Carlsbad Energy Center LLC

1817 Aston Avenue, Suite 104

Carlsbad, CA 92008

Direct: (760) 710-2146

Fax: (760) 710-2158

NRG

June 5, 2009

Mr. Gerardo Rios

Air Division AIR-3

U.S. Environmental Protection Agency

75 Hawthorne Street

San Francisco, CA 94105

Subject: PSD Non-Applicability Determination Request for the Carlsbad Energy

Center Power Project

Dear Mr. Rios:

On behalf of Carlsbad Energy Center LLC, we are requesting written confirmation from

EPA that the proposed Carlsbad Energy Center Power (CECP) project will not trigger

Prevention of Significant Deterioration (PSD) review.

Background

On September 17, 2007 an Application for Certification (AFC) for the CECP project was

submitted to the California Energy Commission (CEC). As part of the peiiiiitting process

for this proposed project an Application for an Authority to Construct/Determination of

Compliance (ATC/DOC) was submitted to the San Diego Air Pollution Control District

(SDAPCD) on September 12, 2007. The CECP project consists of the proposed

replacement of three existing boilers at the Encina Power Station (Units 1, 2, and 3) with

two new rapid startup natural gas-fired combined cycle gas turbines. The proposed CECP

project also includes the installation of a new 246 hp Diesel emergency fire-pump engine.

A complete description of the CECP project was included in the SDAPCD's engineering

evaluation for the proposed permit for the CECP project. A copy of this document was

submitted to EPA in November 2008 and is also enclosed as Attachment 1 for your

reference.
Mr. Gerald() Rios

EPA Region IX

June 5, 2009

Page 2 of 5

significant for one or more attainment pollutants, the next step is to compare the

facility-wide net emission change for each of these pollutants to the PSD significance

levels. A project is a major modification subject to PSD review if there is a facility-wide

net emission increase above a PSD significance level.

The potential to emit for the new equipment associated with the CECP project is shown

below in Table 1. The detailed emission calculations are shown in the enclosed SDAPCD

engineering evaluation for the proposed permit for the CECP project. Because the

SDAPCD is currently in the process of issuing a new engineering evaluation for the final

permit for the CECP project, the information in the enclosed SDAPCD document was used

for this PSD applicability analysis. It is expected that the potential to emit for the new

equipment and baseline emissions for existing equipment will be nearly identical in the

SDAPCD engineering evaluation for the final permit compared to the emission levels

discussed in this PSD analysis. Therefore, the issuance of the final SDAPCD permit is not

expected to change the conclusions discussed in this analysis.

As shown in Table 1, the potential to emit for the proposed new equipment is above the

PSD significance levels for the attainment pollutants NOx, CO, and PM 1 0. Therefore, for

these pollutants it will be necessary to determine whether there is a facility-wide net

emission increase above PSD significance levels. Because San Diego County is classified

as a Federal non-attainment area for ozone, the PSD regulation does not apply to VOC

emissions. Consequently, VOC emissions are excluded from this PSD regulatory analysis.

Table 1

CECP Project New Equipment Potential to Emit

Pollutant

Potential to Emit for New

Equipment* (tons/year)

PSD Significance Level

(tons/year)

NOx 72.8 40

CO 339.9 100

VOC 25.0 N/A

SOx 5.6 40

PM1 0 39.0 15

Note (Table 1):

* See Attachment 1, Table 5c and permit condition 44 for potential to emit levels for new
Mr. Geraldo Rios

EPA Region IX

June 5, 2009

Page 3 of 5

with the date of the emission increase associated with the new equipment [40 CFR

52.21.b.3.ii]. The final SDAPCD permit along with the CEC approval for the proposed

CECP project is expected to occur by the end of 2009. Consequently, construction of the

proposed new equipment could begin at the beginning of 2010. Therefore, for the

proposed CECP project the contemporaneous period under the PSD regulation begins on

January 1, 2005 (5-year lookback from start of construction) and ends when the proposed

new equipment begins normal operation. Because this period includes the shutdown of

Encina Power Station Units 1, 2, and 3, it is necessary to calculate the emission decrease

associated with the shutdown of these units.

To calculate the emission decrease for the shutdown of Encina Units 1, 2, and 3, it is

necessary to calculate the actual baseline emissions for these three units. While the

Federal PSD regulation generally requires that baseline emissions for existing electric

utility steam generating units be based on a 2-year average of actual emissions during the

five years preceding the initial construction of new equipment (see 40 CFR 52.21.b.48.i),

the PSD regulation allows the use of a different lookback period if requested by an

applicant and approved by EPA. This flexibility allowed in the PSD regulation is an

important tool given the difficulty in accurately estimating the future operation of existing

units during the period between when a permit is processed/issued for new equipment and

when construction begins on new equipment. An example of this flexibility in the allowed

baseline period for existing units is a decision that EPA Region IX made for the Mono

Bay Plant Modernization Project where EPA allowed a 10-year lookback period to

establish the baseline emissions for existing utility boilers (see Attachment 2 for copy of

this EPA decision).

Given the uncertainty of future operations/emissions of Encina Units 1, 2, and 3, we

believe that it is appropriate for PSD applicability purposes to use actual emissions during

the period from 2002 to 2006 to determine the emission decrease associated with the

shutdown of Encina Units 1, 2, and 3. This period was selected because it matches the

baseline period used by the SDAPCD for New Source Review (NSR) permitting purposes.

In addition, we believe that the operation of the existing Encina boilers during this period

is most representative of historical operation. As shown in the SDAPCD engineering

evaluation (CECP PDOC, Table 5a), the maximum 2-year average NOx, CO, and PM i o

emissions for Encina Units 1, 2, and 3 occurred during the period from 2004 to 2005. For

purposes of this PSD analysis, the actual emissions for Encina Units 1, 2, and 3 for this

two year period will be used as part of the net emission change calculation for the proposed

CECP project
Mr. Geraldo Rios

EPA Region IX

June 5, 2009

Page 4 of 5

Table 2

PSD Applicability for CECP Project

Emission Reductions

Potential to for Shutdown of Net PSD

Emit for New Encina Units 1, 2 & 3 Emission Significance

Equipment Based 2004-2005 Change Levels

Pollutant (tons/year) Average (tons/year) (tons/year) (tons/year)

NOx 72.8 -38.9 33.9 40

CO 339.9 -296.1 43.8 100

PM I0 39.0 -37.6 1.4 15

As discussed above, the new equipment proposed as part of the CECP project is to replace

existing Encina Units 1, 2, and 3. Because it is necessary for Encina Units 1, 2, and 3 to be

able to provide power during the shakedown of the new equipment, there will be a period

of time when the new units are undergoing shakedown and the existing Encina Units 1, 2,

and 3 will operate periodically to provide power to the grid. The SDAPCD permit will

prohibit the operation of a new unit if an existing Unit 1, 2, or 3 is operating (see permit

condition 81). Consequently, there will be no simultaneous operation of the new units and

Encina Units 1, 2, or 3 on an hourly basis. In addition, the SDAPCD permit will limit the

annual emissions from existing Encina Units 1, 2, and 3 and the new units during this

shakedown period (see permit conditions 82, 83, and 84). Furthermore, the SDAPCD

permit includes a 180-day limit on the shakedown period for the new equipment (see

permit condition 17). For PSD applicability purposes, the emission increase for the new

equipment does not occur until these units become "operational." Under the PSD

regulations a new unit becomes "operational" only after a reasonable shakedown period

not to exceed 180 days (40 CFR 52.21.b.3.viii). This section of the PSD regulation allows

for an overlap between the operation of existing units (which will be shutdown) and new

units that must be operated for shakedown purposes. The SDAPCD permit limits

discussed above will ensure that the proposed new equipment will not trigger PSD review

during this shakedown period.

Based on the above information, we request written confirmation from EPA that the

proposed CECP project will not trigger PSD review. If you have any questions or need

any additional informationplease do not hesitate to call me at (760) 7102156
Mr. Geraldo Rios

EPA Region IX

June 5, 2009

Page 5 of 5

Enclosure

cc: Steve Moore, SDAPCD

John McKinsey, Stoel

Will Walters, CEC

Michael Monasmith, CEC

CEC Dockets Office (07-AFC-6)
ATTACHMENT 1 

SDAPCD ENGINEERING EVALUATION 

PDOC FOR CECP 
AIR POLLUTION CONTROL DISTRICT

COUNTY OF SAN DIEGO

Greg Cox

Dianne Jacob

Pam Slater-Price

Ron Roberts

Bill Horn

District 1

District 2

District 3

District 4

District 5

Air Pollution Control Board

November 21, 2008

MIKE MONASMITH

PROJECT MANAGER

CALIFORNIA ENERGY COMMISSION

1516 NINTH STREET

SACRAMENTO CA 95814

Dear Mr. Monasmith:

Enclosed for your review and comment is the District's Preliminary Determination of

Compliance for the Carlsbad Energy Center LLC's proposed development of the Carlsbad

Energy Center Project (District Applications No. 985745, 985747, and 985748), a 558 megawatt

combined cycled power plant consisting of two natural-gas-fired combustion turbine generators,

each with a heat recovery steam generator and emission control equipment, and a diesel fire

pump engine, to be located at 4600 Carlsbad Blvd, Carlsbad, California, on the same grounds as

the existing Encina Power Station. Also enclosed is a copy of the public notice that will be

published on November 25, 2008.

The District performed an evaluation of the air pollution impacts of this proposal and the

equipment is expected to operate in compliance with all applicable District Rules and

Regulations and all applicable federal requirements. The proposed permit incorporates

-conditions necessary to ensure compliance with all federal and District requirements.

Please direct your written comments concerning the District's proposed action to the attention of

Steven Moore, San Diego Air Pollution Control District, 10124 Old Grove Road, San Diego, CA

92131, within the 30-day public comment period commencing on November 25, 2008, and

ending on December 24, 2008. Should you have any questions regarding this matter, please

contact Steven Moore at (858) 586-2750.

Sincerely,

TOM WEEKS

Chief of Engineering

Enclosures

ID#: 333A

10124 Old Grove Road, San Diego, California 92131-1649 • (858) 586-2600

FAX (858) 586-2601 • Smoking Vehicle Hotline 1-800-28-SMOKE • www.sdapcd.org

Printed on Recycled Paper
PRELIMINARY 

DETERMINATION OF COMPLIANCE 

CARLSBAD ENERGY CENTER PROJECT

SAN DIEGO AIR POLLUTION CONTROL DISTRICT 

Applications Number 985745, 985747, and 985748 

November 20, 2008 
Project Engineer Camqui Nguyen 

Senior Engineer: Steven Moore 

Application Numbers: 985745, 985747, and 985748 

Site ID Number: 333A 

Fee Schedule: 20F 

BEC: New 

 APPLICATION INFORMATION

 Owner / Operator: Carlsbad Energy Center, LLC 

 Mailing Address: 1817 Aston Ave, Suite 104 

 Carlsbad, CA 92008 

 Equipment Address: 4600 Carlsbad Blvd 

 Carlsbad, CA 92008 

 

 Contact: Tim Hemig 

 Company: Carlsbad Energy Center LLC 

Position: Vice President 

 Phone Number: (760) 710-2144 

 Fax Number: (760) 710-2158 
TABLE OF CONTENTS

I. PROJECT DESCRIPTION............................................................................................... 1 

II. EQUIPMENT DESCRIPTION....................................................................................... 3 

III. PROCESS DESCRIPTION............................................................................................ 4 

IV. EMISSION ESTIMATES............................................................................................... 7 

Combustion Turbine Generator Emissions—Standard operations....................................... 7 

Maximum Hourly Emissions ................................................................................................ 7 

Emergency Fire Pump Engine Emissions........................................................................... 11 

Project Emissions—Standard operations............................................................................ 12 

Combustion Turbine Generator Emissions—Commissioning period ................................ 13 

Project Emissions—Commissioning period ....................................................................... 15 

V. RULES ANALYSIS ........................................................................................................ 17 

District and Federal NSR and PSD Regulations................................................................. 17 

Rule 20.1(c)(35) – Major Stationary Source................................................................... 17 

Rule 20.1(c)(58) – Prevention of Significant Deterioration (PSD) Stationary Source and 

40 CFR 52.21.................................................................................................................. 17 

Rule 20.1( c)(16), 40 CFR §52.21, and 40 CFR Appendix S to Part 51– 

Contemporaneous Emission Increase ............................................................................. 18 

Rule 20.1(c)(33) – Major Modification .......................................................................... 25 

Rule 20.1(c)(57) PSD Modification and 40 CFR 52.21 ................................................. 25 

Rule 20.3(d)(1)- Best Available Control Technology(BACT)/Lowest Achievable 

Emission Rate(LAER) .................................................................................................... 26 

Rule 20.3(d)(2) – Air Quality Impact Analysis (AQIA)................................................. 37 

Rule 20.3 (d)(3), (4)-Prevention of Significant Deterioration (PSD) ............................. 37 

Rule 20.3(d)(4) – Public Notice and Comment .............................................................. 38 

Rule 20.3(d)(5)-Emission Offsets................................................................................... 38 

Rule 20.3(e)(1) – Compliance Certification ................................................................... 39 

Rule 20.3(e)(2) – Alternative Siting and Alternatives Analysis..................................... 40 

Rule 20.5 – Power Plants................................................................................................ 40 

District Prohibitory Rules ................................................................................................... 40

Rule 50 – Visible Emissions........................................................................................... 40 

Rule 51 – Nuisance ......................................................................................................... 40 

Rule 53 – Specific Air Contaminants ............................................................................. 41 

Rule 68 –Oxides of Nitrogen from Fuel Burning Equipment......................................... 42 

Rule 69.3-Stationary Gas Turbines – Reasonably Available Control Technology ........ 42 

Rule 69.3.1 – Stationary Gas Turbines – Best Available Retrofit Control Technology. 42 

Rule 69.4 – Stationary Reciprocating Internal Combustion Engines – Reasonably 

Available Control Technology........................................................................................ 43 

Rule 69.4.1– Stationary Reciprocating Internal combustion Engines – Best Available 

Retrofit Control Technologies. ....................................................................................... 43 

Rule 1200 – Toxic Air Contaminants ............................................................................. 45 

Regulation XIV – Title V Operating Permits ................................................................. 45 

State Regulations Implemented by the District .................................................................. 46 

Health and Safety Code §42301.6 .................................................................................. 46 
Title 17 of the California Codes of Regulations (CCR) §93115—Airborne Toxic 

Control Measure (ATCM) for Stationary Compression Ignition Engines...................... 46 

National Emissions Standards for Hazardous Air Pollutants (NESHAPS)........................ 48 

40 CFR Part 63 Subpart YYYY – National Emissions Standards for Hazardous Air 

Pollutants for Stationary Combustion Turbines.............................................................. 48 

40 CFR Part 63 Subpart ZZZZ - National Emissions Standards for Hazardous Air 

Pollutants for Stationary Compression Ignition Internal Combustion Engines.............. 49 

New Source Performance Standards (NSPS) ..................................................................... 49 

40 CFR Part 60- Subpart KKKK- National Standards of Performance for New Stationary 

Combustion Turbines.......................................................................................................... 49

40 CFR Part 60 Subpart IIII – Standards of Performance for Stationary Compression 

Ignition Internal Combustion (CIIC) Engines ................................................................ 52 

Acid Rain ............................................................................................................................ 53 

40CFR Part 72- Subpart A – Acid Rain Program........................................................... 53 

40CFR Part 72- Subpart C – Acid Rain Permit Applications......................................... 53 

40CFR Part 73- Sulfur Dioxide Allowance System ....................................................... 53 

40CFR Part 75 – Continuous Emission Monitoring....................................................... 53 

VI. ADDITIONAL ISSUES ................................................................................................ 55 

Particulate Emission Relating to the Use of Reclaimed Water for Evaporative Cooling... 55 

Commissioning Period........................................................................................................ 55 

VII. CONCLUSIONS AND RECOMMENDATIONS..................................................... 56 

APPENDICES 

 Appendix A – Approval of Air Quality Impact Analysis 

 Appendix B – Approval of Health Risk Assessment 

 Appendix C – Proposed Permit Conditions 
Preliminary Determination of Compliance Page 1 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

I. PROJECT DESCRIPTION 

Carlsbad Energy Center LLC (the Applicant) proposes to develop the Carlsbad Energy 

Center Project (CECP). This project is a combine cycled power plant with a total nominal 

base load gross power output of 558 MW. The CECP will utilize two Siemens SGT6-5000F 

Rapid Response Combined-Cycle (R2C2) combustion turbine generators (CTGs) equipped 

with steam power augmentation. The nominal gross power output is 208 megawatts (MW) 

with a corresponding heat input of 1976 million British thermal units per hour (MMBtu/hr) 

per turbine (without power augmentation at 61 o

F average ambient temperature). The 

combustion turbines are also equipped with evaporative coolers that can be used cool the 

inlet air to each turbine to increase power during periods of high ambient temperature. Each 

CTG is followed by a heat recovery steam generator (HRSG) equipped with a selective 

catalytic reduction (SCR) system to reduce oxides of nitrogen (NOx) emission and an 

oxidation catalyst to control the carbon monoxide (CO) and volatile organic compounds 

(VOC) emissions. Steam from each HRSG will feed a steam turbine generator (STG) 

associated with that HRSG. This combination of a CTG with a HRSG and STG is referred to 

as a 1-on-1 combined-cycle power plant. By making use of the turbine exhaust heat to 

generate electricity with the steam turbine, combined-cycle power plants are significantly 

more efficient than other combustion turbine power plants. 

The CECP is subject to the approval of the California Energy Commission (CEC) because 

the proposed power plant has a nominal rating greater than 50 MW. CECP filed an 

application for certification (AFC) with the CEC in September 2007 (07-AFC-6). The San 

Diego Air Pollution Control District (District) is considered a responsible agency for this 

approval and is required to submit a Preliminary Determination of Compliance (PDOC) and 

a Final Determination of Compliance (FDOC) to the CEC. Pursuant to District Rule 20.5 the 

FDOC review is functionally equivalent to an Authority to Construct review. 

The CECP is located north of the intersection of Carlsbad Blvd. and Cannon Road in the city 

of Carlsbad in San Diego County. The project is proposed to be located in the northeast area 

of the existing Cabrillo Power I LLC’s Encina Power Station, between the existing rail line 

and Interstate 5 (I-5). The two main power units of the project will be at the location of 
Preliminary Determination of Compliance Page 2 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

previously existing fuel oil tanks, which are currently being removed. The existing Encina 

Power Station is comprised of five utility boilers using steam to generate a total of 

approximately 1000 megawatts (MW) of electrical power at full load and having a combined 

rated heat input of 9874 million British thermal units per hour (MMBtu/hr). The boilers are 

permitted to burn both natural gas and, in cases of force majeure natural gas curtailments, 

No. 6 fuel oil. As part of the CECP, three existing utility boilers, known as Units 1, 2, and 3, 

at the Encina Power Station will be retired when the two combined-cycled turbines are fully 

operational (the other two utility boilers will remain in operation). 

The project will be fueled by natural gas, which will be supplied by the San Diego Gas and 

Electric Company. No provisions for use of an alternative fuel in the event of a curtailment 

of the natural gas supply are proposed by the applicant. 
Preliminary Determination of Compliance Page 3 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

II. EQUIPMENT DESCRIPTION

CECP has proposed to construct and operate the following equipment at this facility under 

application No. 985745, 985747, and 984748: 

• Application 985745: Power block Unit #6 consisting of one nominal 208 MW (219 

MW with steam augmentation) natural-gas fired combined-cycle Siemens SGT6-

PAC5000F combustion turbine generator, serial number to be determined, with an 

ultra low NOx (ULN) combustor, an evaporative inlet air cooler, a heat recovery 

steam generator with a selective catalytic reduction unit, an oxidation catalyst, and a 

steam turbine generator and associated air-cooled heat exchanger to condense the 

exhaust steam from the steam turbine. 

• Application 985747: Power block Unit #7 consisting of one nominal 208 MW (219 

MW with steam augmentation) natural-gas fired combined-cycle Siemens SGT6-

PAC5000F combustion turbine generator, serial number to be determined, with an 

ultra low NOx (ULN) combustor, an evaporative inlet air cooler, a heat recovery 

steam generator with a selective catalytic reduction unit, an oxidation catalyst, and a 

steam turbine generator and associated air-cooled heat exchanger to condense the 

exhaust steam from the steam turbine. 

• Application 985748: An emergency fire pump engine, Cummins diesel engine, Model 

CFP6E-F35, as preliminarily proposed, rated at 246 brake horsepower, serial number 

to be determined. 
Preliminary Determination of Compliance Page 4 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

III. PROCESS DESCRIPTION

The CECP consists of two power blocks, each having one CTG, one HRSG, and one condensing 

STG to provide a nominal 219 MW of electricity from the combustion turbine at full load with 

steam power augmentation and an additional 60 MW from the steam turbine. Thermal energy 

produced in the CTG through combustion of natural gas is converted to mechanical energy to 

drive the combustion turbine compressor and electric generator. The hot CTG exhaust gases at 

approximately 1,100°F enter the HRSG. In the HRSG, boiler feedwater is converted to steam 

and delivered to the STG. Steam leaving the steam turbine is condensed in an air-cooled surface 

condenser. Some of the steam from the HRSG is injected into the combustion turbine when 

steam power augmentation is employed. 

The chosen CTG combines the fast starting capability of a simple-cycle gas turbine and the 

efficiency of a combined-cycle plant. The system is designed to start and reach 150 MW in ten 

minutes for a hot start and operate with combined-cycled efficiency in 45 minutes for a hot start 

and approximately 125 minutes for a cold start. The one-hour averaged NOx emission 

concentration is controlled to 2 parts per million by volume on a dry basis (ppmvd) and corrected 

to 15 percent oxygen (O2) by a combination of the ULN combustor in the CTG and the SCR 

system located in the HRSG. In the SCR, ammonia will be injected into the CTG exhaust stream 

via nozzles located upstream of the catalyst module. Ammonia slip, or the concentration of 

unreacted ammonia in the HRSG exhaust stack, is limited to 5.0 ppmvd averaged over one hour. 

The HRSG is also equipped with an oxidation catalyst to control CO emissions leaving the 

HRSG exhaust stack to 2.0 ppmvd and VOC emissions to 2.0 ppmvd averaged over one hour. 

Exhaust from each HRSG will be discharged from individual 21.3-foot diameter stacks proposed 

to be 139-foot tall. 

Each CTG is equipped with a continuous emission monitoring systems (CEMS) to sample, 

analyze, and record the natural gas fuel flow rate, NOx and CO concentration levels, and 

percentage of O2 in the exhaust gas from the HRSG stack. The data will be transmitted to a data 

acquisition and handling system (DAHS) that will store the data and generate emission reports. 

The DAHS will also include alarms that will send signals to the plant distributed control system 

(DCS) when emission limits are approached or exceeded. 
Preliminary Determination of Compliance Page 5 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Because of regional system needs, the CECP is expected to operate primarily at intermediate 

average annual capacity factors. The facility is designed to operate between 25 and 100 percent 

of the base load (558 MW) to support dispatch service in response to customer electricity 

demands. The basic operational modes primarily affecting emissions are startups, shutdowns, 

short transients, and normal operations. The applicant has provided CTG performance data and 

emission data based on vendor guarantees for operations under different loads and different 

ambient temperatures. The expected emissions used in various aspects of the evaluation are 

presented in Tables 1a and 1b. 

Startup is defined as the period beginning with ignition of a combustion turbine and lasting until 

the turbine can achieve the most stringent emission limits during normal operations (for this 

turbine the manufacturer has guaranteed turbine emissions at greater than 60% of base load 

capacity (124.8 MW). Shutdown is a period beginning with the lowering of the output of a 

combustion turbine below the minimum load necessary to achieve the most stringent emission 

limits during normal operations of its load capacity and ending when combustion has ceased. 

The minimum load is typically between 40% and 60% of the maximum load, depending on the 

combustion turbine. The applicant has proposed a minimum load threshold for a shutdown to be 

initiated of 114 MW, which is about 55% of the nominal base load (without steam 

augmentation). 

Emissions during startups and shutdown are significantly higher than during steady state 

operation. However, because of its unique design, the plant will be able to startup and achieve 

emission limits much faster than conventional large combined-cycle power plants. The applicant 

estimates that there will be 300 startups per turbine per year and 300 shutdowns per turbine per 

year. Maximum annual emissions are calculated based on 300 hours with a startup, 300 hours 

with a shutdown, and 3,500 hours per year at full-load operation under average conditions for 

both CTGs. 

The CECP may be completed in two phases expected to end in 2012 with the two combustion 

turbines sequentially achieving full operation. Phase I would consist of bringing one CTG/STG 
Preliminary Determination of Compliance Page 6 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

to full operation. Phase II would consist of bringing the remaining CTG/STG to full commercial 

operation. The completion of these two phases could be separated by as much as six months. 

Consequently, the three existing utility boilers may also be retired, or have their operations 

limited, in two phases. During the phase-in process the applicant has committed to not operating 

the combustion turbines and the steam boilers simultaneously, which minimizes emission 

impacts. However, to maintain grid reliability, maximum flexibility is desired in operating the 

existing boilers during the phase-in process when one or both CTG/STG units may not be fully 

operational. 
Preliminary Determination of Compliance Page 7 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

IV. EMISSION ESTIMATES

COMBUSTION TURBINE GENERATOR EMISSIONS—STANDARD OPERATIONS

MAXIMUM HOURLY EMISSIONS

Project emissions of NOx, CO, sulfur oxides (SOx), VOC, particulate matter less than or equal to 

10 microns in diameter (PM10), and particulate matter less than or equal to 2.5 microns in 

diameter (PM2.5) were estimated based on data supplied by the turbine manufacturer and 

emission limits in proposed permit conditions. The startup and shutdown, emission rates are 

provided by the turbine manufacturer. For steady state operations, emission rates for NOx, CO, 

and VOC are calculated based on emission concentration limits (in ppmvd at 15%O2) in 

proposed permit conditions and exhaust flow rates in dry standard cubic feet per hour (dscfh) at 

average ambient temperature for annual emissions and cold ambient temperature for peak hour 

and peak day emissions: 

Emissions, lbs/hr = (concentration, ppmvd) x 10-6 x (exhaust flow rate, dscfh) x (molecular 

weight/standard molar volume). 

Maximum hourly emissions of SOx are calculated based on the fuel heat input MMBtu/hr, and a 

SOx emission factor of 0.0021 lbs/MMBtu, which was derived from the maximum allowable 

sulfur content of 0.75 grains per 100 standard cubic feet based on the California Public Utility 

Commission (PUC) standard for pipeline natural gas. Emissions of PM10 are calculated based 

on vendor supplied guaranteed emission rates. Table 1a presents the hourly emission rates in 

pounds per hour (lbs/hr) for all five criteria pollutants at cold ambient temperature (37.4°F) and 

average ambient temperature (73.6°F). The PM2.5 emission rates are identical to PM10 

emission rates since all particulate matter is considered to be PM2.5. 
Preliminary Determination of Compliance Page 8 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 1a – Maximum Turbine Emission Rates During Normal Operations 

Pollutant Concentration, 

ppmvd @15%O2 

Emission Rate at 

Cold Ambient 

Temperature, 

lb/hr 

Emission Rate at 

Average Ambient 

Temperature, 

lbs/hr 

NOx 2 (1- hour average) 15.1 14.13 

CO 2 (3-hour average) 9.2 8.60 

VOC 2 (3-hour average) 5.3 4.93 

PM10 N/A 9.5 9.50 

PM2.5 N/A 9.5 9.50 

SOx N/A 4.4 4.4 

During a CTG startup, there are typically approximately 22 minutes of emission rates higher than 

emissions during normal operation. Therefore, hourly emission rates during startup are based on 

22 minutes of high emission levels followed by 38 minutes of normal operation emission levels. 

