, and 6, respectively. From this data, as 

shown in the table below, the 0.2 ratio differential results in an impact of 0.02 to 0.053 

deciview based on visibility change between the 1.1 to 2.2 SO2 trading ratios. In 

similar fashion, the visibility impact 0.2 ton ranges from 0.016 to 0.027 deciviews based 

on the change in visibility between the 2.2 to 3.3 ratios. The Department acknowledges 

the visibility impact is not perfectly linear across the trading ratios. However, looking 

at this full range of 1.1. to 3.3 ratios inherently captures how the visibility may change 

with each ton of trade. 

These deciview impact of 0.2 tons SO2 can then be added to the total visibility impact 

result for the 2.2 SO2 trading ratio. This calculation results in the adjusted visibility 

impact of trading at the 2.0 SO2 to 1.0 NOx ratio. As can be seen these adjusted values 

do not exceed the visibility impact for the BART mass caps (w 10% environmental 

benefit). Therefore the Department believes a 2:1 SO2 to NOx trading ratio is supported 

for the Georgia Pacific alternative compliance option. 

 
19

2002 2003 2004

2.56 1.33 2.14

1.1:1 2.8 1.32 2.15

2.2:1 2.51 1.21 1.98

1.1 Ratio Incerment 0.29 0.11 0.17 

0.2 Ratio 0.053 0.020 0.031 

Adjusted 2:1 2.56 1.23 2.01 

2.2:1 2.51 1.21 1.98

3.3:1 2.35 1.12 1.83

1.1 Ratio Incerment 0.16 0.09 0.15 

0.2 Ratio 0.029 0.016 0.027 

Adjusted 2:1 2.54 1.23 2.01 

Trading Ratio 

Adjustment

Trading Ratio 

Adjustment

Maximum Deciview Impact

BART

Trading Ratio Case

7.7 Comment: Georgia Pacific commented that because the trading plan is not BART, 

compliance for the trading plan option should be Dec. 31, 2017 instead of the Dec. 31, 

2015 date for BART. 

Response: WDNR maintains that compliance with BART is Dec. 31, 2015, even under 

a trading plan. 

8.0 Compliance Requirements

Comment 8.1: U.S. EPA commented that the Georgia-Pacific BART requirements must 

be established in a permanent enforceable document. 

Response: The Department agrees. The Georgia Pacific BART requirements are to be 

established in a permanent administrative order. The Department commits to, once the 

contents of the order proposed in this submittal are approved, to submit the finalized 

signed administrative order to U.S. EPA for inclusion to the Haze SIP. 
20

II. Electric Generating Unit (EGU) BART Requirements 

Comment: The National Parks Service commented that Department can either show that 

the proposed BART emission rate limits for the EGUs modeled at maximum actual 

emissions for PM10 have no significant impact on visibility, or propose limits that reflect 

the capability of existing controls. 

Response: The EGUs must implement the Utility MACT emission limitations, finalized 

by EPA in November 2011. The Utility MACT is expected to lower PM10 emission 

limits to below 0.03 Lb/mmBtu by 2015. Combined with the minimal visibility impact 

at the permit emission limits, the Department maintains that no additional emission 

limitation for PM10 is necessary. 
21

Appendix A

Determination of CAIR Applicability Boiler B25 

Georgia Pacific Broadway Mill 
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

WASHINGTON, D.C. 20460 

Kelly L. Wolff 

Vice President - Manufacturing 

Georgia Pacific Corporation 

Green Bay Operations 

1919 South Broadway 

P.O. Box 19130 

Green Bay, WI 54307-9130 

MAY 25 20i1 

OFFICE OF 

AIR AND RADIATION 

Ref CAIR Applicability Determination for Georgia Pacific Corporation, Broadway 

Paper Mill, Boiler B25 located in Green Bay, Wisconsin 

Dear Mr. Wolff: 

This letter is EPA's determination of applicability under the EPA-administered trading 

programs under the Clean Air Interstate Rule (CAIR) and the CAIR Federal Implementation 

Plans (FIN), for Georgia Pacific Corporation's (Georgia Pacific) Broadway Paper Mill Boiler 

B25 in Green Bay, Wisconsin) This applicability determination is in response to Georgia 

