PREVENTION OF SIGNIFICANT DETERIORATION PERMIT

PROPOSED PURSUANT TO THE

REQUIREMENTS AT 40 CFR § 52.21

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION IX

PSD PERMIT NUMBER: SAC 12-0 1

PERMITTEE: Sierra Pacific Industries

P.O. Box 496028

Redding, CA 96049-6028

FACILITY NAME: Sierra Pacific Industries- Anderson

FACILITY LOCATION: 19758 Riverside Avenue

Anderson, California 96007

Pursuant to the provisions ofthe Clean Air Act (CAA), Subchapter 1, Part C (42 U.S.C. Section

7470, et. seq.), and the Code of Federal Regulations (CFR) Title 40, Section 52.21, the United

States Environmental Protection Agency Region 9 (EPA) is issuing a Prevention ofSignficant

Deterioration (PSD) air quality permit to Sierra Pacific Industries (SPI). This Permit applies to

the approval to construct and operate a new stoker boiler capable of generating 31 MW of gross

electrical output from the combustion of clean cellulosic biomass, and related auxiliary

equipment.

SPI is authorized to construct and operate the 31 MW cogeneration unit at SPI-Anderson as

described herein, in accordance with the permit application (and plans submitted with the permit

application), the federal PSD regulations at 40 CFR § 52.21, and other terms and conditions set

forth in this PSD Permit. Failure to comply with any condition or term set forth in this PSD

Permit may be subject to enforcement action pursuant to Section 113 ofthe Clean Air Act. This

PSD Permit does not relieve SPI from the obligation to comply with applicable federal, state, and

Shasta County Air Quality Management District (District) air pollution control rules and

regulations.

Per 40 CFR § 124.15(b), this PSD Permit becomes effective 30 days after the service of notice of

this final permit decision unless review is requested on the permit pursuant to 40 CFR § 124.19.

1IJ/ 1j / 1 I // — /1 i

1 / I/i/i/I/I Z YWVVL/ L/ I!. ‘

Deborah Jordan Date

Director, Air Division
SIERRA PACIFIC INDUSTRIES - ANDERSON (SAC 12-0 1)

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT

PERMIT CONDITIONS

PROJECT DESCRIPTION

Sierra Pacific Industries, Inc. (SPI) applied for the approval to construct and operate a new stoker

boiler capable of generating 31 MW of gross electrical output from the combustion of biomass

and natural gas, and related auxiliary equipment. The original Prevention of Significant

Deterioration (PSD) permit for this lumber manufacturing facility was issued in 1994 by the

Shasta County Air Quality Management District (District). The site currently contains a woodfired boiler cogeneration unit with associated air pollution control equipment and conveyance

systems that produce steam to dry lumber in existing kilns. On March 3, 2003, USEPA revoked

and rescinded the District’s authority to issue and modify federal PSD permits for new and

modified major sources of attainment pollutants in Shasta County. Therefore, EPA is issuing this

PSD permit to authorize SPI to construct and operate the additional boiler and related auxiliary

equipment described in this permit at the SPI-Anderson facility. The PSD permit previously

issued by the District to SPI is still in effect and applies to existing equipment at the SNAnderson site.

Fuel for the new stoker boiler will be generated on site and received from other fuel sources,

mainly other SPI facilities, to produce roughly 250,000 pounds per hour of steam. This steam

will be used to dry lumber in existing kilns for the lumber operation, as well as feed a turbine

that will drive a generator to produce electricity for use on site or for sale to the grid. A closedloop three-cell cooling tower will be used to dispose of waste heat from the steam turbine.

This PSD permit for the modification requires the use of Best Available Control Technology

(BACT) to limit emissions of nitrogen oxides (NOw), carbon monoxide (CO), total particulate

matter (PM), PM under 10 micrometers (jim) in diameter (PMio), PM under 2.5jirn in diameter

(PM2s), and greenhouse gases (GHG), to the greatest extent feasible. Air pollution emissions

from the modification will not cause or contribute to violations of any National Ambient Air

Quality Standards (NAAQS) or any applicable PSD increments for the pollutants regulated under

the permit.

Additional equipment includes the construction of an additional cooling tower and an emergency

natural gas engine to power the emergency boiler recirculation pump.