During a typical CTG shutdown, there are approximately 53 minutes of normal operation 

followed by 7 minutes of higher emission levels. Therefore, typical hourly emission rates during 

shut down are based on 53 minutes of normal operation emission levels followed by 7 minutes of 

higher emission levels. For any hour when both a typical startup and a shutdown occur, there 

would be 22 minutes of startup emissions, 31 minutes of normal emissions and 7 minutes of 

shutdown emissions. Because there is some variability in emissions during startup and 

shutdown, the hourly emissions for CO and NOx are estimated at twice the expected emission 

value. Table 1b presents the maximum emission rates for each turbine during startup and 

shutdown in pounds per hour. The maximum emission rates of PM10 and PM2.5 are not 

affected during startup and shutdown and the emission limit for normal operations remains in 

effect for these periods. The maximum emission rate of SOx is reduced because the turbine 

operates at low loads (and low heat input) during startups and shutdowns. 
Preliminary Determination of Compliance Page 9 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 1b – Maximum Turbine Emission Rates During 

Startup and Shutdown 

Pollutants Startup Emissions, 

lbs/hr 

Shutdown Emissions,

lbs/hr 

Startup and Shutdown, 

lbs/hr 

NOx 69.2 47 86 

CO 545 286 814 

VOC 16.3 10 21 

PM10 9.5 9.5 9.5 

PM2.5 9.5 9.5 9.5 

SOx <4.4 <4.4 <4.4 

Maximum Daily Emissions

Maximum daily emissions from each combustion turbine are calculated based on the assumption 

that each turbine operates up to 24 hours per day, of which 6 hours include a startup, 6 hours 

include a shutdown, and 12 hours for steady state operation at cold ambient temperature, as 

follows: 

Daily emissions = (startup emissions, lbs/hr) x (6 hours/day) + (shutdown emissions, lbs/hr) 

x (6 hours/day) + (steady state operation emissions, lbs/day) x (12 hours /day) 

 

Table 1c presents estimated maximum daily emissions from the combustion turbines in pounds 

per day (lbs/day). 
Preliminary Determination of Compliance Page 10 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 1c – Expected Maximum Turbine Daily Emissions 

Pollutants Emissions from Each Turbine 

lbs/day 

Emissions from Both Turbines 

lbs/day 

NOx 877 1754 

CO 5102 10205 

VOC 219 439 

PM10 228 456 

PM2.5 228 456 

SOx 106 211 

Maximum Annual Emissions

Maximum annual emissions for the combustion turbines are estimated based on the assumption 

that each turbine operates up to 4100 hours per year, of which 300 hours are for startup, 300 

hours are for shutdown, and 3500 hours for steady state operation at average ambient 

temperature, as follows: 

Annual emissions = (startup emissions, lbs/hr) x (300 hours/year) + (shutdown emissions, 

lbs/hr) x (300 hours/year) + (steady state operation emissions, lbs/day) x (3500 hours 

/years) 

Table 1d presents estimated maximum turbine annual emissions in tons per year (tons/yr). 
Preliminary Determination of Compliance Page 11 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 1d – Maximum Turbine Annual Emissions 

Pollutants Emissions from Each Turbine, 

tons/yr 

Emissions from Both Turbines, 

tons/yr 

NOx 37.77 75.54 

CO 108.65 217.3 

VOC 12.52 25.05 

PM10 19.48 38.95 

PM2.5 19.48 38.95 

SOx 9.02 18.04 

EMERGENCY FIRE PUMP ENGINE EMISSIONS

At a minimum, the diesel emergency fire pump engine must comply with Tier 2 emission 

standards for EPA certified engines of model year 2008. Daily emissions from the engine are 

calculated based on one hour of operation and annual emissions are calculated based on 50 hours 

of operation. Table 2a presents the engine hourly, daily, and annual emissions. 

Table 2a – Emergency Fire Pump 

Engine Emissions

Pollutant Engine Hourly Emissions, 

lbs/hr 

Engine Daily Emissions, 

lb/day 

Engine Annual Emissions, 

tons/yr 

NOx 2.08 2.08 0.052 

CO 0.24 0.24 0.006 

VOC 0.05 0.05 0.00125 

SOx 0.0027 0.0027 0.00007 

PM10 0.035 0.035 0.0008 

PM2.5 0.035 0.035 0.0008 
Preliminary Determination of Compliance Page 12 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

PROJECT EMISSIONS—STANDARD OPERATIONS

Total emissions from the project include emission from both combustion turbines and emissions 

from the emergency fire pump engine. Table 3a and 3b present the estimated maximum project 

total daily and annual emissions pounds per day and tons per year, respectively. 

Table 3a – Maximum Project Total Daily Emissions

Pollutant Turbines Total Daily 

Emissions, lbs/day 

Engine Daily Emissions, 

lbs/day 

Project Total Daily 

Emissions, lbs/day 

NOx 1754.04 2.08 1756.13 

CO 10204.52 0.24 10204.76 

VOC 438.70 0.05 438.75 

SOx 211.06 0.0027 211.06 

PM10 456.04 0.035 456.04 

PM2.5 456.04 0.035 456.04 

Table 3a – Maximum Project Total Annual Emissions

Pollutant Turbines Total Annual 

Emissions, tons/yr 

Engine Annual Emissions, 

tons/yr 

Project Total Annual 

Emissions, tons/yr 

NOx 75.54 0.052 75.6 

CO 217.3 0.006 217.3 

VOC 25.05 0.00125 25.1 

SOx 18.04 0.00007 18.04 

PM10 38.95 0.0008 39 

PM2.5 38.95 0.0008 39 

Toxic air contaminant emissions, or noncriteria pollutant emissions, are presented in details in 

the Toxic Health Risk Assessment Section in Appendix B of this determination. 
Preliminary Determination of Compliance Page 13 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

COMBUSTION TURBINE GENERATOR EMISSIONS—COMMISSIONING PERIOD

Following construction of the power plant and prior to full commercial operation, the 

combustion turbine generators, the steam turbine generator, emission control equipment, heat 

recovery steam generator and other equipment will be tested and tuned. During this period, 

because the CTG burners may not yet be tuned for optimal emissions and because the post 

combustion control equipment will not yet be in full operation, emissions from the plant will be 

higher than normal operating emissions. The plant is expected to operate 415 hours per turbine 

over approximately 49 operating days during this commissioning period, which includes hours of 

operation at different load levels and with and without emission control equipment. 

Commissioning emission data provided by the turbine vendor consist of different emission 

scenarios corresponding to different phases of the commissioning period. Table 4a presents the 

expected commissioning maximum hourly emission rates. In order to minimize emission 

impacts during the commissioning period, emission rates for NOx and CO for both turbines 

combined will be limited to the levels expected for one turbine in commissioning mode and one 

turbine in normal operation mode (including startups and shutdowns) by proposed permit 

conditions. 

Table 4a –Maximum Turbine Hourly Emissions 

During Commissioning 

Pollutants Single Turbine 

Emissions, lbs/hr 

Allowed Combined 

Turbine Emissions, lbs/h

NOx 200 286 

CO 3813 4627 

VOC 164 327.5 

SOx 4.4 8.80 

PM10 9.50 19.0 

PM2.5 9.50 19.0 

For a single combustion turbine, expected maximum daily emissions during commissioning are 

based on the peak emission day for each pollutant forecast from the projected commissioning 

schedule. Because of the proposed hourly limits on NOx and CO emission rates during 
Preliminary Determination of Compliance Page 14 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

commissioning, peak daily emissions during commissioning from both turbines for NOx and CO 

are estimated as the sum of the peak commissioning emissions for one turbine and expected 

maximum daily emissions from the other turbine under normal operations. For the other 

pollutants, peak daily commissioning emissions are the sum of peak commissioning emissions 

for each turbine. Table 4b presents the maximum daily commissioning emissions. The entire 

commissioning period may take up to 120 calendar days to allow time for reviewing test and 

turning information and operational adjustments to the combustion turbines and associated plant 

equipment. 

Table 4b – Maximum Daily Emissions 

During Commissioning 

Pollutants Single Turbine 

Emissions, lbs/day 

Combined Turbine 

Emissions, lbs/day 

NOx 1755 2632 

CO 43712 48814 

VOC 1310 2620 

SOx 106 211 

PM10 221 442 

PM2.5 221 442 

Total commissioning emissions are based on turbine vendor projected emission data for the 

entire commissioning period. The emergency fire pump engine is not expected to operate during 

the turbine commissioning period. Table 4c presents total commissioning emissions. Note that 

these emissions include all emissions from startups and shutdowns during the commissioning 

period. 
Preliminary Determination of Compliance Page 15 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 4c – Total Turbine Commissioning 

Emissions 

Pollutants Single Turbine 

Emissions, tons 

Combined Turbine 

Emissions, tons 

NOx 6.24 12.48 

CO 65.17 130.34 

VOC 3.48 6.96 

SOx 0.28 0.56 

PM10 1.96 3.92 

PM2.5 1.96 3.92 

PROJECT EMISSIONS—COMMISSIONING PERIOD

For the combustion turbines’ first year of operation during which both commissioning operations 

and normal operations take place, total maximum project emissions are estimated based on 415 

hours of commissioning emissions, 300 hours of maximum startup emissions, 300 hours of 

maximum shutdown emissions, and 2,600 hours of maximum normal operation emissions, and 

estimated maximum emissions from the emergency fire pump engine. Table 4d presents the 

estimated total maximum annual emissions for the project for a year with commissioning. 
Preliminary Determination of Compliance Page 16 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 4d – Total Project Emissions During Year 

With Commissioning

Pollutants Combined Turbine 

Commissioning 

Emissions, tons/yr 

Combined Turbine 

Normal Operation 

Emissions and Engine 

Emissions, tons/yr 

Total Project 

Emissions, tons/yr 

NOx 12.48 62.87 75.35 

CO 130.34 209.56 339.90 

VOC 6.96 15.09 22.05 

SOx 0.56 14.08 14.64 

PM10 3.92 30.40 34.32 

PM2.5 3.92 30.40 34.32 
Preliminary Determination of Compliance Page 17 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

V. RULES ANALYSIS

DISTRICT AND FEDERAL NSR AND PSD REGULATIONS

Rule 20.1(c)(35) – Major Stationary Source

Major stationary source means any emission unit or stationary source which has, or will have 

after issuance of a permit, an aggregate potential to emit one or more air contaminants, including 

fugitive emissions, in amounts equal to or greater than any of following emission rates: 

 Air Pollutant Emission Rates (tons/yr)

 PM10 100 

 NOx 50 

 VOC 50 

 SOx 100 

 CO 100 

 Lead (Pb) 100 

Major source status is only relevant for pollutants for which the District does not attain a national 

air quality standard. Since the District attains all national ambient air quality standards with the 

exception of ozone, major source status is only relevant for NOx and VOCs, both of which are 

ozone precursors. In particular, the major modification thresholds (see below) apply for 

contemporaneous emission increases and associated requirements for NOx and VOCs. Based on 

its potential to emit, the Encina Power Station is an existing major stationary source for both 

NOx and VOCs. 

Rule 20.1(c)(58) – Prevention of Significant Deterioration (PSD) Stationary Source and 

40 CFR 52.21

Because the Encina Power Station is a fossil fuel fired steam electrical generating plant with a 

heat input rating greater than 250 MMBtu/hr, PSD Stationary Source status is defined by an 

aggregate potential to emit one or more air contaminants in amount equal to or greater than any 

of the following emission rates: 
Preliminary Determination of Compliance Page 18 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

 Air Pollutant Emission Rates (tons/yr)

 PM10 100 

 PM2.5 100 

 PM 100 

 NO2 100 

 VOC 100 

 SO2 100 

 CO 100 

 Lead (Pb) 100 

Since the Encina Power Station’s potential to emit exceeds the PSD stationary source threshold 

for at least one pollutant (e.g., NOx, which is considered NO2 for purposes of PSD 

determinations), it is an existing PSD stationary source. District Rule 20.1 does not explicitly 

address PM2.5 or particulate matter of all sizes (PM). However, those pollutants are addressed 

by 40 CFR 52.21 et. seq., which is EPA’s implementation of PSD rules and is an applicable 

requirement for the CECP. 

Rule 20.1( c)(16), 40 CFR §52.21, and 40 CFR Appendix S to Part 51–

Contemporaneous Emission Increase

Contemporaneous emission increase is defined in Rule 20.1 (c)(16) as the sum of emission 

increases from new or modified emission units occurring at a stationary source within the 

calendar year in which the subject emission units is expected to “commence operation” and the 

preceding four calendar years, including all other emission units with complete applications 

under District review and which are expected to commence operation within such calendar year. 

The emission increases for new units are based on the new units’ potential to emit (PTE) as 

limited by proposed permit limits pursuant to Rule 20.1(d)(1)(i)(A). The emission increases may 

also be reduced by actual emission reductions at the facility. In this case, the applicant is 

proposing to create actual emission reductions by shutting down three existing utilities boilers 

(the two other utility boilers, Units 4 and 5, will remain in operation). 
Preliminary Determination of Compliance Page 19 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Rule 20.1(c)(16) does not address when the actual emission reductions must occur relative to the 

initial startup of new or modified equipment. However, for replacement units, up to 180 days 

from the initial startup of new equipment is allowed before the actual emission reduction must be 

effective in federal implementations of PSD regulations [40 CFR §52.21(b)(3)(ii) and (viii)] and 

nonattainment NSR regulations [40 CFR Appendix S to Part 51 II.a.6.ii. and vi.] to allow a 

reasonable shakedown period for the new equipment. 

The CECP is replacing the three existing utility boilers known as Units 1, 2, and 3 at the Encina 

Power Station. At the end of Phase I of the project, full commercial operation for one of the 

CTG/STG systems, part of the electrical generating capacity of these three boilers will be 

replaced. The generating capacity of Units 1, 2, and 3 will be completely replaced by the end of 

Phase II when the second CTG/STG system is fully operational. Since the new CTG/STG 

systems are replacing these three existing boilers, simultaneous operation of the CTG/STGs and 

the three existing boilers is not allowed during the phase-in period and the boilers must be 

shutdown completely at the end of Phase II. 

In this case, 180 days is a reasonable shakedown time for each new CTG and associated 

equipment. This shakedown period allows 120 days for new equipment commissioning, which 

includes achieving the most stringent permitted emission limits, and an additional 60 days for the 

new equipment to reach full commercial operational status including verification testing both for 

emissions and operational reliability. The shakedown periods for the two CTG/STG systems 

could proceed in parallel or sequentially. 

Postproject Contemporaneous Emission Increase

Currently, the proposed CECP is expected to commence full commercial operation in 2012. Full 

commercial operation includes having both CTGs and associated STGs fully operational with 

their emission and operational status verified. Therefore, the five-year contemporaneous 

window in which emission increases need to be evaluated is the time period from 2008 through 

2012. For the years 2008 to 2012, there are no expected emission increases at the Encina Power 

Station. In addition, the District has no applications associated with the Encina Power Station 

other than the CECP that expect to commence operation at any time in the future. Therefore, the 
Preliminary Determination of Compliance Page 20 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

only emission increases for contemporaneous emission increases are those associated with the 

CECP. 

Existing Units 1, 2, and 3 at the Encina Power Station will be shut down and retired prior to full 

commercial operation of both new CTG/STG systems. The shutdown of these boilers will result 

in actual emissions reduction at the site. Rule 20.1(c)(16)(i) allows the sum of emission 

increases to be reduced by actual emission reductions occurring at the stationary source. Rule 

20.1(d)(4)(ii)(A) defines actual emission reductions from the shutdown of an emission unit as 

those calculated based on the emission unit’s preproject actual emissions. 

Preproject actual emissions are based on actual emissions occurring over the 5-year period 

preceding the receipt of the application. Rule 20.1(d)(2)(i)(B) requires the actual emissions to be 

averaged over the total operational time period within the five-year period if a representative 

two-year operating time period does not exist. Since the Application for Certification (AFC) for 

this CECP was submitted to the CEC in 2007, the preceding five years in consideration for actual 

emission reduction estimates are 2002, 2003, 2004, 2005, and 2006. Since the District 

determined that there was not a representative two-year operating time period for Units 1, 2, and 

3 of the Encina Power Station during these five years, the 5-year average of emissions from 

boilers Units 1, 2, and 3 determines pre-project actual emissions for those units. In the case of 

NOx, the emissions are based on CEMS data. For the other pollutants, emissions are based on 

the annual District emission inventory, except that PM10, PM 2.5, and total particulate (PM) 

emissions were adjusted from the inventory values based on EPA’s AP-42 emission factors, 

because the District emission inventory for the existing utility boilers reports all PM as PM10. 

Only PM2.5 results from gas-firing of the existing units. However, No. 6 fuel oil is burned a few 

hours per year to demonstrate the reliability of the backup fuel. This necessitates the adjustment 

of the emission inventory of PM2.5 and PM10 since No. 6 fuel oil combustion produces some 

particulate matter greater than 2.5 microns and some particulate matter greater than 10 microns. 

Table 5a presents the data used to determine the preproject actual emissions. 

 
Preliminary Determination of Compliance Page 21 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 5a – Boiler Units 1,2, and 3 Averaged Actual Emission 

Pollutants 2002 Actual 

Emissions, 

tons/yr 

2003 Actual

Emissions, 

 tons/yr 

2004 Actual 

Emission, 

tons/yr 

2005 Actual

Emission, 

tons/yr 

2006 Actual 

Emission, 

tons/yr 

Baseline 

Average 

Emissions, 

tons/yr 

NOx 39.5 30.8 46 31.8 16.2 32.86 

CO 494.5 228 351 241.1 110 284.9 

VOC 16.2 15.2 23 16 8.3 15.74 

SOx 9.5 12.5 2.6 2 2.7 5.9 

PM10 35.15 27.64 44.10 31.14 17.55 31.51 

PM 2.5 34.91 27.31 44.10 33.07 17.49 31.38 

PM 35.4 28 44.1 33.2 17.6 31.66 

 

 For informational purposes, Table 5b presents the contemporaneous emission increases at the 

site without consideration of proposed permit limits after completion of all phases of the CECP 

and the retirement of existing Units 1, 2, and 3. The increase is calculated based on the total 

emission increase resulting from the CECP and actual emission reductions due to shut down of 

the three existing utility boilers. The maximum annual emissions are based on the larger of the 

emissions during a standard operation year or a commissioning year. 

 
Preliminary Determination of Compliance Page 22 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 5b –Emission Increases for Estimated Maximum CECP Emission Increases 

Pollutants Estimated Maximum 

Emission Increases 

from CECP, 

tons/yr 

Actual Emission 

Reductions from 

Units 1, 2, and 3, 

tons/yr 

Maximum Potential 

Emission Increase, 

 tons/yr 

NOx 75.6 32.86 42.74 

CO 339.9 284.9 55.0 

VOC 25.1 15.7 9.4 

SOx 18 5.9 12.1 

PM10 39 31.5 7.5 

PM 2.5 39 31.4 7.6 

PM 39 31.7 7.3 

However, the actual contemporaneous emission increase, which includes limitations on potential 

to emit of the new equipment accepted by the applicant, are shown in Table 5c. These limits are 

applicable from the first date a turbine has an initial startup. These limits were accepted by the 

applicant to ensure annual emissions did not exceed those upon which the Ambient Air Quality 

Analysis (AQIA) was based (see below) and to ensure emissions were limited to below the 

major modification and PSD modification thresholds (see below). Note that all particulate 

matter emissions from the CECP are considered to be PM2.5, so a limit on PM10 suffices to 

limit PM2.5, PM10, and PM. 
Preliminary Determination of Compliance Page 23 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 5c – Contemporaneous Emission Increases 

Pollutants Allowed PTE Increases

From CECP, 

tons/yr 

Actual Emission 

Reductions from 

Units 1, 2, and 3, 

tons/yr 

Contemporaneous 

Emission Increase, 

tons/yr 

NOx 72.76 32.86 39.9 

CO 339.90 284.9 55 

VOC 25.0 15.74 9.26 

SOx 5.6 5.9 -0.3 

PM10 39 31.5 7.5 

PM2.5 39 31.4 7.6 

PM 39 31.7 7.3 

Contemporaneous Emission Increases After Completion of the Phase I Shakedown Period

The CECP contemplates starting operation of the two CTG/STG units sequentially. The second 

unit to reach full commercial operation (Phase II) may complete its shakedown period 

significantly later than the first (Phase I). To allow for this possibility, contemporaneous 

emission increases were evaluated for the operation of a single combustion turbine and the 

emergency water pump only. 

The applicant agreed to accept emission limits, as necessary, on the single combustion turbine 

and emergency water pump combined and Units 1, 2, and 3 to limit emissions below the PSD 

modification thresholds and, in the case of NOx, limit emissions to a level consistent with the 

emission offsets provided (see below). Consistent with the necessary shakedown period for the 

CTG/STG system (not to exceed 180 days), the actual emission reductions need not occur until 

the end of shakedown period for the first turbine to reach full commercial operation (i.e., before 

that time emissions from the three existing utility boilers are not limited). Therefore, the 

emission limits for Units 1, 2, and 3 do not apply until the end of the 180-day shakedown period 

for Phase I. However, the limits on potential to emit for the combustion turbine and emergency 

engine combined apply from the first date a combustion turbine has an initial startup. During the 

shakedown periods for both turbines the limits on potential to emit for both combustion turbines 

and the emergency engine listed in Table 5c are also in effect, which serves to limit the potential 
Preliminary Determination of Compliance Page 24 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

to emit of all the emission units associated with the CECP during both phases of the shakedown 

period. 

The Phase I limits in Table 5d and 5e are no longer applicable at the end of the shakedown 

period for the second CTG/STG system (i.e., the end of Phase II). At that time the limits in 

Table 5c apply to both combustion turbines and the emergency generator combined, and Units 1, 

2, and 3 must permanently cease operation. 

Table 5d presents the resulting actual emission reductions from emission limitations on the three 

existing utility boilers at the end of Phase I and Table 5e presents the resulting contemporaneous 

emission increases and limitations on the potential to emit for one turbine and the emergency fire 

pump engine combined for Phase I. 

Table 5d – Phase I Actual Emission Reductions 

Pollutants Baseline Emissions 

from Units 1, 2, and 3, 

tons/yr 

Allowed Emissions 

from Units 1, 2, and 3,

tons/yr 

Actual Emission 

Reductions, 

tons/yr 

NOx 32.86 16.33 16.53 

CO 284.9 214.85 70.05 

VOC 15.7 No Limit 0 

SOx 5.9 No Limit 0 

PM10 31.51 26.91 4.6 

PM2.5 31.38 21.78 9.6 

PM 31.66 No Limit 0 
Preliminary Determination of Compliance Page 25 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 5e – Phase I Contemporaneous Emission Increases 

Pollutants Allowed Emission 

Increases from One 

Turbine and Emergency

Fire Pump Engine, 

 tons/yr 

Actual Emission 

Reductions from 

Units 1, 2, 3, 

tons/yr 

Contemporaneous 

Emission Increase, 

 tons/yr 

NOx 36.40 16.53 19.87 

CO 169.95 70.05 99.9 

VOC 12.5 0 12.5 

SOx 2.8 0 2.8 

PM10 19.5 4.6 14.9 

PM2.5 19.5 9.6 9.9 

PM 19.5 0 19.5 

Rule 20.1(c)(33) – Major Modification

Major modification is defined as a physical or operational change which results in a 

contemporaneous emissions increase for a pollutant or its precursors for which the District does 

not attain the federal ambient air quality standards at an existing major stationary source for that 

pollutant. As the only national ambient air quality standard San Diego County does not attain is 

the 8-hour ozone standard, only the ozone precursors NOx and VOCs are evaluated to determine 

whether a major modification occurs. The major modification threshold for both NOx and 

VOCs is a contemporaneous emission increase of the pollutant equal to or greater than 25 tons 

per year. The contemporaneous emission increase of NOx resulting from the CECP is 39.9 tons 

per year (Table 5c), which is higher than the 25 tons per year threshold for a major modification. 

Therefore, the proposed CECP is a major modification to the facility for NOx. The CECP is not 

a major modification for VOCs because the contemporaneous emission increase is only 9.31 

tons per year, less than the major modification threshold. 

Rule 20.1(c)(57) PSD Modification and 40 CFR 52.21

A PSD modification is a contemporaneous emission increase occurring at a modified PSD 

stationary source equal to or greater than the following emission rates: 
Preliminary Determination of Compliance Page 26 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

 Pollutant Emission Rates (tons/yr)

 PM 25 

PM10 15 

 PM2.5 10 

 NO2 40 

 VOC 40 

 SO2 40 

 CO 100 

 Lead (Pb) 0.6 

(All NOx is considered NO2 for the purpose of PSD determinations). 

Without considering proposed annual limits, the contemporaneous emission increase of NOx is 

42.74 tons per year, which is higher than the 40 tons per year threshold for a PSD modification. 

However, the applicant has accepted a limit of 72.76 tons per year of NOx emissions in the 

proposed permit to keep the project NOx emissions below the PSD modification threshold. 

None of the other pollutant contemporaneous emission increases exceed the PSD modification 

level (see Tables 5b and 5c, there are no lead emissions from the CECP). 

Rule 20.3(d)(1)- Best Available Control Technology(BACT)/Lowest Achievable 

Emission Rate(LAER)

Subsection 20.3(d)(1)(i) of the rule requires that Best Available Control Technology (BACT) be 

installed on a new or modified emission unit on a pollutant-specific basis if emissions exceed 10 

lbs/day or more of PM10, NOx, VOC or SOx. Subsection 20.3(d)(1)(v) also requires that 

Lowest Achievable Emission Rate (LAER) be installed for a new emission unit which results in 

an emission increase which constitutes a major modification. Emergency equipment is exempt 

from the LAER requirements of 20.3(d)(1)(v). 

LAER cannot be less stringent than BACT and is required only for air contaminants and their 

precursors for which the stationary source is major and for which the district is classified as nonattainment of a national ambient air quality standard. Because the District attains the National 

Ambient Air Quality Standards (NAAQS) for CO, SO2, PM2.5 and PM10, LAER does not apply 
Preliminary Determination of Compliance Page 27 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

to these pollutants. LAER, however, applies to NOx emissions since the CECP constitutes a 

major modification for NOx. For the combustion turbines, BACT applies for VOC, SOx, and 

PM10 emissions because their emissions are more than 10 pounds per day. 

Rule 20.3(d)(1)(vi) also requires that for a new or modified emission unit at a PSD stationary 

source with an emission increase of one or more air contaminant which constitutes a new PSD 

stationary source or PSD modification, BACT shall apply for each such air contaminant. 

Although the contemporaneous emission increase for CO is less than the PSD modification 

threshold, the emission increase for CO from the CECP itself is larger than the PSD stationary 

source threshold. Therefore, the CO emissions are also subject to BACT. 

In summary, based on emission estimates, LAER is triggered for NOx and, for the combustion 

turbines, BACT is triggered for CO, VOC, SOx, and PM10. For the emergency fire pump 

engine, BACT is triggered only for CO as part of the CECP because the potential to emit VOC, 

SOx, and PM10 is less than 10 pounds per day for the emission unit. 

Oxides of Nitrogen (NOx)—Combustion Turbines, Normal Operations

The turbine vendor has guaranteed a NOx emission level of 2.0 ppmvd at 15% oxygen at greater 

than 60% load with the SCR add-on air pollution control system to control NOx installed. The 

applicant has proposed a NOx emission limit of 2.0 ppmvd averaged over one hour as BACT and 

LAER during normal operations. 

According to the ARB Guidance for Power Plant Siting and Best Available Control Technology, 

September 1999, BACT/LAER for NOx emissions from combined-cycle combustion turbine is 

either a NOx emission concentration of 2.5 ppmvd based on a one-hour averaging period or 2.0 

ppmvd based on a three-hour averaging period, both calculated at 15% oxygen. However ARB 

is revising its BACT/LAER guidance for power plants to include limits achieved or proposed by 

more recent projects. The District consulted the BACT / LAER Clearinghouses, other air 

districts, EPA, and ARB for recent BACT/LAER determinations. A number of combined-cycle 

power plants of comparable size were permitted with NOx at 2.5 ppmvd or lower, averaged over 
Preliminary Determination of Compliance Page 28 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

one hour. The District examined the following projects with NOx emission limits less than 2.5 

ppmvd at 15% oxygen: 

• The Sithe Mystic Development LLC power plant is permitted by the Massachusetts 

Department of Environmental Protection and has been in commercial operation since 

2002. This plant has been in compliance with a 2 ppmvd NOx limit averaged over one 

hour, excluding startups and shutdowns, with less than 0.1% of operating time exceeding 

this standard. 

