Sierra Pacific Industries (SAC 12-01) 

Proposed PSD Permit September 20123

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)

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT

PERMIT CONDITIONS

PROJECT DESCRIPTION

Sierra Pacific Industries, Inc. (SPI) has 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 

clean cellulosic 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 wood-fired 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 proposing issuing theis PSD permit to allow SPI to construct and 

operate the additional boiler and related auxiliary equipment described in this permit at the SPIAnderson facilityfor this additional boiler to incorporate the proposed facility modifications. The 

PSD permit previously issued by the District to SPI is still in effect and applies to existing 

equipment at the SPI-Anderson 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 twothree-cell cooling tower will be used to dispose of waste heat from the steam turbine.

This PSD permit for the proposed 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) and PM under 

2.5μm in diameter (PM2.5) to the greatest extent feasible. Air pollution emissions from the 

proposed 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. 

EQUIPMENT LIST

Table 1 lists the new equipment that will be regulated by the proposed PSD permit:
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Table 1: New Equipment List Regulated by the PSD Permit

ID Unit Description

U1 One Stoker Boiler 

with Vibrating 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 two-cells three cells with an expected water load of 

4.24 gallons per minute per square foot. 

U3 Emergency Engine  256hp at 1,800 rpm

 Spark-ignition Internal Combustion, Nnatural 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. Table 2 is provided for reference purposes only:
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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, 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

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

U10 One Painting Operation

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 of the:

A. date construction is commenced, postmarked within 30 days of such date; 
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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.G H and HI, 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.G H and HI; 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.HI.

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 

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 R9.AEO@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.
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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 

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 
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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

Annual emissions, in tons per year (tpy) on a 12-month rolling average basis, shall not 

exceed the following: 

Table 3- U1 Rolling 12-Month Emission Limits

ID NOx CO PM PM10 PM2.5

U1 267 472 41 41 41

B. Air Pollution Control Equipment and Operation

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, Permittee shall continuously operate, and maintain the following during 

boiler operations: an SNCR system for control of NOx, and multiclone collectors and an 

ESP for the control of PM, PM10 and PM2.5, and good combustion practices for the 

control of CO. Permittee shall also perform any necessary operations to minimize 

emissions so that emissions are at or below the emission limits specified in this permit. 

Permittee shall also to the extent practicable, maintain and operate equipment in a manner 

consistent with good air pollution control practice for minimizing emissions.The 

Permittee shall employ the multiclone collectors, ESP and good combustion practices at 

all times when the combustion process is occurring in U1. 

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 each unit into the atmosphere in 

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

U1

NOx

 60.970.2 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 7

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 lbs/hr (hourly average)

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). 

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

34. 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). 

45. Visible emissions from the U1 shall not exceed 40% opacity for more than three minutes 

out of any one 60-minute period.

56. 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 clean cellulosic biomass fuels, as defined in Condition X.FG.1., and Public Utilities 

Commission (PUC)-quality pipeline natural gas shall be fired during startup and 

shutdown. PUC-quality pipeline natural gas shall not exceed a sulfur content of 0.20 

grains per 100 dry standard cubic feet (dscf) on a 12-month rolling average basis and 
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shall not exceed a sulfur content of 1.0 grains per 100 dscf, at any time.

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 Limitations

NOx

(hourly 8 hour

average)

CO

(hourly 8 hour

average)

PM, PM10, PM2.5

(24- hour average)

SO2

(hourly average) Duration

Startup 70.2 lb/hr 108 lb/hr 8.93 lb/hr 2.34 lb/hr 24 hours

Shutdown 70.2 lb/hr 108 lb/hr 8.93 lb/hr 2.34 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 SO2 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:

Table 6- U2 and U3 Emissions Limits

U2 U3

NOx

 4.0 g/kW-hr (3-hour block average)

 0.78 lb/hr 
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CO

 3.54.0 g/kWhp-hr (3-hour block 

average)

 6.11 lb/hr

PM/ PM10

 0.26 0.272 lbs/hr (hourly 

average)

 0.20 g/kW-hr (3-hour block average)

 0.0216 lb/hr

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

purposes, including as required for fire safety testing. 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. All leaks, spills and upsets of any kind shall be corrected or cleaned with 4 hours.

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

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

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

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

for leaks and for deterioration caused by corrosion or other factors.

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

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

19.18. 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.

FG. Fuel Restrictions

1. Clean cellulosic biomassThe following biomass fuels shall constitute the only fuel 

allowed for use as fuel in U1, except during periods defined in X.D. and to counteract 

upset conditions.:

2. a. Untreated wood pallets, crates, dunnage, untreated manufacturing and construction
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wood debris from urban areas;

b. All agricultural crops or residues;

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

i. 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

ii. Harvested for the purpose of forest fire fuel reduction or forest stand 

improvement.

