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 12-01 

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 of the Clean Air Act (CAA), Subchapter I, 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 of Significant 

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 of the 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. 

 

Deborah Jordan Date 

Director, Air Division
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Sierra Pacific Industries- Anderson (SAC 12-01) 

Proposed Final PSD Permit

 – April 2014November 2013

SIERRA PACIFIC INDUSTRIES - ANDERSON (SAC 12-01)

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 SPIAnderson 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 (NOx), carbon monoxide (CO), total particulate 

matter (PM), PM under 10 micrometers (μm) in diameter (PM10), PM under 2.5μm in diameter 

(PM2.5), 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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Proposed Final PSD Permit

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EQUIPMENT LIST 

Table 1 lists the new equipment that will be regulated by the proposed PSD permit: 

Table 1 - New Equipment List Regulated by the PSD Permit 

ID Unit Description 

U1 One Stoker Boiler with 

Grate 

 Biomass-fired with natural gas burners for start-up 

 Maximum annual average heat input of approximately 468 MMBtu/hr and steam 

generation rate of 250,000 lbs/hr 

 Equipped with two natural gas burners, each with a maximum rated heat input of 62.5 

MMBtu/hr 

 Equipped with selective non-catalytic reduction (SNCR) system to reduce NOx, and 

multiclone with an electrostatic precipitator (ESP) to control PM emissions 

U2 Cooling Tower  Composed of three cells with an expected water load of 4.24 gallons per minute per square 

foot. 

U3 Emergency Engine  256 hp at 1,800 rpm 

 Spark-ignition internal combustion, natural gas-fired 

 Powers emergency boiler recirculation pump 

 40 CFR Part 60 - Subpart JJJJ Compliant 

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

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

requirements of the PSD permit (Permit No. 94-PO-18) issued by the District. Table 2 is 

provided for reference purposes only: 

Table 2 - Existing Equipment List 

ID Unit Description 

U4 One Wellons Stoker Boiler  Biomass-fired with natural gas burners for start-up

 Maximum annual average heat input of approximately 116.4 MMBtu/hr 

 Equipped with SNCR system to reduce NOx, and multiclone with ESP to control PM 

emissions 

 Equipped with one 30,400 ft3, fuel storage bin, 2 hog fuel bins, 2 wood chip fuel bins 

U5 One Conveyance System  (2) Cyclones with combined flow rate of 51.004 scfm 

 (1) 7,118 ft2 MAC Pulse Jet Baghouse with 300hp Blower 

 (1) 35” x 45” Rotary Airlock 

 (1) Buhler en-masse, 19”, 22tph Conveyor 

 (2) Each overhead storage bins with enclosed sides 

U6 One Spray Unit  Closed loop unit equipped with integrated, negative pressure, mist collection system and 

65’ exhaust stack 

U7 One Wood Chip Loading 

Facility 

 (1) Platform truck dumper 

 (1) Wood chip conveying system with dust containment hood 

 (1) 200hp, 59,000CFM Rader blower 

U8 Seven De-greasing Tanks  Non-solvent based tanks 

U9 One Gas Storage Tank  Above ground with 10,000 gallon capacity tank 

U10 One Painting Operation  Miscellaneous painting operation 

U11 Drying Kilns  (8) steam-heated, double-track, lumber drying kilns 

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Sierra Pacific Industries- Anderson (SAC 12-01) 

Proposed Final PSD Permit

 – April 2014November 2013

PERMIT CONDITIONS 

I. 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 § 52.21(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. 

II. PERMIT NOTIFICATION REQUIREMENTS 

Permittee shall notify EPA Region IX by letter or by electronic mail, to aeo_r9@epa.gov, 

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 X.H 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 X.H 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 of the CEMS performance test protocol required pursuant to 

Condition X.I. 

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 U1, 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 U1, U2 and U3. At a minimum, the plan shall identify 

measures for assessing the performance of U1, 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 U1, U2 and U3 

in good operating condition. 

IV. MALFUNCTION REPORTING 

A. Permittee shall notify EPA at aeo_r9@epa.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 X of this 

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 of the malfunctioning equipment or 

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

emissions were increased due to the failure, the cause of the 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 of this 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 of the 

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 of this PSD Permit are severable, and, if any provision of the PSD Permit 

is held invalid, the remainder of this 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 

1. Annual emissions from U1, 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 - U1 Rolling 12-Month Emission Limits 

NOx CO PM PM10 PM2.5

267 472 41 41 41

2. CO2e emissions from U1 shall not exceed 0.36 lb CO2e/lb steam produced (12-month 

annual rolling average basis). This CO2e 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 U1 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 U1 (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 NOx, multiclone 

collectors and an ESP for the control of PM, PM10 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 of the Facility. 