Pacific's Jude 1 7 request for an applicability determination for Boiler B25 under the CAIR 

trading programs and supplemental information provided by Georgia Pacific on August 23, 

October 18, and November 1, 2007, February 13, April 4, and June 24, 2008, December 11, 

2009, and March 23, April 22, and November 23, 2010 and February 4, 2011. 2 

Background 

Under the CAIR trading programs for NOx annual and ozone season and SO2 emissions, 

a unit that is a "stationary, fossil-fuel-fired boiler or a stationary, fossil-fuel-fired combustion 

turbine serving at any time, since the later of November 15, 1990 or the start-up of the unit's 

combustion chamber, a generator with nameplate capacity of more than 25 MWe producing 

electricity for sale" is generally a CAIR NOx, CAIR SO2, and CAIR NOx Ozone Season unit 

subject to the requirements of the trading programs. 40 CFR 97.104(a) (1), 97.204(a) (1), and 

1On October 16, 2007, EPA approved Wisconsin's State Implementation Plan (SIP) in part and 

disapproved in part. 72 Fed. Reg. 58542 (Oct. 16, 2007). By its approval of the SIP as an 

abbreviated SIP, EPA approved the methodology to be used to allocate NOx annual and ozone 

season allowances under the CAIR FIPs, except for allowances in the compliance supplement 

pool. The CAIR FIPs, with these approved modifications, are applicable to Wisconsin sources. 

2Georgia Pacific also submitted several petitions under 40 CFR 97.175 and 97.375 requesting 

extensions of time for meeting the requirements, under the CAIR FIPs, that Georgia Pacific 

install and certify continuous emission monitoring systems (CEMS) at Boiler 25. EPA's latest 

approval of such a petition was on September 30, 2010. 

1 

Internet Address (URA.) • http://wmv.epagov 

Recycled/Recyclable • Printed wNn Vegetable ON Based inks on Recycled Paper (Minimum 30% Postconsurner) 
97.304(a) (1). However, certain units meeting these criteria are exempt from being CAIR NOx, 

CAIR SO2, or CAIR NOx Ozone Season units. For example, any unit meeting the following 

criteria is exempt from the CAIR trading programs: 

(A) Qualifying as a cogeneration unit during the 12-month period starting on the 

date the unit first produces electricity and continuing to qualify as a cogeneration unit; 

and 

(B) Not serving at any time, since the later of November 15, 1990 or the start-up 

of the unit's combustion chamber, a generator with nameplate capacity of more than 25 

MWe supplying in any calendar year more than one-third of the unit's potential electric 

output capacity or 219,000 MWh, whichever is greater, to any utility power distribution 

system for sale. 

40 CFR 97.104(b)(1)(i), 97.204(b)(1)(i), and 97.304(bX1)(i).(These provisions are generally 

referred to as the "cogeneration unit" exemption.) 

Under CAIR a cogeneration unit is defined as: 

a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine: 

(1) Having equipment used to produce electricity and useful thermal energy for 

industrial or commercial, heating, or cooling purposes through the sequential use of 

energy; and 

(2) Producing during the 12-month period starting on the date the unit first 

produces electricity and during any calendar year after the calendar year in which the unit 

first produces electricity — 

(i) For a topping-cycle cogeneration unit, 

(A) Useful thermal energy not less than 5 percent of total energy output; and 

(B) Useful power that, when added to one-half of useful thermal energy produced, 

is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 

percent or more of total energy output, or not less than 45 percent of total energy input, if 

useful thermal energy produced is less than 15 percent of total energy output. 

(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 

percent of total energy input; 

(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of 

this definition shall equal the unit's total energy input from all fuel except biomass if the 

unit is a boiler. 

See 40 CFR 97.102, 97.202, and 97.302 (definition of "cogeneration unit"). 