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Final PSD Permit

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EQUIPMENT LAST

Table 1 lists the ne equipment that \ill be regulated by the proposed PSD permit:

Table 1 - New Equipment List Regulated by the PSD Permit

ID Unit Description

- I One Stoker Boiler sith • Biomass—tred with natural gas burners for start-up

Grate • Maximum heat input of approximately 468 MMBtuhr and steam generation rate of

250.000 il’s, hr

• Equipped vUth to natural gas burners, each with a maximum rated heat input of 62.5

MMBtu/hr

• Equipped with selectie non-catalytic reduction (SNCR) system to reduce \O and

multiclone ss ith an electrostatic precipitator (ESP) to control PM emissions

[2 cooling foser • composed of three cells with an expected water load ol 4.24 gallons per minute per square

IboL

13 Emergency Engine • 256 lip at 1.800 rpm

• Spark-ignition internal combustion, natural gas-lired

• Possers emergency boiler recirculation pump

• 40 CER Part 60 - Subpart JJJJ Compliant

Table 2 lists the existing equipment that is not included in this PSD permit. The equipment listed

helo is permitted by the District and the Permittee must comply with all applicable

requirements of the PSD permit (Permit No. 94-PU-I 8) issued by the District. Table 2 is

provided for reference purposes only:

Table 2 - Existing Equipment List

ID Unit Description

I 4 One Wellons Stoker l3oiler • Biomass-tired

• Maximum annual acrage heat input of approximately 116.4 MMRtuihr

• Equipped with SNCR system to reduce NO. and multiclone with ESP to control PM

emissions

• Equipped with one 30.400 fl hid storage bin. 2 hog fuel bins. 2 .ood chip fuel bins

15 One Cons cyance System • (2) cyclones with combined hloss rate of51.004 schin

• (I) 7.118 ft2 MAC Pulse Jet Baghouse ss ith 300hp Blower

• (1) 35” x 35” Rotary Airlock

• (I) Buhler en-masse. 19”. 22tph Cons ey or

• (2) Each overhead storage bins with enclosed sides

(6 One Spra% (nit • closed loop unit equipped with intLgrated. negative pressure. mist collection system and

65’ exhaust stack

[7 One Wood Chip I oading • (I) Platform truck dumper

Facility • (1) Wood chip convey inc system v ith dust containment hood

• (I) 200hp. 59.000C FM Rader hlos er

[8 Sesen Dc-greasing tanks • Non-solvent based tanks

1 9 One Gas Storage lank • Abuse ground with 10.000 gallon capacity tank

1 10 One Painting Operation • Miscellaneous painting operation

Ill Drying Kilns • (8) steam-heated. double-track. lumber drying kilns

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Sierra Pac’I/k Industries— InIerson (S. I C 12—()I.

I ma! I’S!) Permit

Ipril ‘014
PERMIT CONDITIONS

PERMIT EXPIRATION

As provided in 40 CFR § 52.21(r), this PSD permit shall become invalid if construction:

A. is not commenced (as defined in 40 CFR § 52.2 l(b)(9)) within 18 months after the

approval takes effect; or

B. is discontinued for a period of 18 months or more; or

C. is not completed within a reasonable time.

IL PERMIT NOTIFICATION REQUIREMENTS

Permittee shall notify EPA Region IX by letter or by electronic mail, to 9jj2agov,

of the:

A. date construction is commenced, postmarked within 30 days of such date;

B. actual date of initial startup, as defined in 40 CFR § 60.2, postmarked within 15 days

of such date;

C. date upon which initial performance tests will commence, in accordance with the

provisions of Conditions XH and I, postmarked not less than 30 days prior to such

date. Notification may be provided with the submittal of the performance test

protocol required pursuant to Conditions XH and I; and

D. date upon which initial performance evaluation of the continuous emissions

monitoring system (CEMS) will commence in accordance with 40 CFR § 60.13(c),

postmarked not less than 30 days prior to such date. Notification may be provided

with the submittal ofthe CEMS performance test protocol required pursuant to

Condition XI.

III. FACILITY OPERATION

A. At all times, including periods of startup, shutdown, shakedown, and malfunction,

Permittee shall, to the extent practicable, maintain and operate the Facility, including

associated air pollution control equipment, in a manner consistent with good air

pollution control practice for minimizing emissions. Determination of whether

acceptable operating and maintenance procedures are being used will be based on

information available to EPA, which may include, but is not limited to, monitoring

results, opacity observations, review of operating maintenance procedures and

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inspection of the Facility.

B. The Permittee shall operate and maintain Ui, U2 and U3 in a manner consistent with

good engineering practices for its full utilization.

C. As soon as practicable following initial startup of the facility (as defined in 40 CFR §

60.2) but prior to commencement of commercial operation (as defined in 40 CFR §

72.2), and thereafter, the Permittee shall develop and implement an operation and

maintenance plan for UI, U2 and U3. At a minimum, the plan shall identify

measures for assessing the performance of U!, U2, and U3, the acceptable range of

performance measures for achieving the desired output, the methods for monitoring

the performance measures, and the routine procedures for maintaining UI, U2 and U3

in good operating condition.

IV. MALFUNCTION REPORTING

A. Permittee shall notify EPA at j9jea.gov within two (2) working days

following the discovery of any failure of air pollution control equipment or process

equipment, or failure of a process to operate in a normal manner, which results in an

increase in emissions above the allowable emission limits stated in Section Xofthis

permit.