Clean cellulosic biomass shall have the meaning as defined in 40 CFR Part 241.2. In

particular, clean cellulosic means those residuals that are akin to traditional cellulosic

biomass such as forest-derived biomass (e.g., green wood, forest thinnings, clean and

unadulterated bark, sawdust, trim, and tree harvesting residuals from logging and sawmill 

materials), corn stover and other biomass crops used specifically for energy production 

(e.g., energy cane, other fast growing grasses), bagasse and other crop residues (e.g., 

peanut shells), wood collected from forest fire clearance activities, trees and clean wood 

found in disaster debris, clean biomass from land clearing operations, and clean 

construction and demolition wood. These fuels are not secondary materials or solid 

wastes unless discarded. Clean biomass is biomass that does not contain contaminants at 

concentrations not normally associated with virgin biomass materials.

32. 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

GH. Monitoring Conditions

1. For U1, Permittee shall maintain the following equipment at all times when the 

combustion process is occurring

a. Permittee shall install, calibrate, operate and quality assure a CEMS that measures

CO, NOx, and CO2 in ppmv.

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

Condition X.G.2Condition X.H.2.

c. Permittee shall operate and maintain a COMS capable of measuring stack gas opacity

d. Permittee shall install a stack gas volumetric flowrate monitor and steam production 

rate monitor.

 

2. The CEMS 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, 
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and data recording) for each successive 15-minute clock-hour period.

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.GH.2. 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. 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, Procedure 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. steam production rate;

11. Permittee shall furnish the EPA with a written report of the results of tests within 60 

days of completion. 

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

status and Rapper On/Off status. 

13. 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, permittee shall install and maintain an operational non-resettable elapsed time 

meter to record the operating time of the emergency engine.

HI.Performance Tests

1.. Performance tests shall be 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 7 for NOx emissions.

e. EPA Methods 1-3 and 29 for Pb emissions.

f. EPA Methods 1-4 and 5 for PM 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 

27. In lieu of Method 202, the Permittee may use Other Test Method 28.

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

i. 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, Permittee shall conduct initial performance tests (as described in 40 

CFR Part 60.8) for NOx CO, PM, PM10, PM2.5, VOC, SO2 and Pb emissions.

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 shall be conducted at the facility’s maximum 

steam production rate.

d. Performance tests for NOx and CO shall be conducted 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).

e. 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 
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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 , to ensure that the TDS limits are 

not exceeded, 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 60.860.4244) for NOx, CO and PM10 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.

6. Permittee shall take monthly samples of the natural gas combusted. The samples shall be 

analyzed for sulfur content using an ASTM method. As an alternative, Permittee may 

obtain laboratory analysis of sulfur content from the fuel supplier on a monthly basis, if 

Permittee can demonstrate that the fuel tested is representative of fuel delivered to the 

facility.

J. Recordkeeping and Reporting 

1. 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 certifying compliance with fuel sulfur content for Condition X.H.6X.D.1.; and 

all other information required by this permit recorded in a permanent form suitable for 

inspection. 

2. Permittee shall 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.
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3. For U1, 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.

4. 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. 

5. 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 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.

6. A period of monitor down-time shall be any unit operating clock hour in which sufficient 
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data are not obtained by the CEMS to validate the hour for NOx, CO, or CO2.

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

limits and standards set forth in Conditions X.C.1, and X.C.2, X.C.3 and X.D.5.

8. 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.

9. 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.

9.10. For U3, the permittee 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. 

1011. 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

CO Carbon Monoxide

CO2 Carbon Dioxide

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

gpm Gallons Per Minute

gr Grains

HHV Higher Heating Value

hr Hour

lbs Pounds

MMBtu Million British Thermal Units

MW Megawatt

NAAQS National Ambient Air Quality Standards

NO2 Nitrogen Dioxide

NOX Oxides of Nitrogen

NSPS New Source Performance Standards

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

PSD Prevention of Significant Deterioration

RATA Relative Accuracy Test Audit

SCR Selective Catalytic Reduction

SO2 Sulfur Dioxide

SOX Oxides of Sulfur

TDS Total Dissolved Solids

tpy Tons Per Year

yr Year

XII. AGENCY NOTIFICATIONS
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All correspondence as required by this Approval to Construct must be sent to:

A. Director, Air Division (Attn: AIR-5)

EPA Region IX

75 Hawthorne Street

San Francisco, CA 94105-3901

Email: R9.AEO@epa.gov

Fax: (415) 947-3579

With a copy to:

B. Air Pollution Control Officer

Shasta County Air Quality Management District

1855 Placer Street, Suite 101

Redding, CA 96001

Fax: (661) 723-3450