PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

ISSUED PURSUANT TO THE 

REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION IX 

PSD PERMIT NUMBER: SAC 08-01 

PERMITTEE: Covanta Energy Corporation 

40 Lane Road 

Fairfield, NJ 07004 

FACILITY NAME: Burney Mountain Power 

FACILITY LOCATION: 37800 Energy Drive 

Burney, California 96013 

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 Covanta Energy Corporation (Covanta). This Permit 

applies to the modification and operation of a 10.2 megawatt (MW) biomass power plant known 

as Burney Mountain Power (BMP) in Burney, California. 

Covanta is authorized to construct and operate the BMP power plant 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 Covanta from the obligation to comply with applicable federal, state, and Shasta County 

Air Quality Management District air pollution control rules and regulations. 

This PSD Permit becomes effective on the date of issuance pursuant to 40 CFR § 124.15(b)(3). 

Director, Air Division 

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Final PSD Permit/October 201 0 

Date 
PSD PERMIT NUMBER: SAC 08-01 

BURNEY MOUNTAIN POWER 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION IX 

PROJECT DESCRIPTION 

Burney Mountain Power (BMP) is a 10.2 MW biomass-fired power plant that employs a 

Zurn wood-fired Boiler. The applicant is including additional types of biomass to its 

allowable fuel feed and installing a 75 horsepower hammer hog on the fuel feed inlet. The 

additional fuels allowed to be utilized include: peach pits, walnut shells, sander dust, 

urban wood fuel, waste wood roofing shakes with tar paper component, and waste 

activated carbon. Previous editions of the PSD Permit were issued by Shasta County Air 

Quality Management District (the District). 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. Therefore, EPA is modifying the PSD 

Permit issued by the District to incorporate the proposed modifications. 

EQUIPMENT LIST 

Emission Description 

Unit Id. 

EU-1 One (1) 190 MMBTU/hr Zurn wood-fired boiler equipped with two (2) 22 

MMBTU/hr pipeline natural gas-fired burners and a flue gas recirculation system 

EU-2 50 T/hr truck dump (fugitive emissions) 

EU-3 12 T/hr hammer hog (fugitive emissions) 

EU-4 50 T/hr fuel storage stackout conveyer (fugitive emissions) 

EU-5 50 T/hr fuel storage hammer hog (fugitive emissions) 

EU-6 50 T/hr fuel storage reclaimer/conveyor (fugitive emissions) 

EU-7 7600 GPM evaporative cooling tower (fugitive emissions) 

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. 

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II. Permit Notification Requirements 

Permittee shall notify EPA Region 9 in writing or by electronic mail of the: 

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

B. actual date that permittee will commence operation as modified source, postmarked 

within 15 days of such date. 

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

provisions of Condition X.F .1., 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 Condition X.F.2. 

D. date upon which initial performance evaluation of the 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.C.6. 

III. Facility Operation 

At all times, including periods of startup, shutdown 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 the EPA which may 

include, but is not limited to, monitoring results, opacity observations, review of 

operating maintenance procedures and inspection of the source. 

IV. Malfunction Reporting 

A. Permittee shall notify EPA by facsimile or electronic mail within two (2) working 

days following the discovery of any failure of air pollution control equipment, process 

equipment, or 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.D. of this permit. 

B. In addition, Permittee shall notify EPA in writing or electronic mail within fifteen 

( 15) days of any such failure described under Condition IV .A. The 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.D., 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. 

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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 source is located or where any records are required to 

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

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; and 

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 facilities to be constructed, this 

PSD Permit shall be binding on all subsequent owners and operators. Permittee shall 

notify the succeeding owner and operator of the existence of this PSD Permit and its 

conditions by letter, a copy ofwhich shall be forwarded to EPA Region 9. 

