1 Georgia

- Pacific LLC

Consumer Products

Crossett Paper Operations

100 Mill Supply R oa d

P.O. Box 3333

Crossett, AR 71635

(870) 567

- 8000

(870) 364

- 9076 (fax)

www.gp.com

April 1 , 2013

Ms. Mary Pettyjohn

, Epidemiologist

Arkansas Department of Environmental Quality

5301 Northshore Drive

North Little Rock, AR 72118

Re: Georgia

- Pacific LLC Crossett Paper Operations

Best Available Retrofit Technology

- Request for Exemption from Five Factor Analysis

AFIN: 02

- 00013 Title V Permit No. 0597

- AOP

- R14

Dear Ms. Pettyjohn:

This letter is being submitted pursuant to a tele conference call on March 20, 2013, between a number of

people from the Arkansas Department of Environmental Quality, the Region 6 Office of the U.S

Environmental Protection Agency, Jim Cutbirth of Georgia Pacific Crossett Paper Operations, and

Wayne Galler from Georgia

- Pacific’s Air Permitting Group in Atlanta, GA. The persons on the

teleconference call are listed below:

Arkansas DEQ (ADEQ)

Mary Pettyjohn

- Epidemiologist

Stuart Spencer

- Attorney Specialist

Derek Brown

- Permitting Engineer

Region 6 Office of US EPA

Guy Donaldson

- Chief of Air Planning Section

Dayana Medina

- Lead Arkansas Regional Haze Coordinator , Air Planning Section

Joe Kordzi

- Overall Region 6 Haze Coordinator

, Air Planning Section

Michael Feldman, Ph.D.

- Regional Haze Modeler, Air Planning Section

Georgia

- Pacific (GP)

Jim Cutbirth

- Superintendent, Environmental Services, Crossett Paper Operations

Wayne Galler, Director, Air Permitting, Corporate Environmental Af fairs Department, Atlanta, GA

The conference call was in response to ADEQ’s recent request for additional information 1 to support our

1 See attached e

- mails from Dayan Medina of EPA Region 6, dated Feb. 12 and March 4, 20132

position that the Nos. 6A (SN

- 19) and 9A (SN

- 22) Boilers at the Crossett Paper Operations should be

“screened out” of the BART requirements. The authority to exempt a source from a “five

- factor”

analysis, is conditioned on a source’s ability to meet the state’s criteria conforming to Section III of 40

CFR Part 51 Appendix Y and showing through dispersion modeling.

GP subm itted the required dispersion modeling to ADEQ for these two boilers in December 2011 2 . The

CALPUFF modeling for the three pollutants of concern (sulfur dioxide

- SO 2 , nitrogen oxides

- NO

x , and

particulate matter with an aerodynamic particle size less than 1 0 microns in diameter

- PM 10 ), showed

that the total impact from both boilers on five different Class I Areas were all below the 0.5 deciview

(dv) screening threshold, with the highest impact value of 0.36 dv shown to occur at the Caney Creek

AR National Wil derness Area. A copy of the results of the 2011 CALPUFF modeling analysis was

submitted to Mary Pettyjohn on May 18, 2012 and is also attached to this letter.

Wayne Galler explained that the May 18, 2012 CALPUFF modeling submitted to ADEQ was the second

time that GP had conducted this work, with the first CALPUFF modeling submitted to the ADEQ in

2007. As part of the Title V Renewal application we prepared in 2008, we used a more conservative

NO

x emission factor for natural gas combustion in 6A Boiler. Thus, we prepared a second submittal with

CALPUFF modeling to reflect the higher NO

x emission rate from the 6A Boiler to reflect the use of a

higher emission factor for natural gas combustion and to also run the CALPUFF model using a lower

SO 2 emission rate from the 9A Boiler.