B. In addition, Permittee shall provide an additional notification to EPA in writing or

electronic mail within fifteen (15) days of any such failure described under Condition

IV.A. This notification shall include a description ofthe malfunctioning equipment or

abnormal operation, the date ofthe initial malfunction, the period of time over which

emissions were increased due to the failure, the cause ofthe failure, the estimated

resultant emissions in excess of those allowed in Section X, and the methods utilized

to mitigate emissions and restore normal operations.

C. Compliance with this malfunction notification provision shall not excuse or otherwise

constitute a defense to any violation of this permit or any law or regulation such

malfunction may cause.

V. RIGHT OF ENTRY

The EPA Regional Administrator, and/or an authorized representative, upon the

presentation of credentials, shall be permitted:

A. to enter the premises where the Facility is located or where any records are required

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to be kept under the terms and conditions ofthis PSD Permit;

B. during normal business hours, to have access to and to copy any records required to

be kept under the terms and conditions of this PSD Permit;

C. to inspect any equipment, operation, or method subject to requirements in this PSD

Permit; and

D. to sample materials and emissions from the source(s).

VI. TRANSFER OF OWNERSHIP

In the event of any changes in control or ownership of the Facility, this PSD Permit shall

be binding on all subsequent owners and operators. Within 14 days of any such change

in control or ownership, Permittee shall notify the succeeding owner and operator ofthe

existence of this PSD Permit and its conditions by letter. Permittee shall send a copy of

this letter to EPA Region IX within 30 days of its issuance.

VII. SEVERABILITY

The provisions ofthis PSD Permit are severable, and, if any provision ofthe PSD Permit

is held invalid, the remainder ofthis PSD Permit shall not be affected.

VIII. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER

ENVIRONMENTAL LAWS

Permittee shall construct the Project in compliance with this PSD permit, the application

on which this permit is based, and all other applicable federal, state, and local air quality

regulations. This PSD permit does not release the Permittee from any liability for

compliance with other applicable federal, state and local environmental laws and

regulations, including the Clean Air Act.

IX. RESERVED

X. SPECIAL CONDITIONS

A. Boiler Annual Emission Limits

I. Annual emissions from Ui, in tons per year (tpy) (12-month rolling sum basis), shall

not exceed the following emission limits. These limits shall apply at all times,

including during startup and shutdown periods.

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Table 3 - Ui Rolling 12-Month Emission Limits

NO CO PM PMjo PM2

267 472 41 41 41

2. C02e emissions from UI shall not exceed 0.36 lb C02e/lb steam produced (12-month

annual rolling average basis). This C02e limit shall apply at all times, including

during startup and shutdown periods.

B. Air Pollution Control Equipment and Operation

The Permittee shall construct and operate U 1 and its associated equipment with an

energy efficient design and use good combustion practices as described in the

Permittee’s permit application and subsequent submissions to the EPA. This

includes, but not limited to, (1) construction and operation of an efficient, state-ofthe-art, air-cooled, reciprocating stepgrate stoker boiler that ensures good

combustion; (2) operation of the boiler as a cogeneration unit at the Facility; and (3)

operation and maintenance of the boiler in accordance with the manufacturer’s

recommendations.

As soon as practicable following initial startup of Ui (startup as defined in 40 CFR §

60.2) but prior to commencement of commercial operation (as defined in 40 CFR §

72.2), and thereafter, the Permittee shall continuously operate, and maintain the

following during boiler operations: an SNCR system for control of NOR, multiclone

collectors and an ESP for the control of PM, PMio and PM2.5, and good combustion

practices for the control of CO. The Permittee shall also perform any necessary

operations to minimize emissions so that emissions are at or below the emission

limits specified in this permit.

The Permittee shall also, to the extent practicable, maintain and operate equipment

and associated monitoring equipment in a manner consistent with good air pollution

control practice for minimizing emissions. Determination of whether such operation

and maintenance procedures are being used will be based on information available to

the Administrator which may include, but is not limited to, fuel use records,

monitoring results, review of operation and maintenance procedures, review of

operation and maintenance records. review of reports required by this Permit, and

inspection ofthe Facility.

C. Steam Production and Emission Limitations

1. Except as noted below under Condition XD., on and after the date of initial startup,

Permittee shall not discharge or cause the discharge from Ui into the atmosphere in

excess of the following:

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Table 4 - Ui Short-Term Emission Limits

Pollutant Ui

• 70,2 lbs/hr (3-hour block average)

• 0.13 lbsfMMBtu (12-month rolling basis)

• 0.15 lbsl MMBtu (3-hour block average)

• EPA Method 1-4 and 7E

• 107.7 lbs/hr (3-hour block average)

CO • 023 lbJMMBtu (3-hour block average)

• EPA Method 1-4 and 10

• 0,02 lbIMMl3tu (3-hour block average) PM, PM10PM2.5 • 9.4 lb/hr (hourly average), corrected to 12 /C02

2. CO emissions at all times from Ul, including startup and shutdown events as defined

ConditionsXD.3. and XD.4., shall not exceed 432 lbs/hr (hourly average).