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. Other Applicable Regulations 

Permittee shall construct and operate this project in compliance with this PSD permit 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. Reserved 

B. Air Pollution Control Equipment, Operation and Work Practices 

1. The following air pollution control equipment shall be used at all times that 

biomass is used in the combustion process: 

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a. char reinjection 

b. multiclone collector 

c. electrostatic precipitator (ESP) 

d. combustion controls 

2. Good combustion practices, including but not limited to control ofunderfire air, 

control of overfire air, and control of combustion excess air shall be exercised at 

all times. 

3. Sander dust and waste activated carbon shall be mixed with biomass wood fuel 

upon arrival in the fuel yard or stored in closed containers until use. 

4. All ash shall be transported in a wet condition in covered containers. It shall be 

the responsibility of the Permittee to ensure that any and all contract or company 

carriers adhere to this condition. 

5. Fugitive emissions, inCluding but not limited to any of the following, shall be 

minimized at all times: 

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

b. Fugitive sawdust from fuel-pile areas or fuel-handling devices. 

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

removed from the boiler by other means. 

d. 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. 

6. Visible emissions shall be inspected daily. Ifvisible emissions are observed, 

corrective action shall be taken to minimize visible emissions. If visible emissions 

cannot be corrected within 24 hours, then a visible emissions test using EPA 

Method 22 shall be performed within 48 hours of when the visible emissions were 

first observed. 

C. Continuous Monitoring Systems 

1. Permittee shall operate, maintain, certifY, and quality-assure a continuous 

emission monitoring system (CEMS) which measures stack gas NOx, CO and 02 

concentrations in ppmv, a continuous emission rate monitoring systems (CERMS) 

which measures stack gas NOx in lbs/hr and a continuous opacity monitoring 

system (COMS) which measures stack gas opacity onEU-1. 

2. The Permittee shall operate and maintain devices as necessary to monitor the 

following parameters in the combustion process: 

a. stack gas flow rate 

b. combustion temperature (at the superheater tube area) 

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c. temperature at inlet/outlet of ESP 

d. steam production rate 

3. NOx and 0 2 CEMS shall meet the applicable requirements of 40 CFR Part 60 

Appendix B, Performance Specifications 2 and 3 upon initial installation, and 40 

CFR Part 60 Appendix F, Procedure 1 thereafter. 

4. The CO CEMS shall meet the applicable requirements of 40 CFR Part 60 

Appendix B, Performance Specification 4A upon initial installation, and 40 CFR 

Part 60 Appendix F, Procedure 1 thereafter. 

5. The performance evaluation of the CEMS and CERMS to monitor the stack gas 

flow may either be conducted separately or as part of the new fuel mixture source 

test. 

6. Permittee shall submit a CEMS and CERMS 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. 

7. The CEMS and CERMS shall be tested annually in accordance with the 

requirements of 40 CFR 60 Appendices B and F. 

8. The CEMS shall complete a minimum of one cycle of operations (sampling, 

analyzing and data recording) for each successive IS-minute period. 

9. Permittee shall furnish the EPA a written report of the results of CEMS and 

CERMS performance tests within 60 days of completion. 

D. Production, Operation and Emission Limits 

1. The following production and operation limits shall apply at all times: 

a. Steam production rate shall not exceed 120,000 lbslhr. 

b. Operation of the boiler shall not exceed 8,400 hours on a 12-month rolling 

basis. 

2. The following annual facility emission limits shall apply on a 12-month rolling 

basis: 

a. PM emissions shall not exceed 33 tpy. 

b. PM10 emissions shall not exceed 23 tpy. 

c. PM2.s emissions shall not exceed 18 tpy. 

d. VOC emissions shall not exceed 109 tpy. 

e. so2 emissions shall not exceed 22 tpy. 

f. NOx emissions shall not exceed 139 tpy. 

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g. CO emissions shall not exceed 790 tpy. 

