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NORTH CAROLINA

DIVISION OF AIR QUALITY

Application Review

Permit Issue Date: xx

Region: Washington Regional Office

County: Craven

NC Facility ID: 2500104

Inspector’s Name: Betsy Huddleston

Date of Last Inspection: 06/25/2015

Compliance Code: 3 / Compliance - inspection

Facility Data

Applicant (Facility’s Name): Weyerhaeuser NR Company - Vanceboro Pulp

Facility Address: Weyerhaeuser NR Company - Vanceboro Pulp

1785 Weyerhaeuser Road

Vanceboro, NC 28586

SIC: 2611 / Pulp Mills

NAICS: 32211 / Pulp Mills

Facility Classification: Before: Title V After: Title V

Fee Classification: Before: Title V After: Title V

Permit Applicability (this application only)

SIP: N/A

NSPS: N/A

NESHAP: N/A

PSD: N/A

PSD Avoidance: N/A

NC Toxics: N/A

112(r): N/A

Other: N/A

Contact Data Application Data

Application Number: 2500104.14A

Date Received: 04/17/2014

Application Type: Modification

Application Schedule: TV-Sign-501(c)(2) Part II

Existing Permit Data

Existing Permit Number: 02590/T51

Existing Permit Issue Date: 6/13/2016

Existing Permit Expiration Date: 12/31/2016

Facility Contact

Treva Maxwell-Anderson

Sr. Environmental

Engineer

(252) 633-7427


Vanceboro, NC 28586

Authorized Contact

John Ashley

Mill Manager

(252) 633-7242


Vanceboro, NC 28586

Technical Contact

Treva Maxwell-Anderson

Sr. Environmental

Engineer

(252) 633-7427


Vanceboro, NC 28586

Total Actual emissions in TONS/YEAR:

CY SO2 NOX VOC CO PM10 Total HAP Largest HAP

2014 266.27 689.85 452.56 305.61 70.80 255.72 199.20

[Methanol (methyl alcohol)]

2013 292.00 750.03 489.45 516.39 76.16 268.98 204.14


2012 346.01 708.88 685.17 418.23 40.18 297.66 235.63


2011 505.78 726.44 722.46 480.31 53.54 318.07 251.03


2010 717.05 712.70 740.77 1723.85 76.84 325.20 252.23


Review Engineer: Rahul Thaker

Review Engineer’s Signature: Date: July 22, 2016

Comments / Recommendations:

Issue 02590/T52

Permit Issue Date: xx

Permit Expiration Date: xx

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1. Purpose of Application

Weyerhaeuser NR Company, New Bern, NC (Weyerhaeuser) has submitted a permit application in accordance with

15A NCAC 02Q .0516 "Significant Permit Modification" for the following issues:

(i) To obtain a Part 70 permit revision as a 2nd step of 02Q .0501(c)(2) provision for the previously approved project,

comprising of alternate operating scenario (AOS) for the Recovery Furnace Electrostatic Precipitator (CD 445-340

and CD 445-369).

(ii) To obtain a Part 70 permit revision as a 2nd step of 02Q .0501(c)(2) provision for the previously approved Turbine

Generator project.

(iii) To remove No. 6 fuel oil for No.1 Power Boiler (ES 150-001) from the list of permitted fuels.

(iv) To obtain approval for No. 2 fuel oil burning capability for Lime Kiln (ES 455-061).

(v) To obtain approval for a 300 HP Power House Emergency Generator (ES 206-049-70).

(vi) To replace the Recovery Area Cummins Diesel Engine (ES-100-004) with the Fire House Pump Engine (ES 100-

004).

(vii) To remove the existing visible emissions monitoring requirement for River Oxygen Diesel Motor (ES 185-127).

2. Facility Description

The facility operates an integrated bleached Kraft pulp mill in Vanceboro (near New Bern), North Carolina. The

primary activity at the facility is fluffed pulp production from softwood and operations include multiple fuel-fired

boilers, chemical recovery operations, wood pulping and bleaching operations, and additional operations and

equipment necessary to support these operations.

3. Application Chronology

April 17, 2014 - DAQ received the application.

February 19, 2016 - DAQ discussed various requested items of the application with the Permittee and asked her to

provide electronic copies of the emissions calculations and cover letter write-up.

March 10, 2016 - DAQ received the requested information on electronic files for emissions calculations and

application cover letter.

April 15, 2016 - The processing of application 2500104.14A was stopped to allow for the processing completion of a

separate application (2500104.15B) by Russell Braswell. The 2500104.15B application was farther into the Title V

permitting process, so it was decided after consultation with the applicant that it would be better for both the applicant

and the agency to first finish the processing of that application.

4. Statement of Compliance

Betsy Huddleston of Washington Regional Office conducted the last compliance inspection on multiple days (April

21, May 14, May 27, and June 25, 2015) and concluded that “the facility appeared to be in compliance with all

applicable regulations and permit conditions at the time of the inspection.”

In addition, the facility responsible official has submitted a Form E5 "Title V Compliance Certification", certifying

that the "facility is in compliance with all applicable requirements".

5. Permit Modification/Changes

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5.1 To obtain a Part 70 permit revision using the 2nd step of 02Q .0501(c)(2) provision for the previously approved

project, comprising of AOS for the Recovery Furnace Electrostatic Precipitator (ESP) (CD 445-340 and CD

445-369).

The recovery furnace (boiler) (ES 445-001) emissions are controlled by the two-sided (two chambers) ESP (CD 445-

340 and CD 445-369) in normal operation. However, when one side of the ESP is inoperable and being repaired, the

operation of the recovery furnace venting to only one chamber of ESP can still be continued under the AOS. This

alternate scenario was permitted through an air permit 02590T46 (April 8, 2013). The permit was issued based on

historical data provided during the application review by the Permittee, showing compliance with the PM limits in

SIP (02D .0508) and NSPS (Subpart BB). The permit included a limit for the hours of operation in this AOS to no

more than 500 hours per consecutive 12-month period and required stack testing to verify compliance with the

applicable PM limits under these regulations for this scenario by July 8, 2013. The Permittee performed the required

stack test on May 27, 2013. The results of this test demonstrated that the particulate matter emissions from the furnace

would be below all applicable PM emissions limits/standards in 02D .0508, .0524 [NSPS Subpart BB], and .1111

[NESHAP Subpart MM]. The following Table includes the test results for the AOS, when the recovery furnace

emissions are controlled by only one chamber of the ESP. It needs to be stated here that the Stationary Source

Compliance Branch (SSCB) has reviewed and approved the test results on October 10, 2013.

Pollutant Test Results Emission Limit Emission Standard Compliance

Filterable PM 0.60 lb/ADTP 3.0 lb/ADTP 15A NCAC 2D .0508 Yes

Condensible PM 0.22 lb/ADTP

Total PM 0.82 lb/ADTP

Filterable PM 0.0517 g/dscm at 8% O2 0.10 g/dscm

at 8% O2

40 CFR 60 Subpart BB

Yes

Filterable PM 0.0517 g/dscm at 8% O2 0.10 g/dscm

at 8% O2

40 CFR 63 Subpart MM

Yes1

The permit also included a PSD avoidance stipulation, comprising of limited operating hours, when only one chamber

of the ESP is operating and controlling PM emissions from the recovery furnace, to 500 hours per consecutive 12-

month consecutive period. The underlying monitoring required the Permittee to keep daily records of hours of

operation for the AOS. The permit requires semi-annual reporting of monthly hours of operation of ESP in AOS for

the previous 17 months.

In summary, all of the above applicable requirements are accurate and no changes are required. As requested by the

Permittee, the only change to the current permit required to be made with respect to this approved recovery furnace

ESP project, is to add explicitly the same AOS for the NESHAP requirements as well, specifically for compliance

with the PM filterable standard of 0.10 g/dscm, corrected at 8% O2. As indicated above, the actual emissions (0.0517

g/dscm, corrected at 8% O2) when operating only one chamber of the ESP, are less than the filterable PM standard.

The DAQ will thus, modify the existing AOS stipulation in Section 2.1 I.4. of the current permit to explicitly state

that the AOS applies to all PM limits/standards included in 02D .0508, .0524, and .01111, as included in Sections 2.1

I.1.a., Section 2.1 I.3.b., and Section 2.2 B.

Finally, the Appendix 1 to this application review includes an associated review for the air permit 02590T46 (April 8,

2013) for reference.

5.2 To obtain a Part 70 permit revision as a 2nd step of 02Q .0501(c)(2) provision for the previously approved

Turbine Generator project.

The steam demand of the New Bern Mill is currently being met by the permitted Power Boilers No. 1 and 2, and a

Recovery Boiler. Some portion of the steam is used for mill processes and the remaining portion is used to produce

electricity, partially satisfying facility’s electricity needs.

1 The compliance determination for the NESHAP PM standard was not made by the SSCB.

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Through the permit issuance 02590T47 (August 1, 2013), the DAQ allowed the replacement of the existing turbine

generator (maximum 30 MWe) with a more efficient turbine generator (38 MWe). The Permittee has stated that the

replacement turbine generator would allow more efficient utilization of high pressure steam while reducing both the

amount of electricity to be purchased for the facility operations and the utilization of the facility’s Power Boilers.

As allowed under the NC’s SIP (02D .0530), the actual-to-projected actual applicability test (APTA) was used for this

replacement project to determine the change in emissions. Because the Permittee had used the APTA to avoid

applicability of PSD, monitoring in the form of record keeping for actual emissions of NOx, CO, and GHG (as CO2e),

and fuel usage for both fuel oil and natural gas, for five calendar years for these boilers was required. In addition, the

Permittee was required to submit reports within 60 days of the calendar year (for each of the years for which the record

keeping was required).