• The Avenal Power Center is proposed to be permitted by the San Joaquin Valley Air 

Pollution Control District in a Preliminary Determination of Compliance issued on July 

11, 2008 [CEC Docket No. 08-AFC-01]. This plant is proposed to be permitted at 2.0 

ppmvd of NOx averaged over one hour. 

• The Diamond Wanapa, L.P, power plant is permitted by EPA, Region X, at 2 ppmvd of 

NOx averaged over three hours. This plant has not been constructed yet. 

• The El Segundo Power, LLC is proposed to be permitted by South Coast Air Quality 

Management District in a Preliminary Determination of Compliance issued on August 22, 

2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two 

rapid response combined-cycle Siemens turbines identical to the combustion turbines 

proposed for the CECP, and is proposed to be permitted at 2.0 ppmvd of NOx averaged 

over one hour. 

• The Palomar Energy Center in Escondido permitted by the District has been able to 

comply with 2.0 ppmvd NOx limit averaged over one hour during normal operations, 

excluding startup and shutdown periods, limited periods of low load operation, rapid 

transients, and tuning of the combustors and the SCR. 

 Based on the above information, the District has preliminarily determined that BACT for NOx 

should be 2.0 ppmvd at 15% oxygen, averaged over one hour for normal operation with 
Preliminary Determination of Compliance Page 29 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

appropriate exclusions to address technical feasibility for startups and shutdowns and other 

abnormal periods of operation. As defined in Rule 20.1(c)(32), LAER means the most stringent 

emission limitation, or most effective emission control device or control technique, unless such 

emission limit , device or technique is not achievable. An emission limit of 2.0 ppmvd NOx at 

15% averaged over one hour is considered by the District to be the current most stringent 

emission limit for larger combined-cycle combustion turbines that is achievable. Therefore, this 

standard also applies as LAER for NOx for such turbines. 

As proposed by the applicant, the CECP combustion turbines will be equipped with dry ultra 

low-NOx combustors and a selective catalytic reduction (SCR) that in combination are designed 

to achieve 2.0 ppmvd NOx averaged over one hour. The District is unaware of any 

demonstrations that alternative technologies for control of NOx such as the XONONTM catalytic 

combustors or EMxTM (SCONOX) catalyst system can achieve NOx emission levels lower than 

the combination of dry ultra low-NOx combustors and SCR on large (greater than 50 MW) 

natural-gas-fired combustion turbines. A continuous emission monitoring system (CEMS) and 

annual source testing will be used to confirm compliance with this emission limit. 

Carbon Monoxide (CO)—Combustion Turbines, Normal Operations

The turbine vendor has guaranteed a CO emission level of 2.0 ppmvd at 15% oxygen at greater 

than 60% load with the oxidation catalyst add-on air pollution control system to control CO 

installed. The applicant has proposed a CO emission limit of 2.0 ppmvd averaged over one hour 

as BACT and LAER during normal operations. 

According to ARB Guidance for Power Plant Siting and Best Available Control Technology, 

September 1999, BACT for CO emissions from this equipment is 6.0 ppmvd based on a 3-hr 

averaging period, calculated at 15 % oxygen. Because the ARB Guidance is being updated, 

other air districts, EPA, and ARB Clearinghouses, were been consulted for more recent 

determinations. The District examined the following projects with CO emission limits less than 

4.0 ppmvd at 15% oxygen: 
Preliminary Determination of Compliance Page 30 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

• The Sithe Mystic Development LLC power plant in Massachusetts is permitted at 2.0 

ppmvd CO averaged over one hour with startups and shutdowns excluded. 

• The Avenal Power Center is proposed to be permitted by the San Joaquin Valley Air 

Pollution Control District in a Preliminary Determination of Compliance issued on July 

11, 2008 [CEC Docket No. 08-AFC-01]. This plant is proposed to be permitted at 4.0 

ppmvd of CO averaged over three hours. 

• The Magnolia Power Project is permitted by the South Coast Air Quality Management 

District at 2.0 ppmvd CO averaged over one hour. This plant has not been built yet. 

• The El Segundo Power, LLC is proposed to be permitted by South Coast Air Quality 

Management District in a Preliminary Determination of Compliance issued on August 22, 

2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two 

rapid response combined-cycle Siemens turbines identical to the combustion turbines 

proposed for the CECP, and is proposed to be permitted at 2.0 ppmvd of CO averaged 

over one hour. 

• The Palomar Energy Center in Escondido has been able to comply with 4.0 ppmvd CO 

limit averaged over three hours during normal operations, excluding startup and 

shutdown periods and periods of low-load operations and tuning. District experience 

based on CEMS data indicates that it likely achieves 2.0 ppmvd averaged over one hour. 

Based on the information above, the District has preliminarily determined a CO limit of 2.0 

ppmvd calculated at 15% oxygen averaged over one hour to be BACT for CO for the CECP 

combustion turbines for normal operation with appropriate exclusion to address technological 

feasibility for startups and shutdowns and other abnormal periods of operation. To meet this 

requirement, the applicant evaluated the use of an oxidation catalyst, which is the only postcombustion technology currently available to control CO, VOC, and toxic emissions. This 

technology is acceptable as BACT for CO. The applicant will therefore use an oxidation catalyst 
Preliminary Determination of Compliance Page 31 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

to meet the BACT level of 2.0 ppmvd at 15 % oxygen on a one-hour average. A CEMs and 

annual source testing will be used to confirm compliance with this limit. 

Volatile Organic Compounds (VOCs)—Combustion Turbines, Normal Operations

The turbine vendor has guaranteed a VOC emission level of 2.0 ppmvd at 15% oxygen at greater 

than 60% load with the oxidation catalyst add-on air pollution control system to control VOCs 

installed. The applicant has proposed a VOC emission limit of 2.0 ppmvd averaged over one 

hour as BACT and LAER during normal operations. 

According to ARB Guidance for Power Plant Siting and Best Available Control Technology, 

September 1999, BACT for VOC emissions from this type of equipment is 2.0 ppmvd based on a 

three-hour averaging period, calculated at 15 % oxygen. Because the ARB Guidance is being 

updated, other air districts, EPA and ARB Clearinghouses, have been consulted for more recent 

determinations. The District examined the following projects with VOC emission limits of 2.0 

ppmvd or less at 15% oxygen: 

• The Sithe Mystic Development LLC power plant in Massachusetts was permitted at 1.7 

ppmvd VOC averaged over one hour. The Sithe Mystic Power Plant combustion turbine is a 

Mitsubishi 501G turbine. This turbine is considerably larger and a newer generation G-class 

combustion turbine as compared the Siemens F-class turbine proposed for this project. 

• The Magnolia Power Project was permitted by the South Coast Air Quality 

Management District at 2 ppmvd VOC averaged over one hour. This plant has not been 

built yet. 

• The Avenal Power Center is proposed to be permitted by the San Joaquin Valley Air 

Pollution Control District (SJVAPCD) in a Preliminary Determination of Compliance 

issued on July 11, 2008 [CEC Docket No. 08-AFC-01]. This plant is proposed to be 

permitted at 1.4 ppmvd of VOCs averaged over three hours. However, SJVAPCD has 

indicated in communications to the District that the most stringent limit for CTGs larger 

than 160 MW that are actually operating in the SJVAPCD is 2.0 ppmvd of VOCs 
Preliminary Determination of Compliance Page 32 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

averaged over three hours, with clock hours that include a portion of a startup or 

shutdown period excluded. 

• The El Segundo Power, LLC is proposed to be permitted by South Coast Air Quality 

Management District in a Preliminary Determination of Compliance issued on August 22, 

2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two 

rapid response combined-cycle Siemens turbines identical to the combustion turbines 

proposed for the CECP, and is proposed to be permitted at 2.0 ppmvd of VOC averaged 

over one hour. 

• The Palomar Energy Center in Escondido has been able to comply with 2.0 ppmvd 

VOC limit averaged over three hours during normal operations, excluding startup and 

shutdown periods, limited periods of low load operation, and tuning. District experience 

based on CO CEMS data indicates that it likely achieves 2.0 ppmvd averaged over one 

hour. 

Based on the above information, the District has preliminarily determined that BACT for the 

CECP combustion turbines is 2.0 ppmvd VOC, measured as methane at 15% O2, based on a onehour averaging period for normal operation with appropriate exclusion to address technologically 

feasibility for startups and shutdowns and other abnormal periods of operation. 

The applicant analyzed the use of an oxidation catalyst, which is the only post combustion 

technology currently available to control CO, VOC, and toxic emissions. An initial source 

test will be used to confirm compliance with these limits. Additionally, the source test data 

will be used to establish a correlation between CO emissions and VOC emissions to provide 

an accurate indicator of continued compliance with these limits using the CEMS data for CO. 

Compliance will be determined based on both source test data and a surrogate relationship 

with CO because CEMS technology is not available for VOCs. 
Preliminary Determination of Compliance Page 33 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Startups and Shutdowns—Combustion Turbines, NOx, CO, and VOCs

Startups are limited to 60 minutes and shutdowns to 30 minutes (an additional 5 minutes are 

allowed to purge emissions from the stack). These times are consistent with, or more 

stringent than the recently issued PDOC by the SCAQMD for an identical combined-cycle 

turbine for the El Segundo Power Redevelopment Project (ESPRP) as recently amended 

[CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. The expected duration of the 

turbine startups and shutdowns are 22 minutes and 7 minutes, respectively. The additional 

time is allowed to address contingencies during startups and shutdowns. 

Emissions during startup and shutdown are further controlled by setting mass emission limits 

per startup and shutdown event (excluding the commissioning period). The mass emission 

limits are based on manufacturer emission estimates for the expected startup or shutdown 

durations and maximum emissions during the remainder of the time with an adjustment 

factor of two for NOx and CO, as proposed by the applicant, to allow for increased emissions 

during the potential rapid transients during these operations. No adjustment factor is used for 

VOC emissions, also as proposed by the applicant. For example, for a 60-minute startup, 

total allowed emissions for NOx are: 

Emissions = 2 x (25 lb for the 22 minute startup + (38/60) x 15.1 lbs/hr for normal 

operations) 

 = 69.2 lbs 

and, for a 30-minute shutdown, total allowed emissions for VOCs are: 

Emissions = 5 lb for the 7 minute shutdown + (23/60) x 5.3 lbs/hr for normal operations 

 = 7 lbs 

Table 6a presents the mass emissions limits during startup and shutdown 
Preliminary Determination of Compliance Page 34 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Table 6a – Emission Limits During Startup and 

Shutdown – SCR to Operate as Soon as Feasible

Pollutants Startup Emissions, 

pounds per event 

Shutdown Emissions,

pounds per event 

NOx 69.2 25.7 

CO 545 277 

VOC 16.3 7.0 

 An additional requirement that applies during startups and shutdowns (and all other times 

the combustion turbine is operating with an SCR system) is that the SCR be in full operation 

as soon as its reaches its minimum operating temperature to control NOx to the maximum 

extent feasible. The minimum temperature is set at 450 degrees Fahrenheit in the proposed 

permit conditions based on the minimum operating temperature provided by the 

manufacturer for the similar SCR associated with the ESPRP. 

The District has preliminarily determined that the above requirements represent BACT for 

NOx, CO, and VOCs and LAER, for NOx only, specifically applicable to the CECP during 

startups and shutdowns of the combustion turbines. 

Abnormal Events—Combustion Turbines, NOx, CO, and VOCs

Modern combustion turbines with ultra low NOx combustors normally operate under 

extremely lean conditions (low fuel to air ratio) where most of the fuel and air are premixed 

prior to combustion to achieve low NOx, CO, and VOC emissions (lean premix combustion). 

The operating point is close to the fuel to air ratio where combustion becomes unstable 

because of the low combustion temperature. To prevent combustion instability, which may 

result in a turbine trip (unplanned shutdown) and the resulting expense and increased 

emissions from a unplanned startup, automatic control systems may increase the fuel to air 

ratio under some abnormal operating conditions. Furthermore, at low loads the fuel may not 

be premixed with air (diffusion flame mode) to maintain combustion stability. In both these 

situations, the NOx, CO, VOCs can be much higher than in the lean premix combustion 
Preliminary Determination of Compliance Page 35 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

mode. It is, therefore, not technologically feasible, to achieve the BACT emission levels 

applicable to normal operations in such situations. 

Startups and shutdowns are abnormal operating conditions that are discussed above. The 

applicant has identified transient events (excluding startups and shutdowns) as another 

abnormal operating condition. Other abnormal operating conditions that, in the District’s 

experience, may occur with large combined-cycle combustion turbines are low-load 

operation (excluding startups and shutdowns) and tuning of the turbine combustors or 

emission control systems to achieve the most efficient operation and low emission rates. 

Low-load operation can occur when the turbine’s automatic control system senses a possible 

combustion or other equipment problem and automatically reduces the turbine load to 

prevent an immediate turbine trip. In most cases, the problem is resolved without shutting 

down the turbine, which avoids the emissions and cost of a restart. 

Based on information supplied by the applicant and the District’s experience with ongoing 

operations at a large combined-cycle power plant, the District has preliminarily determined 

that following represent BACT for NOx, CO, and VOCs and LAER for NOx during 

specified abnormal events: 

• Tuning events are not to exceed 720 minutes in a calendar day nor exceed 40 hours in 

a calendar year for each turbine. 

• The BACT emission limits for normal operations with a three-hour-averaging time 

instead of a one-hour-averaging time are applicable for any hour in which the change in 

gross electrical output produced by the combustion turbine exceeds 50 MW per minute 

for one minute or longer. 

• Periods of operation at low load are not to exceed 130 minutes in any calendar day nor 

an aggregate of 780 minutes in any calendar year. 
Preliminary Determination of Compliance Page 36 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

For NOx, emission limits of 12.6 ppmvd averaged and 42 ppmvd averaged over one hour, 

which correspond to District Rules 69.3.1 and 69.3 standards, respectively, remain in effect 

during all abnormal periods. The District has proposed amending Rule 69.3.1 to exclude 

low-load periods. However, if this amendment is adopted, the Rule 69.3 limit would still 

remain in effect. The District’s preliminarily proposed criteria for a transient events and 

BACT levels have been acceptable to another large combined-cycle facility. 

PM10 and SOx—Combustion Turbines

From the ARB Guidance for Power Plant Siting and Best Available Control Technology, 

September 1999, BACT for this equipment is the use of natural gas that contains less than 1 

grain of sulfur compounds per 100 standard cubic feet of natural gas. Public Utility 

Commission (PUC) quality natural gas sold in San Diego County is required to meet a 

maximum sulfur content limit of 0.75 grains of sulfur compounds per 100 standard cubic feet 

of natural gas. Therefore, use of PUC quality natural gas meeting this 0.75 grains limit is 

recommended as BACT. In actuality, the natural gas in the local gas distribution system 

averages well under 0.75 grains per 100 standard cubic feet of gas. The applicant will be 

required to maintain documents showing the sulfur content of natural gas used. Any 

alternative supplies of natural gas must meet this sulfur content limit. 

BACT—Emergency Fire Pump Engine

When technologically feasible, BACT for emergency engines is to use an engine fueled with 

natural gas. However, emergency fire pumps require an independent source of fuel for 

reliable operation in emergency situations in which the natural gas supply might be 

interrupted. In addition, add-on emission control systems are not technologically feasible as 

they may compromise the reliability of the fire pump. Therefore, the District has 

preliminarily concluded that BACT for the emergency fire pump engine is purchase of an 

engine certified to the most stringent federal emission standard for fire pump engines (i.e., a 

2009 or later model year engine). The fire pump engine must also comply with the 

requirements of Section 93115 et. seq. of Title 17 of the California Codes of Regulations 

(CCR) 
Preliminary Determination of Compliance Page 37 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Rule 20.3(d)(2) – Air Quality Impact Analysis (AQIA)

This subsection of Rule 20.3 requires that a project resulting in an emission increase equal to 

or greater than the AQIA Thresholds shall demonstrate through an AQIA that the project will 

not cause or contribute to a violation of a state or national ambient air quality standard. For 

the CECP, an Air Quality Impact Analysis (AQIA) was performed to determine if the 

proposed project by itself contributes to an exceedance of the National Ambient Air Quality 

Standards or the State Ambient Air Quality Standard. The modeling was done under 

expected worst-case hourly and annual emission rates during commissioning, startup and 

shutdown, and normal operations. The analysis shows no violation of any Ambient Air 

Quality Standard. The analysis can be reviewed in the Appendix A of this determination. 

The proposed permit conditions contain hourly and annual emission limits that are applicable 

at all times to ensure that the project will not cause or contribute to a violation of any 

National Ambient Air Quality Standard or State Ambient Air Quality Standards. 

Rule 20.3 (d)(3), (4)-Prevention of Significant Deterioration (PSD)

This subsection requires that a PSD evaluation be performed for any new PSD stationary 

source (source that has an aggregate potential to emit of one or more air contaminants in 

amount equal to or greater than the PSD thresholds) and to any PSD modification 

(contemporaneous emission increase occurring at a modified PSD stationary source equal to 

or greater than the PSD modification thresholds), for those air contaminants for which the 

District is classified as attainment or unclassified with respect to a national ambient air 

quality standard. The Encina Power Plant is an existing PSD stationary source. Therefore, 

only the PSD modification threshold is applicable to determining whether a PSD evaluation 

needs to be performed. The applicant has accepted that an annual limit of 72.76 tons per year 

of NOx emissions to keep the project NOx emissions below the PSD modification threshold. 

Since the annual limit suffices to avoid the PSD modification threshold and NOx emissions 

are monitored with the CEMS, no limits on hours of normal operations or startup and 

shutdown are necessary. As shown in Tables 5b and 5c, the contemporaneous emissions 

increase for all other pollutants do not exceed the applicable PSD modification thresholds 

after completion of the project. In addition, for Phase I of the project the applicant has 
Preliminary Determination of Compliance Page 38 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

accepted proposed permit limits, as necessary, to limit contemporaneous emission increases 

to less than all PSD modification thresholds (see Tables 5d and 5e). 

Rule 20.3(d)(4) – Public Notice and Comment

For any project that is subject to the AQIA requirements of Rule 20.3(d)(2), these provisions 

require the District to publish a notice of the proposed action in at least one newspaper of 

general circulation in San Diego County as well as send notices and specified documents to 

the EPA and ARB. Because the project is not subject to Rule 20.3(d)(3) the additional 

notification requirements of Rule 20.3(d)(3)(iii) are not applicable. Notice of proposed 

installation of the CECP will be published in the San Diego Daily Transcript and mailed to 

EPA and ARB air districts for a 30-day comment period. 

Rule 20.3(d)(5)-Emission Offsets

This provision requires that emission offsets be provided for projects that result in a 

contemporaneous emission increase of any federal nonattainment criteria pollutant or its 

precursors which exceed new major source or major modification thresholds. The District is 

a federal nonattainment area only for ozone. Therefore, offsets are potentially only required 

for NOx and VOC emissions, as ozone precursors. For the CECP, VOC contemporaneous 

emission increases do not exceed the major modification thresholds and an annual emission 

limit has been accepted. Therefore, offsets are only required for NOx emissions. The 

maximum contemporaneous emission increase of NOx is 39.9 tons per year for this project. 

An offset ratio of 1.2 to 1 is required [Rule 20.3(d)(8)(i)(B)], so a total of 47.88 tons per year 

of NOx emission offsets will be required. The offsets must be surrendered to the District 

prior to the initial startup of the equipment for which they are required [Rule 20.1(d)(5)(iii)]. 

Since the CECP may become operational in two phases, 23.91 tons per year of the offsets are 

assigned to each combustion turbine and 0.06 tons per year are assigned to the emergency 

fire pump engine. 

For Phase I of the project, the applicant has accepted proposed permit limits on NOx to limit 

contemporaneous emission increases to a level consistent with the emission offsets provided 

for a single combustion turbine and the emergency fire pump engine. The offsets assigned to 
Preliminary Determination of Compliance Page 39 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

the emergency fire pump engine do not rely on any actual emission reductions at the facility 

to reduce the engine’s contemporaneous emission increase by itself. However, the 

contemporaneous emission increase for the combustion turbine and the emergency fire pump 

engine combined are limited to a level consistent with the offsets provided for both emission 

units. 

Offsets may be actual emission reductions, stationary source Class A emission reduction 

credits (ERCs) issued under District Rules 26.0-26.10, or mobile source emission reduction 

credits (MERCs) issued under District Rule 27 (if approved by ARB and EPA.). The 

applicant currently owns Emission Reduction Credits (ERCs) representing 37.6 tons per year 

of NOx emission offsets and has identified more than 10.3 tons per year of NOx emission 

offset available for purchase. For the purpose of the PDOC, the District considers this an 

adequate demonstration that the applicant can obtain sufficient credits. 

Rule 20.3(e)(1) – Compliance Certification

This rule requires that prior to receiving an Authority to Construct (or Final Determination of 

Compliance), an applicant for any new or modified stationary source required to satisfy the 

LAER provisions of Rule 20.3(d)(1) or the major source offset requirement of Rule 

20.3(d)(8) shall certify that all major sources operated by such person in the state are in 

compliance with all applicable emissions limitations and standards under the federal Clean 

Air Act. Carlsbad Energy Center, LLC (the applicant) is an indirect wholly owned 

subsidiary of NRG Energy, Inc., which also operates the Encina Power Station, which is a 

major stationary source located in San Diego County, and on whose property the CECP will 

be located. The Encina Power Station operation has been regulated by the San Diego Air 

Pollution Control District under permits to operate issued for its five boilers and one gas 

turbine. Besides the Encina Power Station, NGR Energy, Inc., owns other potential major 

stationary sources in the state, including the El Segundo Generating Station in El Segundo 

California and the Long Beach Generating Station in Long Beach California. A compliance 

certification for all major sources in the state owned by NRG Energy, Inc. will be required 

before the FDOC is issued. 
Preliminary Determination of Compliance Page 40 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Rule 20.3(e)(2) – Alternative Siting and Alternatives Analysis

The applicant has provided an analysis of various alternatives to the project. This analysis 

included a No Project alternative, alternative sites, and alternative technologies. Since all of 

San Diego County is currently classified as non-attainment for ozone, an alternative location 

within San Diego would not avoid the project being located in a non-attainment area.

Rule 20.5 – Power Plants

This rule requires that the District submit Preliminary and Final Determinations of 

Compliance reports to the California Energy Commission (CEC). The Final Determination of 

Compliance is equivalent to a District Authority to Construct. This Preliminary 

Determination of Compliance is to be submitted to the CEC. The Final Determination of 

Compliance will be submitted subsequently after a 30-day comment period for the PDOC 

and after consideration of any comments received. 

DISTRICT PROHIBITORY RULES

Rule 50 – Visible Emissions

This rule limits air contaminants emissions into the atmosphere of shade darker than 

Ringlemann 1 (20% opacity) to not more than an aggregate of three minutes in any 

consecutive sixty-minute period. 

Based on the proposed equipment and the type of fuel to be used (natural gas), no visible 

emissions at or above this level are expected during operation of the power plant. 

Rule 51 – Nuisance

This rule prohibits the discharge of air contaminants that cause or have a tendency to cause 

injury, nuisance, annoyance to people and/or the public or damage to any business or 

property. 

No nuisance or complaints are expected from this type of equipment. 
Preliminary Determination of Compliance Page 41 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Rule 53 – Specific Air Contaminants

This rule limits emissions of sulfur compounds (calculated as SO2) to less than or equal to 

0.05% (500 ppm) by volume, on a dry basis. The rule also limits particulate matter 

emissions from gaseous fuel combustion to less than or equal 0.1 grains per dry standard 

cubic foot of exhaust calculated at 12% CO2. 

Sulfur Compounds

The applicant proposes to use Public Utilities Commission (PUC) quality natural gas sold in 

San Diego County. Because of the low sulfur content of the fuel, the plant is expected to 

comply with the sulfur emission requirements of Rule 53. The fuel is expected to have a 

sulfur content less than 0.75 grains per 100 dry standard cubic foot (gr/100 dscf). 

Using an F-Factor of 8710 standard cubic feet of exhaust gas per million Btu of heat input for 

natural gas combustion at 0% O2 in the exhaust, assuming all sulfur in the fuel is converted 

into SO2, the concentration by volume of SO2 in the exhaust gas is: 

SO2 concentration = (0.75 grain /100 scf fuel) x (1lb SO2 / 7000 grain) x (385 scf SO2 / 64 lb 

SO2) x (1 scf fuel / 1015 x 10-6 MMBtu) x (1MMBtu / 8710 dscf of exhaust) x (106

) = 0.72 

ppm SO2 by volume. 

This is well below the Rule 53 limit of 500 ppm SO2 by volume. Therefore, the project is 

expected to comply with this rule. 

Particulates

Using an F-Factor of 198.025 standard cubic feet of exhaust per pound of natural gas 

combusted @ 12% CO2, a maximum natural gas usage of 91,454 lbs /hr, and an estimated 

maximum particulate matter emission rate of 9.5 lbs/hr, combustion particulate at maximum 

load are estimated to be: 

Grain loading = [(9.5 lbs/hr)(7,000 gr/lb)] / (198.025 scf/lb fuel)(91,454 lbs fuel/hr)) = 0.004 

gr/dscf 
Preliminary Determination of Compliance Page 42 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

This is well below the Rule 53 emission limit of 0.1 gr/dscf. Therefore the plant is expected 

comply with this rule. 

Rule 68 –Oxides of Nitrogen from Fuel Burning Equipment

This rule limits NOx emissions from any natural gas fueled combustion equipment to less 

than 125 ppmvd calculated at 3% oxygen on a dry basis. However, this equipment is subject 

to the more stringent requirements of Rule 69.3 and Rule 69.3.1 and is exempt from Rule 68. 

Rule 69.3-Stationary Gas Turbines – Reasonably Available Control Technology

This rule limits NOx emissions from combustion turbines fueled with natural gas greater than 

0.3 MW to 42 ppmvd at 15% oxygen when fired on natural gas. Equipment is exempt from 

the standards during 120 minute startup and shutdown periods. 

As proposed, the combustion turbines for this project will be equipped with dry ultra low 

NOx combustors and SCR controls for NOx. Proposed permit conditions limit NOx 

emissions to 2.0 ppmvd during normal operations, which is far below the 42 ppmvd rule 

standard. Maximum durations of startups have been proposed by the applicant (60 minutes 

for startup and 30 minutes for shutdown) are shorter than Rule 69.3 requirements. However, 

commissioning, low-load operation, tuning, and transient periods are still subject to the rule 

standards. The facility permit will contain conditions to limit emissions below the emissions 

levels specified in Rule 69.3 (excluding startups and shutdown as defined in Rule 69.3). A 

CEMS will monitor emissions during combustion turbine operations. 

Rule 69.3.1 – Stationary Gas Turbines – Best Available Retrofit Control Technology

This rule limits NOx emissions from combustion turbines greater than 10 MW to 15x(E/25) 

ppmvd when operating uncontrolled and 9 x (E/25) ppm at 15% oxygen when operating with 

add-on emission controls and averaged over a one-hour period, where E is the thermal 

efficiency of the unit. The rule also specifies monitoring and record keeping requirements. 

Startups, shutdowns, and fuel changes are defined by the rule and excluded from compliance 

with these limits. Equipment is exempt from the standards during 120 minute startup and 

shutdown periods. Maximum durations of startups have been proposed by the applicant (60 

minutes for startup and 30 minutes for shutdown) are shorter than Rule 69.3.1 requirements. 
Preliminary Determination of Compliance Page 43 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

The thermal efficiency for each turbine, as stated by the applicant, is 36.5 %. Therefore the 

maximum allowable uncontrolled NOx concentration is 21.9 ppmvd based on a 1-hour 

averaging period at 15% oxygen and the maximum allowable controlled NOx concentration 

is 12.6 ppmvd. The uncontrolled concentration limit would only be applicable prior to 

installation of the SCR system. 

As proposed, the combustion turbines for this project will be equipped with dry ultra low 

NOx combustors and SCR controls for NOx. Proposed permit conditions limit NOx 

emissions to 2.0 ppmvd during normal operations, which is far below the 12.6 ppmvd rule 

standard. Maximum durations of startups have been proposed by the applicant (60 minutes 

for startup and 30 minutes for shutdown) are shorter than Rule 69.3.1 requirements. 

