# A TTACHMENT 

# 9Public 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 207Green 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 ChiefMailed 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 

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,• • .• • .•

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 f 

# 3 it oki, at) 1 this

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 54305-3600Paul 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 54307-9055Mike 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

Wisconsin State Journal PWSJ 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.

# A TTACHMENT 

# 10BEFORE 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 visibilityof 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, SecretarySTATE 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 dulyprepaid 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 C 

### iA./: ■ 

### _, day of 

# a xiiv o, apONSIN 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 sectionWith a restate

anto any irna Class I area ess towards man-Made identifiedcitify subregional air poll
?loco to The Clean Air •Act 169A(b)(2)* * siding l isted 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. Thiadocument WiscOnsin's 'fulfillment of SIP requirements established by the rule for of remedying and

Mass protecting ,federal I areas. includes

able Wisconsin's strategy rrson i 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 alteThativefor 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-

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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 :N a n for is affal n ; 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 Av ailable Retrofit Control program according to 40 CFR part 51.308(e) of the Federal Regi onal Haze Rule. The Department initially proposed BART requirements for public comment in June of 2010. Based on received comment and analysis, the Department re-p roposed BART requirements in July of 2010 for public comment. On the re-proposed BA RT the Department received comment from Georgia Pacific, U.S. Forest Service, Na tional Parks Service, U. S EPA, and joint
comment from Sierra Club and the Midwes t Environment Defense Center. This document comprises the Department's respons e 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 Nationa l 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 ca lculating baseline emissions should
reflect boilers “shut down” of boile rs B24 and B25 with zero emissions.

Response : The Department agrees that boiler B2 4 should not be incl uded in calculating a mass cap requirement. Georgia Pacific bega n 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 th e 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 pe nding a review by U.S. EPA for determining CAIR applicability. In May 2, 2011, U.S. EP A provided a determination, appendix A, that boiler B25 is not subject to CAIR. Therefore this boile r is no longer restricted in operation.

The Department believes using operation during the BART baseline years is representative of bo iler B25 returned status to fu ll allowable operation. This is supported by looking at the tota l heat input for the stack S 10 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 sw itched to the ot her 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 the2 consistent approach for reflecting operation of all affected boilers, including B25, is the use of the baseline years em ission and operation data.

Comment 1.2: The U.S. EPA, Federal Land Manage rs, and Sierra Club commented that
baseline SO 2 emissions should not be calculated us ing a design fuel but rather reflect
actual historic emission levels.

Response : The Department agrees. The finaliz ed baseline emissi ons reflect actual historic emission levels during the BART baseline years of 2002 to 2004. Specifically, the 12 month rolling mass cap is calculate d using the three year average of SO 2 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 SO 2 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 inpu t 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 emissi ons; 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 histor ic fuels and operation.

Response: The Department concurs and evaluate d 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 a ffect the combustion and necessary slagging characteristics of the cyclone furnace. Th erefore, 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% capac ity utilization of the stack S10 boiler system. The U.S. EPA commented th at 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-d ay average mass cap be calculated using historic operating levels which occurr ed during the BART baseline years.