Georgia Pacific operates five coal-fired boilers at the Broadway Paper Mill, Boilers B25, 

B26, B27, B28, and B29 with maximum design heat input capacities of 200 mmBtu/hr, 350 

mmBtu/hr, 615 mmBtu/hr, 250 mmBtu/hr, and 486 mmBtu/hr respectively. These boilers 

provide steam to a common header, which distributes steam (at 400 psi) to the mill processes and 

to five steam turbine/ generator combinations with nameplate capacities of 10.0, 17.3, 18.7, 28.9, 

2 
43.2, and 28.2 MWe respectively, from which steam is drawn at several different points and 

pressures (e.g., at 35, 135, and 400 psi) and distributed to the mill for processes and heating and 

which produce electricity. See August 23, 2007, June 24, 2008, December 11, 2009, and 

November 23, 2010 supplemental information. According to Georgia-Pacific, the Broadway 

Paper Mill initially used its on-site boilers to produce only steam and met all on-site processing 

and heating needs but, since at least 1954, used some of the steam to generate electricity, as well, 

for on-site use. Since at least 1980, on-site boilers have met all of the mill's steam and electricity 

needs. See November 23, 2010 supplemental information (response 1). In 1990, the mill began 

supplying some of the generated electricity for sale, through a 10,000 kW tie line, to a utility 

distribution system, i.e., a portion of an electricity grid owned or operated by a utility (Wisconsin 

Public Service Corporation). The capacity of the tie line was increased to 25,000 kW in 1999. 

See id. (response 2); and 40 CFR 97.102, 97.202, and 97.302 (definition of "utility power 

distribution system"). 

According to Georgia Pacific, each of the five boilers produces electricity and useful 

thermal energy for industrial purposes through sequential use of energy and is a topping-cycle 

unit. See 40 CFR 97.102, 97.202, and 97.302 (definitions of "cogeneration unit" and "topping 

cycle cogeneration unit"). Further, Georgia Pacific asserted that the overall efficiency of the 

system of on-site boilers and steam turbine/generators (all of which are on a common steam 

header) meets the efficiency requirement, and that the system and each individual boiler meet the 

sales limitation requirement, for the exemption from the CAIR trading programs for 

cogeneration units under 40 CFR 97.104(b)(1)(i), 97.204(b)(1)(i), and 97.304(b)(1)(i). 

Georgia Pacific provided calculations for 2005 through 2009 that used the steam 

contribution (in mmBtus) measured at each of the five boilers as a percentage of total steam 

contribution by the group of all five boilers to apportion to each individual boiler the total useful 

power and total useful thermal energy produced by the system (i.e., five boilers serving five 

steam turbine/generators). In its calculations, Georgia Pacific also used fuel sampling data on 

theleat input per ton for the types of coal combusted in the boilers and data on the tons of coal 

combusted in each boiler to calculate annual energy input for each boiler. Georgia Pacific then 

calculated annual efficiency for each individual boiler by adding the useful power produced to 

one-half of the useful thermal energy produced and dividing the result by the energy input. 

Based on this calculation, all the boilers except Boiler B25 met the efficiency requirement for the 

cogeneration unit exemption. Georgia Pacific also calculated annual efficiency for the entire 

system by adding total useful power produced by the system to one-half of total useful thermal 

energy produced by the system and dividing the result by total energy input for the system. 

Based on that calculation, the entire system, and thus all five boilers in the system, met the 

efficiency requirement. See August 23, 2007 and April 22, 2010 supplemental information. 

According to Georgia Pacific, calculating the efficiency of each boiler or the efficiency of 

the system requires the calculation of useful thermal energy produced, which, in turn, requires 

data on the amounts and pressure of the steam provided from the boilers and the steam turbine/ 

generators for mill processing and heating. Georgia Pacific stated that it does not have data on 

steam drawn before 2005 from the steam turbine/generators and that therefore it is unable to 

3 
produce even "reasonable estimates" of the efficiency of the boilers before 2005. March 23, 

2010 supplemental information; see also November 23, 2010 supplemental information. , According Georgia-Pacific, the total amount of useful thermal energy provided from the boilers 

and steam turbine/generators was higher before 2005 because of steam reduction projects that 

starting in 2005 reduced the steam processing needs of the mill. Id. 