Since the 6A Boiler was originally constructed in approximately 1962, well before the issuance of the

New Source Performance Standard (NSPS) at 40 CFR 60 Subpart D, GP should have used a NO

x emission factor of 280 lbs/ MM ft 3 natural gas burned for boilers with a heat input rating greater than 250

MM Btu/hr to calculate the NO

x emission rate (see Table 1.4

- 1 of AP

- 42). However, GP inadvertently

used an emission factor of 100 lbs/MM ft 3 natural gas burned, which is appli cable for large natural gas

fired boilers that use flue gas recirculation to reduce NO

x emissions. 3 The 6A Boiler does not have a

flue gas recirculation system in place to reduce NO

x emissions.

Mr. Galler then pointed out that the 9A Boiler primarily bur ns bark and natural gas, but is also permitted

to burn tire

- derived fuel (TDF) and on

- specification grade fuel oil. The 9A Boiler is permitted to burn a

number of additional fuels that were not specifically discussed during the call, but include non

conde nsable gases ( NCGs ) from the pulp mill operations , agricultural derived fuel (ADF), refuse

derived fuel (RDF), wastewater treatment sludge, paper pellets, used oil absorbent material, and creosote

treated railroad ties. The TDF contains sulfur in quantitie s of approximately 1.0% (wt.). The NCGs

contain less than 0.1% (wt.) sulfur content. ADF and the other fuels other than TDF

, on

- specification

oil , and used oil absorbent material, contain negligible quantities of sulfur.

GP determined that the SO 2 emission rate from the 9A Boiler would need to be lower than the existing

Title V Permit limit of 502.5 lbs/hr to satisfy the exemption criteria using a screening approach and a

revised baseline NO

x emission rate. After reviewing the operation of the 9A Boiler and the fuels

burned, and conducting stack testing for SO 2 emissions w hen TDF and fuel oil were being fired in

combination with bark, GP determined that it could operate the 9A Boiler at a lower SO 2 emission rate

by reducing the quantity of on

- speci fication grade fuel oil burned in the unit

. In addition, the inherent

2 Section 169A(c) of the Clean Air Act allows sources to be screened out of the BART five

- factor analysis requirements if the

source will not emit any air pollutan t which may reasonably be anticipated to cause or contribute to a significant impairment

of visibility in any mandatory Class I Federal area.

3 The Crossett Mill decided to voluntarily remove on

- specification fuel oil as an allowable fuel to be burned in t he 6A

Boiler as part of Revision R

- 13 to its Title V Permit.3

nature of burning bark in combination with other sulfur

- bearing fuels, such as TDF and non

- condensable

gases (NCGs) from the pulp mill

, plus the use of a slightly caustic solution in th e wet venturi scrubber,

results in the removal of a significant portion of SO 2 emissions generated inside of the boiler. GP

requested the ADEQ to reduce t he permitted quantity of on

- specification grade fuel oil fired in the 9A

Boiler fr om 249.0 MM Btu/hr to 40.9 MM Btu/hr. GP made this request a s part of Revision R

- 13 to its

Title V Permit, which was issued by ADEQ on August 4, 2011

.

Guy Donaldson of the Region 6 Office pointed out that GP needs to provide EPA and ADEQ detailed

information to verify that the actual SO 2 emissions, as well as PM 10 and NO

x emissions, from the two

boilers during the three baseline years of 2001, 2002, and 2003, were below the Title V permit limits for

each boiler and the values used in the CALPUFF modeling . Guy also stat ed that GP needed to explain

how the maximum 24

- hour emission rate values for the baseline years were calculated. Wayne Galler

explained to the group of people on the conference call that the maximum 24

- hour average emission

rates for the baseline years w ere based on either stack test results (for PM 10 emissions only for the 9A

Boiler), or published EPA emission factors from AP

- 42, multiplied by the maximum 24

- hour fuel usage

for the other pollutants for both boilers.