The following Table includes the fuel usage projections as included in the Section 2.2 D.6. of the current permit:

Emission Source Parameters Projection*

(Per consecutive 12-months)

No. 1 Power Boiler Natural Gas Burning

Fuel Oil Burning

167.17 million sft3

1,391,000 gallons


Fuel Oil Burning

516.99 million sft3

4,302,000 gallons

Recovery Furnace Natural Gas Burning

or

Fuel Oil Burning

276.52 million sft3

or

1,855,610 gallons * These projections are not enforceable limitations. If parameter exceeds the projection, consistent with 15A NCAC 2D .0530, the

permit shall include in its annual report an explanation as to why the actual rates exceeded the projection.

After the issuance of an air permit 02590T47, approving the turbine generator replacement project, the Permittee sent

a letter to the DAQ Director on August 21, 2013, requesting modification of its Air Quality Permit through informal

means and a change to the permit condition requiring tracking of fuel usage for both natural gas and fuel oil. The

Permittee argued that the permit application supporting this permit included two scenarios for emissions increases

under the maximum electrical output for the new turbine: Scenario 1, burning natural gas only, demonstrated that the

emissions increases would be below the applicable significance thresholds for various pollutants. Scenario 2, based

on both fuel oil and natural gas burning, also showed emissions increases would be less than the applicable significance

thresholds. Because there would be no emissions increases above the applicable significant rates for any regulated

NSR pollutants, irrespective of the amount of natural gas that would be burned, the Permittee argued that monitoring

for only fuel oil is justified / required. The DAQ (Rahul Thaker) emailed Weyerhaeuser (Treva Maxwell) on

September 10 and 12, 2013, essentially agreeing with the Permittee and stating that the DAQ would revise the permit

stipulation (Section 2.2 D.7.) through the processing of then "in-house” PSD application, which was also separately

being processed at that time. However, this issue was somehow not taken care of by the DAQ at that time.

Through this permit issuance, the DAQ will remove the natural gas fuel tracking requirement for the previously

approved turbine replacement project in the revised permit and modify the above table as follows:

.

Emission Source Parameters Projection*


No. 1 Power Boiler Fuel Oil Burning 1,391,000 gallons

No. 2 Power Boiler Fuel Oil Burning 4,302,000 gallons

Recovery Furnace Fuel Oil Burning 1,855,610 gallons

* These projections are not enforceable limitations. If parameter exceeds the projection, consistent with 15A NCAC 2D .0530, the

permit shall include in its annual report an explanation as to why the actual rates exceeded the projection.

Finally, the Appendix 2 to this application review includes an associated review for the air permit 02590T47 (August

1, 2013) for reference.

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5.3 To remove No. 6 fuel oil for No. 1 Power Boiler (ES 150-001) from the list of permitted fuels.

The No. 1 Power Boiler (ES 150-001) is currently permitted to burn No. 2, No. 4 and No. 6 fuel oils, and natural gas.

The Permittee wishes to remove No. 6 fuel oil as a permitted fuel as it wishes to run this furnace primarily on No. 2

fuel oil with natural gas as a back-up fuel.

The DAQ will make this change in the revised permit.

5.4 To obtain approval for No. 2 fuel oil for Lime Kiln (ES 455-061).

The Lime Kiln (ES 455-061) is currently permitted to burn No. 6 fuel oil, natural gas, and low volume high

concentration (LVHC) gases. The Permittee wishes to add to this list No. 2 fuel oil. Weyerhaeuser states that it will

primarily burn natural gas, but will burn No. 2 fuel oil when the natural gas usage is curtailed or its supply is

interrupted.

The Permittee argues that burning of No. 2 fuel oil is not expected to adversely change the emissions profile as the

emissions for various pollutants are expected to be lower when burning No. 2 fuel oil than No. 6 fuel oil, nor it will

trigger any additional requirement (beyond currently applicable requirements pertaining to No. 6 fuel oil). The

following includes a comparison of emissions factors for these fuels, available from the current version of AP-42

(Tables 1.3-1 through 1.3-3), which indicates that the No. 2 fuel oil is less dirty than No.6 fuel oil:

Pollutant No. 6 fuel oil

Emissions Factor

lb/103 gallons

No. 2 fuel oil

Emissions Factor

lb/103 gallons

SO2 157S 157S

NOx 47 24

CO 5 5

Filterable PM 9.19(S)+3.22 2

Condensible PM 1.5 1.3

VOC 1.13 0.34

It should be noted that the Permittee had made the same request for adding No. 2 fuel oil to the permitted list of fuels

for the lime kiln through a separately filed 502(b(10) application on September 19, 2014 [2500104.14C]. The DAQ

had allowed this requested change as a 502(b)(10) change on September 26, 2014 emphasizing that the Permittee

assumed all financial risks associated with this change without first having an air permit.

The revised permit will allow burning of No. 2 fuel oil for this source. The lime kiln will continue to be subject to

all existing requirements when burning No. 2 fuel oil, as discussed below:

15A NCAC 02D .0508 Particulates from Pulp and Paper Mills

The lime kiln is subject to an emission standard of 0.5 pound per equivalent ton of air dried pulp (ADTP). The current

permit requires annual stack testing or as required. If the results of the testing demonstrate that the actual emissions

are less than 80 percent of the above emission standard, the frequency of testing can be reduced to once every five

years. The lime kiln was tested in February-March 2012. The observed test results were 0.04 lb/ADTP (residual fuel

oil) and 0.03 lb/ADTP (natural gas). Thus, the next testing is required (as the actual emissions are less than 80 percent

of the standard) in 2017 (five years from 2012). Refer to the inspection report dated September 21, 2015. It is this

engineer’s judgement that the lime kiln will continue to be meeting this emission standard when burning No. 2 fuel

oil.

With respect to monitoring, the Permittee is mandated to control PM emissions from the kiln using the ESP and

required to follow the NESHAP Subpart MM requirements. The existing permit also includes semi-annual reporting,

comprising of a summary report for all monitoring and record keeping requirements.

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All of these requirements under 02D .0508 are accurate and no changes are required due to burning of No. 2 fuel oil.

15A NCAC 02D .0516 Sulfur Dioxide Emissions from Combustion Sources

The kiln is subject to 2.3 lb/million Btu emission limit. The current permit limits the sulfur content of residual fuel

oil (Nos. 4 and 6 oils) to 2.1 percent weight and requires record keeping in the form of fuel supplier certification. The

distillate fuel sulfur content is expected to be 0.5 weight percent or less. No fuel sulfur monitoring for distillate fuel

(No. 2 oil) is justified.

15A NCAC 02D .0521 Control of Visible Emissions

The lime kiln is subject to 20 percent opacity limit. The visible emissions are monitored using the continuous opacity

monitoring system (COMS). The Permittee will be required to monitor visible emissions when No. 2 fuel oil is burned

in the kiln. No changes to the existing requirements are required.

15A NCAC 02D .0524 New Source Performance Standard

The lime kiln is subject to the NSPS Subpart BB "Standards of Performance for Kraft Pulp Mills".

The kiln is subject to an emission standard of 0.13 gr/dscf of PM, corrected to 10 percent oxygen when burning fuel

oil. It is also subject to an emission standard of 8 ppm of total reduced sulfur (TRS), corrected to 10 percent oxygen.

The above standards will apply when burning No. 2 fuel oil in the kiln.

With respect to monitoring for PM, emissions are to be controlled by ESP and the Permittee is required to follow all

applicable monitoring, record keeping and reporting requirements under NESHAP Subpart MM. No changes to these

existing requirements are required for burning No. 2 fuel oil in the lime kiln.

For TRS emissions, the Permittee is required to maintain and operate a continuous monitoring system for TRS

emissions. No changes to this existing requirement is required for burning No. 2 fuel oil in the lime kiln.

15A NCAC 02D .1111 Maximum Achievable Control Technology

The lime kiln is subject to the NEPSHAP Subpart MM “National Emission Standards for Hazardous Air Pollutants

for Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite, and Stand-Alone Semichemical Pulp Mills”.

The kiln is subject to the following limits:

PM emissions shall be no greater than 0.064 gr/dscf, corrected to 10% oxygen.

Opacity shall not be greater than 20 percent for more than 6 percent of the operating time within any quarterly

period. [note: the 20 percent opacity is a monitoring requirement and not an opacity standard]

With respect to monitoring PM emissions for the lime kiln, visible emissions are to be measured and recorded for each

successive 6-minute period using COM.

For the lime kiln, the Permittee is required to implement corrective action, as specified in the startup, shutdown, and

malfunction plan prepared under §63.866(a), when the average of ten consecutive 6-minute averages results in a

measurement greater than 20 percent opacity;

The Permittee is deemed in violation of §63.862 when opacity is greater than 20 percent for 6 percent or more of the

operating time within any quarterly period;

5.5 To obtain approval for a 300 HP Power House Emergency Generator (ES 206-049-70).

http://www.daq.state.nc.us/rules/rules/D0516.pdf

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This is an existing emergency generator, operated by a propane-fired spark ignition engine. The maximum engine

output is 300 HP. The generator was manufactured prior to September 1992, and both commenced construction and

operation occurred in September 1992.

The following Table includes an emission estimate for this generator:

The potential emissions for the propane-fired emergency generator are based upon 500 hours of operation and Table

1.5.1 “Emission Factors for LPG Combustion”, AP-42, USEPA, RTP, NC, 07/08. As can be seen in the above Table,

the potential uncontrolled emissions for the source are less than the 5 tons/yr (each criteria pollutant) and the 1000

lbs/yr (any single HAP) thresholds. Therefore, it will be deemed an “insignificant activity” in accordance with 02Q

.0503(8) and included in the attachment list to the cover letter to the revised permit with an ID “IES 206-049-70”.