• 

Georgia Pacific requested that, using one of the following approaches, EPA determine 

that Boiler B25 is not subject to the CAIR trading programs: 

1) Approve use of the overall annual efficiency of the system at the Broadway Paper 

Mill, comprising all five boilers on a common steam header that serves five 

turbine/generator combinations and supplies process steam, to determine whether 

Boiler B25 and the other boilers qualify for the exemption for cogeneration units 

under the CAIR trading programs; or 

2) Establishing, and applying to Boiler B25, a new exemption from the CAIR trading 

programs for boilers serving a common header that are incapable of individually 

providing enough steam to a steam turbine/generator combination to generate at least 

25 MWe without additional steam from some other unit or source? 

EPA's Determination 

As discussed above, according to Georgia Pacific, each of the five boilers at the 

Broadway Paper Mill serves at least one generator with a nameplate capacity greater than 25 

MWe producing electricity for sale. Each boiler is therefore subject to the CAIR trading 

programs unless it qualifies for the cogeneration unit exemption. See 40 CFR 97.104(a)Orand 

(b)(1)(i), 97.204(a)(1) and (b)(1)(i), and 97.304(a)(1) and (bX1)(i). As discussed above, in order 

to be a cogeneration unit, each boiler must -- during the 12-month period starting on the date the 

boiler first produces electricity and thereafter -- have the equipment to produce electricity, and 

useful thermal energy for industrial or commercial, heating, or cooling purposes, through 

sequential use of energy. Further, because each boiler is a topping-cycle unit in that it produces 

first electricity and then useful thermal energy' s, the remaining requirements for qualification for 

3In its request, Georgia Pacific only requested a determination of applicability of the CAIR 

NOx annual and NOx ozone season trading programs, ostensibly because the initial control 

periods for these programs arein 2009 while the initial control period for the CAIR SO2 trading 

program is in 2010. However, the applicability provisions relevant to Boiler 25, and the 

provisions for cogeneration units in particular, are identical in all three trading programs. 

Accordingly, if a unit qualifies for the exemption for certain cogeneration units under any of 

these trading programs, the unit qualifies for the exemption under all three trading programs. 

EPA is therefore extending, sua sponte, its applicability determination for Boiler 25 to cover all 

three CAIR trading programs. 

4 
the cogeneration unit exemption concerning the five boilers are that: (i) during the 12-month 

period starting on the date the boiler first produced electricity and each calendar year thereafter, 

useful thermal energy equal not less than 5 percent of total energy output and useful power that, 

when added to one-half of useful thermal energy produced, equal not less than 42.5 percent of 

total energy input; and (ii) starting November 15, 1990, the generators served by the boilers not 

prolluce more than one-third of the unit's potential electric output capacity or 219,000 MWh, 

whichever is greater, to any utility power distribution system for sale. 

EPA determines that -- based on boiler performance data for 2005 through 2009 and 

electricity sales data from 1999 through 2009 and conditioned on the accuracy and completeness 

of certain assumptions about boiler performance before 2005 -- Boiler B25 qualifies for the 

cogeneration unit exemption, and is not covered by the CAIR trading programs, up through 

2009. Further, EPA concludes that a new exemption (i.e., for any boiler that cannot produce 

enough steam to generate more than 25 MWe without additional steam from another unit) from 

the CAIR trading programs cannot be established, through this applicability determination. 

A. Cogeneration Unit Exemption 

As discussed above, in order to be a cogeneration unit, a unit must be fossil-fuel-fired and 

-- during the 12-month period starting on the date the unit first produces electricity and thereafter 

-- have the equipment to produce electricity, and useful thermal energy for industrial or 

commercial, heating, or cooling purposes, through sequential use of energy. Georgia Pacific 

stated that it believes that each of the boilers at the Broadway Paper Mill was designed for 

cogeneration and has been consistently used as a cogeneration unit since installation of the 

steamturbine/ generators in to order provide steam and electricity for the mill. See November 

23, 2010 supplemental information (response 5). 