3. Steam production from Ui shall not exceed 275,000 lbs/hr (24 hour block average).

4. Visible emissions from Ui, except for uncombined water vapor or during periods

defined in Condition XD., shall not exceed 20% opacity in any six minute period, as

verified by the continuous opacity monitoring system (COMS).

5. Visible emissions from the Ui shall not exceed 40% opacity for more than three

minutes out of any one 60-minute period.

6. At all times, including equipment startup and shutdown, Permittee shall minimize the

cause or discharge ofthe following emissions:

a. Dust from unpaved roads or any other non-vegetation-covered area.

b. Fugitive sawdust from fuel-handling devices and/or storage areas.

c. Char and/or bottom ash which is processed by the char handling systems or

removed from UI by other means.

d. Accumulation of sawdust or ash on outside surfaces including, but not limited to,

the main building, Ul, ESP, support pads, road areas. Surfaces shall be cleaned on

a regular basis to prevent the build-up of ash and/or fugitive dust.

e. Fuel dust or ash spilled due to an upset condition shall be cleaned up in a timely

manner. In no event shall spilled dust or ash be allowed to exist beyond 24 hours

of the upset.

D. Requirements during Startup and Shutdown

1. Only biomass fuels, as defined in ConditionXG.1, and Public Utilities Commission

(PUC)-quality pipeline natural gas shall be fired during periods of startup, shutdown,

and flame stabilization.

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2. For Ui, normal operating temperature shall be defined as the normal operating

temperature specified by the unit manufacturer.

3. For U!, startup shall be defined as the period beginning with UI not in operation and

concluding when Ui has reached a normal operating temperature. During startup. the

generator shall be separated from the electrical grid.

4. For UI, shutdown shall be defined as the period beginning with curtailment of fuel

feed and concluding when the recorded superheater outlet temperature reaches 150°F

and remains so for at least one hour. During shutdown, the generator shall be

separated from the electrical grid.

5. For UI, the duration of startup and shutdown periods and emissions of NON, CO. PM,

PMio and PM2.5 shall not exceed the following, as verified by the CEMS and fuel

usage data:

Table 5 -Ui Startup and Shutdown Limits

NO CO PM, PM10 PM2 Duration

(8 hour average> (8 hour average) (24 hour average)

Startup 702 lb/hr 108 lb/hr 8.93 lb/hr 24 hours

Shutdown 70.2 lb/hr 108 lb/hr 8.93 lb/hr 24 hours

6. For UI, the Permittee must operate the CIEMS during startup and shutdown periods.

7. For UI, the Permittee must record the time, date, and duration of each startup and

shutdown event.

8. For UI, the Permittee must keep records that include calculations of NON, CO. Pivi,

PMio, PM25 and emissions in lb/hr and lb/MMBtu during each startup and shutdown

event based on the CEMS and fuel usage data.

E. Auxiliary Equipment Emissions Limitations

I. Permittee shall not discharge or cause the discharge from each unit into the

atmosphere in excess ofthe following:

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Table 6 - U2 and U3 Emission Limits

Pollutant U2 U3

NO N/A • 0.78 lb/hr

N/A • 4.0 glhp-hr (3-hour block average)

6.11 lb/hr

PMI PMa • 0.272 lbs/hr (hourly average) • 0.0216 lb/hr

2. Except during an emergency, U3 shall be limited to operation for maintenance and

testing purposes. Annual hours of operation for U3, for maintenance and testing, shall

not exceed 100 hours per 12-month rolling average.

F. Operating Conditions and Work Practices

1. Low SNCR activation temperature shall be defined as the lowest operating

temperature for U! at which the SNCR system is recommended for operation to

reduce NO emissions as defined by the SNCR manufacturer. This temperature value

shall be included in the operation and maintenance plan required by Condition III.C.

2. For UI, SNCR systems for the control of NO shall be in operation at all times that

lJl exceeds the low SNCR activation temperature.

3. For Ul, the multiclones and ESP for the control of PM, PMio and PM25 shall be in

operation at all times during the combustion process.

4. U3 shall not operate during startup of UI, except when required for emergency

operations.

5. Wood waste collection and storage bin leaks shall be minimized at all times. All

identified wood waste collection and storage bin leaks, spills and upsets of any kind

shall be corrected or cleaned immediately, within 4 hours, as practicable, to correct

the leak, spill or upset.

6. Wood waste collection and storage bins shall be emptied on a schedule that ensures

that the cyclone-separator system does not become plugged.

7. Wood waste collection and storage bins, not including the fuel shed, shall remain

enclosed to mitigate the fugitive emissions from the unloading process.

