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Georgia-Pacific LLC

Consumer Products 

Crossett Paper Operations

100 Mill Supply Road

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 teleconference 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 Affairs Department, Atlanta, GA

The conference call was in response to ADEQ’s recent request for additional information1to support our 

 

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See attached e-mails from Dayan Medina of EPA Region 6, dated Feb. 12 and March 4, 2013
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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 submitted the required dispersion modeling to ADEQ for these two boilers in December 20112. The 

CALPUFF modeling for the three pollutants of concern (sulfur dioxide-SO2, nitrogen oxides-NOx, and 

particulate matter with an aerodynamic particle size less than 10 microns in diameter-PM10), 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 Wilderness 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 

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

CALPUFF modeling to reflect the higher NOx 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 

SO2 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 NOx

emission factor of 280 lbs/MM ft3natural gas burned for boilers with a heat input rating greater than 250 

MM Btu/hr to calculate the NOx emission rate (see Table 1.4-1 of AP-42). However, GP inadvertently 

used an emission factor of 100 lbs/MM ft3natural gas burned, which is applicable for large natural gasfired boilers that use flue gas recirculation to reduce NOx emissions.3

 The 6A Boiler does not have a 

flue gas recirculation system in place to reduce NOx emissions.

Mr. Galler then pointed out that the 9A Boiler primarily burns 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 noncondensable gases (NCGs) from the pulp mill operations, agricultural derived fuel (ADF), refusederived fuel (RDF), wastewater treatment sludge, paper pellets, used oil absorbent material, and creosote 

treated railroad ties. The TDF contains sulfur in quantities 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 SO2 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 NOx emission rate. After reviewing the operation of the 9A Boiler and the fuels 

burned, and conducting stack testing for SO2 emissions when TDF and fuel oil were being fired in 

combination with bark, GP determined that it could operate the 9A Boiler at a lower SO2 emission rate 

by reducing the quantity of on-specification grade fuel oil burned in the unit. In addition, the inherent 

 

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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 pollutant 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 the 6A 

Boiler as part of Revision R-13 to its Title V Permit.
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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 the wet venturi scrubber, 

results in the removal of a significant portion of SO2 emissions generated inside of the boiler. GP 

requested the ADEQ to reduce the permitted quantity of on-specification grade fuel oil fired in the 9A 

Boiler from 249.0 MM Btu/hr to 40.9 MM Btu/hr. GP made this request as 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 SO2 emissions, as well as PM10 and NOx 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 stated 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 were based on either stack test results (for PM10 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 summarizes 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 SO2, PM10, and NOx emissions

for each of the boilers4 which can be compared to the CALPUFF modeled emission rates. Table 1 also 

contains individual worksheet for each of the three baseline years which list of the daily fuel firing rates 

for each boiler and the calculated SO2, PM10, and NOx 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 average emission rates for the three pollutants of concern 

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

summarized below, with the baseline SO2 emission rates 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.

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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 each 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 Mill’s 

fuel usage recordkeeping system:

 AP-42

Pollutant Emission Factor Emission Factor 

(converted units of gas usage at Mill)

 lb/MM ft3 lb/M ft3

PM10 7.6 0.0076

SO2 0.6 0.0006

NOx 280 0.28

Example calculation:

Jan 1, 2001 Gas usage for 24-hour period = 459 M ft3

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)

PM10 (lbs/hr) = 459 M ft3/24 hr x 0.0076 lbs/M ft3= 0.145 lbs PM10/hr

SO2 (lbs/hr) = 459 ft3/24 hr x 0.0006 lbs/M ft3= 0.0115 lbs SO2/hr

NOx (lbs/hr) = 459 ft3/24 hr x 0.28 lbs/M ft3= 5.355 lbs SO2/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

PM10 (May 12) = 2.46 ~ 2.5 lbs/hr 

SO2 (May 12) = 0.19 ~ 0.2 lbs/hr

NOx (May 12) = 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

 PM10 (March 22 = 1.8 lbs/hr 
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SO2 (March 22) = 0.14 ~ 0.1 lbs/hr

NOx (March 22) = 66.3 lbs/hr

2003 Baseline Year

 PM10 (December 2) = 1.6 lbs/hr 

SO2 (December 2) = 0.13 ~ 0.1 lbs/hr

NOx (December 2) = 58.8 lbs/hr

Calculation of Pollutant Emission Rates Emissions for 9A 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 period of 2001 

through 2003.

The emission rate calculations for SO2 and NOxfor 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 ft3 lb/ton

PM10 0.0076 0.594

SO2 0.0006 0.225

NOx 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

Calculations for bark emission factors:

PM10 0.066 lb/MM Btu (from Table 1.6-1 AP-42 for boiler with wet scrubber for PM 

control – assume PM10 = PM filterable)

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

SO2 0.025 lb/MM Btu (from Table 1.6-2 AP-42 for wood-fired boiler)

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

NOx 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 electronic 

recording and recordkeeping system
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Jan 1, 2001 Bark usage for 24-hour period = 814 tons

PM10 (lbs/hr) = 814 tons/24 hours x 0.594 lb/ton bark = 20.15 lbs/hr

SO2 (lbs/hr) = (814 tons/24 hr x 0.225 lbs/ton bark) = 7.63 lbs/hr 

NOx (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 ft3

PM10 (lbs/hr) = 2,513 M ft3/24 hr x 0.0076 lbs/M ft3= 0.8 lbs PM10/hr

SO2 (lbs/hr) = 2,513 ft3/24 hr x 0.0006 lbs/M ft3= 0.063 lbs SO2/hr

NOx (lbs/hr) = 2,513 ft3/24 hr x 0.19 lbs/M ft3= 19.9 lbs SO2/hr

Total PM10 = 20.15 + 0.8 = 20.95 lbs/hr

Total SO2 = 7.63 + 0.063 = 7.69 lbs/hr

Total NOx = 67.15 + 19.9 = 87.0 lbs/hr (The NOx emission factor for 9A is 190 

lb/MM ft3gas 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 ft3for the units of 

measure that the Mill’s recordkeeping is 

based on. 

For PM10 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 PM10 emission from spreadsheet calculations:

2001: 43.4 lbs/hr

2002: 42.2 lbs/hr

2003: 48.4 lbs/hr

Total PM10 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 stack test results for the PM10 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.