An Excel spreadsheet that summar ize s the 24

- hour maximum emission rates for each of the three

pollutants used as part of the Class I modeling for both the 6A and 9A Boilers is attached as Table 1

. Table 1 also contains a summary of most recent Title V permit limits for SO 2 , PM 10 , and NO

x e missions

for each of the boilers 4 which can be compared to the CALPUFF modeled emission rates. Table 1 also

contains individual work sheet for each of the three baseline years which l ist of the daily fuel firing rates

for each boiler and the calculate d SO 2 , PM 10 , and NO

x emission rates for each day of the year

. The

details of how the emission rates were calculated for each of the baseline years are more fully explained

in Attachment 1 to this letter.

Wayne Galler briefly explained that the daily averag e emission rates for the three pollutants of concern

during the baseline years were all below the ir respective Title V Permit limits, as shown in Table 1 and

summarized below, with the baseline SO 2 emission rate s for the 9A Boiler much lower than the Title V

Permit limits.

4 The most recent Title V Permit (R

- 14) for the Crossett Paper Operations was issued on May 23, 2012.5 ATTACHMENT 1

EXPLANATION OF 24

- HR POLLUTANT BASELINE EMISSION

CALCULATIONS FOR BART CALPUFF MODELING

2001

- 2002

- 2003

Calculation of Pollutant Emission Rates Emissions for 6A Boiler:

The pollutant emission rate calculations for eac h baseline year were conducted by taking the daily fuel

usage of natural gas fired in the boiler and multiplied by the following emission factors taken from

Table 1.4

- 1 of AP

- 42 and converting the factors so they are in the same units of measure as the Mil l’s

fuel usage recordkeeping system:

AP

- 42

Pollutant Emission Factor Emission Factor

( converted units of gas usage at Mill)

lb/MM ft 3 lb/M ft 3

PM 10 7

. 6 0.0076

SO 2 0.6 0.0006

NO

x 280 0.28

Example calculation:

Jan 1, 2001 Gas usage for 24

- hour period = 459 M ft 3

Daily gas usage values were taken from the Mill's Utility Department electronic recording and

recordkeeping system (see “ 2001 TOTAL FUELS TO BOILERS ” tab on attached spreadsheet)

PM 10 (lbs/hr) = 459 M ft 3 /24 hr x 0.0076 lbs/M ft 3

= 0.145 lbs PM 10 /hr

SO 2 (lbs/hr) = 459 ft 3 /24 hr x 0. 000 6 lbs/M ft 3 = 0. 0115 lbs SO 2 /hr

NO

x (lbs/hr) = 459 ft 3 /24 hr x 0. 28 lbs/M ft 3

= 5.355 lbs SO 2 /hr

After calculating the hourly pollutant emission rate for each day of the year, the maximum

daily emission rate was determined using the "max" function of Excel. For each of the baseline

years, the maximum daily emission rates were as follows:

2001 Baseline Year

PM 10 ( May 12 ) = 2.46 ~ 2.5 lbs/hr

SO 2 ( May 12 ) = 0. 19 ~ 0.2 lbs/hr

NO

x ( May 1 2) = 90.67 ~ 90.7 lbs/hr

A similar process for 2002 and 2003 was used to determine the maximum hourly emission rates

which are summarized below:

2002 Baseline Year

PM 10 (March 22 = 1.8 lbs/hr6 SO 2 ( March 22 ) = 0.14 ~ 0.1 lbs/hr

NO

x ( March 2 2) = 66.3 lbs/hr

200 3 Baseline Year

PM 10 ( December 2 ) = 1.6 lbs/hr

SO 2 ( December 2 ) = 0. 13 ~ 0.1 lbs/hr

NO

x ( December 2 ) = 58.8 lbs/hr

Calculation of Pollutant Emission Rates Emissions for 9 A Boiler:

The only fuels burned in the 9A Boiler during the baseline years were natural gas and bark. No TDF or

on

- specification grade fuel oil was burned, or any other permitted fuels during the per iod of 2001

through 2003.