Moreover, EPA's requirement that a unit has equipment to produce electricity and useful 

thermal energy using sequential use of energy is analogous to the sequential-use-of-energy 

requirement in the definition of "cogeneration facility" adopted by the Federal Energy 

Regulatory Commission (FERC) and reflected in FERC's decisions about whether facilities are 

"qualifying cogeneration facilities". Compare 40 CFR 97.102, 97.202, and 97.302 (paragraph 

(2)(k) for the definition of "cogeneration unit") with 18 CFR 292.202(c) (definition of 

"cogeneration facility). Applying the same criterion as EPA of sequential use of energy to 

produce electricity and useful thermal energy (as well as other ownership, operating, and 

efficiency requirements), FERC approved certification of the Broadway mill (then owned by 

Fort Howard Corporation) as a qualifying cogeneration facility on June 8, 1990. See Fort 

Howard Co •. Small Power Production and Co eneration Facilities -- • uali in Status, 51 

FERC ¶62,223 (Je. 8, 1990) (holding that the mill, then comprising 6 boilers and 9 steam 

turbine/generators, was a "topping-cycle cogeneration facility"). There is no indication that this 

certification was ever subsequently terminated. For the period before the issuance of FERC's 

certification approval, EPA assumes, based on the information provided by Georgia Pacific and 

4 See 40 CFR 97.102, 97.202, and 97.302 (definitions of "topping cycle cogeneration unit"). 
solely for purposes of this determination, that each boiler at the Broadway Paper Mill has 

consistently operated as a cogeneration unit since the boiler's commencement of electricity 

generation up to the issuance date of the FERC approval. 

In addition, a unit that is a topping-cycle unit, like Boiler B25, must -- during the 12- 

month period starting on the date the unit first produces electricity and each calendar year 

thereafter -- meet the requirement of producing useful thermal energy equal to not less than 5 

percent of total energy output and producing useful power that, when added to one-half of useful 

thermal energy produced, equal at least 42.5 percent of total energy input. 

Georgia Pacific provided data for 2005 through 2009, during which period all five boilers 

operated, except for Boiler B25 in 2009. That data indicated that, for each year, both the system 

(including five boilers and five turbine/generator combinations) and each boiler alone -- except 

Boiler B25 in 2009 -- produced useful thermal energy well in excess of the minimum of 5 

percent of total energy output, i.e., ranging from 49.1 to 53.9 % on a system wide basis and from 

48.8 to 56.7 % on an individual-boiler basis. The data also indicated that, for each year, the 

system produced useful power that, when added to one-half of useful thermal energy produced 

by the system, was in excess of the minimum of 42.5 percent of total energy input for the system, 

i.e., ranging from 47.4 % to 48.4 %. Further, the data showed that Boiler B25 alone did not 

meet this latter efficiency requirement on an individual-boiler basis, having an efficiency of 36 

% for 2005, 34.1 % for 2006, 37.1 % for 2007, and 35.2% for 2008 and no efficiency percentage 

value for 2009, when the unit did not operate. See August 23, 2007 and April 22, 2010 

supplemental information. 

EPA has reviewed Georgia Pacific's efficiency calculations for the units at the Broadway 

Paper Mill. Based on this review, EPA finds that, given the configuration and operational 

conditions unique to the Broadway Paper Mill, i.e., where five boilers feed five 

turbine/generators through a common header, one boiler is used as a swing boiler to reduce the 

effects of variability of load and capacity availability on the other boilers, process steam is 

extracted from the common header and from the five turbines, and the turbines power five 

electricity generators, it is not feasible to calculate, with any reasonable accuracy, the individual 

boiler efficiencies for this facility. 

The accuracy of the efficiency calculation for Boiler B25 depends on the ability to 

accurately calculate the efficiency of that boiler separately from the efficiency of the other 

boilers in the system. As explained by Georgia Pacific, Boilers B27 and B29 are used as base 

load units for steam demand at the Broadway Mill, and the use of Boilers B26 and B28 is 

adjusted to follow steam demand. However, Boiler B25 is the first boiler whose use is adjusted 

to steam demand changes and boiler maintenance outages, i.e., is used as a swing boiler to 

address variability in steam demand and availability of steam production capacity. In those 

circumstances, Boiler B25 is used in lieu of or before starting up one of the other larger boilers. 