3. The following emission limits shall apply to EU-1 at all times, except as provided 

by the provisions in Section X.E. 

a. PM emissions shall not exceed 0.05 gr/dscf at 12% C02. 

b. S02 emissions shall not exceed 15 ppm on an hourly average basis at 12% 

C02. 

c. VOC emissions shall not exceed 26 lbs/hr, based on a 3-hour averaging period. 

d. CO emission concentrations shall not exceed the following: 

1. 1200 ppm (dry basis, corrected to 12% C02) when burning biomass only, 

based on a rolling 24-hour average 

11. 400 ppm (dry basis, corrected to 12% C02) when burning pipeline natural 

gas only, based on a rolling 3-hour average 

111. When firing a combination of gaseous and solid fuel (dry basis, corrected 

to 12% C02), Z, as determined by the following equation based on a 

rolling 24-hour average: 

( 400 * X) + (1200 * Y) = z 

X+Y 

where; Z = ppm limit of firing combination 

X = annual heat input from gaseous fuel 

Y = annual heat input from non- gaseous fuel 

4. Except during periods of startup and shutdown as defined in Conditions X.E.2 and 

X.E.3., NOx emission concentrations from EU-1 shall not exceed the following at 

all times, based on a rolling 3-hour average of CEMS data: 

a. When burning biomass: either 115 ppm (dry basis at 12% C02) or 0.15 

lbs/MMBTU heat input, 

b. When burning pipeline natural gas only: either 70 ppm (dry basis at 3%.02) or 

0.084 lbs/MMBTU of heat input 

c. When firing a combination of gaseous and solid fuel (dry basis, corrected to 

12% C02), Z1 and Z2, as determined by the following equation: 

(70 * X) + (115 * Y) = z 

X+Y 1 

(0.084 *X)+ (0.15 * Y) _ Z 

X+Y - 2 

where; zl =ppm limit of firing combination 

Z2 = lbs/MMBTU limit of firing combination 

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X = annual heat input from gaseous fuel 

Y = annual heat input from non-gaseous fuel 

5. NOx emissions shall not exceed 33 lbs/hr, based on a 24-hour daily average of 

CERMS data. All periods of inoperation shall be excluded from the calculated 

average. 

E. Requirements during Malfunction, Startup and Shutdown Periods 

1. During start-up and shutdown of the boiler, the PM concentration shall not exceed 

0.1 gr/dscf. 

2. Startup is defined as the period beginning with EU-1 ignition and lasting until the 

equipment has reached a continuous operating level and the emission limits 

specified in Condition X.D.3. 

3. Shutdown is defined as the period beginning with the lowering of equipment from 

normal operating load and the start of natural gas burners at a minimum firing rate, 

and lasting until the concentration of02 inside EU-1 is at or above 18%, or EU-1 is 

offline. 

4. Startup and shutdown periods shall not exceed three hours in duration. 

F. Performance Tests 

1. Performance tests shall be conducted in accordance with the test methods set forth 

in 40 CFR 60.8 and 40 CFR 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)(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 1-3 and 29 for Pb emissions. 

d. EPA Methods 1-4 and 5 for PM emissions. 

e. 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 ofMethod 5, the Permittee may use Other 

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

Method 28. 

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

2. Permittee shall submit a performance test protocol to EPA no later than 30 days 

prior to the test to allow review ofthe 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. 

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

written approval from EPA. 

4. Within 60 days after achieving the facility's maximum operating production rate, 

but not later than 120 days after the modification, permittee shall conduct initial 

performance tests (as described in 40 CFR 60.8) for NOx CO, PM, PM10, PM2.5, 

and VOC emissions. 

a. After achieving the maximum production rate, initial performance tests for Pb 

and SOz shall be completed within 120 after receiving fuels X.I.l.i, X.I.l.j and 

X.I.l.k. 

b. Annual performance tests shall be required for PM10. 

5. Annual source tests ofthe high heating value (HHV) in Btu/lb shall be required of 

all mill waste received at the facility. 

6. 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 60.8(e). 

7. 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. 

G. Recordkeeping and Reporting 

1. Permittee shall maintain daily electrical generation data on site. 

2. Permittee shall maintain records of the hours of operation for E/U's 1, 2 and 3, on 

a 12-month rolling basis updated by the 15th day of the following month. 