However, commissioning, low-load operation, tuning, and transient periods are still subject 

to the rule standards. The facility permit will contain conditions to limit emissions below the 

emissions levels specified in Rule 69.3.1 (excluding startups and shutdown as defined in 

Rule 69.3.1). A CEMS will monitor emissions during combustion turbine operations. A 

CEMS will monitor emissions during combustion turbine operations. 

Rule 69.4 – Stationary Reciprocating Internal Combustion Engines – Reasonably 

Available Control Technology

This rule applies to stationary internal combustion engines with brake horsepower rating of 

50 or greater and located at a stationary source with potential to emit of 50 tons per year or 

more of NOx. Since the proposed emergency fire pump engine is subject to Rule 69.4.1, 

which contains more stringent standards, compliance with Rule 69.4.1 will serve for 

compliance with Rule 69.4. 

Rule 69.4.1 – Stationary Reciprocating Internal combustion Engines – Best Available 

Retrofit Control Technologies.

Rule 69.4.1(d)(1) requires the engine to meet the NOx emission standard of 6.9 grams per 

brake horsepower hour (g/bhp-hr). This preliminarily proposed engine is an EPA certified 

engine with NOx emission at 3.92 g/bhp-hr. In addition, proposed permit conditions will 
Preliminary Determination of Compliance Page 44 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

require the engine to meet the more stringent EPA certification requirements for model year 

2009 and later engines. Therefore, the engine is in compliance with this requirement. 

Rule 69.4.1(d)(2) requires the engine to meet CO emission standard of 4500 ppmvd at 15% 

oxygen. This engine is in compliance with this requirement, with a CO emission level of 

61.2 ppmvd at 15% oxygen. 

Rule 69.4.1(d)(4) requires the engine to use only California Diesel fuel. The use of CARB diesel 

is specified in the proposed permit conditions. 

Rule 69.4.1(e)(3) requires installation of a non-resettable totalizing meter or a non-resettable 

hour meter. The proposed engine has an hour meter. 

Rule 69.4.1 requires the engine operator to conduct periodic maintenance of the engine and its 

control system in accordance with a procedure recommended by the manufacturer or approved 

by the District. Compliance with this requirement is verified through recordkeeping. 

 

Rule 69.4.1(g)(1)(v), (vi) requires the engine operator to keep records of California Diesel 

fuel certification and engine maintenance procedure. Compliance with this requirement is 

verified through recordkeeping. 

Rule 69.4.1(g)(2) requires the engine operator to maintain an operating log of the dates and 

times of engine operation, of the total cumulative hours of operation per calendar year, and of 

engine periodic maintenance. Compliance with this requirement is verified through 

recordkeeping. 

Rule 69.4.1(g)(6) requires all records to be kept on site for at least three years and made 

available to the District upon request. The proposed permit conditions require records to be 

kept five years. 

Rule 69.4.1(i)(1) exempts emergency standby engines from periodic source testing. 
Preliminary Determination of Compliance Page 45 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Rule 1200 – Toxic Air Contaminants

Rule 1200 New Source Review for Toxic Air Contaminants requires that a Health Risk 

Assessment (HRA) be performed if the emissions of toxic air contaminants will increase. A 

detailed HRA is necessary if toxics emissions exceed District de minimis levels. Toxic Best 

Available Control Technology (TBACT) must be installed if the HRA shows a cancer risk 

greater than one in a million. Additional requirements apply if the cancer risk is expected to 

exceed ten in a million. 

An HRA was performed using EPA AP-42 emission factors and California Air Toxics 

Emission Factors (CATEF) for toxic air contaminant emissions from the project, which 

include the two combustion turbines and the emergency fire pump engine. The health risk 

was determined to be less than one in a million at all the receptors located beyond the plant 

boundary. In addition, a supplementary HRA was performed using emission factors based 

on a recent source test of a combined-cycle power plant during the first hour of a cold start. 

These emission factors were used to further examine acute, chronic, and cancer health risks 

during startup and commissioning operations. The HRA performed shows that the cancer 

risk is less than one in a million if the number of startups per turbine is limited to 1460 per 

year. Proposed permit conditions limit the number of startups for each turbine to 1460 per 

year, so TBACT is not required. The acute and chronic health risks also meet Rule 1200 

requirements. Although TBACT is not required for this project, the oxidation catalyst 

installed as BACT for CO and VOC emissions will also significantly reduce toxic air 

contaminant emissions. The heath risk analysis of this project is discussed in Appendix B of 

this document. 

Regulation XIV – Title V Operating Permits

The CECP is co-located with the Encina Power Station and under common control 

ownership. The Encina Power Station currently has a Title V Operating Permit. The 

applicant has submitted an application to modify this Title V Operating Permit to include the 

CECP project. 
Preliminary Determination of Compliance Page 46 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

STATE REGULATIONS IMPLEMENTED BY THE DISTRICT

Health and Safety Code §42301.6

This section of the state Health and Safety Code requires the District to notify parents of 

students at a school if a new source of air pollution is within a 1000 feet of the boundary of 

that school. The District has determined that the CECP is not within 1000 feet of any school 

boundary. 

Title 17 of the California Codes of Regulations (CCR) §93115—Airborne Toxic Control 

Measure (ATCM) for Stationary Compression Ignition Engines

The emergency diesel fire pump engine is subject to the Title 17 of the California Codes of 

Regulations (CCR) §93115—Airborne Toxic Control Measure (ATCM) for Stationary 

Compression Ignition Engines. 

Section 93115.5(a)(1) requires that by January 1, 2006, no owner or operator of a new 

stationary CI engine or an in-use prime stationary diesel-fueled CI engine shall fuel the 

engine with any fuel unless the fuel is one of the following: CARB Diesel Fuel; or an 

alternative diesel fuel that meets the requirements of the Verification Procedure; or an 

alternative fuel; or CARB Diesel Fuel used with fuel additives that meets the requirements of 

the Verification Procedure; or any combination of the above fuels. The proposed permit 

conditions required the use of only CARB Diesel Fuel. 

Section 93115.6(a)(1) requires that no owner or operator shall operate a new stationary 

emergency standby diesel-fueled CI engine for nonemergency use, including maintenance 

and testing, during the following periods: whenever there is a school sponsored activity, if 

the engine is located on school grounds; and between 7:30 am and 3:30 pm on days when 

school is in session if the engine is located within 500 feet of school grounds. This 

requirement does not apply if the engine emits no more than 0.01 g/bhp-hr of diesel PM. 

Compliance is required through proposed permit conditions. 
Preliminary Determination of Compliance Page 47 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Section 93115.6(a)(3)(A)(1) requires that new stationary emergency standby diesel-fueled 

engines (>50 bhp) shall emit diesel PM at a rate less than or equal to 0.15 g/bhp-hr; or meet 

the current model year PM standards specified in the Off-Road Compression Ignition Engine 

Standards for off-road engines with the same maximum rated power (title 13 CCR, section 

2423), whichever is more stringent; and not operate more than 50 hours per year for 

maintenance and testing purposes. The proposed engine PM emission rate is 0.09 g/bhp-hr. 

The engine is limited to 50 hours per year for testing and maintenance operation by proposed 

permit conditions. 

Section 93115.6(a)(3)(B) requires that new stationary emergency standby diesel-fueled 

engines (>50 bhp) meet the HC, NOx, NMHC+NOx, and CO standards for off-road engines 

of the same model year and maximum rated power as specified in the Off-Road 

Compression-Ignition Engine Standards (Title 13, CCR, Section 2423). The preliminarily 

proposed engine meets the Tier 2 HC, NOx, NMHC + NOx and CO standards for off-road 

engine of the 2005 model year. 

Section 93115.10(a) requires each owner or operator of new and in-use stationary CI engines, 

including non-diesel-fueled CI engines, to submit to the District APCO information on 

owner/operator contact information; engine information; fuel used; operation information; 

receptor information; and whether the engine is included in an existing AB2588 emission 

inventory. The District may exempt the owner or operator from providing all or part of this 

information if there is a current record of the information in the owner or operator’s permit to 

operate, permit application, or District records. This information has been provided by the 

applicant in the application submitted for the CECP.

Section 93115.10(e) requires that a non-resettable hour meter be installed upon engine at 

installation on all engines subject to all or part of the emission standards requirements. The 

engine will be required to have an hour meter by the proposed permit conditions. 

Section 93115.10(g)(1) requires each owner or operator of an emergency standby dieselfueled CI engine to keep records and prepare a monthly summary that lists and documents 
Preliminary Determination of Compliance Page 48 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

the nature of use for emergency use hours, maintenance and testing hours, initial start-up 

testing hours, retention of fuel purchase records for CARB diesel fuel. Compliance is 

required through proposed permit conditions. 

Section 93115.10(g)(2) requires all records to be retained for a minimum of 36 months. 

Records for the prior 24 months shall be retained on-site, and made immediately available to 

District staff upon request. Records for the prior 25 to 36 months shall be made available to 

District staff within 5 working days from request. Compliance is required through proposed 

permit conditions. 

Section 93115.13 requires that upon approval by the District APCO, the following sources of 

data may be used in whole or in part to meet the emission data requirements: 

A. Off road engine certification test data for the stationary diesel-fueled CI engine. 

B. Engine manufacturer test data. 

C. Emission test data from a similar engine, or 

D. Emission test data used in meeting the requirements of the Verification Procedure for 

the emission control strategy implemented. 

Engine manufacturer emission data were used to verify compliance with emission standard 

requirements. 

NATIONAL EMISSIONS STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPS)

The Encina Power Station is an existing major source of hazardous air pollutants (HAPs) 

based on the potential to emit hexane over the 10 ton per year major source threshold for a 

single HAP. Estimated actual emissions of hexane, calculated using an EPA (AP-42) 

emission factor, were about 13.5 tons per year in 2006. Therefore, equipment at the Encina 

Power Station are subject to NESHAPS applicable to major stationary sources of HAPs. 

40 CFR Part 63 Subpart YYYY – National Emissions Standards for Hazardous Air 

Pollutants for Stationary Combustion Turbines

This subpart establishes national emission limitations and operating limitations for hazardous 

air pollutants (HAP) emissions from stationary combustion turbines located at major sources 

of HAP emissions, and requirements to demonstrate initial and continuous compliance with 
Preliminary Determination of Compliance Page 49 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

the emissions and operating limitations. However, except for Initial Notification 

requirements [40 CFR §63.6145] EPA has stayed the applicability of this regulation for gasfired combustion turbines [40 CFR §63.6905(d)]. 

40 CFR Part 63 Subpart ZZZZ - National Emissions Standards for Hazardous Air 

Pollutants for Stationary Compression Ignition Internal Combustion Engines

This subpart for stationary compression ignition internal combustion engines requires [40 

CFR §63.6590(c)] engines rated less than 500 brake horsepower located at major sources of 

HAP emissions (and also all engines at nonmajor sources of HAPs) to comply with the 

requirements in 40 CFR Part 60 Subpart IIII— Standards of Performance for Stationary 

Compression Ignition Internal Combustion (CIIC) Engines. There are no other requirements 

applicable to such engines. Proposed permit conditions require compliance with Subpart IIII. 

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

40 CFR Part 60- Subpart KKKK- National Standards of Performance for New 

Stationary Combustion Turbines.

This new source performance standard requires stationary combustion turbines with a heat 

input equal to or greater than 10 MMBtu/hour based on the high heating value of the fuel to 

comply with NOx and SOx emission standards.

 

Section 60.4320 requires new combined-cycle combustion turbines firing natural gas with a 

rated heat input greater than 850 MMBtu/hour to comply with a NOx standard of 15 ppmvd 

at 15% O2 averaged over each 30 operating days, or alternatively, a standard of 0.42 pounds 

per megawatt hour (lb/MWh) during normal operations. During periods of less than 75% 

load the corresponding standards are 96 ppmvd and 4.7 lb/MWh. The actual limit during any 

30-day period is an average of the normal and less than 75% standards. 

With SCR as post-combustion emission control, NOx emissions from this combustion 

turbine are controlled to 2 ppm at 15% O2 during normal operation. Information submitted as 

part of the proposed City of Vernon Power Plant (06-AFC-4, Table 8.1B-2) indicates that the 
Preliminary Determination of Compliance Page 50 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

expected typical maximum NOx level for this model turbine is 50 ppm at less than 50% load 

(as occurs during startup and shutdown. Assuming NOx emission concentration during 

startup and shut down is 50 ppm at 15% O2, the NOx emission concentration averaged over a 

30-day period that has 50 hours of startup, 25 hours of shutdown and 250 hours of normal 

operation is: 

NOx concentration = [50 ppm x (50 startup hours)] x [50 ppm x (25 shutdown 

hours)] + (2 ppm x 250 normal operation hours)] / (325 hours) = 13 ppm 

Therefore, the turbine is expected to comply with the NOx emission standard of this subpart. 

Compliance is required through proposed permit conditions. 

Section 60.4330 prohibits sulfur dioxide emissions from combustion turbine in excess of 0.90 

lbs/MW-hour gross output or 0.060 lbs/MMBtu heat input. SO2 emission from the 

combustion turbines of this project is 0.002 lbs/MMBtu. 

SO2 emission rates = (4.4 lbs/hr) x (1 hour/ 1947 MMBtu) = 0.002 lbs/MMBtu 

Therefore, the turbine is in compliance with the SO2 limit requirement. 

Section 60.4340(b) requires turbines not using water injection or steam injection to install, 

calibrate, maintain and operate a continuous emission monitoring system (CEMS) consisting 

of a NOx monitor and a diluent gas (oxygen) or carbon dioxide monitor to determine the 

hourly NOx emission rate in ppmvd or lb/MWh. Turbines complying with concentration 

limit based standards must install calibrate, maintain and operate a fuel flow meter to 

measure heat input. Turbines complying with output-based standards must install, calibrate, 

maintain and operate a watt meter to measure the gross electrical output in megawatt-hours. 

This combustion turbine will be equipped with a CEMS to monitor NOx and CO emissions 

in parts per million and oxygen content in the exhaust gas. In addition, the gross electrical 

output in MWh will also be monitored. 
Preliminary Determination of Compliance Page 51 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Section 60.4345 requires the CEMS to be installed and certified according to Performance 

Specification 2 in Appendix B to this part, or according to Appendix A of part 75 of this 

chapter, and each fuel meter and watt meter shall be installed, calibrated, maintained and 

operated according to the manufacturer’s instructions. The turbine operator must develop 

and keep on site a QA plan for all continuous monitoring equipment. The CEMS for this 

combustion turbine will be required to go through Relative Accuracy Test Audit (RATA) and 

all other required certification tests in accordance with 40 CFR Part 75 Appendix A and B. 

The proposed permit requires continuous monitoring equipment meeting these requirements 

to be installed, calibrated, and maintained. 

Section 60.4350 requires turbine operator to use data from the CEMS to identify excess 

emissions in accordance with specific procedures. These requirements are included in the 

proposed permit conditions. 

Section 60.4365 exempts the requirement to monitor total sulfur content of the fuel if it can 

be demonstrated through a valid purchase contract , tariff sheet or transportation contract for 

the fuel that total sulfur content of natural gas used is 20 grains of sulfur or less per 100 

standard cubic feet. Sulfur content of natural gas fuel used in this turbine is 0.75 grains per 

100 cubic feet of gas or less. Quarterly records of natural gas sulfur content are to be kept on 

site to satisfy this requirement. 

Section 60.4375 requires submittal of reports of excess emissions and monitor downtime for 

all periods of unit operation, including startup, shutdown and malfunction. The proposed 

permit includes a condition to satisfy these requirements. Annual source tests are not 

required pursuant to Subpart KKKK for combustion turbine equipment with CEMS. Since 

this combustion turbine is subject to a NOx limit that is seven times more stringent than the 

NOx limit of this NSPS, excess emissions are not expected to occur. In addition, reports on 

the CEMS system are to be submitted in accordance with Rule 19.2 requirements and CEMS 

protocol approved by the District and excess emissions and monitoring reports are required 

by the proposed permit conditions.. 
Preliminary Determination of Compliance Page 52 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

Section 60.4400 requires that an initial performance test and annual NOx performance test be 

conducted in accordance with certain requirements. Annual source tests are not required 

pursuant to Subpart KKKK for combustion turbine equipment with CEMS. This combustion 

turbine is required to be source tested initially to demonstrate compliance with NOx, CO, 

VOC, and ammonia emission standards. The source tests are to be conducted in accordance 

with the applicable EPA test methods and applicable requirements of 40 CFR 75 Appendix 

B. The proposed permit contains conditions satisfying these requirements of Subpart KKKK. 

40 CFR Part 60 Subpart IIII – Standards of Performance for Stationary Compression 

Ignition Internal Combustion (CIIC) Engines

Section 60.4205 requires owners and operators of fire pump engines rated between 175 bhp 

and 300 bhp and of model year 2008 and earlier to comply with NOx + HC emission limit of 

7.8 grams per brake horsepower hour (g/bhp-hr), CO limit of 2.6 g/bhp-hr and a PM limit of 

0.4 g/bhp-hr. Fire pump engines of model year 2009 and after must comply with NOx + HC 

emission limit of 3 g/bhp and PM emission limit of 0.15 g/bhp-hr. Although the engine 

preliminarily proposed by the applicant would not comply with model year 2009 standards, 

the applicant has committed to purchase of a compliant engine and the proposed permit 

conditions require compliance with the standards of Subpart IIII for model year 2009 and 

later engines. 

Section 60.4207 requires that beginning October 1, 2007, owners and operators of station 

CIIC engines subject to Subpart IIII to use diesel fuel with a maximum sulfur content of 500 

ppm per gallon; and beginning October 1, 2010, to use diesel fuel with a maximum fuel 

content of 15 ppm per gallon. This engine is required to use CARB diesel fuel, which 

complies with this requirement. 

Section 60.4209 requires that owners or operators of engines subject to Subpart IIII to install 

a non-resettable hour meter prior to startup of the engine. This requirement is included in 

the proposed permit conditions. 

Section 60.4214 states that owner of engines that are stationary emergency standby engines 

are not required to submit an initial notification 
Preliminary Determination of Compliance Page 53 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

ACID RAIN

40CFR Part 72- Subpart A – Acid Rain Program 

This part establishes general provisions and operating permit program requirements for 

sources and units affected under the Acid Rain program, pursuant to Title IV of the Clean Air 

Act. The combustion turbines of this project are affected by this Acid Rain Program as a 

utility unit in accordance with Section 72.6(a). 

40CFR Part 72- Subpart C – Acid Rain Permit Applications

This subpart requires any source with an affected unit to submit a complete Acid Rain permit 

application by the applicable deadline. Requirement for submittal of Acid Rain Program 

application will be included in the proposed Authority to Construct for the combustion 

turbines of this project. 

40CFR Part 73- Sulfur Dioxide Allowance System

This part establishes the requirements and procedures for the allocation of sulfur dioxide 

emission allowances; the tracking, holding and transfer of allowances; the deduction of 

allowances for purposes of compliance and for purposes of offsetting excess emissions 

pursuant to Parts 72; the sale of allowances through EPA-sponsored auctions and a direct 

sale; the application for allowances from the Conservation and Renewable Energy Reserve; 

and the application for allowances for desulfurization of fuel by small diesel refineries. 

Requirements from this part will be included in evaluation for the Acid Rain program 

application required by Part 72. The proposed permit requires compliance with this 

requirement. 

40CFR Part 75 – Continuous Emission Monitoring

This part established requirements for the monitoring, recordkeeping, and reporting of SO2, 

NOx, and CO2 emissions, volumetric flow, and opacity data from emission units under the 

Acid Rain Program. The regulations include general requirements for the installation, 

certification, operation, and maintenance of continuous emission or opacity monitoring 

systems, certification tests and procedures, and quality assurance tests and procedures. 

Subpart B on Monitoring Provisions established general operating requirements for the 
Preliminary Determination of Compliance Page 54 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

monitoring systems. Subpart C establishes requirements on initial certification and 

recertification procedures. Subparts F and G establish requirements on recordkeeping and 

reporting requirements. All applicable requirements are included in the Authority to 

Construct conditions. 
Preliminary Determination of Compliance Page 55 of 56 November 20, 2008 

Applications No. 985745, 985747, and 985748 

VI. ADDITIONAL ISSUES

PARTICULATE EMISSION RELATING TO THE USE OF RECLAIMED WATER FOR 

EVAPORATIVE COOLING

The proposed Siemens turbines have inlet air filters located upstream of the evaporative 

coolers. The evaporative cooler is turned on only during normal operation when ambient 

temperature is higher than 60°F. The particulate emission factor of 9.5 lbs/hr provided by the 

turbine vendor includes anticipated particulate matter from the evaporative cooler 

parameters. Therefore, no further particulate emissions from the evaporative cooler are 

included in the emission calculation. 

COMMISSIONING PERIOD

After construction of the equipment has been completed, the applicant will be allowed a 

commissioning period of 120 days or 415 operating hours for each turbine, whichever comes 

sooner. During the 120-day commissioning period, the turbines will go through testing and 

tuning to ensure that the equipment is working properly and will be able to comply with all 

the proposed emission limits. However, during the initial startup, certain emissions standards 

must remain in effect. These include the 72.76 tons/yr limit for NOx, hourly mass emission 

limits for NOx and CO to ensure there will be no violation of any state or national ambient 

air quality standards, and the hourly concentration limits for NOx to ensure compliance with 

the District RACT and BARCT Rules 69.3 and 69.3.1, respectively. A CEMS will be 

required to be installed at the time of initial startup to monitor emissions during the 

commissioning period from each turbine. 

Once the emissions control equipment has been installed and is in good working order, the 

turbines must meet all BACT/LAER standards and permit requirements. CEMS and source 

testing will be used to show compliance with these standards. 
Ori mall Si ned b

Date

VII. CONCLUSIONS AND RECOMMENDATIONS

A Determination of Compliance confers the same rights and privileges as an Authority to

Construct only when and if the California Energy Commission (CEC) approves the

Application For Certification, and the CEC certificate includes all conditions of the

Determination of Compliance as proposed by the Air Pollution Control Officer.

If operated in accordance with the conditions specified in this Preliminary Determination of

Compliance, this equipment is expected to operate in compliance with all Rules and

Regulations of the San Diego County Air Pollution Control District.

11/.2.1log

Project Engineer Date

Originally Signed by 

Senior Engineer Approval

Preliminary Determination of Compliance

Applications No. 985745, 985747, and 985748

Page 56 of 56 November 20, 2008
APPENDIX A 

APPROVAL OF AIR QUALITY IMPACT ANALYSIS 
1 

 

AIR QUALITY IMPACT ANALYSIS 

FINAL REVIEW REPORT

CARLSBAD ENERGY CENTER PROJECT 

APPLICATION 985423 

SEPTEMBER 24, 2008 

Prepared For 

Mechanical Engineering 

San Diego Air Pollution Control District 

10124 Old Grove Road 

San Diego, California 92131

Prepared By 

Ralph DeSiena 

Monitoring and Technical Services 

San Diego Air Pollution Control District 

10124 Old Grove Road 

San Diego, California 92131
2

1.0 INTRODUCTION

An Air Quality Impact Analysis (AQIA) was performed for the Carlsbad Energy Center 

Project (CECP) by Sierra Research of Sacramento, CA. This report focuses on Section 

5.1 of the AFC and the AQIA analysis results provided in the original (September, 2007) 

and subsequent modeling analysis performed (May 13, 2008). 

2.0 PROJECT DESCRIPTION

NRG Energy, Inc. is proposing to remove three existing boilers at the Encina Power 

Station (Units 1, 2 and 3) and install two new Siemens Rapid Response SGT6-5000F 

Combined Cycle (R2C2) combustion turbine generators (CTGs). The gas turbines will be 

equipped with steam power augmentation and evaporative cooling. Each gas turbine is 

followed by a heat recovery steam generator (HRSG) and condensing steam turbine 

generator. The two units will provide a total nominal generating capacity of 558 MW net. 

 

3.0 AIR QUALITY IMPACT ANALYSIS

Dispersion modeling was conducted for Normal, Startup/Shutdown and Commissioning 

period emissions of NO2, CO, SO2, and PM10 and PM2.5. The applicant and their consultant 

(Sierra Research) worked closely with the District in developing modeling and analysis 

procedures in support of demonstrating compliance with all applicable NSR requirements. 

Modeling was performed in order to determine whether emissions during these time 

periods would impact the State and/or Federal Ambient Air Quality Standards for all 

criteria pollutants. 

The modeling procedures are discussed in the following subsections. 

 

3.1 MODELING METHODOLOGIES

AERMOD was used first to “screen” the different turbine stack emission and ambient 

temperature parameters for the conditions that generate the highest ground-level 

concentrations of criteria pollutants. Gas turbine specifications were developed and 

modeled for four temperature scenarios: extreme hot temperature (104 F), summer 

average temperature (74 F), annual average temperature (61 F) and extreme low 

temperature (37 F). Stack parameters and criteria pollutant emission rates were provided 

at each of these three ambient temperatures. Similarly, stack parameters and emission 

rates were provided at each ambient temperature for the turbines running at 100%, 75%, 

60% and 50% load. The stack parameters and maximum emission rates for the screening 

modeling are presented in Table 3-1 and the maximum predicted screening model impacts 

are shown in Table 3-2. 

After screening modeling, refined modeling was performed using EPA’s AERMOD 

(Version 06341) model with the “maximum impact” turbine stack conditions and emission 

rates to determine the maximum criteria pollutant concentrations for the appropriate 

averaging periods for each criteria pollutant. Table 3-3 shows the inputs for the refined 

modeling. 

Startup/Shutdown and Commissioning modeling for the elevated emission rates of NOx 

and CO existing during these conditions was also performed. The model inputs used to 

simulate those conditions are provided in Table 3-4. 
3

Additionally, the EPA’s SCREEN3 (Version 96043) model is used to determine the 

potential impacts if the project emissions are subjected to fumigation from breakup of the 

overnight inversion that can form. This special case is modeled as an extra precaution to 

avoid an exceedance of ambient air quality standards under these special atmospheric 

conditions. 

All modeling was performed in accordance with EPA guidance and District standard 

procedures. Regulatory default settings were used. The receptor grid was sufficiently 

dense to identify maximum impacts. 

3.2 METEOROLOGICAL DATA USED FOR DISPERSION MODELING

Meteorological data used for EPA’s Aermod Prime model consisted of the following data 

for the 2003 through 2005 time period. The data was processed by the District using 

EPA’s Aermet meteorological data processor (Version 06341) to produce Aermod ready 

files. 

• Wind speed, wind direction, standard deviation of the horizontal wind direction and 

temperature from the District’s Camp Pendleton monitoring station. 

• Twice-daily upper-air soundings from Miramar Marine Corps Air Station, San Diego, CA. 

• Cloud height and total opaque cloud amount from Palomar Airport, Carlsbad, CA. 

• Wind speed, wind direction and temperature data from Palomar Airport, Carlsbad, CA for 

replacement of missing data in the Camp Pendleton data set. 

• Wind speed, wind direction and temperature data with height from the District’s wind 

profiler with RASS located near the Miramar Marine Corps Air Station, San Diego, CA. 
4 

Table 3-2 

Screening Level Modeling Impacts 
5

Table 3-3 

Emission Rates and Stack Parameters for Refined Modeling
6

Table 3-3 (Continued) 

Emission Rates and Stack Parameters for Refined Modeling
7

Table 3-3 (Continued) 

Emission Rates and Stack Parameters for Refined Modeling 
8

Table 3-4

Startup/Shutdown and Commissioning Modeling Inputs
9 

4.0 AIR QUALITY IMPACT ANALYSIS RESULTS

In accordance with EPA and San Diego Air Pollution Control District New Source Review 

Guidance and the modeling methodologies described above, maximum predicted 

concentrations associated with facility operations were determined for each of the required 

criteria pollutant and the applicable averaging period during Normal, Startup/Shutdown 

and Commissioning conditions. The maximum predicted concentrations occurring during 

any of the operating conditions modeled were added to worst-case background 

concentrations for comparison to Federal and State Ambient Air Quality Standards. Worst 

case background concentrations were determined from the review of 3 years (2004-2006) 

of monitoring data taken from the District’s Camp Pendleton, Escondido or San Diego 

monitoring stations, whichever was available for a specific criteria pollutant and deemed 

to be most representative of air quality in the facility area. Table 4-1 summarizes the worst 

case background concentrations. 

The maximum ground-level impacts at any location from normal operations, 

startup/shutdowns and the special circumstances of inversion breakup fumigation are 

given in Table 4-2. 