C. Steam Production and Emission Limitations 

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

Permittee shall not discharge or cause the discharge from U1 into the atmosphere in 

excess of the following: 
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Table 4 - U1 Short-Term Emission Limits 

Pollutant U1 

NOx

 70.2 lbs/hr (3-hour block average) 

 0.13 lbs/MMBtu (12-month rolling basis) 

 0.15 lbs/ MMBtu (3-hour block average) 

 EPA Method 1-4 and 7E

CO

 107.7 lbs/hr (3-hour block average)

 0.23 lb/MMBtu (3-hour block average)

 EPA Method 1-4 and 10

PM, PM10, PM2.5

 0.02 lb/MMBtu (3-hour block average)

 9.4 lb/hr (hourly average), corrected to 12% CO2

2. CO emissions at all times from U1, including startup and shutdown events as defined 

Conditions X.D.3. and X.D.4., shall not exceed 432 lbs/hr (hourly average). 

3. Steam production from U1 shall not exceed 275,000 lbs/hr (24 hour block average). 

4. Visible emissions from U1, except for uncombined water vapor or during periods 

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

verified by the continuous opacity monitoring system (COMS). 

5. Visible emissions from the U1 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 of the 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 U1 by other means. 

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

the main building, U1, 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 Condition X.G.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 U1, normal operating temperature shall be defined as the normal operating 

temperature specified by the unit manufacturer. 

3. For U1, startup shall be defined as the period beginning with U1 not in operation and 

concluding when U1 has reached a normal operating temperature. During startup, the 

generator shall be separated from the electrical grid. 

4. For U1, 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 U1, the duration of startup and shutdown periods and emissions of NOx, CO, PM, 

PM10 and PM2.5 shall not exceed the following, as verified by the CEMS and fuel 

usage data: 

Table 5 - U1 Startup and Shutdown Limits 

NOx 

(8 hour average)

CO 

(8 hour average)

PM, PM10, PM2.5 

(24 hour average) Duration 

Startup 70.2 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 U1, the Permittee must operate the CEMS during startup and shutdown periods. 

7. For U1, the Permittee must record the time, date, and duration of each startup and 

shutdown event. 

8. For U1, the Permittee must keep records that include calculations of NOx, CO, PM, 

PM10, PM2.5 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 

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

atmosphere in excess of the following:
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Table 6 - U2 and U3 Emission Limits 

Pollutant U2 U3

NOx N/A  0.78 lb/hr 

CO N/A  4.0 g/hp-hr (3-hour block average)

 6.11 lb/hr

PM/ PM10  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 U1 at which the SNCR system is recommended for operation to 

reduce NOx 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 U1, SNCR systems for the control of NOx shall be in operation at all times that 

U1 exceeds the low SNCR activation temperature. 

3. For U1, the multiclones and ESP for the control of PM, PM10 and PM2.5 shall be in 

operation at all times during the combustion process. 

4. U3 shall not operate during startup of U1, 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. 

18. 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 

U1, except during periods defined in Condition X.D. and to counteract upset 

conditions: 

a. Untreated wood pallets, crates, dunnage, untreated manufacturing and 
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Sierra Pacific Industries- Anderson (SAC 12-01) 

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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 of the stem, 

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

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

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

management activities 

c.e.Wood and wood wastes identified to follow all of the following practices; 

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

accordance with the Z'berg-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% of the total heat input 

to U1 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 U1, 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, NOx, and CO2. 

b. The CO and NOx CEMS shall measure and record (i) CO and NOx emissions in 

ppmv, and (ii) exhaust gas CO and NOx concentrations corrected to 12 percent by 

volume stack gas CO2 dry basis. 

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

Condition X.H.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 U1 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 of the CEMS may either be conducted separately or as part of 

the initial performance test of U1. The CEMS must undergo and pass initial 

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

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

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

traverse during the initial run of annual relative accuracy test auditing of the 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 X.I.2.d.The Permittee shall submit a CEMS performance test protocol 

to the EPA no later than 30 days prior to the test date 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 accordance with the submitted protocol and any changes required by 

EPA. 