3. Permittee shall maintain CEMS and CERMS records that contain the following: 

the occurrence and duration of any startup, shutdown or malfunction, performance 

testing, evaluations, calibrations, checks, adjustments, maintenance, duration of 

any periods during which a continuous monitoring system or monitoring device is 

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

of system repairs or adjustments, and emission measurements. 

4. A period of monitor down time shall be any EU-1 operating hour in which 

sufficient data are not obtained to validate the hour for NOx, CO or Oz. 

5. Excess emissions as measured by the CEMS and CERMS, shall be defined as 

follows: 

a. ForNOx, 

1. any operating hour, excluding periods of startup and shutdown as defined 

in Conditions X.E.2.,X.E.3. and X.E.4., in which the rolling 3-hour 

average NOx concentration exceeds the maximum emission limit set forth 

in Condition X.D.4.a, or 

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u. any day in which the average NOx mass exceeds the maximum emission 

limit set forth in Condition X.D.5. 

b. For CO, any operating hour in which the rolling 24-hour average CO 

concentration exceeds the maximum emission limits set forth in Condition 

X.D.3.f.i. 

6. Permittee shall maintain records and a summary report of all excess emissions on 

site. The records and summary report shall contain information according to 40 

CFR 60.7(c) and (d), including: 

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 CERMS 

was inoperative (monitor down time); and 

c. A negative declaration when no excess emissions occurred or when the CEMS 

or CERMS has not been inoperative, repaired, or adjusted. 

7. Excess emissions indicated by the CEMS shall be considered violations of the 

applicable emission limit for the purpose of this permit. 

8. Permittee shall submit excess emissions reports to EPA semiannually. The report 

is due on the 30th day following the end of the calendar quarter. 

9. Permittee shall submit to EPA a written report of the results of performance tests 

within 60 days of completion. 

10. Records of fuel dust or ash spilled due to an upset condition shall be kept on site. 

Spills that are allowed to exist beyond 24 hours of the upset shall be reported to 

the District. 

11. Records of visible emissions tests using EPA Method 22 shall be kept on site. 

Facility staff shall report the results of the test to the District. 

12. Records of the total heat input and input specifically from pipeline natural gas to 

the boiler shall be derived from the power output of the biomass boiler recorded 

on an hourly basis. 

13. The Permittee shall maintain records of all fuel deliveries, excluding pipeline 

natural gas, which include the fuel type, the date received, fuel source and weight 

in bone-dry tons (BDT). 

14. The Permittee shall maintain records of each type and total fuels received, other 

than natural gas, on a monthly basis. 

15. The Permittee shall maintain records of all source tests for mill waste that include 

the HHV of the fuel as received and dry. 

16. The Permittee shall maintain records of the monthly pipeline natural gas used for 

the boiler that include the HHV-and volume received. 

17. The Permittee shall maintain records of contracts from each vendor delivering 

biomass fuel procured from private and/or public lands which verify that the fuel 

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was harvested in accordance with the State Forest Practice Act or a Management 

Plan consistent with the National Environmental Policy Act. 

18. The Permittee shall maintain records which demonstrate that wood, lumber, brush 

or vegetation from land clearings conducted as part of a land development project 

have been reviewed and approved by Shasta County, the City of Anderson, the 

City of Redding, or the City of Shasta Lake. 

19. The Permittee shall maintain records which demonstrate that deliveries of waste 

activated carbon were derived from municipal drinking water filtration systems. 

Material Safety Data Sheets and Materials Characterization Forms pertaining to 

waste activated carbon fuel shall be kept on site. 

20. All records required by this PSD Permit shall be retained on site for five years 

following the date of such measurements, maintenance, and reports. 