8. All ash shall be transported in a wet condition in covered containers or stored in

closed containers at all times.

9. Fugitive dust generated from access and on-site roads shall be minimized by

application of water, dust palliative, chip-sealing, or paving.

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10. Fugitive dust from storage piles, processing area, and disturbed areas shall be

minimized by periodic cleanup and/or use of sprinklers, tarps, or dust palliative

agents.

11. During periods of high winds, Permittee shall take immediate action to correct

fugitive dust emissions from the chip processing area.

12. All necessary surfaces shall be cleaned or washed sufficiently to prevent wind-blown

dust from leaving the property boundaries.

13. All truck loading and unloading conducted at the facility shall be done in a manner

that minimizes spillage, and fugitive emissions.

14. For U2, the drift rate shall not exceed 0.0005%.

15. Each container holding volatile organic waste shall be labeled with the contents

identified and information noting the date when waste material was added.

16. The Permittee shall inspect all containers holding VOCs or waste, at least weekly, for

leaks and for deterioration caused by corrosion or other factors.

17. Containers holding ignitable or reactive waste must be located within the property

boundary at least 50 feet from the facility’s property line.

1 8. Incompatible wastes must not be placed in the same container. The treatment,

storage, and disposal of ignitable or reactive waste, and the commingling of wastes,

or wastes and materials, must be conducted so it does not:

a. Generate extreme heat, pressure, explosion, or violent reaction;

b. Produce uncontrolled toxic mists, fumes, dusts or gases in sufficient quantities to

threaten human health;

c. Produce flammable fumes or gases in sufficient quantities to pose a risk of fire or

explosions;

d. Damage the structural integrity of the device or facility containing the waste; or

e. Through other means threaten human health or the environment.

G. Fuel Restrictions

1. The following biomass fuels shall constitute the only fuel allowed for use as fuel in

U I, except during periods defined in Condition XD. and to counteract upset

conditions:

a. Untreated wood pallets, crates, dunnage, untreated manufacturing and

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construction wood debris from urban areas;

b. All agricultural crops or residues;

c. Mill residues including hog fuel, shavings, sawdust, trimmings, and bark.

d. Forest residues including treetops, non-merchantable sections ofthe stem,

branches, and bark, left on the ground after logging or accumulating as a result of

a storm, fire, delimbing, or other similar disturbance.

e. Non-merchantable forest biomass consisting of byproducts and residuals of forest

management activities identified to follow all of the following practices;

(1) Harvested pursuant to an approved timber management plan prepared in

accordance with the Zberg-Nejedly Forest practice Act of 1973 or other

locally or nationally approved plan; and

(2) Harvested for the purpose of forest fire fuel reduction or forest stand

improvement.

2. The heat input from pipeline natural gas shall not exceed 10% ofthe total heat input

to Ui on a 12-month rolling basis.

3, The heat input to U3 shall only be PUC—quality pipeline natural gas

H. Monitoring Conditions

1. For Ui, the Permittee shall maintain the following continuous monitoring systems at

all times when the combustion process is occurring:

a. The Permittee shall install, calibrate, operate and quality-assure a Continuous

Emissions Monitoring System (CEMS) that measures CO. NOR, and C02.

b. The CO and NO CEMS shall measure and record (i) CO and NO emissions in

ppmv, and (ii) exhaust gas CO and NO concentrations corrected to 12 percent by

volume stack gas CO2 dry basis.

c. The Permittee shall conduct initial certification ofthe CEMS in accordance with

Condition XH,2.

d. The Permittee shall operate and maintain a Continuous Opacity Monitoring

System (COMS) capable of measuring stack gas opacity.

e. The Permittee shall install a stack gas volumetric flowrate monitor, and steam

production rate monitor.

2. The CEMS and stack gas volumetric flowrate monitor for Ui shall meet the

applicable requirements of 40 CFR Part 60.13 and 40 CFR Part 60 Appendix B, and

40 CFR Part 60 Appendix F, Procedure 1.

3. Each CEMS shall complete a minimum of one cycle of operation (sampling,

analyzing, and data recording) for each successive 15-minute clock-hour period.

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4. Data sampling, analyzing, and recording of the CEMS shall also be adequate to

demonstrate compliance with emission limits during startup and shutdown.

5. The initial certification ofthe CEMS may either be conducted separately or as part of

the initial performance test of UI. The CEMS must undergo and pass initial

performance specification testing on or before the date ofthe initial performance test.

6. The CEMS shall be audited quarterly and tested annually to demonstrate that it meets

the specifications in Condition XH.2. The Permittee shall perform a full stack

traverse during the initial run of annual relative accuracy test auditing ofthe CEMS,

with testing points selected according to 40 CFR Part 60 Appendix A, Method 1.

7. The Permittee shall submit a CEMS performance test protocol to EPA in accordance

with Condition XI.2.d.