As such the source is subject to the requirements in 02D .0516, .0521, and .1111 (RICE MACT). A detailed

applicability review for each of the above requirements will not be performed, as the source has been deemed an

“insignificant activity”. It will be listed accordingly in the Attachment to the cover letter of the permit with the

reference to the applicability for MACT ZZZZ.

5.6 To replace the Recovery Area Cummins Diesel Engine (ES-100-004) with the Fire House Pump Engine (ES

100-004).

The DAQ has already processed this particular request through issuance of an air quality permit 02590T49 (November

25, 2015).

5.7 To remove existing visible emissions monitoring requirement for River Oxygen Diesel Motor (ES 185-127).

This is a diesel-fired emergency engine, which is a back-up unit for the electric motor. The motor provides the

necessary electric power for adding dissolved oxygen in treated wastewater in normal operation. For any reason, the

electric motor is not available, this emergency engine will perform the same function as the motor. With respect to

the visible emissions requirement in 02D .0521, the DAQ has required visible emissions monitoring on a monthly

basis as per Section 2.1 E.2.c. Typically, the DAQ does not require any monitoring for visible emissions for diesel-

fired combustion sources (whether it is an emergency or a non-emergency use) unless the DAQ (through its

jurisdictional regional office) has found some compliance issue(s) for a particular source. The last inspection report

did not include any compliance issues for this emergency engine. Moreover, the subject engine is an emergency

engine, which is by its very nature is operated on as-needed basis. Thus, the DAQ believes that the existing visible

emissions monitoring is not really justified; therefore, it proposes to remove it from the permit.

6. Attainment Status, PSD, CAM, and 112(r)

PSD

Pollutant Potential Emissions

tons/yr

PM negligible

PM10 negligible

PM2.5 negligible

SO2 negligible

NOx 0.03

CO 0.02

VOC negligible

Single HAP not expected

Total HAP not expected

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The County of Craven is either in attainment or unclassifiable/attainment for all promulgated National Ambient Air

Quality Standards (NAAQS), except 1-hour SO2 NAAQS, in accordance with §81.334. The EPA has not yet

designated (whether in attainment, unclassifiable/attainment, or non-attainment) Craven County for the 1-hour SO2

NAAQS. The PSD program applies to any major stationary source and any major modification to an existing major

stationary source in this County.

The Weyerhaeuser Vanceboro facility is an existing “major stationary source” for PSD. The specific changes as

discussed in this application review do not amount to a major modification review.

Finally, Craven County is triggered for PM10, SO, and NOx, with respect to minor source baseline date. However,

this modification does not affect these triggered pollutants.

Compliance Assurance Monitoring (CAM)

Not applicable.

112(r)

The Permittee does not store on-site any regulated compound in quantities exceeding the threshold levels, as per the

application.

7. Facility-wide Emissions

The following Table includes facility wide emissions. Actual emissions are taken from the emission inventory, as

submitted to the DAQ for 2014.

Pollutant Actual Emissions

Tons/year

Particulate (TSP) 197.03

Particulate (PM-10) 70.80

Particulate (PM-2.5) 55.37

Carbon Monoxide 305.61

Nitrogen Oxides 689.85

Sulfur Dioxide 266.27

Volatile Organic

Compounds

452.56

GHG as CO2e Not Available

Single Largest HAP

(methanol)

199.20

Total HAP 255.7

8. Public Notice/EPA and Affected State(s) Review

Pursuant to 15A NCAC 02Q .0521, a notice of the DRAFT Title V Permit will be placed on the NCDEQ (North

Carolina Department of Environmental Quality) website. The notice will provide for a 30-day comment period with

an opportunity for a public hearing. Copies of the public notice will be sent to persons on the Title V mailing list and

the EPA. Pursuant to 15A NCAC 02Q .0522, a copy of the proposed permit (in this case, the draft permit) will also

be provided on the same day to the EPA for their 45-day review. Also pursuant to 02Q .0522, a notice of the DRAFT

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Title V Permit will be provided to each affected State at or before the time notice provided to the public under 02Q

.0521 above. A copy of the final permit will also be provided to the EPA upon issuance as per 02Q .0522.

9. Stipulation Review

The following changes were made to the Weyerhaeuser Vanceboro Air Quality Permit No. 02590T51:

Old Page No.

[Air Quality

Permit No.

02590T51]

New Page No.

[Air Quality

Permit No.

02590T52]

Condition No. Changes

Attachment 1 Attachment 1 - Include 300 HP propane-fired emergency

generator (IES 206-049-70).

3

8

3

8

Section 1 Table

Remove No. 6 fuel oil from the source descriptor

for Power Boiler No. 1.

Add No. 2 fuel oil burning permission in the

descriptor for the Lime Kiln.

10 10 Section 2.1 A. Remove No. 6 fuel oil from the source descriptor

for Power Boiler No. 1.

21 21 Section 2.1 E. Remove VE monitoring requirement and

associated record keeping and reporting from

Sections 2.1 E.2.c. through e.

32 31 Section 2.1 I.4.a. Explicitly state that the AOS apply to all PM

limits/standards in 02D .0508, .0524, and .1111.

37 36 Section 2.1 K. Add No. 2 fuel oil burning permission in the

descriptor for the Lime Kiln.

64 63 Section 2.2 D.6.d. Remove all projections pertaining to natural gas.

10. Conclusions, Comments, and Recommendations

The PE seal requirement is not applicable pursuant to 02Q .0112.

The application does not include any new or modified emissions sources and/or control devices. Thus, the local

zoning consistency determination requirement is not applicable pursuant to 02Q .0507(d).

The draft permit was emailed to the Washington Regional Office for review on July 14, 2016. Betsy Huddleston

from the regional office email on July 18th with several editorial/grammatical comments on application review

and the drat permit. The DAQ will implement all these editorial comments. In addition, Ms. Huddleston sent

one correction in Section 2.1 K.2.c. to state “any fuel oil” instead of “No. 6 fuel oil”, associating sulfur content

limit of 2.1 percent by weight. The DAQ will make this change.

The draft permit was emailed to the applicant for review on July 14, 2016. Treva Maxwell-Anderson emailed

on July 21st with a correction on heat input rate for the recovery boiler as included in the descriptor in Section 2.2

B., from 4.2 million lbs BLS/day to 4.5 million BLS/day. The DAQ will correct this heat input rate value to 4.5

million Btu BLS/day in the permit.

This permit engineer recommends issuing the initial Title V permit upon completion of both the public and EPA

review periods.

Appendix 1-1

Appendix 1

Permit Review for Air Quality Permit 02590T46

Appendix 1-2

NORTH CAROLINA DIVISION OF

AIR QUALITY

Air Permit Review

Permit Issue Date:


County: Craven





Facility Data

Applicant (Facility’s Name): Weyerhaeuser NR Company Vanceboro Pulp

Facility Address: Weyerhaeuser NR Company Vanceboro Pulp


Vanceboro, NC 28586






SIP:

NSPS:

NESHAP:

PSD:

PSD Avoidance:

NC Toxics:

112(r):

Other:


Application Number: 2500104.12G



Application Schedule: TV-Sign-501(c)(2)





Facility Contact

Brad Chesson

Environmental Engineer

(252) 633-7230


Vanceboro, NC 28586

Authorized Contact

John Ashley

Vice President

(252) 633-7242


Vanceboro, NC

28586+760

Technical Contact

Brad Chesson


(252) 633-7230


Vanceboro, NC 28586

Review Engineer: Gautam Patnaik

Review Engineer’s Signature: Date: April 8, 2013


Issue 02590/T46

Permit Issue Date: April 8, 2013

Permit Expiration Date: December 31, 2016

1. Facility Description.

The facility operates an integrated bleached Kraft pulp mill near New Bern, North Carolina. The

primary activity at the Weyerhaeuser New Bern Mill is pulp production, and operations include

power boilers, chemical recovery operations, wood pulping and bleaching operations, and additional

operations and equipment necessary to support these operations.


The Dry Bottom, two-chamber electrostatic precipitator (ESP) (IDs for each chamber CD 445-340

and CD 445-369) installed on the facility’s Recovery Furnace (ID No. ES 445-001) is oversized. The

facility has historical data that show the Recovery Furnace meets applicable PM standards even if

one side of the ESP is not operating. Continuous opacity monitoring data show that the mill can

continue to meet the opacity standards under these conditions. As per the applicant “NC DAQ has

Appendix 1-3

indicated that this mode of operation should be specifically called out in the permit as an alternate

operating scenario (AOS).” Therefore, the application requests the addition of an AOS allowing

operation of the Recovery Furnace if only one side of the ESP is operating.

The facility is also requesting removal of the state-only NC air toxics limits for MACT-affected

sources with this application.

This application also includes an additional insignificant emission source, a new white liquor storage

tank.

Proposed Project Description

a) AOS allowing operation of the Recovery Furnace (ID No. ES 445-001) while only one side of the

ESP is operating (IDs for each chamber CD 445-340 and CD 445-369).