Response : The Department agrees and is amending the 30 day rolling mass cap calculation to reflect historic operating le vels. The mass cap now reflects the maximum 30 day heat input demonstrated for stack S 10 system (excluding bo iler B24) during the BART baseline years. This maximum 30 day heat input is then multiplied by the3 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 appl ying BART control levels. The proposed 30 day mass cap is also less than would occu r 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 asse ssing BART control op tions. 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 mont h rolling mass cap. The 12 month rolling cap is the driver for meeting the BART cont rols on a long-term basis while the 30 day rolling mass cap ensures visibility im pacts 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 Ma nagers commented that 95% control efficiency for the flue gas desulfurization eq uipment accounts for necessary variability in control levels and the Department applying a 2% compliance margin in determining a 93% control compliance requirement double coun ts any needed adjustment for control variability. Sierra Cl ub commented that a SO 2 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 su b-category (CFB). In evaluating BART
for SO 2 at Georgia-Pacific, Department maintain s that it is necessary to consider the weight of evidence for the spray-dryer cate gory as a whole, not limiting the evaluation to just CFB or Turbosorp in particular. Th e 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 sin ce 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, wi th taking coke out, the inlet at GP becomes 3.0 Lb/mmBtu, whereas the tes ting at Greenidge Unit 4 was 3.6 Lb/mmBtu on average. For these reasons, it is questionable to use Tu rbosorp 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 SO 2 control level of 93% on boilers B26 and B27 co mbined with removal of coke. The total
control level on boilers B26 a nd 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 the4 Department is aware. North Dakota dism issed 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 SO 2 Control Manual. Also, the Cross-State Air Pollution Ru le (which is proposed as equivalent to BART for BART-subject utilities) ap plies 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 findi ng the Department proposed an operating NOx control efficiency of 75% for RSCR a nd applied a 70% reduction in allowing for a compliance margin and determining final compliance requirements. The Department
continues to believe these control leve ls 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 hi gher 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, sma ll 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 pp mdv 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 conseque nce of the RSCR needs to be considered further in setting final control levels.

Since the initial BART assessment, Ba bcock Power provided a ROM equipment estimate for applying RSCR to the Georgia Pa cific stack S10 boiler system. In that estimate Babcock Power stated a design contro l 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 s lip is likely to occur. Because ammonia can contribute to particulate and visibility issues allowi ng for further minimization of ammonia slip closer to traditional SCR le vels may be warranted. The Department considers this a secondary factor in evalua ting appropriate compliance margins. Actual operation in meeting the current proposed 70% compliance requirement is assumed to5 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% contro l efficiency level which the Department further confirmed w ith Babcock Power as an appropriate long term control level for RSCR applied to a coal fired unit 1 . The Department then applied a compliance margin in determining the final compliance requirement. In this case the compliance margin may allow for further redu ced 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 successfu lly 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. Therefor e, without actual operating data on similar sources the Department believes allowing fo r a 5% compliance margin is appropriate under the Georgia Pacific BART determination.

Comment 3.2 The Department proposed in th e 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 requiremen ts. This finding is based on both the physical equipment configuration and resul ting high cost of applying RSCR to boiler B26. As a note - one of the original con cerns described in the 2011 BART finding for applying RSCR to boiler B26 was the potential for high SO 2 concentrations in the flue gas which could result in SO 3 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 th e 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 duc t exits from each fabric filter out of the building and enter opposite sides of the flue st ack. 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 se parate ducts. Therefore the default configuration is to place tw o separate RSCR units – one on each flue duct. The previous discussion further identified th at 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 th e control of boiler B26 requires a RSCR be placed on the
second flue duct between the fabr ic filter and stack. The cost of this unit is then placed

1 Babcock Power, personal communication6 against the flow rate and emissions equivalent of boiler B26 2 . In looking the RSCR based control options the highest control leve l is achieved by overfire air and flue gas recirculation on the boiler followed by th e RSCR control (OFA/FGR/RSCR). This configuration results in a 0.11 deciview im provement 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 capita l cost of the RSCR based sy stem 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 add itional 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 marg in 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 th e 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 a nd further information. Since that time the Department evaluated historic emissi ons 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 be lieved to represent best operational levels for reducing NOx emissions while under opt imal combustion efficiency conditions. Although, 60% control efficiency is techni cally achievable it may come at the expense of poor combustion characteristics and increased emissions of incomplete combustion such as carbon monoxide, dioxi ns and furans. Under the currently proposed ICI MACT regulation, these hazar dous pollutants are to be controlled through good combustion practices. The Depa rtment believes an overfire air control efficiency should not be set that potentially works agains t 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 fo r overfire air control levels applied to cyclone bo ilers under these constraints. Reviewing emissions data for Nelson Dewey's two cyclone boilers de monstrates 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 se t 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, do es 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 SO 2 mass caps the emissions from the stack S10 boilers, if continuing to burn coal fuels, must be contro lled 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 li kely contrary to visibility improvement gained from the SO 2 reduction. At a minimum the exact design point for particulate loading and emissions versus SO2 c ontrol 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 particul ate loading will be changing as a result of another portion of the BART requirement.