Table 4-3 provides the summary of project modeled maximum impacts for Commissioning 

period operating conditions. 

Table 4-4 provides the summary of the proposed project modeled maximum impacts, 

including worst case ambient background concentrations, compared with Federal and 

California Ambient Air Quality Standards (AAQS). 

Table 4-5 provides a comparison of maximum modeled impacts during normal operation 

and PSD significant impact levels. 
10

TABLE 4-1 

MAXIMUM BACKGROUND CONCENTRATIONSa

, PROJECT AREA, 2004-2006 

(μg/m3

) 

Pollutant Averaging 

Time 2004 2005 2006 

NO 1-hour 185.9 144.6 152.1 2 (Camp 

Pendleton) Annual 22.5 22.5 20.7 

1-hour 110.0 94.3 89.1 

3-hour 52.4 68.1 78.6 

24-hour 23.6 23.6 23.5 

SO2 (San Diego) 

Annual 10.5 7.9 10.5 

1-hour 6,300 5,900 5,700 CO (Escondido) 8-hour 3,800 3,100 3,600 

24-hour 58 42 52 

PM10 (Escondido) Annual 27 24 24 

24-hourb

 37 32 28 

PM2.5 (Escondido) Annual 14.1 12.3 11.5 

Source: California Air Quality Data, California Air Resources Board website; EPA AIRData website. 

Reported values have been rounded to the nearest tenth of a μg/m3

 except for PM10 which were already 

rounded to the nearest integer. 

Notes: 

a. With the exception of 24-hr PM2.5, bolded values are the highest during the three years and are used to 

represent background concentrations. 

b. 24-hour average PM2.5 concentrations shown are 98th percentile values rather than highest values 

because compliance with the ambient air quality standards is based on 98th percentile readings. Since the 

ambient standard is based on a 3-year average of the 98th percentile readings, the 3-year average of the 

2004 to 2006 98th percentile readings was used to represent the background concentration. 
11

TABLE 4-2 

NORMAL OPERATION AIR QUALITY MODELING RESULTS FOR NEW EQUIPMENT

Modeled Maximum Concentrations (μg/m3

) 

Pollutant 

Averaging 

Time 

Normal 

Operations 

AERMOD 

Startup/Shutdown 

AERMOD 

Fumigation 

SCREEN3 

Shoreline 

Fumigation 

SCREEN3 

Combined Impacts Both CTGs 

NO2 1-hour 

Annual

 13.3 

0.1 

 80.4 

a 

 2.6 

c 

 18.5 

c 

SO2 1-hour 

3-hour 

24-hour 

Annual 

4.3 

2.0 

 0.4 

0.0 

b 

b 

b 

b 

0.8 

0.6 

0.3 

c 

 5.4 

 4.8 

 0.5 

c 

CO 1-hour 

8-hour 

 9.0 

 1.9 

1133.8 

 236.0 

1.6 

1.0 

 11.3 

 3.5 

PM2.5/PM10 24-hour 

Annual 

1.2 

0.1 

b 

b 

 0.9 

c 

 1.7 

c 

Fire pump Engine 

NO2 1-hour 

Annual

108.0 

0.1 

d 

d 

e 

e 

e 

e 

SO2 1-hour 

3-hour 

24-hour 

Annual 

0.2 

0.0 

0.0 

0.0 

d 

d 

d 

d 

e 

e 

e 

e 

e 

e 

e 

e 

CO 1-hour 

8-hour 

18.2 

 1.0 

d 

d 

e 

e 

e 

e 

PM2.5/PM10 24-hour 

Annual 

0.0 

0.0 

d 

d 

e 

e 

e 

e 

Combined Impacts New Equipment 

NO2 1-hour 

Annual

 108.0 

0.1 

f 

f 

f 

f 

f 

f 

SO2 1-hour 

3-hour 

24-hour 

Annual 

 4.3 

 2.0 

 0.4 

0.0 

f 

f 

f 

f 

f 

f 

f 

f 

f 

f 

f 

f 

CO 1-hour 

8-hour 

 18.2 

 1.9 

f 

f 

f 

f 

f 

f 

PM2.5/PM10 24-hour 

Annual 

1.2 

0.1 

f 

f 

f 

f 

f 

f 

a. Not applicable, because startup/shutdown emissions are included in the modeling for annual average. 

b. Not applicable, because emissions are not elevated above normal operation levels during startups/shutdowns. 

c. Not applicable, because inversion breakup is a short-term phenomenon and as such is evaluated only for shortterm averaging periods. 

d. Not applicable, because engine will not operate during CTG startups/shutdowns. 

e. Not applicable, this type of modeling is not performed for small combustion sources with relatively short stacks. 

f. Impacts are the same as shown for CTGs. 
12

TABLE 4-3 

MODELED IMPACTS DURING COMMISSIONING (COMBINED IMPACTS 

BOTH CTGS)

Pollutant/Averaging Period Modeled Concentration, μg/m3 

NO2 – 1-hour 127.5 

CO – 1-hour 3228.0 

CO - 8-hour 675.9 

TABLE 4-4 

MODELED MAXIMUM PROPOSED PROJECT IMPACTS 

Pollutant 

Averaging 

Time 

Maximum 

Project Impact 

(μg/m3

) 

Background 

(μg/m3) 

Total 

Impact 

(μg/m3) 

State 

Standard 

(μg/m3) 

Federal 

Standard 

(μg/m3) 

NO2 1-hour 

Annual 

 127.5a 

 0.1 

185.9 

22.5 

 313 

23 

338 

56 

- 

100 

SO2 1-hour 

3-hour 

24-hour 

Annual 

4.3 

2.0 

 0.4 

0.0 

110.0 

78.6 

23.6 

10.5 

 114 

81 

24 

11 

650 

- 

109 

- 

- 

1300 

365 

80 

CO 1-hour 

8-hour 

3,228.0a

 675.9a 

6,300 

3,800 

9,528 

4,476 

23,000 

10,000 

40,000 

10,000 

PM10 24-hour 

Annual 

1.2 

0.1 

58 

27 

59 

27 

50 

20 

150 

-- 

PM2.5 24-hour 

Annual 

1.2 

0.1 

32.7 

14.1 

34 

14 

-- 

12 

35 

15 

Notes: 

 a. Impacts during gas turbine commissioning.
13 

TABLE 4-5 

COMPARISON OF MAXIMUM MODELED IMPACTS DURING NORMAL OPERATION AND 

PSD SIGNIFICANT IMPACT LEVELS

Pollutant Averaging Time

Significant 

Impact Level, 

μg/m3

Maximum 

Modeled Impact 

for CECP, 

μg/m3

Exceed 

Significant 

Impact Level? 

NO2 Annual 1 0.1 No 

SO2 3-hour 

24-Hour 

Annual 

25 

5 

1 

2.0 

0.4 

0.0 

 No 

CO 1-Hour 

8-Hour 

2000 

500 

1134 

236 

 No 

PM10 24-Hour 

Annual 

5 

1 

1.2 

0.1 

 No 

5.0 CONCLUSION

The results of the modeling indicate that the proposed facility operations including 

Commissioning and Startup/Shutdowns will not cause or contribute to an exceedance of 

the Federal and California Ambient Air Quality Standards for NO2, SO2 and CO. 

For PM10, background concentrations already exceed the annual and 24 hour California 

standard. Since the background is already in exceedance of the annual standard no 

additional violations can be due to facility operations. Additionally the 0.1 μg/m3 predicted 

annual impact is well below PSD significant impact levels shown in Table 4-5. Predicted 

impacts less than SILs are normally considered to not significantly affect compliance with 

Federal Ambient Air Quality Standards regardless of the background level. Specifically in 

non-attainment areas, project impacts less than the SILs are deemed to not significantly 

cause or contribute to violations of the Federal Ambient Air Quality Standard. This can be 

considered the case for California Ambient Air Quality Standards as well. 

Since the initial modeling estimated maximum 24 Hour PM10 impacts of approximately 1.2 

μg/m3

, additional AERMOD modeling could be performed for all days in the 2004-2006 

period that 24 Hour PM10 background concentrations were between 49 μ/m3

 and 50 μg/m3

(California Standard) to determine whether additional violations would result from facility 

operations. There were no monitoring days that concentrations were measured within this 

range (highest monitored value less than the California Standard was 44 μg/m3

. Therefore 

it can be concluded that facility operations would not cause or contribute to additional 

violations of the California 24 Hour Ambient Air Quality Standard for PM10. 

The modeling results also indicate that no exceedance of the Federal annual or 24 hour 

PM2.5 standard is predicted. Monitored background levels exceeded the California 

annual standard. Since the background is already in exceedance of the annual standard 

no additional violations can be due to facility operations. 
14

5.1 AFC SECTION 5.1 REVISIONS

The following are revisions to Tables included in Section 5.1, Air Quality of the original 

AFC (CEC) and application for an Authority to Construct (SDAPCD) submittal dated 

September, 2007. 

TABLE 5.1-6 

PM10 LEVELS IN SAN DIEGO COUNTY, ESCONDIDO MONITORING STATION, 1997-2006 (μg/m3)

 199

7 

199

8 

199

9 

200

0 

200

1 

200

2 

200

3 

200

4 

200

5 

200

6 

Highest 24-Hour 

Average 63 51 50 63 72 50 124* 58 42 52

Annual 

Arithmetic Mean 

(State Standard 

= 20 μg/m3

) 

29 24 30 30 31 25 33 27 24 24 

Number of Days Exceeding: 

State Standard 

(50 μg/m3, 24-

hour) 

3 1 1 2 2 1 5 1 0 1 

Federal 

Standard 

(150 μg/m3, 24-

hour) 

0 -- 0 0 0 0 3 0 0 0 

Source: California Air Quality Data, California Air Resources Board website 

(http://www.arb.ca.gov/adam/welcome.html; EPA AIRData website (http://www.epa.gov/air/data/index.html). 

*Removed exceptional event value of 179 
15

TABLE 5.1-7 

PM2.5 LEVELS IN SAN DIEGO COUNTY, ESCONDIDO MONITORING STATION, 1997-2006 (μg/m3

)

 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 

Highest 24-Hour Average -- -- 64.0 66.0 60.0 54.0 38.0 67.0 43.0 41.0 

Number of Days Exceeding: 

Federal Standard 

(65 μg/m3, 24-hour) 0 0 0 1 0 0 0 1 0 0 

 (35 μg/m3, 24-hour 

 effective December 17, 

 2006) 

-- -- -- -- -- -- -- -- -- -- 

98th Percentile -- -- 45.0 48.0 41.0 39.0 34.0 37.0 32.0 28.0 

3-yr Average, 98th

Percentile -- -- -- -- 44.7 42.7 38.0 36.7 34.3 32.3 

Annual Arithmetic Mean 

(State Std = 12 μg/m3

) -- -- 18.0 15.8 17.5 16.0 14.1 14.1 12.3 11.5 

3-yr Annual Average 

(Federal Std = 15 μg/m3

) -- -- 18 16 18 16 14 14 12 12 

Source: California Air Quality Data, California Air Resources Board website (http://www.arb.ca.gov/adam/welcome.html; 

EPA AIRData website (http://www.epa.gov/air/data/index.html). 

TABLE 5.1-29 

Maximum Background Concentrationsa

, project area, 2004-2006 (μg/m3) 

Pollutant Averaging Time 2004 2005 2006 

1-hour 185.9 144.6 152.1 NO2 (Camp Pendleton) Annual 22.5 22.5 20.7 

1-hour 110.0 94.3 89.1 

3-hour 52.4 68.1 78.6 

24-hour 23.6 23.6 23.5 

SO2 (San Diego) 

Annual 10.5 7.9 10.5 

1-hour 6,300 5,900 5,700 CO (Escondido) 8-hour 3,800 3,100 3,600 

24-hour 58 42 52 

PM10 (Escondido) Annual 27 24 24 

24-hourb

 37 32 28 

PM2.5 (Escondido) 

Annual 14.1 12.3 11.5 

Source: California Air Quality Data, California Air Resources Board website; EPA AIRData website. Reported 

values have been rounded to the nearest tenth of a μg/m3

 except for PM10 which were already rounded to the 

nearest integer. 

Notes: 

a. With the exception of 24-hr PM2.5, bolded values are the highest during the three years and are used to 

represent background concentrations. 

b. 24-hour average PM2.5 concentrations shown are 98th percentile values rather than highest values because 

compliance with the ambient air quality standards is based on 98th percentile readings. Since the ambient 

standard is based on a 3-year average of the 98th percentile readings, the 3-year average of the 2004 to 2006 

98th percentile readings was used to represent the background concentration. 
APPENDIX B 

APPROVAL OF HEALTH RISK ASSESSMENT 
Rule 1200 Health Risk Assessment Report 

Facility ID: 333A 

Applications: 985745, 985746, 985747, and 985748. 

Project Engineer: Steve Moore 

Toxics Risk Analyst: Michael Kehetian 

HRA Tool Used: AERMOD - HARP 

Report Date: 11/21/08 

Review of Health Risk Assessment (HRA) evaluation for the 

Carlsbad Energy Center Project (CECP) 

I. SUMMARY & CONCLUSION

SUMMARY

This health risk assessment (HRA) is an assessment of the potential health risks from the 

Carlsbad Energy Center Project (CECP) consisting of two combustion turbine generators with a 

nominal gross power output of 208 megawatts (MW) and with a corresponding heat input of 

1976 million British thermal units per hour (MMBtu/hr) per turbine (without power 

augmentation at 61 oF average ambient temperature). At 37 oF the maximum heat input is 2085 

MMBtu/hr without power augmentation. The combustion turbines are proposed to be equipped 

with a carbon monoxide (CO) catalyst to control CO and volatile organic compounds and a 

selective catalytic reduction system to control oxides of nitrogen. The CO catalyst also reduces 

toxic air pollutant emissions. 

The combustion turbines are also equipped with evaporative coolers that can be used cool the 

inlet air to each turbine to increase power during periods of high ambient temperature. 

Additionally, a 240 horsepower diesel-fueled emergency fire pump engine is also part of the 

proposed project. 

The applicant submitted toxic air pollutant emission factors, calculated emission rates, and HRA 

modeling results to evaluate the potential health impact during normal operations, startups and 

shutdowns, and commissioning. These results were reviewed and found to be technically 

accurate in so far as they estimated health impacts based on the emission factors and emission 

rates submitted. 

In addition to the above submittal from the applicant, supplementary analyses based on the same 

receptor grid and meteorological data used in the applicant’s submittal were prepared by the 

District to identify the likely worst-case potential health risk from the project using more 

extensive emission scenarios. Based on the applicant’s submittal and the supplemental analyses, 

the expected and the likely worst-case potential health impacts from the emissions of toxic air 

contaminants for the project as compared to Rule 1200 significance levels are presented in Table 

1-1. 
Rule 1200 Health Risk Assessment Report 

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The potential health impact at the point of maximum impact (PMI) in the tables elsewhere in this 

document is the maximum impact at a location beyond the facility’s boundary. This location 

does not necessarily represent the maximum incremental cancer risk nor the total acute or 

chronic Health Hazard Index (HHI) because a person may not reasonably be expected to be 

present at the PMI location for the exposure period of concern. 

It should be noted that the potential health risks presented in Table 1-1 are conservatively high 

due to the conservative assumptions specified in the California Office of Health Hazard 

Assessment (OEHHA) health risk assessment guidance. In addition, the health risks presented in 

Table 1-2 are based on an operating scenario that may be unrealistic—8760 hours of operation, 

including 1460 startups—and may not be possible because of constraints imposed by proposed 

permit conditions for criteria pollutants. 

Table 1-1 

Worst-Case Potential Health Impacts 

Category 

Health 

Impact 

Rule 1200 

Significance Level 

Maximum Incremental Cancer Risk—Resident (per million) 0.71 

1.0 

 or 

 10 (with TBACT) 

Maximum Incremental Cancer Risk—Worker (per million) 0.54 

1.0 

 or 

 10 (with TBACT) 

Total Chronic Noncancer Health Hazard Index—Resident 0.017 1.0 

Total Chronic Noncancer Health Hazard Index—Worker 0.019 1.0 

Total Acute Noncancer Health Hazard Index—Resident 0.57 1.0 

Total Acute Noncancer Health Hazard Index—Worker 0.57 1.0 

CONCLUSION

The indicated health impacts are all less than the Rule 1200 significance levels. Therefore, the 

project HRA is preliminarily approved. For an incremental cancer risk of less than one in a 

million, toxic best available control technology (TBACT) is not required. However, the 

combustion turbines are proposed to be equipped with a CO oxidation catalyst, which would be 

considered TBACT for this type of equipment. Thus, the project would be approvable with a 

cancer risk of up to 10 in a million. 
Rule 1200 Health Risk Assessment Report 

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II. EMISSION FACTORS

COMBUSTION TURBINE GENERATOR FACTORS—STANDARD OPERATIONS

Applicant Submitted Emission Factors

For standard operations, the applicant based the health risk analysis on toxic air pollutant emission 

factors in pounds per million standard cubic feet (lb/MMscf) of natural gas combusted. For the most 

part, emission factors for stationary combustion turbines in EPA’s standard emission factor 

reference AP-42 (Table 3.1-3) and the California Air Toxic Emission Factor (CATEF) database for 

toxic compounds were used. The emission factor for ammonia was calculated based on the 

proposed permit limit of 5 parts per million by volume dry (ppmvd). 

In some cases, the emission factors for emissions controlled by an oxidation catalyst were taken 

from the background document for the latest edition of AP-42. No control factor was assigned for 

the other toxic compounds. Emission rates were calculated from these emission factors based on a 

maximum heat input of 2085 MMBtu/hr and a higher heating value of 1019 Btu/scf for natural gas. 

For polycyclic aromatic hydrocarbons (PAHs), only those compounds listed in CATEF that had a 

quantified unit risk factor (URF) for cancer were included. Conservatively, these were all assumed 

to be composite PAHs with the same risk factor as benzo(a)pyrene, which is used as a surrogate in 

risk analyses since its URF is higher than most PAHs. The emission factors proposed by the 

applicant are shown in Table 2-1. 
Rule 1200 Health Risk Assessment Report 

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Table 2-1 

Normal Operation Emission Factors Proposed by Applicant 

CHEMICAL NAME 

Emission 

Factor, 

lb/MMscf Reference URF available 

AMMONIA 6.95E+00 Permit 

ACETALDEHYDE 4.08E-02 AP-42 Y 

ACROLEIN 3.69E-03 

AP-42 

(background) Y 

BENZENE 3.33E-03 

AP-42 

(background) Y 

BUTADIENE, 1,3- 4.39E-04 AP-42 Y 

ETHYL BENZENE 3.26E-02 AP-42 Y 

FORMALDEHYDE 3.67E-01 

AP-42 

(background) Y 

HEXANE, n- 2.59E-01 CATEF 

NAPHTHALENE 1.66E-03 CATEF Y 

PROPYLENE 7.71E-01 CATEF 

PROPYLENE OXIDE 2.96E-02 AP-42 Y 

TOLUENE 1.33E-01 AP-42 Y 

XYLENES 6.53E-02 AP-42 Y 

PAHs 

BENZO[a]ANTHRACENE CATEF Y 

BENZO[a]PYRENE CATEF Y 

BENZO[b]FLUORANTHENE CATEF Y 

BENZO[k]FLUORANTHENE CATEF Y 

CHRYSENE CATEF Y 

DIBENZ[a,h]ANTHRACENE CATEF Y 

INDENO(1,2,3-cd)PYRENE CATEF Y 

PAH (COMPOSITE) 1.31E-04 CATEF Y 

Normal Operation Emission Factors for District Supplemental Analyses

Although the applicant’s proposed emission factors are conservative in some ways, the District 

elected to perform additional analyses based on a set of emission factors similar to a set that the 

District has based its most recent previous evaluation of a large combined-cycle turbine. With the 

exception of ammonia and formaldehyde, these emission factors are taken from AP-42 unless an 

AP-42 emission factor is not available. A uniform control factor of 50% to account for the use of a 

CO oxidation catalyst is applied to all emission factors except ammonia. The formaldehyde 

emission factor is taken from CATEF since the controlled emission factor is most representative of 

recent compliance source tests for a large combined-cycle turbine. All PAHs listed in CATEF are 

represented. Those without an approved URF are quantified as composite PAHs. These emission 

factors are shown in Table 2-2. 
Rule 1200 Health Risk Assessment Report 

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Table 2-2 

District Emission Factors 

CHEMICAL NAME 

Emission 

Factor 

(Uncontrolled)

, lb/MMscf 

Emission Factor 

(Controlled), 

lb/MMscf Reference 

AMMONIA 6.95E+00 6.95E+00 Permit 

ACETALDEHYDE 4.08E-02 2.04E-02 AP-42 

ACROLEIN 6.53E-03 3.27E-03 AP-42 

BENZENE 1.22E-02 6.10E-03 AP-42 

BUTADIENE, 1,3- 4.39E-04 2.20E-04 AP-42 

ETHYL BENZENE 3.26E-02 1.63E-02 AP-42 

FORMALDEHYDE 9.17E-01 4.59E-01 CATEF 

HEXANE, n- 2.59E-01 1.30E-01 CATEF 

NAPHTHALENE 1.33E-03 6.65E-04 AP-42 

PROPYLENE 7.71E-01 3.86E-01 CATEF 

PROPYLENE OXIDE 2.96E-02 1.48E-02 AP-42 

TOLUENE 1.33E-01 6.65E-02 AP-42 

XYLENES 6.53E-02 3.27E-02 AP-42 

PAHs 

ACENAPTHENE 9.50E-06 CATEF 

ACENAPTHYLENE 7.35E-06 CATEF 

ANTHRACENE 1.69E-05 CATEF 

BENZO[a]ANTHRACENE 2.26E-05 1.13E-05 CATEF 

BENZO[a]PYRENE 1.39E-05 6.95E-06 CATEF 

BENZO[b]FLUORANTHENE 1.13E-05 5.65E-06 CATEF 

BENZO(e)PYRENE 2.72E-07 CATEF 

BENZO(g,h,i)PERYLENE 6.85E-06 CATEF 

BENZO[k]FLUORANTHENE 1.10E-05 5.50E-06 CATEF 

CHRYSENE 2.52E-05 1.26E-05 CATEF 

DIBENZ[a,h]ANTHRACENE 2.35E-05 1.18E-05 CATEF 

FLUORANTHENE 2.16E-05 CATEF 

FLUORENE 2.90E-05 CATEF 

INDENO(1,2,3-cd)PYRENE 2.35E-05 1.18E-05 CATEF 

PHENANTHRENE 1.57E-04 CATEF 

PYRENE 1.39E-05 CATEF 

PAH (COMPOSITE) 5.24E-04 2.62E-04 CATEF 

COMBUSTION TURBINE GENERATOR EMISSION FACTORS—STARTUP, SHUTDOWN, AND 

COMMISSIONING

Startup and Shutdown Emission Factors

For startup and shutdown emissions, the emission factors in Table 2-3 were used, as applicable, 

both for analyses performed by the applicant and reviewed by the District and District 

supplemental analyses. The applicant used the emission factors for acetaldehyde, acrolein, 

benzene, and formaldehyde in modeling potential acute health impacts. 
Rule 1200 Health Risk Assessment Report 

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As indicated many of these emission factors were derived from a source test. The source test 

was performed during the first hour of a cold start of a natural gas-fired GE 7FA gas turbine at 

the Palomar Energy Center. This is a combined-cycle turbine with ultra-low-NOx combustors. 

The turbine was equipped with a CO oxidation catalyst. During the first hour of the startup, the 

turbine tested was operating at very low loads (0–18%). Although the oxidation catalyst control 

efficiency was not quantified during the test it is assumed the catalyst was operating at reduced 

efficiency during a large portion of the hour because of the low temperatures in the heat recovery 

steam generator where the catalyst is located. 

The District only considers these emission factors to be potentially applicable at loads below the 

point where the ultra-low-NOx combustors are no longer operating in the low-NOx mode (typically 

40-60% of maximum load). This would include shutdown operations. However, emissions during a 

shutdown are likely to be overestimated with these emission factors because the oxidation catalyst 

would be close to its normal operating temperature. 
Rule 1200 Health Risk Assessment Report 

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Table 2-3 

Startup and Shutdown Emission Factors 

CHEMICAL NAME 

Emission Factor, 

lb/MMscf Reference 

AMMONIA 6.95E+00 Permit 

ACETALDEHYDE 1.28E+00 Source Test 

ACROLEIN 6.89E-02 Source Test 

BENZENE 2.56E-02 Source Test 

BUTADIENE, 1,3- 4.39E-04 AP-42 

ETHYL BENZENE 3.26E-02 Source Test 

FORMALDEHYDE 4.63E+00 Source Test 

HEXANE, n- 2.59E-01 CATEF 

NAPHTHALENE 1.04E-03 Source Test 

PROPYLENE 7.71E-01 CATEF 

PROPYLENE OXIDE 2.96E-02 AP-42 

TOLUENE 9.28E-02 Source Test 

XYLENES 3.48E-03 Source Test 

PAHs 

ACENAPTHENE CATEF 

ACENAPTHYLENE CATEF 

ANTHRACENE CATEF 

BENZO[a]ANTHRACENE 2.25E-05 Source Test (ND)a

BENZO[a]PYRENE 1.39E-05 Source Test (ND) a

BENZO[b]FLUORANTHENE 1.13E-05 CATEF 

BENZO(e)PYRENE CATEF 

BENZO(g,h,i)PERYLENE CATEF 

BENZO[k]FLUORANTHENE 1.10E-05 CATEF 

CHRYSENE 2.25E-05 Source Test (ND) a

DIBENZ[a,h]ANTHRACENE 2.25E-05 Source Test (ND) a

FLUORANTHENE CATEF 

FLUORENE CATEF 

INDENO(1,2,3-cd)PYRENE 2.25E-05 Source Test (ND) a

PHENANTHRENE CATEF 

PYRENE CATEF 

PAH (COMPOSITE) 5.24E-04 CATEF 

a

These compounds were tested for but not detected during the source test. The emission factor is 

based on one half the detection limit. 

Commissioning Emission Factors

Commissioning operations involve a wide-range of loads and add-on emission control effectiveness. 

During the early part of commissioning the oxidation catalyst is not typically installed and the 

turbine is operated at loads of 50% or less. In the absence of any other information, the District 

considers the startup and shutdown emission factors applicable to commissioning operations at loads 

of 50% or less. 
Rule 1200 Health Risk Assessment Report 

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Emergency Pump Engine Emission factors

The emission factors proposed by the applicant for the emergency diesel fire pump engine are based 

on Ventura County Air Pollution Control District Combustion Emission Factors for internal 

combustion diesel engines. The factors were reviewed by the District. The proposed emission 

factors are preliminarily determined to be representative of toxic air pollutant emissions from this 

emission unit. 

III. MODELING

APPLICANT SUBMITTED MODELING

Modeling Procedures

In the modeling submitted, cancer, chronic, and acute risks were estimated using ARB’s HARP 

Risk Analysis Module to determine source strengths (grams per seconds per microgram per 

cubic meter [(g/s)/ug/m3] based on emission factors for the equipment proposed and operating 

scenarios. The source strengths were input into EPA’s AERMOD dispersion model to directly 

estimate acute, chronic, and cancer health risks. The District independently reviewed the 

AERMOD model inputs for technical accuracy and adherence with ARB and OEHHA HRA 

guidance and District Rule 1200 standard procedures. 

The following AERMOD model inputs (g/s per ug/m3) were reviewed: 

• Annual and Hourly Emissions Rates (g/s) 

• Cancer Potencies (mg/kg-d)-1 

• Chronic and Acute Reference Exposure Levels (RELs) (ug/m3) 

• Derived (Adjusted) Method Breathing Rate = 302 (L/kg-d) 

• Worker Breathing Rate = 149 (L/kg-d) 

• Worker Exposure (5 days per week, 245 days per year, 40 years) 

• Muti-Pathway Oral (Dermal and Soil Ingestion) 

A list of applicant submitted and other material reviewed is given in Attachment A. 

Release Parameters

The release parameters used by the applicant are for combustion turbine normal operations, 

startup and shutdowns, and commissioning are shown in Tables 3-1a. 