8. For Ui, opacity shall be monitored by a COMS that meets the applicable

requirements of 40 CFR Part 60 Appendix B, Performance Specification 1.

9. The COMS shall have a span value of 100% and utilize a computer or other facility

which has the capability of interpreting sampling data and producing output to

demonstrate compliance with applicable standards. The span value for the continuous

measuring system for measuring opacity shall be between 60 and 80%. The span for

the recording instrumentation for the opacity meter shall be 0 to 100%.

10. The operator/owner shall monitor the following combustion and control parameters

for U 1 on a continuous basis unless otherwise noted:

a. Combustion temperature (at the superheater tube area)

b. Temperature at air heater outlet

c. Hourly steam production rate

11. The Permittee shall furnish the EPA with a written report ofthe results of

performance tests as identified in this Permit within 60 days of completion.

12. The Permittee shall continuously monitor the ESP for transformer/rectifier (T/R set)

On/Offstatus and Rapper On/Off status.

13. The Permittee shall record hourly readings of ESP zone voltage (minimum 10

kilovolts, maximum 60 kilovolts) and amps on the operator log.

14. For U3, the Permittee shall install and maintain an operational non-resettable elapsed

time meter to record the operating time ofthe emergency engine.

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I. Performance Tests

1. Performance tests shall be performed by an independent testing firm, and conducted

in accordance with the test methods set forth in 40 CFR Part 60.8 and 40 CFR Part

60-Appendix A, as modified below:

a. EPA Methods 1-4, 18 and 25A for VOC emissions. Methods 18 and 25A may

both be used simultaneously to quantify the annual emissions ofthe organic

compounds listed in 40 CFR 51.100(s)(l) (using Method 18) and subtract this

amount from the annual total VOC emissions (as determined from Method 25A).

b. EPA Methods 1-4 and 6(c) for S02 emissions.

c. EPA Methods 1-4 and 10 for CO emissions.

d. EPA Methods 1-4 and 7E for NO emissions.

e. EPA Methods 1-4 and 29 for Lead (Pb) emissions.

f. EPA Methods 1-4 and 5 for PM emissions. (This performance test may be done

concurrently with EPA Method 29 for Pb emissions.)

g. EPA Methods 1-4, 5 and 202 with a two-hour test run period for each test for

PMio and PM2.s emissions. In lieu of Method 5, the Permittee may use Other Test

Method 201A.

h. EPA Method 3A for C02 emissions.

i. The provisions of 40 CFR Part 60.8(f).

j. In lieu ofthe specified test methods, alternative methods may be used with prior

written approval from EPA.

2. ForUl,

a. Within 60 days after achieving normal operation, but not later than 120 days after

the modification, the Permittee shall conduct initial performance tests (as

described in 40 CFR Part 60.8) for CO, C02, NOX, Pb, PM, PMio, PM25, SO2 and

VOC emissions. The performance test requirements for CO, NON, and C02 shall

be demonstrated using the initial relative accuracy test auditing of the C EMS, for

each applicable pollutant, required in Condition XH.6.

b. For performance test purposes, sampling ports, platforms, and access shall be

provided on the emission unit exhaust system in accordance with the requirements

of 40 CFR Part 60.8(e).

c. Annual performance tests of PMio, CO. CO2, and NO shall be conducted at no

less than 90 percent of the facility’s maximum steam production rate of 250,000

lb/hr. The performance test requirements for CO. NON, and C02 shall be

demonstrated using the annual relative accuracy test auditing of the CEMS, for

each applicable pollutant, required in Condition XH.6.

d. The Permittee shall submit a performance test protocol to EPA no later than 30

days prior to a performance test to allow review of the test plan and to arrange for

an observer to be present at the test. The performance test shall be conducted in

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accordance with the submitted protocol, and any changes required by EPA.

3. For U2, the Permittee shall do the following:

a. Perform weekly tests of the blow-down water quality using an EPA-approved

method. The operator shall maintain a log that contains the date and result of each

blow-down water quality test, the water circulation rate at the time of the test, and

the resulting mass emission rate. This log shall be maintained onsite for a

minimum of five years and shall be provided to EPA and District personnel upon

request.

b. Calculate PM, PMio, and PM2.5 emission rate using an EPA-approved calculation

based on the total dissolved solids (TDS) and water circulation rate.

c. Conduct all required cooling tower water quality tests in accordance with an EPAapproved test and emissions calculation protocol. Thirty (30) days prior to the

first such test, the operator shall provide a written test and emissions calculation

protocol for EPA review and approval, with a copy to the District as specified in

Condition XII.

d. Establish a maintenance procedure that states how often and what procedures will

be used to ensure the integrity of the drift eliminators and to ensure compliance

with recirculation rates. This procedure is to be kept onsite and made available to

EPA and District personnel upon request. The Permittee shall promptly report any

deviations from this procedure.