In determining controls for particulate and SO 2 emissions, Georgia Pacific will also have to consider the pending ICI Boiler MACT emi ssion limitations. Currently the ICI boiler MACT is proposing filterable particulate em ission 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 previous ly adopted 0.3 lbs/mmbtu total particulate emission limit.

Because the design load of particulat e to the fabric filter related if SO 2 control is pending and because the MACT particulate requirement is also pending the Department is not proposing to further restrict particulate c ontrol 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 ar e operating at low loads.

Response: The Department maintains that a ma ss cap is an appropriate mechanism for implementing continuous control compliance re quirements. 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 prog rams (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 inhe rently 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 not e here is that the mass cap acts to ensure emissions are not simply switched to non-BA RT boilers. This is compared to an8 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 SO 2 and NOx, emission levels for stack S10 remain fairly consta nt 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 c ontrols result in an average 81% and 72%
control of SO 2 and NOx emissions, respectively. Ba sed actual historic emissions the average SO 2 control will potentially range from 79 % to 82%. A further case is looked at where the baseline year average emi ssion rates are multiplied by the low and high heat inputs demonstrated for the stack S10 sy stem to further check control sensitivity – using the baseline year emissi on 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 overa ll 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 w ill have to pursue greater reductions they increase facility production and steam requireme nts. 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 s hows required control levels for both SO 2 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 char t of stack S10 steam load fo r stack S10 shows the range between high and low loads are very consistent and that daily cycli ng 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 l ong term average operations. Therefore the mass cap based on average operating levels acco unts 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 Geor gia 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 Pacifi c 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 Pacifi c decides to reduce control levels at lower loads then reductions must be made up at hi gher 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 ove rall 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 highe r 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 900121416181101121141161181201221241261281301321341361381401421441461481501521541561581601621641661681701

Hour in Month S10 Boilers Steam K#/HR Load K#/HR10 Comment 5.2: U.S. EPA commented that averagi ng emissions over extended periods, 30 day and 12 month periods, allows for more stri ngent 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 evalua ting BART control options are based on long term average reduction levels and not ma ximum design levels. Further, in several cases compliance margins are appropriate for ensuring long term performance and appropriate compliance requirements (refe r to comment 5.3 for discussion of compliance margins). In calculating emissi on requirements the control efficiencies are then placed against the activity level consis tent with that averaging period. This maintains the stringency of the requirement for each averaging period. Therefore the approach used by the Department in identif ying control levels a nd evaluating control equipment options is consistent with sett ing emission limits over 30 day and 12 month averaging periods.

Also in considering emissions averaging pe riods, the requirement must be measured against the targeted purpose in determini ng if it reflects BART control levels. For Georgia Pacific the emission limits are specif ically 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 rolli ng mass caps are set to pr otect visibility at times of maximum operation. With the annua l 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 s hort-term and long-term driver for overall
continuous control levels. Th e 30 day allowable emissions sets at a maximum control
level that is less than could occur if th e operated at maximum capacity even while continuously operating BART control equipmen t. 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 Requi rements 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 desulfuriza tion and overfire air (OFA) and regenerative selective catalytic redu ction (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 c onsideration of a compliance margin is appropriate on a case-by-case basis for the spec ific control equipmen t. Specifically, if long operating levels are clearly demonstrat ed by actual emissions data then this information can be translated directly into a final control requirem ent. However, where there is some variability to final optimal cont rol levels associated w ith characteristics of each source then some level of compliance margin should be assessed. The Department took this approach in applying a low 2% complia nce margin for overfire air
installed to boiler B27 base d on actual operating data. Similarly, a 2% compliance margin is applied to turbosorp based on vari ability of actual emissions data. For the RSCR, where actual operating data on simila r 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 nor mal operation of the source.