Because turbine loads and release parameters change during the startup hour the applicant 

submitted an analysis of startup and shutdown impacts based on a 4-phase startup/shutdown 

hour. The startup phases are: 

• Phase 1. The first 12 minutes of the startup, which includes accelerating the turbine to 

full speed with no load and then subsequently ramping the turbine generator electrical 

output to the final load, which the applicant assumed was 100% of maximum load. 
Rule 1200 Health Risk Assessment Report 

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• Phase 2. The period from the end of the power ramp until the turbine achieves its BACT 

limits, which is proposed to take 10 minutes in a typical startup. 

• Phase 3. Operation at the final load until the end of the hour or shutdown (31 minutes or 

38 minutes with no shutdown). The final load was assumed to be 100% by the applicant. 

• Phase 4. The shutdown time period, which is proposed to be 7 minutes, typically, by the 

applicant. 

The applicant assumed that Phases 1 and 4 could be represented by the steady state operating 

conditions for 50% load. For the commissioning mode, the turbine was also assumed to be 

operating at 50% load. 

Table 3-1a 

Applicant Fuel Heat Input and Release Parameters for Startup, Shutdown, and 

Commissioning 

Operating mode Duration, min 

Fuel Heat 

Input, 

MMBtu/hr 

Stack Exhaust 

Temperature, 

°F 

Exhaust 

Velocity, m/s 

Normal 

Operations N/A 2085 

361 

21.21 

Startup 

Phase1 12 1093 346 12.24 

Phase2 10 2070 361 20.80 

Phase3 31 2070 361 20.80 

Phase4 7 1093 346 12.24 

Commissioning N/A 1093 346 12.24 

Emission Rates

For the combustion turbines, maximum emission rates for normal operations were based on a 

fuel heat input rate of 2085 MMBtu/hr or 2.04 MMscf per hour (fuel higher heating value of 

1019.3 Btu/scf). This fuel heat input rate is equivalent to full load operation at low ambient 

temperature (without power augmentation) and greater than the fuel heat input rate with power 

augmentation at average ambient temperature. Normal operation emissions were also based on 

4100 hours of operation per turbine per year. 

For startups, shutdowns, and commissioning, the fuel heat input rates are based on operation at 

either 100% load (startup Phases 2 and 3) or 50% load (startup Phases 1 and 4 and 

commissioning). The heat input rates correspond to operation at average annual temperature 

including power augmentation at 100% load. 
Rule 1200 Health Risk Assessment Report 

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Source Strengths

Calculated source strengths based on standard HARP health risk factors and based on the 

applicant and District emission factors are shown in Table 3-2. The residential risk factors used 

were based on the derived adjusted OEHHA method (the applicant also calculated source 

strengths for worker exposure). When multiplied by the appropriate fuel heat input rate in 

MMBtu/hr, these source strengths, can be used as input emission rates in AERMOD in 

(g/s)/(ug/m3) to allow the direct estimation of potential health impacts with AERMOD. The use 

of the adjustment factors is explained in Section IV. 

Table 3-2 

Source Strengths, g/s/[(ug/m3)(MMBtu/hr)] 

Category 

Incremental 

Cancer Risk 

(per million)

Source 

Strength 

Chronic 

Noncancer 

Health Hazard 

Index Source 

Strength 

Acute Noncancer 

Health Hazard 

Index Source 

Strength 

Applicant Annual—Resident 2.98E-03 2.78E-05 3.15E-06 

District Annual—Resident 5.96E-03 3.03E-05 2.99E-06 

Adjustment Factor 2.00 1.09 0.95 

Applicant Startup/Shutdown Commissioning N/A N/A 5.11E-05 

District Startup/Shutdown Commissioning 1.52E-02 3.55E-04 5.11E-05 

SUPPLEMENTAL MODELING

General

The District performed additional modeling to more fully examine potential health impacts. The 

modeling relied on the applicants submitted receptor grid and three-year (2003, 2004, and 2005) 

meteorological data, which the District has preliminarily approved. The modeling refined the 

startup, shutdown, and commissioning modeling for acute health impacts and addressed potential 

cancer and chronic health impacts from these operations. 

Modeling Procedures

For startup and shutdown emissions the major refinement was to look at the potential impact of 

low stack exhaust temperatures during the first few minutes of a cold start, which could increase 

the emission impacts. The District was unable to directly obtain any information on the stack 

exhaust temperature during a startup of the proposed turbine. Based on the fact that the turbine 

is proposed, under normal circumstances, to achieve its BACT limits within 22 minutes of 

ignition. The stack exhaust temperature was assumed to rise linearly from ambient (68 °F) to its 

normal operating temperature in 22 minutes. For shutdowns, the minimum stack exhaust 

temperature was assumed to be the exhaust temperature at 50% load. 
Rule 1200 Health Risk Assessment Report 

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The turbine load was assumed to be 0% for first 5 minutes and then to rise at a rate of 30 MW 

per minute until the final operating load for the remainder of the startup hour was reached. This 

startup scenario was based on a presentation given by the turbine manufacturer1. The load was 

calculated on a minute-by-minute basis, and average heat inputs for the four phases of the startup 

were calculated based on information provided by the manufacturer for steady state part load 

operation at an ambient temperature of 41 °F. A higher heating value for natural gas of 1020 

Btu/scf was used in emission factor calculations. 

Even though the turbine is projected to achieve its BACT limits in 22 minutes, the applicant has 

requested a 60 minute startup period. Therefore, in all cases, the final load was assumed to be 

50% of the maximum load for the remainder of the hour (or until shutdown) as a worst case 

analysis. A load of 50% was considered to be the worst case because: (1) this is the point of 

maximum fuel heat inputs at loads low enough for the much higher startup emission factors to be 

representative and (2) it is the point of minimum stack exhaust temperature at steady state 

conditions, based on manufacturer supplied data. 

The release parameters used in the modeling are presented Table 3-3 

Table 3-3 

Fuel Heat Input and Release Parameters for Supplemental Modeling 

Category Duration, min 

Fuel Heat 

Input, 

MMBtu/hr 

Stack Exhaust 

Temperature, 

°F 

Exhaust 

Velocity, m/s 

Startup 

Phase1 12 780 138 8.07 

Phase2 10 1257 281 11.49 

Phase3 31 or 38 1257 346 12.50 

Phase4 7 or 0 569 346 10.17 

Commissioning N/A 1257 346 12.50 

 

1

John Xia and Rick Antos, SGT6-5000F (W501F), 3 Million Hours Fleet Operational Experience, POWER-GEN 

International 2006, Orlando, FL, November 28-30, 2006. 
Rule 1200 Health Risk Assessment Report 

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IV. POTENTIAL HEALTH IMPACTS

NORMAL OPERATIONS

Applicant Results

The applicant’s estimated potential health impacts for normal combustion turbine operations are 

shown in Table 4-1a. These health impacts include those from the diesel emergency pump, 

which are small compared to the combustion turbine impact. 

Table 4-1a 

Applicant Estimated Potential Health Impacts for Normal Operations 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Maximum Exposed Individual Resident 0.068 0.0019 0.036 

Maximum Exposed Individual Worker 0.021 0.003 0.02 

Point of Maximum Impact 0.1 0.003 0.09 

Adjusted Normal Operation Results

To ensure that the HRA fully captured the potential health risks the applicant’s estimated health 

risk for cancer and chronic impacts were adjusted by multiplying by the adjustment factors in 

Table 3.2 that are based on the ratio of the District source strengths to the applicant’s source 

strengths. The differences in source strength ultimately derive from the differences in emission 

factors. Since the proposed permit contains no limits on hours of operation, the applicants 

estimated potential health risks were further adjusted by multiplying by the factor 8760/4100 to 

account for the possibility of operating every hour of the year. This would only be possible if 

criteria emissions could be reduced since operating hours are constrained by criteria emission 

limits in the proposed permit. The adjusted estimated potential health impacts are shown in 

Table 4-1b. The acute noncancer hazard index is not included in the adjustments because the 

adjusted impacts are used to evaluate impacts of startups and commissioning when normal 

operations are, by definition, not occurring. 
Rule 1200 Health Risk Assessment Report 

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Table 4-1b 

Adjusted Estimated Potential Health Impacts for Normal Operations 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Maximum Exposed Individual Resident 0.2905 0.0044 N/A 

Maximum Exposed Individual Worker 0.0897 0.0070 N/A 

Point of Maximum Impact 0.4271 0.0070 N/A 

STARTUP, SHUTDOWN, AND COMMISSIONING

Applicant Results

The applicant’s estimated acute health impacts for combustion turbine startups and shutdowns 

and commissioning are shown in Table 4-1c. The startup and shutdown impacts assume that the 

turbines are simultaneously started and ramped to 100% load and remain there for 41 minutes of 

the startup hour (Phases 2 and 3). The commissioning impacts are based on the startup of one 

turbine to 100% load while the other is undergoing commissioning. The majority of the acute 

health impact during the startup comes from the 41-minute period of operation at 100% load. 

The District provided the emission factors used by the applicant for this analysis, but intended 

they only be used at low loads since they are not applicable at higher loads. Because of this, 

these results are not representative and are only presented for informational purposes. 

 The overall maximum hourly impacts are calculated by a weighted linear combination of the 

impacts for each individual startup phase. The fractional weighting factors were equal to the 

fraction of hour that the individual phase occupied (for example, the weight for Phase 1 is 0.2 

since it lasts for 12 minutes). 
Rule 1200 Health Risk Assessment Report 

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Table 4-1c 

Applicant Estimated Potential Acute Health Impacts for Startups, Shutdowns and 

Commissioning 

Category 

Acute 

Noncancer 

Health 

Hazard Index

Startup and 

Shutdown 

Acute Noncancer 

Health Hazard 

Index 

Commissioning 

Maximum Exposed Individual Resident 0.33 0.33 

Maximum Exposed Individual Worker 0.18 0.16 

Point of Maximum Impact 0.76 0.60 

Supplemental Results

The District performed additional analyses of the potential health impacts from startups, 

shutdowns, and commissioning. The worst case was assumed to be a startup to 50% load and 

commissioning at 50% load. 

For simplicity, and conservatism, only the point of maximum impact was examined. Preliminary 

modeling showed that the difference in impacts between the two turbines was not significant, so 

only a single turbine was modeled. For simultaneous startup of both turbines the single turbine 

impacts were doubled for the combined impact. For commissioning, both the commissioning 

emissions and startup emissions were assumed to originate from the same stack. 

The input source strengths for each startup phase were weighted as explained above to generate 

the combined potential health impact for all four phases directly from AERMOD. Potential 

cancer and chronic health impacts were estimated as well as acute. The following cases were 

examined: 

• Simultaneous startup of both turbines with shutdown occurring at the end of the startup 

hour; 

• Simultaneous startup of both turbines with the turbines operating without shutdown for 

the remainder of the hour (at 50% load); 

• For acute impacts only, startup of one turbine with shutdown occurring at the end of the 

startup hour while the other turbine is in commissioning mode; 

• For acute impacts only, startup of one turbine with the turbine operating without 

shutdown for the remainder of the hour while the other turbine is in commissioning 

mode; and 

• For cancer and chronic impacts, both turbines in commissioning mode. This scenario is 

only used to calculate combined health impacts (see below). 
Rule 1200 Health Risk Assessment Report 

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In all cases, emissions were assumed to occur for 8760 hours per year. The estimated potential 

health impacts are presented for the worst case in Table 4-2 at the point of maximum impact. 

For startups, the worse case was uniformly the case where the turbine or turbines starting up 

operated the remainder of the hour at 50% load (i.e., no shutdown occurred in the startup hour). 

Table 4-2 

Supplemental Estimated Potential Health Impacts—Point of Maximum Impact 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Simultaneous Startup of Both Turbines 2.516 0.0588 0.444 

Startup of One Turbine While the Other 

Turbine is Commissioning 

N/A N/A 0.572 

Commissioning Both Turbines 1.9 0.0456 N/A 

COMBINED ANNUAL IMPACTS

Methodology

Estimated potential cancer and chronic health impacts were estimated by combining the adjusted 

normal operation impacts with the estimated startup, shutdown, and commissioning impacts. 

The following equation was used to estimate combined chronic impacts: 

HI = [(N – S – C)/8760] Rn + (S/8760)Rs + (C/8760)Rc 

where: 

HI is the combined health impact; 

N is the maximum number of normal operating hours per turbine; 

S is the number of startup hours per turbine; 

C is the number of commissioning hours per turbine; 

Rn is the maximum estimated potential health impact for 8760 hours of normal operations 

for both turbines combined; 

Rs is the maximum estimated potential health impact for 8760 hours of startups for both 

turbines combined; and 

Rc is the maximum estimated potential health impact for 8760 hours of commissioning 

for both turbines combined 
Rule 1200 Health Risk Assessment Report 

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For estimating combined potential cancer health impacts, the same formula was used when a 

commissioning year is not included (standard years). For estimating potential cancer health 

impacts including one year of commissioning, the following equation was used: 

HI = [(N – S – (1/70)*C)/8760] Rn + (S/8760)Rs + (1/70)(C/8760)Rc 

The above method is conservative in that it does not account for temporal and spatial variation in 

the location of the separate maximum estimated potential health impacts associated with normal 

operations, startups, and commissioning. 

Combined Operating Scenarios

Table 5-1 defines the basis for estimating the expected and worst case potential health impacts. 

The worst case is based on the 1460 startups since the number of startups per turbine is limited to 

1460 by proposed permit conditions. 

Table 5-1 

Combined Annual Health Impact Basis 

Scenario 

Maximum 

Normal 

Operating 

Hours per 

Turbine 

Number of 

Startups per 

Turbine 

Commissioning 

Mode Hours per 

Turbine 

Standard Year 

Expected 4100 300 0

Worst Case 8760 1460 0 

Commissioning Year 

Expected 4100 300 415 

Worst Case 8760 1460 415 

Maximum Potential Impacts

Tables 5.2a, 5.2b, 5.2c, and 5.2d present the maximum expected and worst-case potential health 

impacts. 
Rule 1200 Health Risk Assessment Report 

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Table 5-2a 

Expected Maximum Potential Health Impacts—Standard Year 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Maximum Exposed Individual Resident 0.22 0.004 

Maximum Exposed Individual Worker 0.14 0.005 

Point of Maximum Impact 0.28 0.005 0.44 

Table 5-2b 

Expected Maximum Potential Health Impacts— Including the Commissioning Year 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Maximum Exposed Individual Resident 0.22 0.006 

Maximum Exposed Individual Worker 0.14 0.007 

Point of Maximum Impact 0.28 0.007 0.57 

Table 5-2c 

Worst-Case Potential Health Impacts—Standard Year 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Maximum Exposed Individual Resident 0.71 0.015 

Maximum Exposed Individual Worker 0.54 0.017 

Point of Maximum Impact 0.82 0.017 0.44 
Rule 1200 Health Risk Assessment Report 

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Table 5-2d 

Worst-Case Potential Health Impacts—Including the Commissioning Year 

Category 

Incremental 

Cancer Risk 

(per million) 

Chronic 

Noncancer 

Health Hazard 

Index 

Acute Noncancer 

Health Hazard 

Index 

Maximum Exposed Individual Resident 0.71 0.017 

Maximum Exposed Individual Worker 0.54 0.019 

Point of Maximum Impact 0.83 0.019 0.57 
Rule 1200 Health Risk Assessment Report 

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ATTACHMENT A 

As part of this review following submittals and documents were reviewed: 

• Carlsbad Energy Center Project, California Energy Commission, Docket No. 07-AFC-6. 

Revised (5/11/08) Modeling Input Summary Tables: Attachment DR84-90-3. June 6, 2008. 

o Table 5.9B-1: Annual and Maximum Hourly Non-Criteria Pollutant Emissions From 

Gas Turbines during Normal Operation. 

o Table 5.9-6 (Revised 5/11/08): Summary of Potential Health Risks. 

o Table 5.9B-5: Calculation of Cancer Risk for Gas Turbines and Diesel Emergency 

Fire Pump. 

o Table 5.9B-6: Calculation of Gas Turbine Acute and Chronic Heath Hazard Indexes. 

o Table 5.9B-8: Calculation of Diesel Emergency Fire Pump Acute Health Hazard 

Index. 

• Application for Authority to Construct for the Proposed Carlsbad Energy Center Project: 

Additional Acute Health Hazard Modeling Analysis. September 24, 2008. 

o Table A-4, 9/24/08: Calculation of HHI Modeling Inputs for Gas Turbines during Startup 

Phases 1 plus 4 using SDAPCD Emission Factors. 

o Table A-5, 9/24/08: Calculation of HHI Modeling Inputs for Gas Turbines during Startup 

Phases 2 plus 3 using SDAPCD Emission Factors. 

• SDAPCD Air Quality Impact Analysis, Final Review Report, Carlsbad Energy Center 

Project (Application 985423). September 24, 2008. 
APPENDIX C 

PROPOSED PERMIT CONDITIONS 
Proposed Conditions Page 1 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

CECP PROPOSED PERMIT CONDITIONS

GENERAL CONDITIONS

1. This equipment shall be properly maintained and kept in good operating condition at all times and, to the 

extent practicable, maintain and operate the equipment and any associated air pollution control 

equipment in a manner consistent with good air pollution control practices for minimizing emissions. 

[Rule 21 and 40 CFR §60.11] 

2. The applicant shall operate the project in accordance with all data and specifications submitted with the 

application under which this license is issued and District Applications Nos. 985745, 985747 and 

985748. [Rule 14] 

3. The applicant shall provide access, facilities, utilities, and any necessary safety equipment, with the 

exception of personal protective equipment requiring individual fitting and specialized training, for 

source testing and inspection upon request of the Air Pollution Control District. [Rule 19] 

4. The applicant shall obtain any necessary District permits for all ancillary combustion equipment 

including emergency engines, prior to on-site delivery of the equipment. [Rule 10] 

5. For each combustion turbine, prior to the initial startup date of that turbine, the applicant shall surrender 

to the District Class A Emission Reduction Credits (ERCs) in an amount equivalent to 23.91 tons per 

year of oxides of nitrogen (NOx) to offset the net maximum allowable increase of 19.93 tons per year of 

NOx emissions for that turbine. [Rule 20.3(d)(8)] 

6. Prior to the earlier of the two dates for the initial startup date of the two turbines the applicant shall 

surrender to the District Class A Emission Reduction Credits (ERCs) in an amount equivalent to 0.06 

tons per year of oxides of nitrogen (NOx) to offset the net maximum allowable increase of 0.05 tons per 

year of NOx emissions from the emergency fire pump engine. [Rule 20.3(d)(8)] 

7. Pursuant to 40 CFR §72.30(b)(2)(ii) of the Federal Acid Rain Program, the applicant shall submit an 

application for a Title IV Operating Permit at least 24 months prior to the initial startup of the 

combustion turbines. [40 CFR Part 72] 

8. The applicant shall comply with all applicable provisions of 40 CFR Part 73, including requirements to 

offset, hold and retire sulfur dioxide (SO2) allowances. [40 CFR Part 73] 

9. All records required by this permit shall be maintained on site for a minimum of five years and made 

available to the District upon request. [Rule 1421] 

COMBUSTION TURBINE CONDITIONS

Definitions

10. For purposes of determining compliance with the emission limits of this permit, a shutdown period is the 

period of time that begins with the lowering of the gross electrical output (load) of the combustion 

turbine below 114 megawatts (MW) and that ends five minutes after fuel flow to the combustion turbine 

ceases, not to exceed 35 consecutive minutes. [Rule 20.3(d)(1)] 
Proposed Conditions Page 2 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

11. A startup period is the period of time that begins when fuel flows to the combustion turbine following a 

non-operational period. For purposes of determining compliance with the emission limits of this permit, 

the duration of a startup period shall not exceed 60 consecutive minutes. [Rule 20.3(d)(1)] 

12. A non-operational period is any five-consecutive-minute period when fuel does not flow to the 

combustion turbine. [Rule 20.3(d)(1)] 

13. Tuning is defined as adjustments to the combustion or emission control system that involves operating 

the combustion turbine or emission control system in a manner such that the emissions control 

equipment may not be fully effective or operational. Only one gas turbine shall be tuned at any given 

time. Tuning events shall not exceed 720 minutes in a calendar day nor exceed 40 hours in a calendar 

year for each turbine. The District compliance division shall be notified at least 24 hours in advance of 

any tuning event. [Rule 20.3(d)(1)] 

14. A Continuous Emission Monitoring System (CEMS) protocol is a document approved in writing by the 

District that describes the methodology and quality assurance and quality control procedures for 

monitoring, calculating, and recording stack emissions from the combustion turbine that is monitored by 

the CEMS. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 

75] 

15. A transient hour is a clock hour during which the change in gross electrical output produced by the 

combustion turbine exceeds 50 MW per minute for one minute or longer during any period that is not 

part of a startup or shutdown period. [Rule 20.3(d)(1)] 

16. For each combustion turbine, the commissioning period is the period of time commencing with the 

initial startup of that turbine and ending the sooner of 120 calendar days from the initial startup, after 

415 hours of turbine operation, or the date the pemittee notifies the District the commissioning period 

has ended. [Rule 20.3(d)(1)] 

17. For each combustion turbine, the shakedown period is the period of time commencing with the initial 

startup of that turbine and ending the sooner of 180 calendar days from the initial startup or the date the 

permittee notifies the District that the shakedown period has ended. [Rules 20.1(c)(16) and 21 and 40 

CFR §52.21] 

18. Turbine A is the combustion turbine as described on Applications No. 985745 or No. 985747, as 

applicable, that first completes its shakedown period. If both turbines complete their shakedown period 

on the same date, then Turbine A is the turbine described on Application No. 985745. [Rules 

20.1(c)(16) and 21 and 40 CFR §52.21] 

19. Turbine B is the combustion turbine as described on Applications No. 985745 or No. 985747, as 

applicable, that last completes its shakedown period. If both turbines complete their shakedown period 

on the same date, then Turbine A is the turbine described on Application No. 985747. [Rules 

20.1(c)(16) and 21 and 40 CFR §52.21] 

20. Low load operation is a period of time that begins when the gross electrical output (load) of the 

combustion turbine is reduced below 114 MW and that ends 10 consecutive minutes after the 

combustion turbine load exceeds 114 MW, provided that fuel is continuously combusted during the 

entire period and one or more clock-hour concentration emission limits specified in this permit are 
Proposed Conditions Page 3 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

exceeded as a result of the low-load operation. Periods of operation at low load shall not exceed 130 

minutes in any calendar day nor an aggregate of 780 minutes in any calendar year. No low load 

operation period shall begin during a startup period. [Rule 20.3(d)(1)] 

21. Unit operating day means, for each combustion turbine, any calendar day in which the turbine combusts 

fuel. [40 CFR Part 60 Subpart KKKK] 

General Conditions

22. The exhaust stacks for each combustion turbine shall be at least 139 feet in height above site base 

elevation. [Rules 20.3(d)(2) and 1200] 

23. The combustion turbines shall be fired on Public Utility Commission (PUC) quality natural gas. The 

permitee shall maintain, on site, daily and quarterly records of the natural gas sulfur content (grains of 

sulfur compounds per 100 dscf of natural gas) and hourly records of the higher and lower heating values 

(btu/scf) of the natural gas; and provide records to District personnel upon request. [Rule 20.3(d)(1)] 

24. Unless otherwise specified in this permit, all continuous monitoring data shall be collected at least once 

every minute. [Rules 69.3, 69.3.1, and 20.3(d)(1)] 

Emission Limits

25. For purposes of determining compliance with emission limits based on source testing, the average of 

three subtests shall be used. For purposes of determining compliance with emission limits based on a 

Continuous Emission Monitoring System (CEMS), data collected in accordance with the CEMS 

protocol shall be used and the averages for averaging periods specified herein shall be calculated as 

specified in the CEMS protocol. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, 

and 40 CFR Part 75] 

26. For purposes of determining compliance with emission limits based on CEMS data, all CEMS 

calculations, averages, and aggregates shall be performed in accordance with the CEMS protocol 

approved in writing by the District. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart 

KKKK, and 40 CFR Part 75] 

27. For each emission limit expressed as pounds, pounds per hour, or parts per million based on a one-hour 

or less averaging period or compliance period, compliance shall be based on using data collected at least 

once every minute when compliance is based on CEMS data. [Rules 69.3, 69.3.1, and 20.3(d)(1)] 

28. When a combustion turbine is combusting fuel (operating), the emission concentration of oxides of 

nitrogen (NOx), calculated as nitrogen dioxide (NO2), shall not exceed 2.0 parts per million by volume 

on a dry basis (ppmvd) corrected to 15% oxygen, except during commissioning, low load operation, 

startup, shutdown, or tuning periods for that turbine. For purposes of determining compliance based on 

CEMS data, the following averaging periods calculated in accordance with the CEMS protocol shall 

apply: 

A. For any transient hour, a 3-clock-hour average, calculated as the average of the transient hour, 

the clock hour immediately prior to the transient hour and the clock hour immediately 

following the transient hour. 

B. For all other hours, a 1-clock-hour average. 
Proposed Conditions Page 4 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

[Rule 20.3(d)(1)] 

29. When a combustion turbine is operating, the emission concentration of carbon monoxide (CO) shall not 

exceed 2.0 ppmvd corrected to 15 % oxygen, except during commissioning, low load operation, startup, 

shutdown, or tuning periods for that turbine. For purposes of determining compliance based on CEMS 

data, the following averaging periods calculated in accordance with the CEMS protocol shall apply: 

A. For any transient hour, a 3-clock-hour average, calculated as the average of the transient hour, 

the clock hour immediately prior to the transient hour and the clock hour immediately 

following the transient hour. 

B. For all other hours, a 1-clock-hour average. 

[Rule 20.3(d)(1)] 

30. When a combustion turbine is operating, the volatile organic compound (VOC) concentration, calculated 

as methane, measured in the exhaust stack, shall not exceed 2.0 ppmvd corrected to 15% oxygen, except 

during commissioning, low load operation, startup, shutdown, or tuning periods for that turbine. For 

purposes of determining compliance based on the CEMS, the District approved CO/VOC surrogate 

relationship, the CO CEMS data, and the following averaging periods calculated in accordance with the 

CEMS protocol shall be used: 

A. For any transient hour, a 3-clock-hour average, calculated as the average of the transient hour, 

the clock hour immediately prior to the transient hour and the clock hour immediately 

following the transient hour. 