The Recovery Furnace (ID No. ES 445-001) emissions are controlled by a two-sided ESP (ID

Nos. CD-455-340 and CD-455-369). As per the applicant emissions from the Recovery Furnace

are 20 percent or less of the applicable NSPS and MACT PM standards when both sides of the

ESP are in operation (the normal or primary operating scenario). The facility has stack test data

that show the Recovery Furnace meets applicable PM standards even if one side of the ESP is

not operating. Continuous opacity monitoring data during the stack test show that the mill can

continue to meet the opacity standards under these conditions. Therefore, the facility would like

to have the option to continue to operate the Recovery Furnace if one side of the ESP was

unexpectedly down, while performing any necessary maintenance to restore proper operation to

the second side of the ESP.

b) New White Liquor Storage Tank

The facility proposes to construct a new (ID No. IES 455-822-02) 500,000-gallon clarified white

liquor storage tank directly east of the existing white liquor storage tank. The purpose of this

tank is to accommodate additional white liquor storage to minimize the effects of recovery area

outages on the pulp mill. The new 500,000 gallon clarified white liquor storage tank will be an

insignificant source per 2Q .0503(8) since the potential uncontrolled emissions, are each no more

than five tons per year and potential emissions of hazardous air pollutants before air pollution

control devices, are each below 1000 pounds per year.

c) Request for Permit Revision for TAP Limits

The purpose of the House Bill 952 “State Air Toxics Program Reform” was to exempt from State

air toxics emission controls those sources of emissions that are subject to certain federal emission

requirements. The facility is requesting that TAP limits for those sources be removed from the

Title V Permit. These affected sources are covered under Boiler MACT (112(j)), Pulp and Paper

Industry MACT I (Subpart S), Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite,

and Stand-Alone Semi-chemical Pulp Mills MACT (MACT II, Subpart MM) or RICE MACT

(Subpart ZZZZ).

3. Regulatory Review

Appendix 1-4

i. AOS allowing operation of the Recovery Furnace (ID No. ES 445-001) while only one side of the

ESP is operating (IDs for each chamber CD 445-340 and CD 445-369)

a) 15A NCAC 2D .0524: NSPS 40 CFR SUBPART BB

The Recovery Furnace (ID No. ES 445-001) is subject to the NSPS Subpart BB “Standards of

Performance for Kraft Pulp Mills.”

Emissions Limitations

This NSPS contains emissions standards for particulate matter, opacity, and total reduced sulfur

(TRS). The 2009 modifications subjected the Recovery Furnace to Subpart BB. Particulate

matter emissions from recovery furnaces are limited to 0.10 g/dscm (0.044 gr/dscf) corrected to 8

percent oxygen and maximum allowable opacity is limited to less than 35 percent on a 6-minute

average. TRS emissions from recovery boilers are limited to 5 ppmvd, corrected to 8 percent

oxygen. The facility conducted an initial performance test on the Recovery Furnace to

demonstrate compliance with NSPS limits after performing the 2009 upgrade.

Additional Testing

As part of the revised permit the applicant will be required to demonstrate compliance with the

particulate matter emission limits above by testing the Recovery Furnace (ID No. ES 445-001)

when emissions are controlled by the operation of both the chambers of the two-chamber

electrostatic precipitator (ID Nos. CD-455-340 and CD- 55-369) (normal operation) AND while

operating only one chamber of the ESP (AOS scenario). The applicant shall ensure that the ESP

(ID Nos. CD-455-340 and CD- 55-369) are tested for total particulate matter (filterable) in

accordance with a testing protocol approved by the DAQ. These requirements are specified in

Section 2.1 I. 3. C. ii., of the modified permit.

Monitoring, Reporting/ Recordkeeping Requirements

There are no changes to the monitoring, reporting, and recordkeeping requirements under this

regulation.

b) 15A NCAC 2D .1111: MACT Subpart S

This facility is subject to MACT Subpart S for the Pulp and Paper Industry. The Recovery

Furnace (ID No. ES 445-001) is a backup control device for pulp mill NCGs (non-condensable

gases) and SOGs (stripper off gas). This AOS/modification does not affect Subpart S

compliance, as the ESP (ID Nos. CD-455-340 and CD- 55-369) does not provide control of

organic HAP regulated under Subpart S.

c) 15A NCAC 2D .0508 “Particulates from Pulp and Paper Mills”

Appendix 1-5

As per this regulation emissions from the production of pulp and paper that are discharged from

this source into the atmosphere shall not exceed 3.0 pounds of particulate matter per equivalent

tons of air dried pulp.

Additional Testing

The applicant shall demonstrate compliance with the particulate matter emission limits above by

testing the Recovery Furnace (ID No. ES 445-001) when emissions are controlled by the

operation of both the chambers of the two-chamber electrostatic precipitator (ID Nos. CD-455-

340 and CD- 55-369) (normal operation) AND while operating only one chamber of the ESP

(AOS scenario).

The applicant shall ensure that the ESP (ID Nos. CD-455-340 and CD- 55-369) are tested for

total particulate matter (filterable and condensable) in accordance with a testing protocol

approved by the DAQ. These requirements are specified in Section 2.1 I. 1. b. ii., of the modified

permit.

d) 15A NCAC 2D .0516: “Sulfur dioxide Emissions from Combustion Sources”

Under this standard, SO2 emissions from any combustion source are limited to 2.3 lb/MMBtu

input. The ESP AOS will not affect SO2 emissions.

e) 15A NCAC 2D .0521: “Control of Visible Emissions”

The Recovery Furnace is subject to the 35% opacity limit in NSPS Subpart BB, thus, this rule

does not apply.

f) 15A NCAC 02D .0528 “Total Reduced Sulfur from Kraft Pulp Mills”

This emission standard applies to recovery furnaces, digester systems, evaporator systems, lime

kilns, smelt tanks, and condensate stripping systems not subject to TRS emission standards under

40 CFR 60. The Recovery Furnace complies with the TRS limits in NSPS Subpart BB, and thus,

this rule does not apply.

g) 15A NCAC 2D. 0530: “Prevention of Significant Deterioration”

The facility belongs to one of the 28 source categories listed in the regulation that has the

potential to emit more than 100 tons per year of any PSD-regulated compound and emits greater

than 100 tons per year of a PSD-regulated compound. Thus, this facility is a major source.

The current Recovery Furnace ESP (ID Nos. CD-455-340 and CD- 55-369) was installed during

the fall of 2005. Following the installation, the mill conducted emissions testing to demonstrate

compliance with the PM emission limits that were applicable at the time. The facility also

performed testing to demonstrate that the ESP could meet those limits with only one of the two

sides operating.

The table below summarizes average filterable PM emissions during the two test scenarios in

2005.

Appendix 1-6

ESP Operating Scenario Filterable PM

(lb/hr)

Production Rate

(*TBLS/hr)

Filterable PM

(lb/TBLS)

One side of the ESP operating 34.84 76.25 0.457

Both sides of the ESP operating 10.31 76.46 0.135

*Ton of black liquor solids

The data above show an increase in filterable PM emission rate of 239% when one side of the

ESP is not operating. This Recovery Furnace was upgraded in 2009 to increase throughput.

The table below summarizes average filterable PM emissions during the test in 2009 (with both

sides of the ESP operating and with operation at the 2009 maximum throughput):

ESP Operating Scenario Filterable PM

(lb/hr)

Production

Rate

(TBLS/hr)

Filterable PM

(lb/TBLS)

Both sides of the ESP operating 6.83 88.6 0.077

*Estimated filterable PM Emissions with one side of the ESP operating: 0.261

* Based on the 2005 test

The only PSD compounds affected by the AOS are PM, PM10, PM2.5 (filterable portions only),

and lead. Condensable PM emissions and all other PSD compound emissions are not expected to

be affected by the AOS. As per the applicant “a PTE of 500 hours per year was chosen because

the AOS equates to an emergency type operating scenario and PTE of emergency equipment

such as a backup generator is evaluated at 500 hours per year. Actual operating time in this AOS

is expected to be minimal.”

The testing conducted both in 2005 and in 2009 was performed using EPA Methods 5 and 202.

However, the data from these test methods was incapable of providing fractionation of the

filterable PM portion of the sample. The National Council for Air and Stream Improvement

(NCASI) provides information for PM fraction from Recovery Furnaces equipped with ESPs. As

per data from NCASI, PM10 from recovery furnaces can be assumed to be comprised of 71.3%

of the filterable fraction plus 100% of the condensable fraction, and for PM2.5 it’s 49.8% of the

filterable fraction plus 100% of the condensable fraction.

To summarize for the 2009 data with the ESP fully in service:

The conversion (ratio) from black liquor solids to pulp is 1.8 (TBLS/ADTP = 1.8)

FPM (filterable particulate matter) = 0.3820 lb/ADTP (ton air-dried pulp)

CPM (condensable particulate matter) = 0.0594 lb/ADTP

TPM = 0.3820+0.0594 = 0.4414 lb/ADTP

PM10 = (0.713*0.3820)+0.0594 = 0.3318 lb/ADTP

PM2.5= (0.498*0.3820)+0.0594 = 0.2496 lb/ADTP

As per the applicant “the current max hourly throughput of the Recovery Furnace is 93.8

TBLS/hr (submitted with our May 2011 NC air toxics modeling demonstration), which is 52.1

ADTP/hr.”

http://www.ncasi.org/

http://www.ncasi.org/

Appendix 1-7

To summarize for the 2009 data and estimating the emissions factors with the ESP partially out

of service:

TPM = (2.39*0.4414 lb/ADTP) = 1.054946 lb/ADTP

PM10 = (2.39*0.3318 lb/ADTP) = 0.793002 lb/ADTP

PM2.5= (2.39 *0.2496 lb/ADTP) = 0.596544 lb/ADTP

At a production of 52.1 ADTP/hr (93.8 TBLS/hr) and an AOS operation of less than 500 hrs/yr,

emissions will increase by [52.1*(1.055-0.44)*500/2000] 8.01 tons of TPM, and increase by

lesser amounts of PM10 and PM2.5. These emissions are much less than the Significant

Emission Rates for PSD and thus a PSD review is not necessary.