8. For U1, 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 U1 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 of the 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/Off status 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. 
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14. For U3, the Permittee shall install and maintain an operational non-resettable elapsed 

time meter to record the operating time of the emergency engine. 

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 of the organic 

compounds listed in 40 CFR 51.100(s)(1) (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 SO2 emissions. 

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

d. EPA Methods 1-4 and 7E for NOx 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 

PM10 and PM2.5 emissions. In lieu of Method 5, the Permittee may use Other Test 

Method 201A. 

h. EPA Method 3A for CO2 emissions. 

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

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

written approval from EPA. 

2. For U1, 

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, CO2, NOx, Pb, PM, PM10, PM2.5, SO2 and 

VOC emissions. The performance test requirements for CO, NOx, and CO2 shall 

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

each applicable pollutant, required in Condition X.H.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 PM10, CO, CO2, and NOx 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, NOx, and CO2 shall be 

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

each applicable pollutant, required in Condition X.H.6. 
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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 

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, PM10, 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 Ppermittee shall promptly report 

any deviations from this procedure. 

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

40 CFR Part 60.4244) for NOx, and CO and emissions and at least every five years 

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

1. 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 U1, 

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

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

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,record the efficiency of U1 daily. 

The heat input, as determined from the U1 efficiency and steam production rate, shall 

not exceed 468 MMBtu/hr on a monthly basis. 

3. By the last30th day of each month, the Permittee shall calculate and record the 12-

month rolling sum of CO, NOx, PM, PM10, and PM2.5 emissions in tpy for U1 for the 

previous 12 months in accordance with Condition X.A.1. 

a. CO and NOx emissions calculations shall be based on emissions data acquired by 

the CO and NOx CEMS. 

b. PM, PM10, and PM2.5 shall be based on emission factors from the most recent 

performance test. 

4. By the last30th day of each month, the Permittee shall calculate and record the 12-

month rolling average of CO2e in lb CO2e/lb steam produced for U1 for the previous 

12 months in accordance with Condition X.A.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 N2O emissions calculations shall be based on the following: 

(1) (i) Tthe heat input of the applicable emission unit.,

(2) T(ii) the default CH4 and N2O 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. 

Fuel Type GHG Pollutant Emission Factor 

(kg/MMBtu) 

Wood and Wood 

Residuals 

CH4 0.0072 

N2O 0.0036 

Natural Gas 

CH4 0.001 

N2O 0.0001 

, and 

b.(3) (iii) Tthe applicable calculation methodology contained in 40 CFR 98.33

in effect on January 1, 2014. 

c. The Permittee shall calculate the CO2e 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 
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Proposed Final PSD Permit

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

published on October 30, 2009 (74 FR 56395). 

GHG Pollutant GWP 

CO2 1 

CH4 25 

N2O 298 

Sulfur hexafluoride (SF6) 22,800

c.

d. The total CO2e shall be based on the sum of the CO2e for CH4, N2O and CO2. 

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

rate output monitoring device. 

5. For U1, the Permittee shall maintain the following records: 

a. The total monthly hours of operation; 

b. 3-hour averages of CO and NOx 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 NOx emissions expressed in 

lbs/hour shall also be included; 

c. 3-hour average calculations of PM10 emissions in units of lbs/MMBtu and 

lbs/hour dry basis using the most recent annual PM10 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 of the 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 
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Proposed Final PSD Permit

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

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

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

following: 

a. Time intervals, data and magnitude of the 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 NOx, CO, or 

CO2. 

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

emission limits and standards set forth in Conditions X.C.1, X.C.2, X.C.3 and X.D.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 U1, 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 Ppermittee shall maintain records of the following: hours of operation, 

purpose of operation, fuel usage on hourly basis and calculated PM/PM10 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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Sierra Pacific Industries- Anderson (SAC 12-01) 

Proposed Final PSD Permit

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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 

CH4 Methane 

CHP Combined Heat and Power 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

CO2e 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 CO2e/lb steam Pounds of CO2 Equivalents per Pound of Steam 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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Sierra Pacific Industries- Anderson (SAC 12-01) 

Proposed Final PSD Permit

 – April 2014November 2013

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: aeo_r9@epa.gov

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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Proposed Final PSD Permit

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C. The owner 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