B. For all other hours, a 1-clock-hour average. 

The CO/VOC surrogate relationship shall be verified and/or modified, if necessary, based on source 

testing. [Rule 20.3(d)(1)] 

31. When a combustion turbine is operating, the ammonia concentration (ammonia slip), shall not exceed 

5.0 ppmvd corrected to 15 % oxygen, except during commissioning, low load operation, startup, 

shutdown, or tuning periods for that turbine. [Rule 1200] 

32. When a combustion turbine is operating with post-combustion air pollution control equipment that 

controls oxides of nitrogen (NOx) emissions, the emission concentration NOx, calculated as nitrogen 

dioxide (NO2), shall not exceed 12.9 ppmvd calculated over each clock-hour period and corrected to 

15% oxygen, except for periods of startup and shutdown, as defined in Rule 69.3.1. This limit does not 

apply during any period in which the facility is subject to a variance from the emission limits contained 

in Rule 69.3.1. [Rule 69.3.1] 

33. When a combustion turbine is operating without any post-combustion air pollution control equipment 

that controls oxides of nitrogen (NOx) emissions, the emission concentration of NOx calculated as 

nitrogen dioxide (NO2) from each turbine shall not exceed 21.6 parts per million by volume on a dry 

basis (ppmvd) calculated over each clock-hour period and corrected to 15% oxygen, except for periods 

of startup and shutdown, as defined in Rule 69.3.1. This limit does not apply during any period in which 

the facility is subject to a variance from the emission limits contained in Rule 69.3.1. [Rule 69.3.1] 

34. When a combustion turbine is operating, the emission concentration of oxides of nitrogen (NOx), 

calculated as nitrogen dioxide (NO2) shall not exceed 42 ppmvd calculated over each clock-hour period 

and corrected to 15% oxygen, on a dry basis, except during periods of startup and shutdown, as defined 
Proposed Conditions Page 5 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

in Rule 69.3. This limit does not apply during any period in which the facility is subject to a variance 

from the emission limits contained in Rule 69.3. [Rule 69.3] 

35. For each rolling 30-day-unit-operating-day period, average emission concentration of oxides of nitrogen 

(NOx) for each turbine calculated as nitrogen dioxide (NO2) in parts per million by volume dry (ppmvd) 

corrected to 15% oxygen or, alternatively, as elected by the permittee, the average NOx emission rate in 

pounds per megawatt-hour (lb/MWh) shall not exceed an average emission limit calculated in 

accordance with 40 CFR Section 60.4380(b)(3). The emission concentration and emission rate averages 

shall be calculated in accordance with 40 CFR Section 60.4380(b)(1). The average emission 

concentration limit and emission rate limit shall be based on an average of hourly emission limits over 

the 30-day-unit-operating period. The hourly emission concentration limit and emission rate limit shall 

be 15 ppmvd corrected to 15% oxygen and 0.43 lb/MWh, respectively, for clock hours when the 

combustion turbine load is equal to or greater than 156 megawatts at all times during the clock hour, 

respectively, and 96 ppmvd corrected to 15% oxygen and 4.7 lb/MWh for all other clock hours when the 

combustion turbine is operating, respectively. The averages shall exclude all clock hours occurring 

before the Initial Emission Source Test but shall include emissions during all other times that the 

equipment is operating including, but not limited to, emissions during low load operation, startup, 

shutdown, and tuning periods. For each six-calendar-month period, emissions in excess of these limits 

and monitor downtime shall be identified in accordance with 40 CFR Sections 60.4350 and 

60.4380(b)(2), except that Section 60.4350(c) shall not apply for identifying periods in excess of a NOx 

concentration limit, and reported to the District and the federal EPA in accordance with Title V 

Operating Permit No. 974488. [40 CFR Part 60 Subpart KKKK] 

36. The emissions of particulate matter less than or equal to 10 microns in diameter (PM10)shall not exceed 

9.5 pounds per hour for each combustion turbine. [Rule 20.3(d)(2)] 

37. The discharge of particulate matter from the exhaust stack of each combustion turbine shall not exceed 

0.10 grains per dry standard cubic foot (0.23 grams/dscm). The District may require periodic testing to 

verify compliance with this standard. [Rule 53] 

38. Visible emissions from the lube oil vents and the exhaust stack of each combustion turbine shall not 

exceed 20% opacity for more than three (3) minutes in any period of 60 consecutive minutes. [Rule50] 

39. Mass emissions from each combustion turbine shall not exceed the following limits, except during 

commissioning, low load operation, startup, shutdown, or tuning periods for that turbine. A 1-clockhour averaging period for these limits shall apply to CEMS data except for emissions during transient 

hours when a 3-clock-hour averaging period shall apply. 

Pollutant Emission Limit, lb

i. Oxides of Nitrogen, NOx (calculated as NO2) 15.1 

ii. Carbon Monoxide, CO 9.2 

iii. Volatile Organic Compounds, VOC 5.3 

[Rule 20.3(d)(2)] 

40. Excluding any minutes that are coincident with a shutdown period, cumulative mass emissions during a 

combustion turbine’s startup period shall not exceed the following limits during any startup period, 

except during that turbine’s commissioning period. 
Proposed Conditions Page 6 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

Pollutant Emission Limit,lb

i. Oxides of Nitrogen, NOx (calculated as NO2) 69.2 

ii. Carbon Monoxide, CO 545 

iii. Volatile Organic Compounds, VOC 16.3 

[Rule 20.3(d)(1)] 

41. Cumulative mass emissions during a combustion turbine’s shutdown period shall not exceed the 

following limits during any shutdown period, except during that turbine’s commissioning period. 

Pollutant Emission Limit,lb

i. Oxides of Nitrogen, NOx (calculated as NO2) 25.7 

ii. Carbon Monoxide, CO 277 

iii. Volatile Organic Compounds, VOC 7.0 

[Rule 20.3(d)(1)] 

42. The oxides of nitrogen (NOx) emissions from each combustion turbine shall not exceed 200 pounds per 

hour and total aggregate NOx emissions from both combustion turbines combined shall not exceed 286 

pounds per hour, calculated as nitrogen dioxide and measured over each 1-clock-hour period. These 

emission limits shall apply during all times one or both turbines are operating, including, but not limited 

to, emissions during commissioning, low load operation, startup, shutdown, and tuning periods. [Rule 

20.3(d)(2)] 

43. The carbon monoxide (CO) emissions from each combustion turbine shall not exceed 3813 pounds per 

hour and total aggregate CO emissions from both combustion turbines combined shall not exceed 4627 

pounds per hour measured over each 1-clock-hour period. This emission limit shall apply during all 

times that one or both turbines are operating, including, but not limited to emissions during 

commissioning, low load operation, startup, shutdown, and tuning periods. [Rule 20.3(d)(2)(i)] 

44. Beginning with the earlier of the initial startup dates for either combustion turbine, aggregate emissions 

of oxides of nitrogen (NOx), calculated as nitrogen dioxide (NO2); carbon monoxide (CO); volatile 

organic compounds (VOCs); particulate matter less than or equal to 10 microns in diameter (PM10); and 

oxides of sulfur (SOx), calculated as sulfur dioxide (SO2), from the combustion turbines described in 

District Applications No. 985745 and 985747 and the emergency fire pump described in Application 

No. 985748, except emissions or emission units excluded from the calculation of aggregate potential to 

emit as specified in Rule 20.1 (d) (1), shall not exceed the following limits for each rolling 12-calendarmonth period: 

Pollutant Emission Limit, tons per year

i. Oxides of Nitrogen, NOx (calculated as NO2) 72.76 

ii. Carbon Monoxide, CO 339.9 

iii. Volatile Organic Compounds, VOC 25.0 

iv. Particulate Matter Less than 10 Microns, PM10 39.0 

v. Oxides of Sulfur, SOx (calculated as SO2) 5.6 

The aggregate emissions of each pollutant shall include emissions during all times that the equipment is 

operating including, but not limited to, emissions during commissioning, low load operation, startup, 

shutdown, and tuning periods. [Rules 20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 
Proposed Conditions Page 7 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

45. For each calendar month, the applicant shall maintain records, as applicable, on a calendar monthly 

basis, of mass emissions during each calendar month of NOx (calculated as NO2), CO, VOCs, PM10, 

PM2.5, and SOx (calculated as SO2), in tons, from each emission unit described in District Applications 

No. 985745, 985747, and 985748, except for emissions or emission units excluded from the calculation 

of aggregate potential to emit as specified in Rule 20.1 (d) (1). These records shall be made available 

for inspection within 15 calendar days after the end of each calendar month. [Rules 20.3(d)(3), 

20.3(d)(8) and 21 and 40 CFR §52.1] 

46. For each calendar month and each rolling 12-calendar-month period, the applicant shall maintain 

records, as applicable, on a calendar monthly basis, of aggregate mass emissions of NOx (calculated as 

NO2), CO, VOCs, PM10, PM2.5, and SOx (calculated as SO2) in tons for the emission units described in 

District Applications No. 985745, 985747, and 985748, except for emissions or emission units excluded 

from the calculation of aggregate potential to emit as specified in Rule 20.1 (d) (1). These records shall 

be made available for inspection within 15 calendar days after the end of each calendar month. [Rules 

20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 

47. For each combustion turbine, the number of startup periods occurring in each calendar year shall not 

exceed 1460. [Rules 1200 and 21] 

Ammonia - SCR

48. Not later than 90 calendar days prior to the start of construction, the applicant shall submit to the District 

the final selection, design parameters and details of the selective catalytic reduction (SCR) and oxidation 

catalyst emission control systems for the combustion turbines including, but not limited to, the minimum 

ammonia injection temperature for the SCR and the oxidation catalyst CO control efficiency versus 

temperature and space velocity. Such information may be submitted to the District as trade secret and 

confidential pursuant to District Rules 175 and 176. [Rules 20.3(d)(1) and 14] 

49. When a combustion turbine is operating, ammonia shall be injected at all times that the associated 

selective catalytic reduction (SCR) system outlet temperature is 450 degrees Fahrenheit or greater. 

[Rules 20.3(d)(1)] 

50. Continuous monitors shall be installed on each SCR system prior to their initial operation to monitor or 

calculate, and record the ammonia solution injection rate in pounds per hour and the SCR outlet 

temperature in degrees Fahrenheit. The monitors shall be installed, calibrated and maintained in 

accordance with a District approved protocol, which may be part of the CEMS protocol. This protocol, 

which shall include the calculation methodology, shall be submitted to the District for written approval 

at least 90 days prior to initial startup of the gas turbines with the SCR system. The monitors shall be in 

full operation at all times when the turbine is in operation. [Rules 20.3(d)(1)] 

51. Except during periods when the ammonia injection system is being tuned or one or more ammonia 

injection systems is in manual control (for compliance with applicable permits), the automatic ammonia 

injection system serving the SCR system shall be in operation in accordance with manufacturer's 

specifications at all times when ammonia is being injected into the SCR system. Manufacturer 

specifications shall be maintained on site and made available to District personnel upon request. [Rules 

20.3(d)(1)]
Proposed Conditions Page 8 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

52. The concentration of ammonia solution used in the ammonia injection system. Shall be less than 20% 

ammonia by weight. Records of ammonia solution concentration shall be maintained on site and made 

available to District personnel upon request. [Rule 14] 

Testing

53. All source test or other tests required by this permit shall be performed by the District or an independent 

contractor approved by the District. Unless otherwise specified in this permit or authorized in writing 

by the District, if testing will be performed by an independent contractor and witnessed by the District, a 

proposed test protocol shall be submitted to the District for written approval at least 60 days prior to 

source testing. Additionally, the District shall be notified a minimum of 30 days prior to the test so that 

observers may be present unless otherwise authorized in writing by the District. [Rules 20.3(d)(1) and 

1200 and 40 CFR Part 60 Subpart KKKK and 40 CFR §60.8] 

54. Unless otherwise specified in this permit or authorized in writing by the District, within 45 days after 

completion of a source test or RATA test performed by an independent contractor, a final test report 

shall be submitted to the District for review and approval. [Rules 20.3(d)(1) and 1200 and 40 CFR Part 

60 Subpart KKKK, 40 CFR §60.8, and 40 CFR Part 75] 

55. The exhaust stacks for each combustion turbine shall be equipped with source test ports and platforms to 

allow for the measurement and collection of stack gas samples consistent with all approved test 

protocols. The ports and platforms shall be constructed in accordance with District Method 3A, Figure 2, 

and approved by the District. Ninety days prior to construction of the turbine stacks the project owner 

shall provide to the District for written approval detailed plan drawings of the turbine stacks that show 

the sampling ports and demonstrate compliance with the requirements of this condition. [Rule 20] 

56. Within 60 calendar days after completion of the commissioning period for each combustion turbine, an 

Initial Emissions Source Test shall be conducted on that turbine to demonstrate compliance with the 

NOX, CO, VOC, PM10, and ammonia emission standards of this permit. The source test protocol shall 

comply with all of the following requirements: 

A. Measurements of NOX and CO concentrations and emissions and O2 concentration shall be 

conducted in accordance with U.S. Environmental Protection Agency (EPA) methods 7E, 10, 

and 3A, respectively, and District source test Method 100, or alternative methods approved by 

the District and EPA; 

B. Measurement of VOC emissions shall be conducted in accordance with EPA 

Methods 25A and/or 18, or alternative methods approved by the District and EPA; 

C. Measurements of ammonia emissions shall be conducted in accordance with Bay Area Air 

Quality Management District Method ST-1B or an alternative method approved by the District 

and EPA; 

D. Measurements of PM10 emissions shall be conducted in accordance with EPA Methods 201A 

and 202 or alternative methods approved by the District and EPA; 

E. Source testing shall be performed at the normal load level, as specified in 40 CFR Part 75 

Appendix A Section 6.5.2.1 (d), provided it is not less than 80% of the combustion turbine’s 

rated load unless it is demonstrated to the satisfaction of the District that the combustion 

turbine cannot operate under these conditions. If the demonstration is accepted, then emissions 

source testing shall be performed at the highest achievable continuous power level. The 
Proposed Conditions Page 9 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

District may specify additional testing at different load levels or operational conditions to 

ensure compliance with the emission limits of this permit and District Rules and Regulations. 

F. Measurements of particulate matter emissions shall be conducted in accordance with SDAPCD 

Method 5 or an alternative method approved by the District and EPA; and 

G. Measurements of opacity shall be conducted in accordance with EPA Method 9 or an 

alternative method approved by the District and EPA. 

[Rules 20.3(d)(1) and 1200] 

57. A renewal source test and a NOX and CO Relative Accuracy Test Audit (RATA) test shall be 

periodically conducted on each combustion turbine to demonstrate compliance with the NOX, CO, 

VOC, PM10, and ammonia emission standards of this permit, using District approved methods. The 

renewal source test and the NOX and CO Relative Accuracy Test Audit (RATA) tests shall be 

conducted in accordance with the applicable RATA frequency requirements of 40 CFR75, Appendix B, 

Sections 2.3.1 and 2.3.3. The renewal source test shall be conducted in accordance with a protocol 

complying with all the applicable requirements of the source test protocol for the Initial Emissions 

Source Test. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 

75] 

58. Relative Accuracy Test Audit (RATA) tests and all other required certification tests shall be performed 

and completed on the CEMS in accordance with applicable provisions of 40 CFR Part 75 Appendix A 

and B performance specifications and 40 CFR §60.4405. [40 CFR Part 60 Subpart KKKK and 40 CFR 

Part 75] 

59. Within 60 calendar days after completion of the commissioning period for each combustion turbine, an 

initial emission source test for toxic air contaminants shall be conducted on that turbine to determine the 

emissions of toxic air contaminants from the combustion turbines. At a minimum the following 

compounds shall be tested for, and emissions, if any, quantified: 

A. Acetaldehyde 

B. Acrolein 

C. Benzene 

D. Formaldehyde 

E. Toluene 

F. Xylenes 

This list of compounds may be adjusted by the District based on source test results to ensure compliance 

with District Rule 1200 is demonstrated. The District may require one or more or additional compounds 

to be quantified through source testing as needed to ensure compliance with Rule 1200. Within 60 

calendar days after completion of a source test performed by an independent contractor, a final test 

report shall be submitted to the District for review and approval. [Rule 1200] 

60. The District may require one or more of the following compounds, or additional compounds to be 

quantified through source testing periodically to ensure compliance with rule 1200: 
Proposed Conditions Page 10 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

A. Acetaldehyde 

B. Acrolein 

C. Benzene 

D. Formaldehyde 

E. Toluene 

F. Xylenes 

If the District requires the permittee to perform this source testing, the District shall request the testing in 

writing a reasonable period of time prior to the testing date. [Rule 1200] 

 

61. The higher heating value of the combustion turbine fuel shall be measured by ASTM D1826–94, 

Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording 

Calorimeter or ASTM D1945–96, Standard Method for Analysis of Natural Gas by Gas 

Chromatography or an alternative test method approved by the District and EPA. [Rules 69.3, 69.3.1, 

and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

62. The sulfur content of the combustion turbine fuel shall be sampled daily in accordance with ASTM 

D5287–97, Standard Practice for Automatic Sampling of Gaseous Fuels, and measured with ASTM 

D1072–90 (Reapproved 1994), Standard Test Method for Total Sulfur in Fuel Gases; ASTM D3246–05, 

Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry; ASTM D4468–85 

(Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and 

Rateometric Colorimetry; ASTM D6228–98 (Reapproved 2003), Standard Test Method for 

Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and 

Flame Photometric Detection; or ASTM D6667–04, Standard Test Method for Determination of Total 

Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence or 

an alternative test method approved by the District and EPA. [[Rule 20.3(d)(1) and 40 CFR Part 60 

Subpart KKKK, and 40 CFR Part 75] 

CONTINUOUS MONITORING

63. The applicant shall comply with the continuous emission monitoring requirements of 40 CFR Part 75. [] 

64. A continuous emission monitoring system (CEMS) shall be installed on each combustion turbine and 

properly maintained and calibrated to measure, calculate and record the following, in accordance with 

the District approved CEMS protocol: 

A. Hourly average(s) concentration of oxides of nitrogen (NOX) uncorrected and corrected 

to 15% oxygen, in parts per million (ppmvd), necessary to demonstrate compliance with 

the NOx limits of this permit; 

B. Hourly average concentration of carbon monoxide (CO) uncorrected and corrected to 

15% oxygen, in parts per million (ppmvd), necessary to demonstrate compliance with the 

CO limits of this permit; 

C. Percent oxygen (O2) in the exhaust gas; 

D. Average concentration of oxides of nitrogen (NOX) for each continuous rolling 3-hour 

period, in parts per million (ppmv) corrected to 15% oxygen; 
Proposed Conditions Page 11 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

E. Hourly mass emissions of oxides of nitrogen (NOX), in pounds; 

F. Cumulative mass emissions of oxides of nitrogen (NOX) in each startup and shutdown 

period, in pounds; 

G. Daily mass emissions of oxides of nitrogen (NOX), in pounds; 

H. Calendar monthly mass emissions of oxides of nitrogen (NOX), in pounds; 

I. Rolling 30-unit-operating-day average concentration of oxides of nitrogen (NOX) 

corrected to 15% oxygen, in parts per million (ppmvd); 

J. Rolling 30-unit-operating-day average oxides of nitrogen (NOx) emission rate, in pounds 

per megawatt-hour (MWh); 

K. Annual mass emissions of oxides of nitrogen (NOX), in tons; 

L. Cumulative mass emissions of carbon monoxide (CO) in each startup and shutdown 

period, in pounds 

M. Hourly mass emissions of carbon monoxide (CO), in pounds; 

N. Daily mass emission of carbon monoxide (CO), in pounds; 

O. Calendar monthly mass emission of carbon monoxide (CO), in pounds; 

P. Annual mass emission of carbon monoxide (CO), in tons; 

[Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

65. No later than 90 calendar days prior to initial startup of each combustion turbine, the applicant shall 

submit a CEMS protocol to the District, for written approval that shows how the CEMS will be able to 

meet all District monitoring requirements. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 

Subpart KKKK, and 40 CFR Part 75] 

66. No later than 60 calendar days after each combustion turbine commences commercial operation (defined 

for purposes of this condition as the first instance when power is sold to the electrical grid), a Relative 

Accuracy Test Audit (RATA) and other required certification tests shall be performed an completed on 

the that turbine’s CEMS in accordance with 40 CFR Part 75 Appendix A Specifications and Test 

Procedures. At least 60 calendar days prior to the test date, the applicant shall submit a test protocol to 

the District for written approval. Additionally, the District and U.S. EPA shall be notified a minimum of 

45 calendar days prior to the test so that observers may be present. Within 45 calendar days of 

completion of this test, a written test report shall be submitted to the District for approval. [Rules 69.3, 

69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

67. A monitoring plan in conformance with 40 CFR 75.53 shall be submitted to U.S EPA Region 9 and the 

District at least 45 calendar days prior to the Relative Accuracy Test Audit test, as required in 40 CFR 

75.62. [40 CFR Part 75] 

68. The oxides of nitrogen (NOX) and oxygen (O2) components of the CEMS shall be certified and 

maintained in accordance with applicable Federal Regulations including the requirements of sections 

75.10 and 75.12 of title 40, Code of Federal Regulations Part 75 (40 CFR 75), the performance 

specifications of appendix a of 40 CFR 75, the quality assurance procedures of Appendix B of 40 CFR 

75 and the CEMS protocol approved by the District. The carbon monoxide (CO) components of the 

CEMS shall be certified and maintained in accordance with 40 CFR 60, Appendices B and F, unless 

otherwise specified in this permit, and the CEMS protocol approved by the District. [Rules 69.3, 69.3.1, 

and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

69. The CEMS shall be in operation in accordance with the District approved CEMs protocol at all times 

when the turbine is in operation a copy of the District approved CEMS monitoring protocol shall be 
Proposed Conditions Page 12 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

maintained on site and made available to District personnel upon request. [Rules 69.3, 69.3.1, and 

20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

70. When the CEMS is not recording data and the combustion turbine is operating, hourly NOx emissions 

for purposes of annual emission calculations shall be determined in accordance with 40 CFR 75 Subpart 

C. Additionally, hourly CO emissions for annual emission calculations shall be determined using CO 

emission factors to be determined from source test emission factors, recorded CEMS data, and fuel 

consumption data, in terms of pounds per hour of CO for the gas turbine. Emission calculations used to 

determine hourly emission rates shall be reviewed and approved by the District, in writing, before the 

hourly emission rates are incorporated into the CEMS emission data. [Rules 20.3(d)(3) and 21 and 40 

CFR Part 75] 

71. Any violation of any emission standard as indicated by the CEMS shall be reported to the District's 

compliance division within 96 hours after such occurrence. [Rule 19.2] 

72. The CEMS shall be maintained and operated, and reports submitted, in accordance with the 

requirements of rule 19.2 Sections (d), (e), (f) (1), (f) (2), (f) (3), (f) (4) and (f) (5), and a CEMS protocol 

approved by the District. [Rule 19.2] 

73. Except for changes that are specified in the initial approved CEMS protocol or a subsequent revision to 

that protocol that is approved in advance, in writing by the District, the District shall be notified in 

writing at least thirty (30) calendar days prior to any planned changes made in the CEMS or Data 

Acquisition and Handling System (including the programmable logic controller) software which affects 

the value of data displayed on the CEMS / DAHS monitors with respect to the parameters measured by 

their respective sensing devices or any planned changes to the software that controls the ammonia flow 

to the SCR. Unplanned or emergency changes shall be reported within 96 hours. [Rules 69.3, 69.3.1, 

and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

74. At least 90 calendar days prior to the Initial Emissions Source Test , the applicant shall submit a 

monitoring protocol to the District for written approval which shall specify a method of determining the 

CO/VOC surrogate relationship that shall be used to demonstrate compliance with all VOC emission 

limits. This protocol can be provided as part of the Initial Source Test Protocol. [Rule 20.3(d)(1)] 

75. Fuel flowmeters shall be installed and maintained to measure the fuel flow rate, corrected for 

temperature and pressure, to each combustion turbine. Correction factors and constants shall be 

maintained on site and made available to the District upon request. The fuel flowmeters shall meet the 

applicable quality assurance requirements of 40 CFR Part 75, Appendix D, and Section 2.1.6. [Rules 

69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

76. Each combustion turbine shall be equipped with continuous monitors to measure, calculate and record 

the following operational characteristics: 

A. Hours of operation, in hours; 

B. Natural gas flow rate to the combustion turbine, in standard cubic feet per hour; 

C. Total heat input to the combustion turbine based the fuels higher heating value, in million 

British thermal units per hour (MMBtu/hr); 

D. Higher heating value of the fuel on an hourly basis, in million British thermal units per 

standard cubic foot (MMBtu/scf); 

E. Stack exhaust gas temperature, in degrees Fahrenheit; 
Proposed Conditions Page 13 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

F. Combustion turbine energy output in megawatts hours (MWh); and 

G. Steam turbine energy output in megawatts hours (MWh). 

The monitors shall be installed, calibrated, and maintained in accordance with a turbine operation 

monitoring protocol, which may be part of the CEMS protocol, approved by the District, which shall 

include any relevant calculation methodologies. The monitors shall be in full operation at all times 

when the combustion turbine is in operation. Calibration records for the continuous monitors shall be 

maintained on site and made available to the District upon request. [Rules 69.3, 69.3.1, and 20.3(d)(1) 

and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

77. At least 90 calendar days prior to initial startup of the each combustion turbine, the applicant shall 

submit a turbine monitoring protocol to the District for written approval. This may be part of the CEMS 

protocol. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

78. Operating logs or Data Acquisition and Handling System (DAHS) records shall be maintained to record 

the beginning and end times and durations of all startups, shutdowns, and tuning periods to the nearest 

minute, quantity of fuel used (in each clock hour, calendar month, and 12 calendar month period in 

standard cubic feet); hours of daily operation; and total cumulative hours of operation during each 

calendar year. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 

75] 

Commissioning and Shakedown

79. Before the end of the commissioning period for each combustion turbine, the applicant shall install postcombustion air pollution control equipment on that turbine to minimize NOx and CO emissions. Once 

installed, the post-combustion air pollution control equipment shall be maintained in good condition and 

shall be in full operation at all times when the turbine is combusting fuel and the air pollution control 

equipment is at or above its minimum operating temperature. [Rule 20.3(d)(1)] 

80. Thirty calendar days after the end of the commissioning period for each combustion turbine, the 

applicant shall submit a written progress report to the District. This report shall include, a minimum, the 

date the commissioning period ended, the periods of startup and shutdown, the emissions of NOx and 

CO during startup and shutdown, and the emissions of NOx and CO during steady state operation. This 

report shall also detail any turbine or emission control equipment malfunction, upset, repairs, 

maintenance, modifications, or replacements affecting emissions of air contaminants that occurred 

during the commissioning period. All of the following continuous monitoring information shall be 

reported for each minute and averaged over each hour of operation: 

A. Concentration of oxides of nitrogen (NOX) uncorrected and corrected to 15% oxygen, in 

parts per million (ppmvd); 

B. Concentration of carbon monoxide (CO) uncorrected and corrected to 15% oxygen, in 

parts per million (ppmvd); 

C. Percent oxygen (O2) in the exhaust gas; 

D. Mass emissions of oxides of nitrogen (NOX), in pounds; 

E. Cumulative mass emissions of oxides of nitrogen (NOX) in each startup and shutdown 

period, in pounds; 

F. Cumulative mass emissions of carbon monoxide (CO) in each startup and shutdown 

period, in pounds 

G. Mass emissions of carbon monoxide (CO), in pounds; 
Proposed Conditions Page 14 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

H. Total heat input to the combustion turbine based on the fuel’s higher heating value, in 

million British thermal units per hour (MMBtu/hr); 

I. Higher heating value of the fuel on an hourly basis, in million British thermal units per 

standard cubic foot (MMBtu/scf); 

J. Gross electrical power output of the turbine, in megawatts hours (MWh) for each hour; 

and 

K. SCR inlet temperature, in degrees Fahrenheit; and 

L. Stack exhaust gas temperature, in degrees Fahrenheit. 

The hourly average information shall be submitted in writing and in an electronic format approved by 

the District. The minute-by-minute information shall be submitted in an electronic format approved by 

the District. [Rules 69.3, 69.3.1, 20.3(d)(1)and 20.3(d)(2)] 

81. The three utility boilers described on District Permits to Operate No. 791, 792, and 793 shall not operate 

at any time one or both combustion turbines are operating. [Rules 20.3(d)(3), 20.3(d)(8) and 21 and 40 

CFR §52.1] 

82. Beginning with the initial startup of Turbine A, aggregate emissions of oxides of nitrogen (NOx), 

calculated as nitrogen dioxide (NO2); carbon monoxide (CO); volatile organic compounds (VOCs); 

particulate matter less than or equal to 10 microns in diameter (PM10); and oxides of sulfur (SOx), 

calculated as sulfur dioxide (SO2), from Turbine A and the emergency fire pump described in 

Application No. 985748, except emissions or emission units excluded from the calculation of aggregate 

potential to emit as specified in Rule 20.1 (d) (1), shall not exceed the following limits for each rolling 

12-calendar-month period: 

Pollutant Emission Limit, tons per year

i. Oxides of Nitrogen, NOx (calculated as NO2) 36.40 

ii. Carbon Monoxide, CO 169.95 

iii. Volatile Organic Compounds, VOC 12.5 

iv. Particulate Matter Less than 10 Microns, PM10 19.5 

v. Oxides of Sulfur, SOx (calculated as SO2) 2.8 

The aggregate emissions of each pollutant shall include emissions during all times that the equipment is 

operating including, but not limited to, emissions during commissioning, low load operation, startup, 

shutdown, and tuning periods. This condition shall not apply on and after the date Turbine B completes 

its shakedown period. [Rules 20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 

83. Beginning with the date Turbine A completes its shakedown period, aggregate emissions of oxides of 

nitrogen (NOx), calculated as nitrogen dioxide (NO2); carbon monoxide (CO); volatile organic 

compounds (VOCs); particulate matter less than or equal to 10 microns in diameter (PM10); and oxides 

of sulfur (SOx), calculated as SO2, from the three utility boilers described on District Permits to Operate 

No. 791, 792, and 793, shall not exceed the following limits for each rolling 12-calendar-month period: 

Pollutant Emission Limit, tons per year

i. Oxides of Nitrogen, NOx (calculated as NO2) 16.33 

ii. Carbon Monoxide, CO 214.85 

iii. Particulate Matter Less than 2.5 Microns, PM2.5 21.78 

iv. Particulate Matter Less than 10 Microns, PM10 26.91 
Proposed Conditions Page 15 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

The aggregate emissions of each pollutant shall include emissions during all times that the equipment is 

operating including, but not limited to, emissions during startup, shutdown, and tuning periods. [Rules 

20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 

 

84. On and after the date that Turbine B completes its shakedown period, the three utility boilers described 

on District Permits to Operate No. 791, 792, and 793 shall not operate. [Rules 20.3(d)(3), 20.3(d)(8) and 

21 and 40 CFR §52.1] 

85. For each calendar month and each rolling 12-calendar-month period, the applicant shall maintain records 

on a calendar monthly basis, of aggregate mass emissions of NOx (calculated as NO2), CO, and PM10, 

in tons, for Turbine A and the emergency generator described on Application No. 985748, except for 

emissions or emission units excluded from the calculation of aggregate potential to emit as specified in 

Rule 20.1 (d) (1). These records shall be made available for inspection within 15 calendar days after the 

end of each calendar month. [Rules 20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 

86. For each calendar month, the applicant shall maintain records on a calendar monthly basis, of mass 

emissions during each calendar month of NOx (calculated as NO2), CO, PM10, and PM2.5, in tons, 

from each emission unit described on District Permits to Operate No. 791, 792, and 793. . These records 

shall be made available for inspection within 15 calendar days after the end of each calendar month. 