A major modification is defined by applicable PSD regulations as “any physical change or

change in the method of operation of a major stationary source that would result in a significant

net emissions increase of any pollutant subject to regulation under the Act.” In this case, the

operational change only occurs when the ESP is operated with one chamber. Therefore the

emission increase associated with the change will be calculated by multiplying the emission

change (e.g. PM increase resulting from going from two chambers to one chamber by the hours

that the unit operates under this alternative scenario. The applicant has requested a 500 hours per

year AOS limit.

The applicant has requested that it wants to avoid any PSD applicability. The modified permit

will include a PSD avoidance stipulation (Section 2.1 I. 5.,) to restrict the hours of operation of

the Recovery Boiler (ID No. ES 445-001) not to exceed 500 hours per year, while only one of

the chambers of the Dry Bottom, two-chamber electrostatic precipitator (ID Nos. CD 445-340

and CD 445-369) is in operation (AOS).

The applicant has relied on FPM (filterable particulate matter) and CPM (condensable particulate

matter) data as well as AOS test data conducted as far back as 2005. An additional testing

requirement, as specified in Section 2.1 I. 1. b. ii., of the modified permit (for compliance with

15A NCAC 2D .0508), will measure both filterable and condensable particulate matter, and test

the ESP for normal and AOS operation. This testing data can be further used to verify the PSD

avoidance limits as required by this AOS. The applicant is required to demonstrate compliance

with this PSD avoidance limits by providing calculations using these latest test data for filterable

particulate matter, condensable particulate matter, and AOS test data to demonstrate compliance.

This requirement is stipulated in Section 2.1 I. 5. d., of the modified permit.

h) 15A NCAC 2D.1100: “Toxic Air Pollutant Emissions”

See the review for “Request for Permit Revision for TAP Limits,” below.

ii. Request for Permit Revision for TAP Limits

a) 15A NCAC 2D.1100: “Toxic Air Pollutant Emissions”

As per the requirement of 15A NCAC 2D .1100, Section 2.2 A. 1., the current permit places

Appendix 1-8

restrictions on the emissions for toxic air pollutants known to be emitted from the facility.

Removal of toxic permit limits

15 NCAC 2Q .0700 requires facilities that emit toxic air pollutants (TAPs) for which they are

required to have a permit under 15 NCAC 2D.1100 to demonstrate compliance with the

Acceptable Ambient Levels (AALs). Facility-wide TAP modeling has been previously submitted

to demonstrate compliance with 2Q .0700.

On June, 2012, the North Carolina Senate Agriculture, Environment, and Natural Resources

Committee unanimously approved House Bill 952 – State Air Toxics Program Reform. The

purpose of the bill was to exempt from State air toxics emission controls those sources of

emissions that are subject to certain federal emission requirements, to direct the Department of

Environment and Natural Resources to require permit conditions that eliminate unacceptable

risks to human health, to direct the Division of Air Quality to review the State Air Toxics

Program, and to require reports on the implementation of the act. Specifically, affected sources

under 40 CFR Part 63 or subject to a case-by-case maximum achievable control technology

permit requirement issued by NC DAQ are exempt from the toxics rule.

As per this rule: “…The Department shall implement rules adopted pursuant to this subsection as

follows:

a. Except as provided in sub-subdivision b. of this subdivision, rules adopted pursuant to this

subdivision that control emissions of toxic air pollutants shall not apply to an air emission

source that is any of the following:

1. Subject to an applicable requirement under 40 C.F.R. Part 61, as amended.

2. An affected source under 40 C.F.R. Part 63, as amended.

3. Subject to a case-by-case maximum achievable control technology (MACT) permit

requirement issued by the Department pursuant to 42 U.S.C. § 7412(j), as amended.

b. Upon receipt of a permit application for a new source or facility, or for the modification of an

existing source or facility, that would result in an increase in the emission of toxic air pollutants,

the Department shall review the application to determine if the emission of toxic air pollutants

from the source or facility would present an unacceptable risk to human health. Upon making a

written finding that a source or facility presents or would present an unacceptable risk to human

health, the Department shall require the owner or operator of the source or facility to submit a

permit application for any or all emissions of toxic air pollutants from the facility that eliminates

the unacceptable risk to human health. The written finding may be based on modeling,

epidemiological studies, actual monitoring data, or other information that indicates an

unacceptable health risk. When the Department requires the owner or operator of a source or

facility to submit a permit application pursuant to this sub-subdivision, the Department shall

report to the Chairs of the Environmental Review Commission on the circumstances surrounding

the permit requirement, including a copy of the written finding.”

The facility requests that TAP limits for those exempt sources be removed from the Permit.

These affected sources are covered under Boiler MACT (112(j)), Pulp and Paper Industry

MACT I (Subpart S), Chemical Recovery Combustion Sources at Kraft, Soda, Sulfite, and

Appendix 1-9

Stand-Alone Semi-chemical Pulp Mills MACT (MACT II, Subpart MM) or RICE MACT

(Subpart ZZZZ).

The Table below shows the sources of HAPs and the applicable MACTs. TAP Emission Source Description Applicable MACT

Power Operations

ES 150-001

No. 1 Power Boiler – No. 2/No. 4/No. 6 Fuel

Oil/Natural Gas-Fired (579 million Btu/hour

nominal maximum heat input)

Case-By-Case MACT

ES 161-001

No. 2 Power Boiler - No. 2, 4 and No. 6 Fuel

Oil/Propane/Natural Gas/LVHC gases/HVLC

gases/SOGs-Fired (287 million Btu per hour

maximum heat input rate from by-product gas,

natural gas, propane and fuel oil/267 million Btu per

hour maximum heat input rate from oil only)

MACT Subpart S Control

Device

Case-By-Case MACT

Washing and Screening

ES 420-123 Primary Rejects Tank (190) MACT Subpart S

ES 420-140 Secondary Rejects Tank (192) MACT Subpart S

Bleach Plant Area

ES 425-032 Pre-Bleach Tower MACT Subpart S

ES 425-036 Pre-Bleach Washer MACT Subpart S

ES 425-038 Pre-Bleach Seal Tank MACT Subpart S

ES 425-060 Eop Stage Tower MACT Subpart S

ES 425-065 Eop Stage Bleach Washer MACT Subpart S

ES 425-067 Eop Stage Seal Box MACT Subpart S

Evaporator Area

ES 440-016 1A Effect Evaporator MACT Subpart S

Chemical Recovery

ES 445-001 Recovery Boiler (New Design) - Black Liquor

Solids/HVLC Gases/LVHC/SOG/Natural Gas/No.

2, No. 4, and No. 6 Fuel Oil-Fired (4.2 million lbs of

Black Liquor Solids /day nominal maximum firing

rate)

MACT Subpart MM


Device

ES 445-121 Smelt Dissolving Tank MACT Subpart MM

Causticizing Area

ES 455-061 Lime Kiln – Residual Fuel Oil/ Natural Gas /LVHC

Gases-Fired (118 million Btu per hour nominal

maximum heat input rate)


Device

MACT Subpart MM

The facility submitted a facility-wide modeling demonstration, which included combustion

sources, in May of 2011 as part of a PSD permit for the Recovery Boiler. An update to this

modeling was submitted in July 2011. Facility wide emission rates were compared to the TPERs

and 26 compounds required modeling.

The results of the 2011 modeling demonstration are listed below:

Maximum

Percent

of

Averaging Concentration AAL AAL

TAP Period (g/m3) Year (g/m3) (%)

Acrolein 1-Hour 2.07 2007 80 2.59%

Appendix 1-10

Maximum

Percent

of



Ammonia 1-Hour 516.38 2008 2,700 19.13%

Arsenic Annual 1.41E-04 2008 0.00023 61.29%

Benzene Annual 0.027 2008 0.12 22.50%

Beryllium Annual 8.14E-05 2008 0.0041 1.99%

Butadiene, 1,3 Annual 0.001 2007 0.44 0.1%

Cadmium Annual 4.77E-04 2008 0.0055 8.68%

Carbon Disulfide 24-Hour 0.953 2007 186.00 0.51%

Chlorine 24-Hour 5.077 2007 37.5 13.54%

1-Hour 26.842 2007 900 2.98%

Chloroform Annual 0.088 2007 4.3 2.05%

Chromium (VI) 24-Hour 0.0053 2005 0.62 0.85%

Ethylene Dibromide Annual 0.002 2007 0.4 0.59%

Formaldehyde 1-Hour 29.60 2005 150 19.73%

Hexachlorocyclopentadiene 24-Hour 0.001 2005 0.6 0.12%

1-Hour 0.003 2005 10.0 0.03%

n-Hexane 24-Hour 0.259 2006 1,100 0.02%

Hydrogen Chloride 1-Hour 10.230 2008 700 1.46%

Hydrogen Fluoride 24-Hour 0.019 2006 30 0.06%

1-Hour 0.049 2009 250 0.02%

Hydrogen Sulfide 24-Hour 1.90 2007 120 1.58%

Manganese 24-Hour 1.31 2005 31 4.23%

Mercury 24-Hour 0.00036 2005 0.6 0.06%

Methyl Mercaptan 1-Hour 15.70 2005 50 31.40%

Methylene Chloride Annual 0.092 2007 24.0 0.38%

1-Hour 3.290 2005 1,700 0.19%

Appendix 1-11

Maximum

Percent

of



Nickel (metal) 24-Hour 0.400 2008 6 6.67%

Phenol 1-Hour 16.09 2005 950 1.69%

Sulfuric Acid 24-Hour 2.55 2008 12 21.27%

1-Hour 6.65 2006 100 6.65%

Xylene 24-Hour 6.43 2007 2,700 0.24%

1-Hour 41.91 2008 65,000 0.06%

With the exception of the annual arsenic emissions, modeled facility impacts are less than 32% of

all AALs for the modeled compounds.