Between scheduled outages in the spring, Boiler B25 is generally kept in operation to avoid 

mechanical problems associated with cycling the boiler. The net result of this type of boiler use 

is that Boiler B25 has more frequent startups and shutdowns, and shorter run periods, than the 

6 
other boilers. See July 1, 2007 request; and June 24, 2008 supplemental information. Because a 

boiler tends to be less efficient during startup and shutdown and more efficient when operating 

for periods of time at a relatively constant load, Boiler B25's calculated efficiency is lower than 

that of the other boilers in the system, but, by operating in this less efficient mode, Boiler 25 

enables the other boilers generally to operate more efficiently. 5Id.; see also Wayne, C. Turner, 

Energy Management Handbook at 109 (5th ed. 2005) (explaining that "boilers generally operate 

most efficiently at 65 to 85% full-load rating", "[n]ewer units and units with higher capacity are 

generally more efficient than are older, smaller units", and "[g]enerally, steam plant load swings 

should be taken in the smallest and least efficient unit"). In short, calculating the efficiency of 

Boller B25 alone ignores the effect of Boiler B25 on the efficiency of the other boilers and 

thereby effectively understates the efficiency that results from operating Boiler B25. 

For this reason, EPA finds that it is not feasible to calculate, with any reasonable 

accuracy, the individual boiler efficiencies for this facility and that, for 2005 through 2009, all 

five boilers, viewed together, met the efficiency requirements for cogeneration units. Georgia 

Pacific stated that it believes that the boilers were operated in essentially the same manner before 

2005 (i.e., as cogeneration units for providing steam and heating, and, starting at least in 1984, 

electricity, for the mill) as during and after 2005. See November 23, 2010 supplemental 

information (response 5). Under these circumstances, with regard to each year from boiler startup through 2004, EPA assumes, solely for purposes of this determination, that the boilers at the 

Broadway Paper Mill have been operated in generally the same manner as they are currently 

operated and that the boilers, viewed together, have met the efficiency and operating 

requirements for a cogeneration unit. See 40 CFR 97.102, 97.202, and 97.302 (setting forth, 

paragraphs (2)(i)(A) and (B), standards for topping-cycle units in definition of "cogeneration 

unit"). 

In addition, EPA finds that the electricity sales limit applicable to Boiler B25 in order to 

qualify for the cogeneration unit exemption is 219,000 MWh because that figure is higher than 

one-third of the unit's potential electric output capacity. Based on Boiler B25's maximum 

design heat input of 200 mmBtu/hr, one-third of the unit's potential electric output capacity is 

56,940 M‘Vh, which is not greater than 219,000 MWh. Georgia Pacific explained that, until 

5However, the full impact of Boiler B25 on the other boilers' efficiency is somewhat more 

complex. According to Georgia Pacific, when Boiler B25 is used instead of increasing load at 

Boilers B26 and B28, the load, and thus the efficiency, of the latter two boilers at those times is 

somewhat lower. See June 24 supplemental information. Determining the efficiency of all five 

boilers together allows for such efficiency interactions to be reflected in the efficiency 

determination. 

6Potential electrical output capacity for a unit is calculated by dividing the maximum design 

heat input capacity in Btu/hr of the unit by 3 (reflecting the assumed efficiency of the unit), 

dividing again by 3,413 (reflecting the assumed heat rate), dividing again by 1,000 (converting to 

MWe), and multiplying by 8,760 (hours per year). See 40 CFR 97.102, 97.202, and 97.302 

(definition of "potential electrical output capacity"). 
1999, the Broadway Paper Mill had a 10,000 kW utility tie line, which, even if used every hour 

to its maximum capacity, could not carry more than about 88,000 KWh per year. While the 

utility tie line capacity was increased to 25,000 kW in 1999, Georgia Pacific provided data on 

electricity sales for the Broadway Paper Mill for 1999 through 2009. According to Georgia 

Pacific, total annual electricity sold during 1999 through 2009 never exceeded 219,000 MWh 

and generally was significantly lower, ranging from less than 1% to about 21 %. November 23, 

2010 supplemental information. Boiler B25's proportional share of the total annual electricity 

generation by the five generators was, of course, less than the total generation sold by the facility 

and comprised an even lower percentage of the 219,000 MWe sales limit. ? 

EPA therefore concludes that, up through 2009 and conditioned on the accuracy of the 

assumptions about the Broadway Paper Mill's boiler operation before June 8, 1990, Boiler B25 

at Georgia Pacific's Broadway Paper Mill qualifies as a cogeneration unit and meets the 

requirements for the cogeneration unit exemption from the CAIR trading programs. Because 

EPA has no data on operations and electricity sales for the Broadway Paper Mill for 2010 and 

later, EPA is not determining whether Boiler B25 is exempt for any year after 2009. 