H. Reserved 

I. Fuel Use 

1. Fuels received at this facility shall be limited to the following on a 12-month 

rolling basis: 

a. Mill waste 

b. Biomass fuel procured from private and/or public lands 

c. Wood, lumber, brush or vegetation from Pacific Gas and Electric and public 

road right-of-ways 

d. Wood, lumber, brush or vegetation from land clearings conducted as part of a 

land development project 

e. Olive pits, up to 5% by weight of total annual fuel received 

f. Almond shells, up to 10% by weight of total annual fuel received 

g. Peach pits, up to 10% by weight of total annual fuel received 

h. Walnut shells, up to 1 0% by weight of total annual fuel received 

1. Sander dust, up to 10% by weight of total annual fuel received 

J. Urban wood fuel, up to 10% by weight of total annual fuel received, not to 

exceed 9,000 bone-dry tons per year (BDT/yr) 

k. Waste wood roofing shakes with tar paper component, up to 10% by weight of 

- total annual fuel received, not to exceed 9,000 BDT/yr 

1. Waste activated carbon, derived from municipal drinking water filtration, at up 

to 1% of weight of total annual fuel received, not to exceed 900 BDT/yr. The 

waste activated carbon received must not be classified as a hazardous waste 

based on federal, state or local regulations. 

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2. "Urban wood fuel" shall be limited to the following materials: 

a. Yard, and garden clippings, including: grass, leaves, tree and branch pruning 

b. Vegetation from residential and commercial operations 

c. Chipped material derived from construction and demolition materials including 

wood pallets, crates, and boxes. 

3. Foreign material such as tar paper, nails, oil, plastics, styrofoam, rubber, paint, or 

other non-wood substances shall not exceed 3% by weight of the urban wood fuel 

mix. Upon the request ofthe EPA Regional Administrator, Air Pollution Control 

Officer of the District and/or an authorized representative, the Permittee shall 

weigh all urban wood fuel to verify compliance. 

4. Mill waste shall be defined as waste wood from wood manufacturing operations. 

5. At least 45% of the heat input from fuels utilized for this facility, calculated on a 

12-month rolling basis, shall be non-mill waste derived. 

6. The Permittee shall not use a new fuel type of any kind or change the maximum 

percent of a fuel type to be received without prior approval from EPA in writing. 

7. The pipeline natural gas auxiliary burners shall only be used during startup and 

shutdown as defined in Section X.E., and to augment combustion stabilization. 

8. The heat input from pipeline natural gas shall not exceed 25% of the total heat 

input to the boiler on a 12-month rolling basis. 

9. Pipeline natural gas, per 40 CFR 72.2, shall be defined as a naturally occurring 

fluid mixture ofhydrocarbons (e.g., methane, ethane, or propane) which is 

provided by a supplier through a pipeline. Pipeline natural gas contains 0.5 grains 

or less of total sulfur per 100 standard cubic feet. Additionally, pipeline natural 

gas must either be composed of at least 70 percent methane by volume or have a 

gross calorific value between 950 and 1100 Btu per standard cubic foot. 

10. The fuel dryer shall be used when the average fuel moisture is equal to or greater 

than 50%. However, in the event of a fuel dryer breakdown, the plant may 

continue operation provided that the facility complies with all emission limit 

conditions in this permit and a breakdown report is submitted to EPA as required 

in Condition IV .B. of this permit. 

XI. Agency Notifications 

A. Unless otherwise directed by the EPA or this permit, the Permittee shall submit a 

copy of all test plans, reports, certifications, notifications, and other information 

pertaining to compliance with this permit to: 

Director, Air Division (Attn: Air-5) 

U.S. Environmental Protection Agency, Region 9 

75 Hawthorne Street 

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San Francisco, CA 94105-3901 

Email: R9.AEO@epa.gov 

Fax: (415) 947-3579 

B. The Permittee shall submit permit applications, permit amendments, and other 

applicable permit information, which includes but not limited to installation of control 

equipment, replacement of an emissions unit, and changes that contravene permit 

terms, to: 

Director, Air Division (Attn: AIR-3) 

U.S. Environmental Protection Agency, Region 9 

75 Hawthorne Street 

San Francisco, CA 94105-3901 

C. Copies of all correspondence required by this PSD Permit shall be forwarded to: 

Air Pollution Control Officer 

Shasta County APCD 

1855 Placer St. Suite 101 

Redding, CA 96001 

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