Applying a compliance margin is appropriate in these identified cases. As Georgia
Pacific identified in earlier comment to th e 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 th e source will be out of compliance based on normal variability.

The compliance margins in the identified cas es 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 appl ying 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
Mar g in
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 boile rs is subject to the Economic Incentive Program (EIP) policy and accordingly must dem onstrate an environmental benefit (EB). The U.S. EPA recommends limiting emissions to 10 percent below th e level that would be required with unit-by-unit limits.

Response: The Department agrees that the stac k 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% additiona l reduction applied to the BART boilers.

The EIP states that a default environmental benefit is the reduc tion of emissions 10%
below that level which would result from dir ectly 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 trading 3 . Because the Georgia Pacific f acility is not in a NALD area the environmental benefit can be met through eith er the additional 10% reduction or a mass

cap.

The Department agrees that setting a co mpliance requirement for total stack S10 emissions is a form of emissions averagi ng across the BART and non-BART boilers for each pollutant. Initially the Department proposed that Georgia Pacific could meet BART requirements by demonstrating complia nce 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 applie d 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 a dditional 10% reduction is applied to the
residual emissions for boilers B 26 and B27 after BART controls. This step is taken to meet the State's BART rule trading requi rements and in applying a more stringent standard for addressing the increased flexibil ity allowed via inter-pollutant trading (SO 2 for NOx) under the alternative complia nce option. The a pplication 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 includi ng 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 SO 2 BART requirements. The EIP stat es 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 Cl ub comments assert that a mass cap compliance approach will not ensure con tinuous operation of BART controls. The concern is that controls will not have to ope rate 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 effici encies and visibility improvement under a mass cap will be equivalent to or greater th an 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 accept able control approach for emission limit requirements. In fact, the EIP consid ers 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 th at the EIP policy applies to programs used by states in meeting regional haze requireme nts – as such the EIP policy applies to implementation of BART requirements. 4

The EIP establishes that a mass cap appro ach 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 dir ect application of RACT technology. The reductions calle d for by the RACT requirements are satisfied through other means.[ ] If your EIP allows sour ces to avoid the direct application of RACT technology, your EIP mu st 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 dir ectly 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 Mana gers commented that the Haze Rule may not support inter-pollutant tr ading of visibility pre-cursors.

Response: The Department maintains that in ter-pollutant trading is allowed and supported by the Haze Rule and other EPA pol icy 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 suppor ts 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 em issions averaging on a facility basis:

"You should consider allowing sources to 'average' emissions across any set of BART of BART-eligible emissi on units within a fenceline, so long as the emission reductions from each pollutant being cont rolled 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 impl ement an emissions trading program or alternative measure rather than to require sources s ubject to BART to install, operate, and maintain BART. To do so, the State must demonstrate that th is emissions trading program or other alternative measure will achieve greater reasonable than would be achieved through the inst allation and operation of BART."

This provision describes a program which can be implemented over th e 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 improveme nt versus meeting BART alone for the
affected Class I areas. EPA further indicat es 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 th an under BART. This modeling would demonstrate "greater reasonable pr ogress" if two criteria are met:

1) Visibility does not dec line 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 theref ore subject to these methods for evaluating visibility. However, the main point to consid er is that none of the Haze Rule trading or alternative option criteria directly state or in fer 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 inhe rently significant variability in visibility impacts at any one time or place. The Depa rtment believes that the Georgia Pacific inter-pollutant trading / alternative comp liance option falls between single pollutant emissions averaging and the broad tradi ng 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 po licies for economic incentive programs (EIP) and new source emission offsets for part iculate matter support the inter-pollutant program proposed for Georgia Pacific. Unde r the EIP policy, EPA encourages the use of emissions averaging and trading where it is not otherwise pr ohibited or addressed through the specific applicable po llutant rule. The EIP also specifically states that the guidance applies to haze regulations 6 . Lastly, the EIP establishes that inter-pollutant trading of precursor em issions is allowable 7 . The policy is developed with ozone precursor trading (NOx and VOC) as the ex ample. Since ozone is regulated to primarily address health related impacts this example seems to set the most stringent criteria for trading. The Department believe s that meeting this oz one trading criteria meets all possible constraints of inter-pollutant trading, out side of the haze rule, for pollutants regulated for visibili ty and haze impacts. The EIP indicates in this case that air quality modeling must be conducted to esta blish the correct ratio for inter-precursor trades of ozone. Such an analysis and resu lting trading ra tio has been established for the Georgia Pacific inter-pollutant tr ading / alternative compliance option.

The U.S. EPA established that inter-polluta nt trading is appropriate in netting PM2.5 offsets for new source review (NSR) requirements 8 . The guidance directly addresses trading SO 2 and NOx as precursors for PM2.5 wh ich clearly establishes that EPA supports inter-pollutant precu rsor trading for the same pollutants and particulate outcomes which affect visibility. EPA in es tablishing this policy pr ovided 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/ai r/nsr/nsrmemos/pm25trade.pdf

.16 methodology for developing inter-pollutant precursor trading based air quality modeling for a specific geogra phic area and then establishing pollutant trading ratios. The Department believes the approach used in establishing inter-pollutant trading for Georgia Pacific follows the same met hodology 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 pr ogram or alternative compliance option is allowed and supported for Georgia Pacific in meeting BART requirements. The program must, however, meet all applicable cr iteria under the haze rule and EIP policy. As discussed in response to comments the De partment believes all EIP criteria are met.

Comment 7.2: U.S. EPA questions whether any in ter-pollutant alternative compliance option can allow levels of SO 2 and NOx to vary over time; i.e. can Georgia Pacific change the amount of SO 2 excess emissions traded in lieu of NOx reductions anytime
into the future.

Response: The Department believes varying SO 2 and NOx levels according to constraints which ensure greater visibility improvement than BART is allowable. However, the proposed alternative complia nce option has been amended such that
traded emissions will be chosen and fixe d into the future. The Department does request, however, that U.S. EPA consider a llowing an inter-pollutant trading program which allows varying SO 2 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 pr oposed inter-pollutant trading option needs to account for future SO2 requirement s because the EIP policy requires emission reductions used for emissions averaging or trading to be "surplus" to other federal requirements.

Response: The Haze Rule specific ally 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 gui dance is that it does not supercede specific requirements or criter ia specifically addressed by another regulation. Therefore emission requirements effective after this time and into the future do not affect the identification of "surplus" emissions fo r purposes of BART. Because the BART requirements will reduce both SO 2 and NOx to levels below any previous requirement,17 including those implemented si nce 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 Departme nts understanding is that this basis will not change into the future based on surplu s being defined under the Haze Rule instead of the EIP policy. A fixed basis for counting su rplus emissions is similar to what occurs under the federally implemented programs such as CAIR and CSAPR.

Comment 7.4: The concern of whether continuou s BART control under a mass cap will
be achieved is further extended to in ter-pollutant compliance option where SO 2 can be traded for NOx. Basically, there is concern that SO 2 reductions can be generated such
that all NOx reduction can be avoided.