The emission rate calculations for SO 2 and NO x for each baseline year were conducted by taking the

daily fuel usage of natural gas and bark fired in the boiler and multiplied by the following emission

factors taken from Table 1.6

- 2 of AP

- 42 and converting the factors so they are in the same units of

measure as the Mill’s fuel usage recordkeeping system :

Pollutant Natural Gas Bark

Emission Factors Emission Factors

lb/M ft 3 lb/ ton

PM 10 0.0076 0.594

SO 2 0. 000 6 0.225

NO

x 0. 28 1.98

To convert from the Mill's recordkeeping for bark usage in tons per day to MM Btu/day,

the tons of bark fired was multiplied by the average heat content for bark of 4,500 Btu/lb:

1 tons of bark = 2,000 lbs

Btu/ton of bark = 2,000 lbs x 4,500 Btu/lb = 9,000,000

Therefore, there are 9.0 MM Btu/ton of bark fired

C alculation s for bark emission factors :

PM 10 0.066 lb/MM Btu (from Table 1.6

- 1 AP

- 42 for boiler with wet scrubber for PM

control

– assume PM 10 = PM filterable)

0.066 lb/MM Btu x 9 MM Btu/ton bark = 0.594 lb/ton bark

SO 2 0.025 lb/MM Btu (from Table 1.6

- 2 AP

- 42 for wood

- fired boiler)

0.025 lb/M M Btu x 9 MM Btu/ton bark = 0.225 lb/ton bark

NO

x 0.22 lb/MM Btu (from Table 1.6

- 2 AP

- 42 for wood

- fired boiler)

0.22 lb/MM Btu x 9 MM Btu/ton bark = 1.98 lb/ton bark

Daily gas and bark usage values were taken from the Mill's Utility Department elect ronic

recording and recordkeeping system7

Jan 1, 2001 Bark usage for 24

- hour period = 814 tons

PM 10 (lbs/hr) = 814 tons/24 hours x 0.594 lb/ton bark = 20.15 lbs/hr

SO 2 (lbs/hr) = ( 814 tons /24 hr x 0.225 lbs/ ton bark ) = 7.63 lbs/hr

NO

x (lbs/ hr) = ( 814 tons/ 24 hr x 1.98 lbs/ ton bark ) = 67.15 lbs /hr

Jan 1, 2001 Gas usage for 24

- hour period = 2,513 M ft 3

PM 10 (lbs/hr) = 2,513 M ft 3 /24 hr x 0.0076 lbs/M ft 3 = 0.8 lbs PM 10 /hr

SO 2 (lbs/hr) = 2,513 ft 3 /24 hr x 0.0006 lbs/M ft 3 = 0.063 lbs SO 2 /hr

NO

x (lbs/hr) = 2,513 ft 3 /24 hr x 0.19 lbs/M ft 3 = 19.9 lbs SO 2 /hr

Total PM 10 = 20.15 + 0.8 = 20.95 lbs/hr

Total SO 2 = 7.63 + 0.063 = 7.69 lbs/hr

Total NO

x = 67.15 + 19.9 = 87.0 lbs/hr (The NO

x emission factor for 9A is 190

lb/MM ft 3 gas from Table 1.4

- 1 of AP

- 42

for boilers constructed after 1971 (9A was

constructed in 1975) and this emission factor

converts to 0.19 lbs/M ft 3 for the units of

measure that the Mill’s recordkeeping is

based on.

For PM 10 emission calculations, the results from stack testing conducted by the Mill when the 9A

Boiler was firing bark and gas was used, as these results were higher than the values calculated

using AP

- 42 emission factors:

Total PM 10 emission from spreadsheet calculations:

2001: 43.4 lbs/hr

2002: 42.2 lbs/hr

2003: 48.4 lbs/hr

Total PM 10 emission from stack testing:

2001: 71.99 lbs/hr

2002: 61.0 lbs/hr

2003: 54.3 lbs/hr

Therefore, for the baseline years, we used the s tack test results for the PM 10 emission rates.

The spreadsheet contains several additional worksheets that were used in some of the emission

calculations:

6A EFs and 9A EFs

- these two worksheets were taken from the Title V application emission

calculations and used for the BART emission factor calculations for consistency

.