4. For U3, the Permittee shall conduct an initial performance test (as described in

40 CFR 60.4244) for NO and CO and emissions and at least every five years

beginning ten years after the initial performance test (within 30 days ofthe tenth

anniversary of the initial performance test date).

5. Upon written request from the Permittee, and adequate justification, EPA may waive

a specific annual test and/or allow for testing to be done at less than maximum

operating capacity.

J. Recordkeeping and Reporting

I. The Permittee shall maintain a file of all records, data, measurements, reports, and

documents related to the operation of the Facility, including, but not limited to, the

following: all records or reports pertaining to adjustments and/or maintenance

performed on any system or device at the facility; initial performance test data for Ut,

documents from the fuel supplier for Condition XD. 1.; and all other information

required by this permit recorded in a permanent form suitable for inspection.

2. The Permittee shall calculate and record on a daily basis the average boiler heat input

in MMbtu/hr (24-hr daily block average). The calculation shall be based on

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April 2014
manufacturer ratio of maximum design heat rating to design steam (maximum design

(MMbtu/hr) divided by design steam (lb/hr)) multiplied by the total steam generated

each day. The heat input, as determined from this, shall not exceed 468 MMBtu/hr on

a monthly basis.

3. By the last day of each month, the Permittee shall calculate and record the 12-month

rolling sum of CO, NON. PM, PMrn, and PM2.5 emissions in tpy for U! for the

previous 12 months in accordance with ConditionXA.].

a. CO and NO emissions calculations shall be based on emissions data acquired by

the CO and NO CEMS.

b. PM, PMio, and PM25 shall be based on emission factors from the most recent

performance test.

4. By the last day of each month, the Permittee shall calculate and record the 12-month

rolling average of C02e in lb C02e/lb steam produced for Ui for the previous 12

months in accordance with Condition XA. 2.

a. CO2 emissions calculations shall be based on emissions data acquired by the CO2

CEMS, and the applicable calculation methodology contained in

40 CFR 98.33(a)(4) in effect on January 1, 2014.

b. CH4 and N20 emissions calculations shall be based on the following:

(1) The heat input ofthe applicable emission unit.

(2) The default Cl-14 and N20 emission factors in Table C-2 of 40 CFR Part 98,

Subpart C as published on November 29, 2013 (78 FR 71952) and effective

on January 1, 2014, and provided in the following table.

n Factor Fuel GI-IG Pollutant

Wood and Wood CH4 — u i 2

Residuals N20 0.0036

CH4 0.001 Natural Gas

N20 0.000 1

(3) The applicable calculation methodology contained in 40 CFR 98.33 in effect

on January 1, 2014.

c. The Permittee shall calculate the C02e emissions based on the procedures and

Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40

CFR Part 98, Subpart A, Table A- 1, as published on November 29, 2013 (78 FR

71948) and effective on January 1, 2014, and provided in the following table.

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GHG Pollutant GWP

CO2 1

CH4 25

N20 298

Sulfur hexafluoride (SF 6) 22,800

d. The total C02e shall be based on the sum of the C02e for CR4, N20 and C02.

e. Steam production shall be based on daily records of the hourly steam production

rate output monitoring device.

5. For Ui, the Permittee shall maintain the following records:

a. The total monthly hours of operation;

b. 3-hour averages of CO and NO emissions in units of lbs/MMBtu and lbs/hour

dry basis. All time periods when the boiler is not in operation shall be excluded

from the averages. The monthly average of CO and NO emissions expressed in

lbs/hour shall also be included;

c. 3-hour average calculations of PMio emissions in units of lbs/MMBtu and

lbs/hour dry basis using the most recent annual PMio source test;

d. Notification of all periods the continuous monitors were not functioning and the

reasons for the same;

e. Steam production rate averaged over a daily (24-hour) period.

6. The Permittee shall maintain CEMS and COMS records that include the following:

a. The occurrence and duration of any startup, shutdown, or malfunction,

performance testing, evaluations, calibrations, checks, adjustments maintenance,

duration of any periods during which a CEMS or COMS is inoperative, and

corresponding emission measurements.

b. Date, place, and time of measurement or monitoring equipment maintenance

activity;

c. Operating conditions at the time of measurement or monitoring equipment

maintenance activity;

d. Date, place, name of company or entity that performed the measurement or

monitoring equipment maintenance activity and the methods used; and

e. Results ofthe measurement or monitoring equipment maintenance.