Under HB 952, any source that is covered under a MACT or Generally Achievable Control

Technology (GACT) standard and any source covered under a 112(j) permit is exempt from

regulation under the state air toxics rule. The legislation requires that, upon receipt of any permit

application that would result in an increase in TAP emissions, DAQ must review the application

to determine if the emissions of TAPs from the facility present an unacceptable risk to human

health. DAQ has already determined that facility-wide emissions from the facility do not present

an unacceptable risk to human health (See review for application # 2500104.12C - Lignin

Removal System).

Because previously submitted facility-wide modeling indicates no exceedance of any AAL, the

facility requests that the TAP limits be removed for all sources affected by MACTs. Thus the

sources mentioned above have all the HAP emissions limits associated with the affected MACTs

removed. Section 2.3 A., of the modified permit lists the sources and the modified emissions

limits from the associated TAPs. The sources still do have HAPs emissions limits. These HAPs

are not regulated under the above listed MACTs.

Operation of only one side of the ESP on the Recovery Furnace affects emissions of only

particulate and metals. In the most recent modeling demonstration, the highest concentration of

any TAP was that of arsenic which was at a level of 61.29% of the AAL, which indicates that the

facility emissions of TAP metals will remain below the AALs. The mill expects to operate under

the AOS infrequently. Therefore, the most recent modeling analysis remains valid and

demonstrates compliance with toxics.

4. NSPS, NESHAPS/MACT, PSD, Attainment Status , 12(r), CAM, Application Processing

Schedule

NSPS, NESHAPS/MACT

Appendix 1-12

Sources at this facility are subject to Case-By-Case MACT, MACT Subpart S, MACT Subpart

ZZZZ, and MACT Subpart MM.

Sources at this facility are subject to NSPS Subpart Db and NSPS Subpart BB.

PSD

See Section 3. i. g), of this review, above.

Attainment Status

This facility is located in Craven County, which is currently designated as an attainment County.

The minor baseline dates for this County has been triggered for PM10, NOx, and SO2 emissions.

This modification does not trigger any increased emissions of NOx and SO2 from this facility. There

will be some increase of PM10 on an hourly basis.

Based on the information of the PSD review in Section 3. i. g), of this review, a PM10 emissions

factor of 0.3318 lb/ADTP (with the ESP fully in service), a PM10 emissions factor of 0.793002

lb/ADTP (with the ESP partially in service), and a potential production rate of 52.1 of ADTP/hr, the

hourly potential emissions increase is [52.1*(0.79-0.33)] 23.97 lbs of PM10 per hour.

112(r)

This facility is not subject to Section 112(r) of the Clean Air Act requirements because it does not

store any of the regulated substances in quantities above the thresholds in the Rule.

CAM

The Compliance Assurance Monitoring (CAM) Rule (40 CFR Part 64) applies to pollutant-specific

emissions units (PSEU) that are pre-control major sources and use a control device to comply with

an emissions limit. The dry bottom, two-chamber electrostatic precipitator (ID No. CD 445-340 and

CD 445-369) controlling emissions from the recovery boiler (ID No. ES 445-001), is currently not

subject to CAM. This AOS will not be subject the control device to CAM.

Application Processing Schedule

The application is being processed as a significant 2Q .0501(c)(2) change, and the applicant pursuant

to 15A NCAC 2Q .0504 shall file a Title V Air Quality permit application on or before 12 months

after commencing of the AOS.

5. Facility Wide Air Toxics & Compliance with House Bill 952

See Section 3. ii. a), of this review, above.

Appendix 1-13

Operation of only one side of the ESP on the Recovery Furnace affects emissions of only particulate

and metals and the most recent modeling analysis demonstrates compliance with toxics. This AOS

will not present an unacceptable risk to human health and thus comply with House Bill 952.


As per Ms. Betsy Huddleston of the Regional Office the latest inspection was done in May 21, 2012,

and the facility appeared to be in compliance. This report also stated

“EPA completed the 10-yr Risk Assessment for MACT Subpart S, and issued the findings at the

beginning of the year. The main changes proposed in the rule as a result of the assessment that will

heavily impact Weyerhaeuser are as follows:

(a) Remove all exemptions for SSM events. Therfore, all NCG ventings count toward the

HVLC/LVHC 4% and 1% venting allowances.

(b) Create new excess emission and malfunction recordkeeping and reporting requirements

(including affirmative defense).

(c) Require stack testing every 5 years.”

The applicant responded “the rule changes were effective September 11, 2012. There is no action

needed on A, and B and C will require updates to the permit.” The applicant will also have the

opportunity to comment on the draft permit before the permit becomes final.

In an e-mail on 4/5/13 the applicant responded “Their venting allowances already include SSM (e.g.,

they are not excused during periods of SSM). The new testing requirements don’t kick in until 2015:

Compliance Dates

With the exception of the specific elements described below, all revisions being promulgated in this

action are effective as of the date of publication, i.e., September 11, 2012. Compliance dates are

different for the following: (1) the first of the 5-year performance tests must be conducted within 3

years (36 months) of the effective date of the standards, i.e., by September 7, 2015 and subsequent

repeat performance tests must be conducted within 5 years (60 months) from the date of the

previous performance test; and (2) as of September 11, 2012, results of performance test data must

be submitted through the EPA Electronic Reporting Tool (ERT) within 60 days of the date of

performance test completion.

Repeat Testing Requirements

The EPA also finalized provisions mandating repeat air emissions performance testing every 5

years for the following sources;

a. Sources complying with the vent gas standards under 40 CFR 63.443(a) (kraft, soda, and semi-

chemical pulp mills), 40 CFR 63.444 (sulfite pulp mills), and 40 CFR 63.445 (bleach plants)

b. Sources complying with the kraft condensate collection and treatment standards under 40 CFR

63.446 using the steam stripper option.

The EPA has also added language to clarify that the 5-year repeat testing is not required for knotter

or screen systems with HAP emission rates below the criteria specified in 40 CFR 63.443(a)(1)(ii)

or for decker systems using fresh water, paper machine white water, or process water with a total

HAP concentration less than 400 ppm by weight as specified in 40 CFR 63.443(a)(1)(iv). It is stated

that the repeat performance testing requirement ensures that control systems are properly maintained

over time and reduces the potential for acute emissions episodes.”

Appendix 1-14

The below set of sources were listed in the source table of the permit but listed anywhere else in the

permit.

ES 420-332 Brown Decker Filtrate Tank

(189)

Not required by MACT to be controlled

ES 420-325 Brown Stock Washed HD Chest

(3)

Not required by MACT to be controlled

ES 420-274 Oxygen Interstage Pulp Tank Not required by MACT to be controlled

ES 425-032 Pre-Bleach Tower Not required by MACT to be controlled

ES 425-036 Pre-Bleach Washer Not required by MACT to be controlled

ES 425-038 Pre-Bleach Seal Tank Not required by MACT to be controlled

ES 425-118 No. 2 Bleached Deckers Not required by MACT to be controlled

In an e-mail on 4/8/13 the applicant responded “the first set of sources is part of the MACT affected

source but there are no requirements. I don’t think they should be in 2.2A since there are no

requirements.” Since these sources are subject to the MACT the sources are listed in Section 2.2. A.,

of the modified permit.

The below set of sources were listed in the source table of the permit but listed anywhere else in the

permit.

ES 155-999 Power Area Fugitive Sources Fugitive emissions catch-all

source (e.g., valves, leaks, etc)

ES 354-044 Log Debarking Fugitive PM

ES 356-999 Pine Wood Chip Piles Fugitive PM/VOC

ES 455-999 Bucket Conveyor Fugitive Sources Fugitive PM

The applicant clarified that these sources are subject only to 15A NCAC 02D .0540 “Particulates

from Fugitive Dust Emission Sources”

A professional engineer’s seal was provided for this modification.

This facility is located in an area without zoning. However, as per 15A NCAC 02Q .0507(d)(3) a

consistency determination is required for a modification of an existing facility. Since the AOS did

not require a physical change to the source, a consistency determination is not required.

The applicant and the Regional Office were provided a copy of the draft permit and their comments

were taken into consideration.


Appendix 1-15

The following table describes the modifications to the current permit as part of the modification

process.

New Page(s) Section Description of Change(s)

Insignificant Activities Added 500,000-gallon clarified white liquor storage tank (ID

No. IES 455-822-02)

28 2.1 I. 1. b. ii. Additional testing for Recovery boiler (ES 445-001) to comply

with 2D .0508.

30 2.1 I. 3. c. ii. Additional testing for Recovery boiler (ES 445-001) to comply

with 2D .0524.