Response: The Department believes that the te st for a BART inter-pollutant trading program is whether it achieves equiva lent visibility improvement whereas SO 2 and NOx are both visibility precursors. Theref ore under the Haze rule, the measure of
continuous BART control is not the net tons reduction of either SO 2 or NOx but rather
the continuous level of visibi lity improvement. The Department's analysis shows that a preferred alternative for the greatest visibi lity improvement is to allow minimal NOx reductions in lieu of greater SO 2 reductions at a tr ading ratio of 2 SO 2 2 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 SO 2 emissions together. Therefore, the alternate compliance option based on inter- pollutant trading in cludes a minimum NOx emission reduction requirement. Accordin gly, a NOx emission cap of 1,522 tons on a 12-month rolling basis and 172 t ons 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 ba seline years of 2002 to 2004 as the basis for evaluating BART controls and visibility impact s. Further, in providing for alternative compliance options the Haze Rule, 40 CFR pa rt 51.308(e)(2)(iv) establishes that excess emissions are to be determined based on regul ations 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 requiremen ts do not alter due to other regulations.
Rather if further emission reductions are need ed for visibility impr ovement 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 em issions are removed from the atmosphere the average visibility improvement from BART controls will increase. The Department
has not identified a scenario where futu re regulations and the finalized BART requirements will result in a negative visibi lity impact versus the BART level of visibility improvement.

7.6 Comment: U.S. EPA commented that a trading ratio of 2.2:1 (SO 2 :NOx) is reflected in the analysis of visibility equiva lency supporting inter-pollutant trading.

Response : The Department acknowledges an actual trading ratio of 2.2 tons SO 2 to 1 ton was modeled in establishing the inter-po llutant compliance option. This slightly higher ratio was an inherent result of the modeling data pr eparation. Even with this difference the Department maintains, base d on information discussed below, that a trading ratio of 2 SO 2 for 1 NOx is appropriate for inter-pollutant compliance alternatives at the Georgia Pacific facility. However to support this ratio the Department is conducting vi sibility modeling for the finalized BART compliance requirements and trading SO 2 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 resu lts at trading ratios of 1.1, 2.2,
and 3.3 SO 2 to 1 NOx. These results were initia lly presented in Table 7.4 of the July 2011 draft BART determination as Cases 2, 4, an d 6, respectively. From this data, as shown in the table below, the 0.2 ratio diffe rential 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 t on 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 inherent ly captures how the visibility may change
with each ton of trade.

These deciview impact of 0.2 tons SO 2 can then be added to th e total visibility impact
result for the 2.2 SO 2 trading ratio. This calculation re sults in the adjusted visibility impact of trading at the 2.0 SO 2 to 1.0 NOx ratio. As can be seen these adjusted values do not exceed the visibility impact for th e BART mass caps (w 10% environmental benefit). Therefore the De partment believes a 2:1 SO 2 to NOx trading ratio is supported for the Georgia Pacific alte rnative 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 b ecause the trading plan is not BART, compliance for the trading plan option shoul d be Dec. 31, 2017 instead of the Dec. 31,
2015 date for BART.

Response : WDNR maintains that compliance w ith BART is Dec. 31, 2015, even under a trading plan.

8.0 Compliance Requirements

Comment 8.1: U.S. EPA commented that the Geor gia-Pacific BART requirements must be established in a permanent enforceable document.

Response : The Department agrees. The Georgi a Pacific BART requirements are to be established in a permanent administrative or der. 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 th at Department can either show that the proposed BART emission rate limits fo r the EGUs modeled at maximum actual
emissions for PM 10 have no significant impact on visibi lity, 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 PM 10 emission limits to below 0.03 Lb/mmBtu by 2015. Combin ed with the minimal visibility impact at the permit emission limits, the Department maintains that no additional emission
limitation for PM 10 is necessary.21 Appendix A

Determination of CAIR Applicability Boiler B25 Georgia Pacific Broadway MillUNITED 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

1 On 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.

2 Georgia 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,

243.2, 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

3produce 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

3 In 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.

4the 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

6other 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. 5 Id.; 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 supplementalinformation (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

5 However, 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. 8Sincerely,

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 anew small unit exemption through a CAIR SIP revision and still participate in the EPAadministered trading programs.

NODA Objection

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