7. The Permittee shall maintain records and submit a written report of all excess

emissions and opacity measurements to EPA and the District semi-annually, except

when more frequent reporting is specifically required by an applicable subpart; or the

Administrator, on a case-by-case basis, determines that more frequent reporting is

necessary to accurately assess the compliance status ofthe source. The report is due

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on the 30th day following the end of each semi-annual period and shall include the

following:

a. Time intervals, data and magnitude ofthe excess emissions, the nature and cause

(if known), corrective actions taken and preventive measures adopted;

b. Applicable time and date of each period during which the CEMS or COMS was

inoperative (monitor down-time). except for zero and span checks, and the nature

of CEMS or COMS repairs or adjustments;

c. A statement in the report of a negative declaration; that is, a statement when no

excess emissions occurred or when the CEMS or COMS has not been inoperative,

repaired, or adjusted;

d. Any failure to conduct any required source testing, monitoring, or other

compliance activities; and

e. Any violation of limitations on operation, including but not limited to restrictions

on hours of operation.

8. A period of monitor down-time shall be any unit operating clock hour in which

sufficient data are not obtained by the CEMS to validate the hour for NOR, CO. or

C02.

9. Excess emissions shall be defined as any period in which emissions exceed the

emission limits and standards set forth in ConditionsXC.], XC.2, XC.3 andXD.5.

10. Excess emissions indicated by the CEMS, COMS, source testing, or compliance

monitoring shall be considered violations of the applicable emission limit or standard

for the purpose of this permit.

11. For UI, daily records of fuel received other than natural gas shall be maintained.

These records shall include a detailed description of the fuel supplier, fuel type and

tons received.

12. For U3, the Permittee shall maintain records ofthe following: hours of operation,

purpose of operation, fuel usage on hourly basis and calculated PM/PMio emissions

based on manufacturer emissions specifications and fuel usage data.

13. Unless otherwise specified herein, all records required by this PSD Permit shall be

retained for not less than five years following the date of such measurements,

maintenance, reports, and/or records.

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XI. ACROYNMS AND ABBREVIATIONS

ASTM American Society for Testing and Materials

BACT Best Available Control Technology

BTU British Thermal Unit

CAA Clean Air Act

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations

CR4 Methane

CHP Combined Heat and Power

CO Carbon Monoxide

CO2 Carbon Dioxide

C0 2e Carbon Dioxide Equivalents

CTG Combustion Turbine Generator

CTM Conditional Test Method

COMS Continuous Opacity Monitoring System

CU Cogeneration Unit

District Shasta County Air Quality Management District

DLN Dry Low NOx

(d)scf (dry) Standard Cubic Feet

EPA Environmental Protection Agency

ESP Electrostatic Precipitator

Facility Sierra Pacific Industries — Anderson Division

FR Federal Register

GHG Greenhouse Gases

gpm Gallons Per Minute

gr Grains

HHV Higher Heating Value

hr Hour

lbs Pounds

lb C0 2e/lb steam Pounds of CO2 Equivalents per Pound ofSteam Produced

MMBtu Million British Thermal Units

MW Megawatt

NAAQS National Ambient Air Quality Standards

NO2 Nitrogen Dioxide

N2O Nitrous Oxide

NOx Oxides of Nitrogen

NSPS New Source Performance Standards

Owner or Operator Sierra Pacific Industries

Permittee Sierra Pacific Industries

PM Total Particulate Matter

PM2.5 Particulate Matter with aerodynamic diameter less than 2.5 micrometers

PM10 Particulate Matter with aerodynamic diameter less than 10 micrometers

ppm Parts Per Million

ppmvd Parts Per Million by Volume, Dry basis

ppmv Parts Per Million by Volume

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PSD Prevention of Significant Deterioration

RATA Relative Accuracy Test Audit

SCAQMD Shasta County Air Quality Management District

SCR Selective Catalytic Reduction

SNCR Selective Non-Catalytic Reduction

SO2 Sulfur Dioxide

SOx Oxides of Sulfur

TDS Total Dissolved Solids

tpy Tons Per Year

yr Year

XII. AGENCY NOTIFICATIONS

A. Unless otherwise directed by the EPA or this permit, the owner or operator shall

submit all information required to be reported by this permit other than notification of

change of ownership, including, but not limited to, test plans, reports, certifications,

notifications and requests to approve alternative monitoring or reporting, to the

following address:

Director, Enforcement Division (Attn: ENF-2-1)

U.S. Environmental Protection Agency, Region IX

75 Hawthorne Street

San Francisco, CA 94105-3901

EMAIL: aco r9a epa.ov

B. Unless otherwise directed by the EPA or this permit, the owner or operator shall

submit all other information pertaining to this permit or facility, including but not

limited to, applications to add, replace or modify an emission unit or control

equipment, notification of change of ownership, and information concerning any

other changes that may contravene existing permit terms, to:

Director, Air Division (Attn: AIR-3)

U. S. Environmental Protection Agency Region IX

75 Hawthorne Street

San Francisco, CA 94105-3901

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C. The owher or operator shall submit a copy of all documents required to be submitted

pursuant to this permit, including but not limited to Sections X.A and X.B, to:

Air Pollution Control Officer

Shasta County Air Quality Management District

1855 Placer Street, Suite 101

Redding, CA 96001-1759

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