30 & 31 2.1 I. 4. Alternate Operating Scenario (AOS) for Recovery boiler (ES

445-001)

31 2.1 I. 5. PSD avoidance conditions for Recovery boiler (ES 445-001)

64 through

76

2.3 A. Updated toxics limits for several sources.

80 to 89 General Conditions Updated

Appendix 2-1

Appendix 2

Permit Review for Air Quality Permit 02590T47

Appendix 2-2

NORTH CAROLINA

DIVISION OF AIR QUALITY

Air Permit Review

Permit Issue Date: 8/1/2013


County: Craven





Facility Data

Applicant (Facility’s Name): Weyerhaeuser NR Company Vanceboro Pulp

Facility Address: Weyerhaeuser NR Company Vanceboro Pulp


Vanceboro, NC 28586






SIP:

NSPS:

NESHAP:

PSD:

PSD Avoidance:

NC Toxics:

112(r): Other: 2D .530(u)


Application Number: 2500104.13A



Application Schedule: TV-Sign-501(c)(2)





Facility Contact

Brad Chesson


(252) 633-7230


Vanceboro, NC 28586

Authorized Contact

John Ashley

Vice President

(252) 633-7242


Vanceboro, NC 28586

Technical Contact

Brad Chesson


(252) 633-7230


Vanceboro, NC 28586

Review Engineer: Rahul Thaker

Review Engineer’s Signature: Date: August 1, 2013


Issue 02590/T47

Permit Issue Date: 8/1/2013

Permit Expiration Date: 12/31/2016


Weyerhaeuser NR Company, New Bern, NC (Weyerhaeuser) has requested to obtain a permit approval to replace the

existing 30 MW turbine generator with a new 38.1 MW turbine generator.

2. Facility Description

Weyerhaeuser manufactures fluffed pulp from softwood.

3. Application Chronology

Refer to “Events Update” screen in the I-BEAM.

5. Statement of Compliance

Betsy Huddleston of WaRO inspected the facility between 4/24/12 and 5/21/12. She concluded that “the facility

appeared to be in compliance with the conditions of Permit R42 and Title V Permit T44 at the time of the inspection.”

Appendix 2-3


5.1 To obtain a permit approval to replace the existing 30 MW turbine generator with a new 38.1 MW turbine

generator.

The steam demand of the New Bern Mill is currently being met by the permitted Power Boilers No. 1 and 2, and a

Recovery Boiler. Portion of the steam is used for mill processes and the remaining portion is used to produce

30 MW electricity (maximum), thus partially satisfying facility’s electricity needs. This above system is generally

called a Combined Heat and Power system (CHP).

These boilers (combustion sources) have been permitted to burn a multiple fuels. Power Boiler 1 is permitted to

burn natural gas and fuel oils (Nos. 2, 4 and 6) at a heat input rate of 579 million Btu/hr. Power Boiler 2 is permitted

to burn natural gas, oils (Nos. 2, 4 and 6), propane, LVHC gases, HVLC gases, and SOGs at a rate of 267 million

Btu/hr (oils) to 287 million Btu/hr (natural gas, propane, and by product gas). Recovery Boiler is permitted to burn

natural gas, oils (Nos. 2, 4 and 6), LVHC gases, HVLC gases, SOGs, and black liquor solids at a rate of 4.2

million lbs of black liquor solids (BLS) per day.

High pressure steam produced from the above boilers is directed to a main steam header and is throttled back to lower

temperatures and pressures before it can be used for mill processes. The existing turbine generator would allow to

reduce pressure and temperature of the steam from high pressure header and will also generate power to reduce the

amount of electricity to be purchased.

The Pemittee is proposing to conduct energy efficiency upgrades for the facility’s steam system as described below.

The primary component of this energy upgrade is the replacement of the existing turbine generator (maximum 30

MWe) with a more efficient turbine generator (38 MWe). As per the Permittee, this replacement turbine generator

will allow more efficient utilization of high pressure steam while reducing both the amount of electricity to be

purchased for the facility operations and the utilization of the facility’s Power Boilers. Various components of the

energy upgrades as described by the Permittee are as follows:

Replacement of existing soot blowers

The replacement of the currently installed high-pressure soot blowers with newer design high-efficiency soot blowers

is expected to decrease the level of buildup slag and soot on the boiler tubes, and thus allow increased heat transfer

with an expected increase in steam production of approximately 1.8 percent from the recovery boiler.

Redirection of currently utilized steam for soot blowing to 850 psig header

The proposed soot blowers operate using lower pressure steam (170 psig) which will be obtained from low pressure

header. By making this change, the high-pressure steam currently used to blow soot on the recovery boiler tubes will

be redirected to the high-pressure (850 psig) steam header and through the new turbine (38.1 MW), thus providing for

a more efficient use of the high-pressure steam.

Replacement of 30 MW turbine generator with 38.1 MW turbine generator

The new turbine is sized to accommodate the additional steam that is currently used for high-pressure soot blowing.

The additional power produced by the new turbine generator will reduce the amount of electricity required to be

purchased as compared to currently purchased power to run the facility operations. In addition, the new turbine

generator will allow for a production of a small surplus power that can be sold to the grid.

Rebalancing of the Mill’s steam production through reduction of firing rate in Power Boiler 2

The new control system and higher efficiency steam balance will increase the amount of available steam, thereby

reducing mill steam demand. Thus, the facility plans to reduce the firing rate of the Power Boiler 2, although the

Appendix 2-4

firing rates for Power Boiler 1 and the recovery boiler will remain the same. However, the Permittee has also stated

that in a short-term high-demand environment, the firing rate for Power Boiler 2 can return to its baseline firing rate.

It appears that no physical changes or changes in method of operation are expected for any of the combustion

equipment (Power Boiler 1, Power Boiler 2, and recovery boiler). The physical changes as requested in the

application are due to the replacement of the existing turbine generator and the soot blowers, which themselves

are not air emission sources. The Permittee also believes that increase in utilization of these power boilers is

not expected. However, DAQ believes that the replacement of turbine generator can affect the emissions of the above

combustion sources and hence, PSD applicability needs to be evaluated for the above-discussed changes.

The following Table 1 includes an applicability analysis for PSD using the actual-to-projected actual test. This

analysis is based upon the input data included in Table 2 which follows Table 1:

Appendix 2-5

Table 1: PSD Analysis

Emissions, tons per year

VOC PM PM10 PM2.5 SO2 NOx CO CO2e F Lead H2SO4 H2S TRS

Baseline Emissions for

Recovery Boiler 17.71 60.89 56.17 52.63 655.54 460.48 537.23 39,823 0.02 0.004 6.40 3.84 3.84


No. 1 Power Boiler 0.64 20.85 17.94 11.68 227.88 16.20 9.72 13,777 0.02 0.001 3.56 - -


No. 2 Power Boiler 2.15 17.06 17.06 17.06 64.47 91.81 32.87 62,863 0.05 0.004 3.79 - -

Baseline Emissions 20.49 98.80 91.17 81.38 947.89 568.49 579.82 116,463 0.09 0.01 13.75 3.84 3.84

Recovery Boiler

Emissions

Accommodated During

Baseline

20.86 72.00 66.42 62.25 1014.15 544.56 635.32 40,430 0.02 0.006 11.30 4.54 4.54

No. 1 Power Boiler

Emissions

Accommodated During

Baseline

0.63 20.50 17.63 11.48 224.02 15.92 9.55 13,544 0.02 0.001 3.50 - -

No. 2 Power Boiler

Emissions

Accommodated During

Baseline

1.93 15.34 15.34 15.34 57.93 82.51 51.12 56,492 0.05 0.003 3.41 - -

Emissions

Accommodated During

Baseline

23.42 107.84 99.39 89.06 1296.11 642.99 695.99 110,466 0.08 0.01 18.21 4.54 4.54

Projected Actual

Emissions for Recovery

Boiler

20.86 72.00 66.42 62.25 1014.15 544.56 635.39 40,430 0.02 0.006 11.30 4.54 4.54

Projected Actual

Emissions for No. 1

Power Boiler

0.88 21.13 18.18 11.83 230.98 22.37 13.42 19,029 0.02 0.001 3.61 - -

Projected Actual

Emissions for No. 2

Power Boiler

2.72 23.94 23.94 23.94 90.44 115.92 79.80 88,188 0.07 0.005 5.32 - -

Projected Actual

Emissions 24.46 117.08 108.54 98.02 1335.57 682.85 728.61 147,647 0.11 0.01 20.23 4.54 4.54

Change in Emissions 1.04 9.24 9.15 8.96 39.46 39.86 32.62 37,181 0.00 0.00 2.02 0.00 0.00

Significant Emission

Rate 40 25 15 10 40 40 100 75,000 3 0.6 7 10 10

Major Modification

Review Required? No No No No No No No No No No No No No

Appendix 2-6

Table 2: Input Data

Source

Description Fuel

Amount of

Fuel

Burning for

Baseline

Emissions

Amount of Fuel

Burning

Accommodated

During

Baseline Period

Amount of Fuel

Burning for

Projected

Actual

Emissions

Units

No. 1 Power

Boiler

Oil 1,475 1,450 1,495

Thousand

gallons/yr

224,190 220,396 227,240 Million Btu/yr

Natural

Gas

231.36 227.45 319.56 Million sft3/yr

235,989 231,996 325,954

Million Btu/yr

No. 2 Power

Boiler

Oil 4,990 4,484 7,000

Thousand

gallons/yr

758,441 681,583 1,064,000 Million Btu/yr

Natural

Gas

782.70 703.39 988.26 Million sft3/yr

798,359 717,456 1,008,026 Million Btu/yr

Recovery

Boiler

Black

Liquor

Solids

639,556 756,336 756,336 Tons BLS/yr

Natural

Gas 266,754 235,044 235,044 Million Btu/yr

Fuel Usage

(Oil or

Natural Gas)

266,754 235,044 235,044 Million Btu/yr

The Permittee first determined the baseline period within the last five years (February 2013 through March 2008)

from the receipt of the complete application (complete application receipt date March 12, 2013). The baseline period

was selected based on the highest 24-month period heat inputs of fuels affected by this project, which was October

2010 through September 2012.