B. Exemption for Low Capacity Boilers 

Georgia Pacific requested that EPA consider alternate rule language exempting small 

boilers that are incapable of providing enough steam on their own to support a 25 MWe steam 

turbine/generator combination (Georgia Pacific's method 2). EPA rejects this argument because 

40 CFR 97.104, 97.204, and 97.304 specifically state that CAIR applies to fossil-fuel fired 

boilers that serve a generator over 25 MWe are CAIR units. The CAIR applicability provisions 

do not differentiate between single boilers or groups of boilers serving the generator over 25 

MWe nor do they make any distinctions based on the boiler capacity or steam output. 

Further, EPA considers Georgia Pacific's argument as a request that the Agency amend 

the CAIR FIP, to create a new exemption from the CAIR requirements. First, EPA promulgated 

the CAIR FIP as a final rule on April 28, 2006, after providing public hearing and opportunity 

for submission of comments, as a final rule on April 28, 2006. EPA cannot, in the context of 

applying the applicability provisions of the EPA-administered trading programs (including the 

CAIR FIP trading programs) amend the applicability provisions of the CAIR FIP to create new 

exemptions. The time for parties to request new exemptions was during the rulemaking process 

for the CAIR FIP, thus affording all interested parties where parties requesting or opposing new 

exemptions would have had the opportunity to comment. 

7 In applying the electricity sales limit, EPA interprets the limit as applying to the total amount of 

electricity produced by all generators served by the unit -- whether the unit serves one generator 

or multiple generators -- and attributable to the steam produced by the unit for such generators. 

Otherwise, a unit providing steam to multiple generators would have a different electricity sales 

limit than a unit with the same maximum design heat input capacity providing the same amount 

of steam but to only one generator. 

8 
Sincerely, 

am Napolitano, Director 

Clean Air Markets Division 

Second, under CAIR, a State that wants to participate in the EPA-administered trading 

programs must adopt rules that -- except for a few, allowed differences — are substantively 

identical to the CAIR model rules. Those model rules include the applicability provisions (in 40 

CFR 96.104, 96.204, and 96.304) that lack an exemption for non-cogeneration units based on 

unit size. See, 40 CFR 51.123(0(2) and (aaX2) and 51.124(0(2). The differences that States 

participating in the EPA-administered trading programs are allowed to adopt in CAIR SIPs do 

not include the creation of small unit exemptions from the applicability provisions. See 40 CFR 

51.123(0(2) and (aa)(2) and 51.124(02). Therefore, under CAIR, Wisconsin cannot create a 

new small unit exemption through a CAIR SIP revision and still participate in the EPAadministered trading programs. 

NODAObjection 

On August 4, 2006, EPA published a Notice of Data Availability for EGU NOx Annual 

and NOx Ozone Season Allocations for the Clean Air Interstate Rule Federal Implementation 

Plan Trading Programs (NODA) (71 FR 44283 (Aug. 4, 2006)). The NODA did not provide 

any allowance allocations for Boiler 25. Georgia Pacific stated that it objected to the lack of 

allocations if EPA determined that the unit was subject to the CAIR trading programs. Because 

EPA has determined that Boiler B25 meets the cogeneration unit exemption up through 2009 for 

reasons explained above, Georgia Pacific's objection to the NODA is moot. 

Conclusion 

EPA's determination is conditioned on the above-described assumptions about the 

Broadway Paper Mill's boiler operation and relies on the accuracy and completeness of the 

information provided by Georgia Pacific in the June 1, 2007 request for an applicability 

determination for Boiler B25 under the CAIR trading programs and supplemental submissions 

by Georgia Pacific on August 23, October 18, and November 1, 2007, February 13, April 4, and 

June 24, 2008, December 11, 2009, and March 23, April 22, and November 23, 2010 and 

February 4, 2011. The determination is appealable under 40 CFR part 78. If you have any 

questions regarding this determination, please contact Louis Nichols at (202) 343-9008. Thank 

you for your continued cooperation. 

cc: Constantine Blathras, EPA Region 5 

Andy Seeber, WDNR