The throughout accommodated during the baseline period for each of these combustion equipment was based upon

the highest annualized month of operation for the recovery boiler (756,336 TPY BLS in February 2011), which was

determined to be almost equivalent to the permitted rate of 4.2 million lbs/day BLS (or 766,500 tons per year BLS),

as included in the current permit stipulation Section 2.2 D.1. This stipulation was added when processing a permit

application 2500104.08D (air permit 02590R37, issuance date 6/15/2009).

The projected actual emissions estimate is based upon facility producing electricity for sell to the power grid, either

by burning natural gas or fuel oil. The Permittee selected the larger value for potential emission rate from each of

these scenarios. The Permittee contends that the current price for purchase of electric power for facility operations is

approximately $50 while the current price for selling electric power to the grid is approximately $80. Due to this cost

offset for producing power, the facility does not intend to produce electric power for selling, and thus, as per the

Permittee these projected actual emissions are for worst-case scenarios, which do not reflect realistic situations.

Thus, as per the Table 1, the change in emissions for each of the regulated NSR pollutants is less than the respective

significance thresholds. Thus, PSD is not triggered for this project for any pollutant. Because, the Permittee has

utilized the projected actual emissions to avoid the applicability of PSD, the underlying input data as included in Table

2 (and also below) supporting the projected actual emissions for each of the pollutants in Table 1 will be memorialized

in the revised permit. As per 2D .0530(u), because the project does not increase the design capacity or the PTE of any

emission units (Power Boilers 1 and 2 and Recovery Boiler) for any regulated NSR pollutant, the Permittee will be

Appendix 2-7

required to keep records on a calendar year basis for both the input parameters and the post-modification actual

emissions for five years following the resumption of regular operations (i. e, commencement of operation of the

replacement turbine generator). In addition, the Permittee will be required to submit a report to the DAQ Director

within 60 days after the end of each year during which the above records (both the projected actual emissions and the

underlying input parameters) are required to be generated. The report shall contain the items listed in 40 CFR

51.166(r)(6)(v)(a) through (c). The Permittee shall make the information documented and maintained in accordance

with 2D .0530(u), and available to the Director or the general public pursuant to the requirements in 40 CFR

70.4(b)(3)(viii).

Emission Source Parameter Projection


No. 1 Power Boiler Oil Burning 1,495,000 gallons

Natural Gas Burning 319.56 million sft3

No. 2 Power Boiler Oil Burning 7,000,000 gallons

Natural Gas Burning 988.26 million sft3

Recovery Boiler

Black Liquor Solids

Burning

756,336 Tons BLS

Oil Burning

OR

Natural Gas Burning

1,546,350 gallons

OR

230.44 million sft3

No other applicability review is required for the proposed project.

6. Stipulation Review

The following describes the changes to be performed to the current permit 03757T37:

Old Page No.

(02590T46)

New Page No.

(02590T47)

Condition No. Changes

Various Various Entire Permit Replace “PSD Pollutants” with “Regulated NSR

Pollutants”.

- 58 Section 2.2 D. 6. Add a new applicable requirement in 2D .0530(u) for the

replacement turbine generator.


PE seal is not required for the proposed project as it does not involve construction of a new control device or a

modification of an existing control device.

The replacement of an existing turbine generator is not a “new” or an “expanded source”. As stated above, the

turbine generator is not a source of air emissions. So, the requirement in 2Q .0113 “Notifications in Areas Without

Zoning” is not applicable.

The draft permit was sent to WaRO for review and comments on July 10, 2013. Betsy Huddleston emailed on

July 24th stating, “everything [in the draft permit] looks great to me.”

The draft permit was sent to the Permittee for review on July 10, 2013. The Pemittee emailed the comments on

July 22nd and July 29th. The Permittee argued that the parameters included in the draft permit did not include the

Appendix 2-8

accurate information on fuel usage and it unreasonably restricted the facility to burn multiple fuels in the

combustion sources (Power Boilers 1 and 2 and recovery boiler). Thus, the Permittee submitted the revised PSD

applicability and addressed the change in emissions for the following scenarios separately: natural gas burning

only and multiple fuels burning (both fuel oil and natural gas). The Tables below include these revisions:

Appendix 2-9

Revised PSD Analysis: Natural Gas Only Scenario




Recovery Boiler 17.71 60.89 56.17 52.63 655.54 460.48 537.23 39,823 0.02 0.004 6.40 3.84 3.84


No. 1 Power Boiler 0.64 20.85 17.94 11.68 227.88 16.20 9.72 13,777 0.02 0.001 3.56 - -


No. 2 Power Boiler 2.15 17.06 17.06 17.06 64.47 91.81 32.87 62,863 0.05 0.004 3.79 - -


Recovery Boiler

Emissions

Accommodated During

Baseline

20.86 72.00 66.42 62.25 1014.15 544.56 635.32 40,430 0.02 0.006 11.30 4.54 4.54

No. 1 Power Boiler

Emissions

Accommodated During

Baseline

0.20 20.50 17.63 11.48 224.02 34.07 3.62 18,267 0.02 0.001 3.50 - -

No. 2 Power Boiler

Emissions

Accommodated During

Baseline

0.63 15.34 15.34 15.34 57.93 82.51 51.12 56,492 0.05 0.003 3.41 - -

Emissions

Accommodated During

Baseline

21.70 107.84 99.39 89.06 1296.11 661.14 690.07 115,189 0.08 0.01 18.21 4.54 4.54

Projected Actual


Boiler 21.19 72.97 67.32 63.08 1024.57 551.88 643.92 40,711 0.02 0.006 11.40 4.60 4.60

Projected Actual

Emissions for No. 1

Power Boiler 1.03 1.43 1.43 1.43 0.11 26.27 15.76 22,347 0.00 0.000 0.00 - -

Projected Actual

Emissions for No. 2

Power Boiler 3.19 4.41 4.41 4.41 0.35 65.11 48.74 69,109 0.00 0.000 0.00 - -

Projected Actual

Emissions 25.41 78.81 73.15 68.92 1025.03 643.26 708.43 132,168 0.02 0.01 11.40 4.60 4.60

Change in Emissions 3.71 -29.03 -26.24 -20.14 -271.08 -17.88 18.37 16,979 -0.06 0.00 -6.81 0.06 0.06


Rate 40 25 15 10 40 40 100 75,000 3 0.6 7 10 10

Major Modification


Appendix 2-10

Revised PSD Analysis: Multiple Fuels (Both Fuel Oil and Natural Gas) Scenario




Recovery Boiler 17.71 60.89 56.17 52.63 655.54 460.48 537.23 39,823 0.02 0.004 6.40 3.84 3.84


No. 1 Power Boiler 0.64 20.85 17.94 11.68 227.88 16.20 9.72 13,777 0.02 0.001 3.56 - -


No. 2 Power Boiler 2.15 17.06 17.06 17.06 64.47 91.81 32.87 62,863 0.05 0.004 3.79 - -


Recovery Boiler

Emissions

Accommodated During

Baseline

20.86 72.00 66.42 62.25 1014.15 544.56 635.32 40,430 0.02 0.006 11.30 4.54 4.54

No. 1 Power Boiler

Emissions

Accommodated During

Baseline

0.20 20.50 17.63 11.48 224.02 34.07 3.62 18,267 0.02 0.001 3.50 - -

No. 2 Power Boiler

Emissions

Accommodated During

Baseline

0.63 15.34 15.34 15.34 57.93 82.51 51.12 56,492 0.05 0.003 3.41 - -

Emissions

Accommodated During

Baseline

21.70 107.84 99.39 89.06 1296.11 661.14 690.07 115,189 0.08 0.01 18.21 4.54 4.54

Projected Actual


Boiler 21.19 72.97 67.32 63.08 1024.57 551.88 643.92 40,711 0.02 0.006 11.40 4.60 4.60

Projected Actual

Emissions for No. 1

Power Boiler 0.66 20.12 17.40 11.55 212.94 44.16 10.51 27,382 0.01 0.001 3.33 - -

Projected Actual

Emissions for No. 2

Power Boiler 2.03 16.55 16.55 16.55 55.21 103.69 70.44 84,680 0.05 0.003 3.24 - -

Projected Actual

Emissions 23.87 109.64 101.26 91.18 1292.73 699.73 724.88 152,773 0.08 0.01 17.97 4.60 4.60

Change in Emissions 2.17 1.80 1.87 2.12 -3.38 38.59 34.81 37,584 0.00 0.00 -0.24 0.06 0.06


Rate 40 25 15 10 40 40 100 75,000 3 0.6 7 10 10

Major Modification


Appendix 2-11

The revised calculations demonstrate that when only burning natural gas in the power boilers, the turbine can

maximize the effective generating capacity without exceeding any of the PSD emission thresholds. The revised

calculations also indicate that when firing fuel oil alone the facility will not be able to reach the annual maximum

effective generating capacity without exceeding the PSD significance level for NOx. However, it is possible to burn

a a combination of both fuel oil and natural gas, corresponding to the potential effective generating capacity of the

turbine, while remaining below the PSD significance levels. The above projected actual emissions for multiple fuels

scenario are based upon the following projected parameters:

Multiple Fuels Scenario

Emission Source Parameters Projection



Fuel Oil Burning

167.17 million sft3

1,391,000 gallons


Fuel Oil Burning

516.99 million sft3

4,302,000 gallons

Recovery Furnace Natural Gas Burning

or

Fuel Oil Burning

276.52 million sft3

or

1,855,610 gallons

DAQ has reviewed the revised PSD analysis and found to be approvable. Thus, the above projected parameters will

be included in the revised permit to assure compliance with the requirements in 2D .0530(u). No other comments

were received from the Permittee.

This engineer recommends issuing the revised permit.

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