[Rules 20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 

87. For each calendar month and each rolling 12-calendar-month period, the applicant shall maintain records 

on a calendar monthly basis, of aggregate mass emissions of NOx (calculated as NO2), CO, PM10, and 

PM2.5, in tons, for the emission units described in District Permits to Operate No. 791, 792, and 793. 

These records shall be made available for inspection within 15 calendar days after the end of each 

calendar month. [Rules 20.3(d)(3), 20.3(d)(8) and 21 and 40 CFR §52.1] 

88. No later than 18 months before the initial startup of either combustion turbine, the applicant shall 

submit an application to the District for a significant Title V permit modification to limit the aggregate 

emissions of oxides of nitrogen (NOx), calculated as nitrogen dioxide; carbon monoxide (CO); 

particulate matter less than or equal to 10 microns in diameter (PM10); and particulate matter less than 

or equal to 2.5 microns in diameter (PM2.5), from the three utility boilers described on District Permits 

to Operate No. 791, 792, and 793 in each rolling 12-calendar-month period as specified in this permit. 

The application shall include a proposed emission calculation protocol to calculate the emissions from 

each emission unit. Where applicable, this protocol may rely in whole or in part on the CEMS or other 

monitoring protocols required by this permit. [Rules 20.3(d)(3), 20.3(d)(8), 1410, and 21 and 40 CFR 

§52.1] 

89. For each combustion turbine, the applicant shall submit the following notifications to the District and U. 

S. EPA, Region IX: 

A. A notification in accordance with 40 CFR Section 60.7(a)(1) delivered or postmarked not later 

than 30 calendar days after construction has commenced; 

B. A notification in accordance with 40 CFR Section 60.7(a)(3) delivered or postmarked within 

15 calendar days after initial startup; and 

C. An Initial Notification in accordance with 40 CFR Section 63.6145(c) and 40 CFR Section 

63.9(b)(2) submitted no later than 120 calendar days after the initial startup of the turbine. 
Proposed Conditions Page 16 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

[40 CFR Part 60 Subpart KKKK, 40 CFR Part §60.7, 40 CFR Part 63 Subpart YYYY, and 40 CFR Part 

§63.9] 

CONDITIONS FOR EMERGENCY FIRE PUMP ENGINE

90. The engine shall be EPA certified to the 2009 model year or later requirements for emergency fire pump 

engines of 40 CFR Part 60 Subpart IIII, Standards of Performance for Stationary Compression Ignition 

Internal Combustion Engines. [Rule 20.3(d)(1), 40 CFR Part 60 Subpart IIII, and 40 CFR Part 63 

Subpart ZZZZ] 

91. Engine operation for maintenance and testing purposes shall not exceed 50 hours per calendar year. 

(ATCM reportable) [Rule 20.3(d)(1) and 17 CCR §93115] 

92. The engine shall only use CARB Diesel Fuel. [Rules 20.3(d)(1), 69.4.1, and 17 CCR §93115] 

93. Visible emissions including crankcase smoke shall comply with Air Pollution Control District Rule 50. 

[Rule 50] 

94. The equipment described above shall not cause or contribute to public nuisance. [Rule 51] 

95. This engine shall not operate for non-emergency use during the following periods, as applicable: 

A. Whenever there is any school sponsored activity, if engine is located on school grounds or 

B. Between 7:30 and 3:30 PM on days when school is in session, if the engine is located within 500 

feet of, but not on school grounds. 

This condition shall not apply to an engine located at or near any school grounds that also serve as the 

student’s place of residence. (ATCM reportable) [17 CCR §93115] 

96. A non-resettable engine hour meter shall be installed on this engine, maintained in good working order, 

and used for recording engine operating hours. If a meter is replaced, the Air Pollution Control 

District’s Compliance Division shall be notified in writing within 10 calendar days. The written 

notification shall include the following information: 

A. Old meter’s hour reading. 

B. Replacement meter’s manufacturer name, model, and serial number if available and current hour 

reading on replacement meter. 

C. Copy of receipt of new meter or of installation work order. 

 A copy of the meter replacement notification shall be maintained on site and made available to the Air 

Pollution Control District upon request. [Rule 69.4.1, 17 CCR §93115, and 40 CFR Part 60 Subpart IIII] 

97. The owner or operator shall conduct periodic maintenance of this engine and add-on control equipment, 

if any, as recommended by the engine and control equipment manufacturers or as specified by the 

engine servicing company’s maintenance procedure. The periodic maintenance shall be conducted at 

least once each calendar year. [Rule 69.4.1] 
Proposed Conditions Page 17 of 17 November 14, 2008 

Applications No. 985745, 985747, and 985748

98. The owner or operator of the engine shall maintain the following records on site for at least the same 

period of time as the engine to which the records apply is located at the site: 

 A. Documentation shall be maintained identifying the fuel as CARB diesel; 

 B. Manual of recommended maintenance provided by the manufacturer, or maintenance procedures 

specified by the engine servicing company; and 

 C. Records of annual engine maintenance, including the date the maintenance was performed. 

These records shall be made available to the Air Pollution Control District upon request. [Rule 69.4.1] 

99. The owner or operator of this equipment shall maintain a monthly operating log containing, at a 

minimum, the following: 

 

A. Dates and times of engine operation, indicating whether the operation was for maintenance and 

testing purposes or emergency use; and, the nature of the emergency, if known; 

B. Hours of operation for all uses other than those specified above and identification of the nature of 

that use. 

 

 [Rule 69.4.1 and 17 CCR §93115] 
ATTACHMENT 2 

EPA MORRO BAY POWER PLANT PSD DETERMINATION 
Morro Bay Power Plant Modernization Project

US EPA Response to Comments

Proposed Prevention of Significant Deterioration Air Permit

Introduction

On May 17, 2006, the Region 9 office of the United States Environmental Protection

Agency (EPA) requested public comment on a proposed permit for the Prevention of Significant

Deterioration (PSD) of air quality, issued in accordance with 40 CFR § 52.21 and Part 124, to

LSP Mono Bay, LLC, for the construction and operation of the Morro Bay Power Plant

Modernization Project (Modernization Project).

The proposed Modernization Project will consist of two combined cycle gas turbine

block units. Each block unit will be capable of producing 600 MW of electrical power, and will

consist of two 180 MW natural gas-fired turbines, two heat recovery steam generators with duct

burners, one 240 MW steam turbine, and associated air pollution control equipment. The

Modernization Project is subject to federal PSD regulations for particulate matter (PM) and

particulate matter less than 10 microns in aerodynamic diameter (PM 10). Other air emissions

from the proposed project, including PM10, are regulated by the San Luis Obispo Air Pollution

Control District (District), and are subject to District air permits. A timeline of the Mono Bay

PSD Permit Issuance process is shown in Table 1.

During the 30-day public comment period, we received forty-six (46) comments by fax,

electronic and U.S. postal mail, thirty-nine (39) of which requested a public hearing for the

proposed permit. A public hearing was scheduled for October 24, 2006 in Morro Bay, California.

Notice for the hearing was provided to all individuals who submitted comments on the proposed

permit, the District, and representatives of the applicant. Additionally, a notice was published in

three local newspapers on September 20, 2006: The Tribune (San Luis Obispo, California), the

Central Coast Sun Bulletin (Morro Bay, California), and The Bay News (Mono Bay, California).

The public hearing was held at the Veterans Memorial Hall at 209 Surf Street in Morro Bay,

California, from 6:00 — 8:15 PM on Tuesday, October 24, 2006. A transcript and audio tape

recording of the hearing was prepared by Merit Reporting and Video (San Luis Obispo,

California), and a video tape is available through AGP Video (Morro Bay, California) 1 .

The public comment period closed on October 30, 2006. Any documents upon which

EPA relied in reaching a final permit decision, and as referenced in this response to comments,

such as the Ambient Air Quality Impact Report (AAQIR) and PSD application, are contained in

the Administrative Record. An index of the Administrative Record, many documents in it, and

the public hearing transcript, will be made available at www.regulations.gov, linked from the

EPA Region 9 website 2 .

This document represents the official U.S. EPA response to comments received during

the public comment period. Each comment is referenced in this response by number (Table 2).

Table 2 includes only substantive comments related to the PSD permit, and does not include

' http://www.slo-span.org/cgi-bin/media.pl?folder—SM

2 http://www.epa.goviregion9/air/permit/r9-permits-issued.html

1 of 21

Morro Bay Power Plant Modernization Project
 

US EPA Response to Comments
 

Proposed Prevention of Significant Deterioration Air Permit
 

Introduction 

On May 17,2006, the Region 9 office of the United States Environmental Protection 

Agency (EPA) requested public comment on a proposed permit for the Prevention of Significant 

Deterioration (PSD) of air quality, issued in accordance with 40 CFR § 52.21 and Part 124, to 

LSP Morro Bay, LLC, for the construction and operation of the Morro Bay Power Plant 

Modernization Project (Modernization Project). 

The proposed Modernization Project will consist of two combined cycle gas turbine 

block units. Each block unit will be capable of producing 600 MW of electrical power, and will 

consist of two 180 MW natural gas-fired turbines, two heat recovery steam generators with duct 

burners, one 240 MW steam turbine, and associated air pollution control equipment. The 

Modernization Project is subject to federal PSD regulations for particulate matter (PM) and 

particulate matter less than 10 microns in aerodynamic diameter (PM IO) . Other air emissions 

from the proposed project, including PM IO, are regulated by the San Luis Obispo Air Pollution 

Control District (District), and are subject to District air permits. A timeline of the Morro Bay 

PSD Permit Issuance process is shown in Table 1. 

During the 30-day public comment period, we received forty-six (46) comments by fax, 

electronic and U.S. postal mail, thirty-nine (39) of which requested a public hearing for the 

proposed permit. A public hearing was scheduled for October 24,2006 in Morro Bay, California. 

Notice for the hearing was provided to all individuals who submitted comments on the proposed 

permit, the District, and representatives of the applicant. Additionally, a notice was published in 

three local newspapers on September 20,2006: The Tribune (San Luis Obispo, California), the 

Central Coast Sun Bulletin (Morro Bay, California), and The Bay News (Morro Bay, California). 

The public hearing was held at the Veterans Memorial Hall at 209 Surf Street in Morro Bay, 

California, from 6:00 - 8:15 PM on Tuesday, October 24,2006. A transcript and audio tape 

recording of the hearing was prepared by Merit Reporting and Video (San Luis Obispo, 

California), and a video tape is available through AGP Video (Morro Bay, California)". 

The public comment period closed on October 30, 2006. Any documents upon which 

EPA relied in reaching a final permit decision, and as referenced in this response to comments, 

such as the Ambient Air Quality Impact Report (AAQIR) and PSD application, are contained in 

the Administrative Record. An index of the Administrative Record, many documents in it, and 

the public hearing transcript, will be made available at www.regulations.gov, linked from the 

EPA Region 9 website'. 

This document represents the official U.S. EPA response to comments received during 

the public comment period. Each comment is referenced in this response by number (Table 2). 

Table 2 includes only substantive comments related to the PSD permit, and does not include 

I http://www.slo-span.org/cgi-bin/media.pl?folder=SM 

2 http://www.epa.gov/region9/air/permit/r9-permits-issued.html 

lof21 
correspondence that we received which only requested a public hearing. Two comments were

generally in favor of the Modernization Project (# 17, 37), and the remaining comments raised

various concerns regarding the PSD permit and the health impacts of PM10. Because many of

these comments contain common themes, they are paraphrased and grouped by issue in this

response.

Table 1: Timeline of Significant Events in the Morro Bay Modernization Project Application

Event Date

Duke Energy Submits Application for Certification (AFC) to the California

Energy Commission (CEC) October 23, 2000

EPA Receives New PSD Permit Application November 1, 2000

San Luis Obispo Air Pollution Control District Issues Final Determination of

Compliance for District Application #3083 August 30, 2001

CEC Issues Part 1 of Final Staff Assessment November 15, 2001

EPA Requests Concurrence from U.S. Fish and Wildlife Service (FWS) that

Modernization Project Not Likely to Adversely Affect Any Federally Listed

Species

November 27, 2001

EPA Requests Concurrence from National Marine Fisheries Service (NMFS)

that Modernization Project Not Likely to Adversely Affect Any Federally

Listed Species

November 30, 2001

CEC Issues Part 2 of Final Staff Assessment December 19, 2001

CEC Issues Part 3 of Final Staff Assessment April 25, 2002

NMFS Concludes Informal Consultation with EPA May 17, 2002

EPA Requests ESA Consultation with FWS April 10, 2003

CEC Approves Morro Bay Modernization Project August 2, 2004

FWS Issues Biological Opinion to EPA May 23, 2005

Duke Energy Submits Addendum to EPA to Implement Conditions of FWS

Biological Opinion June 23, 2005

Ownership of Morro Bay Power Plant changed from Duke Energy Morro

Bay, LLC to LSP Morro Bay, LLC May 4, 2006

EPA Proposes PSD Permit for Modernization Project and Opens Public

Comment Period May 17, 2006

EPA holds Public Hearing in Mono Bay, California October 24, 2006

Public Comment Period for Proposed PSD Permit Closes October 30, 2006

2 of 21

correspondence that we received which only requested a public hearing. Two comments were 

generally in favor of the Modernization Project (# 17,37), and the remaining comments raised 

various concerns regarding the PSD permit and the health impacts of PMIO. Because many of 

these comments contain common themes, they are paraphrased and grouped by issue in this 

response. 

! Table 1: Timeline of Significant Events in the Morro Bay Modernization Project Application 

Event I 

Duke Energy Submits Application for Certification (AFC) to the California
 

Energy Commission (CEC)
 f--------------­

EPA Receives New PSD Permit Application 

San Luis Obispo Air Pollution Control District Issues Final Determination of 

I Compliance for District Application #3083 L
 CEC Issues Part 1 of Final Staff Assessment 

I EPA Requests Concurrence from U.S. Fish and Wildlife Service (FWS) that 

Modernization Project Not Likely to Adversely Affect Any Federally Listed 

I Species 

EPA Requests Concurrence from National Marine Fisheries Service O\JMFS) 

I that Modernization Project Not Likely to Adversely Affect Any Federally 

Listed Species I 

I CEC Issues Part 2 of Final Staff Assessment 

Date
 

October 23,2000
 

November 1,2000
 

August 30, 2001
 

November 15,2001
 

November 27, 2001
 

November 30, 2001
 

December 19,2001
 

CEC Issues Part 3 of Final Staff Assessment April 25, 2002 1------------+-----------1
 NMFS Concludes Informal Consultation with EPA May 17,2002 

EPA Requests ESA Consultation with FWS April 10, 2003 1-------------+-----­ CEC Approves Morro Bay Modernization Project August 2, 2004 

FWS Issues Biological Opinion to EPA 

f------------­

Duke Energy Submits Addendum to EPA to Implement Conditions of FWS
 

Biological Opinion
 

Ownership of Morro Bay Power Plant changed from Duke Energy Morro
 

Bay, LLC to LSP Morro Bay, LLC
 

EPA Proposes PSD Permit for Modernization Project and Opens Public
 

Comment Period
 f-----------------­

EPA holds Public Hearing in Morro Bay, California
 

Public Comment Period for Proposed PSD Permit Closes
 

May 23, 2005 

June 23, 2005 

May 4,2006 

May 17,2006
 

October 24, 2006
 

October 30,2006
 

20f21 
Table 2: Reference Numbers for Comments on the Mono Bay Power Plant (MBPP)

No. Commenter Format3

Date

1 Tacker, Julie A June 14, 2006

2 Dorfman, Barry A; B June 14; October 24, 2006

3 McCurdy, Jack A June 14, 2006

4 Beebe, Curt A June 15, 2006

5 Massa-Gooch, Shelley A June 15, 2006

6 Perlstein, Abe A June 15, 2006

7 Wiley, Susan A June 15, 2006

8 Watson, Elaine A June 17, 2006

9 Smith, Marie A June 20; Sept. 23; Oct. 19, 2006

10 Fram, Joe A July 11, 2006

11 Heinemann, Susan A; C July 23; October 24, 2006

12 Coastal Alliance on Plant Expansion (CAPE) D; A September 28; October 30, 2006

13 Savage, Arline A October 24, 2006

14 Ewing, Roger B October 24, 2006

15 Johnson, Colleen B October 24, 2006

16 Sullivan, Nelson B October 24, 2006

17 Johnson, Garry B October 24, 2006

18 Carter, Joan B October 24, 2006

19 Hill, Phil B October 24, 2006

20 LaPlante, Pauline B October 24, 2006

21 Crotzer, Shoosh B October 24, 2006

22 Crotzer, Colby B October 24, 2006

23 Churney, Bonita B October 24, 2006

24 Lucas, Michael B October 24, 2006

25 Cole, Robin B October 24, 2006

26 Risley, Peter B October 24, 2006

27 Davis, Mandy B October 24, 2006

28 Sadowski, Richard B October 24, 2006

29 Nelson, David B October 24, 2006

30 Groot, Henriette B October 24, 2006

31 Nelson, Monique B October 24, 2006

32 Racano, Joey B October 24, 2006

33 Beetham, Margaret 

Bruton, Marla Jo

B

B

October 24, 2006

34 October 24, 2006

35 Martony, Bill B October 24, 2006

36 Dorfman, Barry B October 24, 2006

37 Cinowalt, Roy B; C October 24, 2006

38 DeMeritt, Melody B; C; A Oct. 24; Oct. 24; Oct. 29, 2006

39 Merrill, Lynda C October 24, 2006

40 Nelson, David C October 24, 2006

41 Taylor, Keith C October 24, 2006

42 Winter, H. Leabah C October 24, 2006

43 Purcell-McWilliams, Catherine A October 30, 2006

44 San Luis Bay Chapter of the Surfrider Foundation A October 30, 2006

45 Santa Lucia Chapter of the Sierra Club A October 30, 2006

46 CAPE A October 30, 2006

3 A = electronic mail, B = Oral Comments at Hearing, C = Written Comments at Hearing, D = U.S. Mail

3 of21

5

10

15

20

25

30

35

40

45

i 

I Table 2: Reference Numbers for Comments on the Morro Bay Power Plant (MBPP) 

No. Commenter 

I Tacker, Julie 

2 Dorfman, Barry 

3 McCurdy, Jack 

4 Beebe, Curt 

Massa-Gooch, Shelley 

6 Perlstein, Abe 

7 Wiley, Susan 

8 Watson, Elaine 

9 Smith, Marie 

Fram, Joe 

11 Heinemann, Susan 

12 Coastal Alliance on Plant Expansion (CAPE) 

13 Savage, Arline 

14 Ewing, Roger 

Johnson, Colleen 

16 Sullivan, Nelson 

17 Johnson, Garry 

18 Carter, Joan 

19 Hill, Phil 

LaPlante, Pauline 

21 Crotzer, Shoosh 

22 Crotzer, Colby 

23 Churney, Bonita 

24 Lucas, Michael 

Cole, Robin 

26 Risley, Peter 

27 Davis, Mandy 

28 Sadowski, Richard 

29 Nelson, David 

Groot, Henriette 

31 Nelson, Monique 

32 Racano, Joey 

33 Beetham, Margaret 

34 Bruton, Marla Jo 

Martony, Bill 

36 Dorfman, Barry 

37 Cinowalt, Roy 

38 DeMeritt, Melody 

39 Merrill, Lynda 

Nelson, David 

41 Taylor, Keith 

42 Winter, H. Leabah 

43 Purcell-McWilliams, Catherine 

44 San Luis Bay Chapter of the Surfrider Foundation 

Santa Lucia Chapter of the Sierra Club 

46 CAPE 

Format'
 

A
 

A;B
 

A
 

A
 

A
 

A
 

A
 

A
 

A
 

A
 

A;C
 

D;A
 

A
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B
 

B;C
 

B;C;A
 

C
 

C
 

C
 

C
 

A
 

A
 

A
 

A
 

Date
 

June 14,2006
 

June 14; October 24,2006
 

June 14,2006
 

June 15,2006
 

June 15,2006
 

June 15,2006
 

June 15, 2006
 

June 17,2006
 

June 20; Sept. 23; Oct. 19,2006
 

July 11, 2006
 

July 23; October 24,2006
 

September 28; October 30, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24,2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

Oct. 24; Oct. 24; Oct. 29, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 24, 2006
 

October 30, 2006
 

October 30,2006
 

October 30, 2006
 

October 30, 2006
 

3 A = electronic mail, B = Oral Comments at Hearing, C = Written Comments at Hearing, D = U.S. Mail 

30f21 

I 
Section A: Pre- and post-project emission rate estimates

1. PM10 emission rates of 11 and 13.3 lb/hr estimated by Sierra Research are too low because

they were determined using inappropriate EPA test methods. Emission rates of condensable

particulate were underestimated by Sierra Research because they were based on EPA

Method 8, which is not approved for the measurement of condensable fraction of PM 10. (#

12, 23, 29, 31, 43-46)

Response to A-1:

Because EPA Method 8 is an approved test method for sulfuric acid

mist, but not for the measurement of condensable particulates, commenters

were concerned that emission limits, and thus air quality impacts, are

underestimated by the applicant. However, it is noted on pagel4 of the

February 6, 2002 transcript from the CEC Evidentiary Hearing 4 that PM10

emission limits proposed by Sierra Research were not based on actual

source tests using EPA Method 8. Rather, the PM10 emission rates

estimated by Sierra Research were based on engineering experience and

judgment.

The proposed PSD permit requires performance tests pursuant to 40

CFR §60.8 (60 days after achieving maximum load but no later than 180

days after initial startup, and annually thereafter) for PM10 from the turbine

exhaust stacks. The PSD permit does not allow the use of EPA Method 8

for condensable particulates; rather, the permit requires EPA Method 5 for

filterable particulate matter (front-half) and EPA Method 202 for

condensable particulates (back-half). Specifically, Method 202 test

methodology must include a) one hour nitrogen purge b) the alternative

procedure described in paragraph 8.1 to neutralize the sulfuric acid c)

evaporation of the last 1 ml of the inorganic fraction by air drying

following evaporation of the bulk of the impinger water in a 105 °C oven

as described in the first sentence of section 5.3.2.3 of Method 202. The

conditional test methods CTM-039 or 040, listed on the EPA Emission

Measurement Center website: http://www.epa.govittn/emc/ctm.html may

be used in lieu of Method 202. The proposed PSD permit has been

modified to include these test method specifications in the final permit.

Additionally, EPA is currently assessing and improving available test

methods for condensable particulate matter.

The proposed emission rates of 11 and 13.3 lb/hr are consistent

with emission limits for similar facilities listed in the EPA

RACT/BACT/LAER Clearinghouse (See Response to B-1 and Table 3).

Additionally, the proposed PM10 emission rates for each turbine block unit,

converted into PM10 emission factors, i.e., PM10 production per unit energy

(0.0054 and 0.0065 lb/MMBtu), are comparable to emission factors for

4 http://www.energy.ca.gov/sitingcases/morrobay/documents/index.html

4 of 21

Section A: Pre- and post-project emission rate estimates 

1.	 PMiO emission rates of11 and 13.3 lb/hr estimated by Sierra Research are too low because 

they were determined using inappropriate EPA test methods. Emission rates ofcondensable 

particulate were underestimated by Sierra Research because they were based on EPA 

Method 8, which is not approved for the measurement ofcondensable fraction ofPMiO. (# 

12, 23, 29, 31, 43-46) 

Response to A-I: 

Because EPA Method 8 is an approved test method for sulfuric acid 

mist, but not for the measurement of condensable particulates, commenters 

were concerned that emission limits, and thus air quality impacts, are 

underestimated by the applicant. However, it is noted on page14 of the 

February 6, 2002 transcript from the CEC Evidentiary Hearing" that PM IO 

emission limits proposed by Sierra Research were not based on actual 

source tests using EPA Method 8. Rather, the PM IO emission rates 

estimated by Sierra Research were based on engineering experience and 

judgment. 

The proposed PSD permit requires performance tests pursuant to 40 

CFR §60.8 (60 days after achieving maximum load but no later than 180 

days after initial startup, and annually thereafter) for PM IO from the turbine 

exhaust stacks. The PSD permit does not allow the use of EPA Method 8 

for condensable particulates; rather, the permit requires EPA Method 5 for 

filterable particulate matter (front-half) and EPA Method 202 for 

condensable particulates (back-half). Specifically, Method 202 test 

methodology must include a) one hour nitrogen purge b) the alternative 

procedure described in paragraph 8.1 to neutralize the sulfuric acid c) 

evaporation of the last 1 ml of the inorganic fraction by air drying 

following evaporation of the bulk of the impinger water in a 105°C oven 

as described in the first sentence of section 5.3.2.3 of Method 202. The 

conditional test methods CTM-039 or 040, listed on the EPA Emission 

Measurement Center website: http://www.epa.gov/ttn/emc/ctm.html may 

be used in lieu of Method 202. The proposed PSD permit has been 

modified to include these test method specifications in the final permit. 

Additionally, EPA is currently assessing and improving available test 

methods for condensable particulate matter. 

The proposed emission rates of 11 and 13.3 lb/hr are consistent 

with emission limits for similar facilities listed in the EPA 

RACTIBACT/LAER Clearinghouse (See Response to B-1 and Table 3). 

Additionally, the proposed PM IO emission rates for each turbine block unit, 

converted into PM IO emission factors, i.e., PMIO production per unit energy 

(0.0054 and 0.0065 Ib/MMBtu), are comparable to emission factors for 

4 http://www.energy.ca. gOY1sitingcases/morrobay 1docum entslindex.html 

40f21 
total PM (sum of filterable and condensable PM) from natural gas fired

turbines (0.0066 lb/MMBtu), reported in Chapter 3-1 of AP 42, the EPA

compilation of emission factors.

PM10 emission limits on the basis of lb/hr and ton per year (tpy) are

separately enforceable conditions in the PSD permit (Permit Condition

IX.B). Therefore, if the facility exceeds the PSD permit limits of 11 and

13.3 lb/hr without and with duct burner firing, or 203.2 tpy PM10, the

facility would be out of compliance and subject to enforcement action.

2. The calculation of the change in emissions resulting from the project uses a baseline period

(1998 — 2000) that is not representative of normal operating conditions. The baseline period

includes a period of high energy production, fueled by the California Energy Crisis, and thus

improperly inflates the actual emissions used to calculate the net emissions increase for the

purpose of PSD applicability. The MBPP has most recently operated at reduced capacity.

This recent period is the appropriate baseline period to use for the PSD analysis. (# 12, 29,

31, 34, 43-46)

Response to A-2:

The PSD permit application submitted by Sierra Research, Inc. in

November 2000 uses a 24-month baseline period from August 1998 — July

2000. Sierra Research additionally provided emissions data from January

1997 — July 2000. These data (Appendix 6.2-1.1) show a general pattern of

higher criteria pollutant emissions during the late summer to early fall

months. The competitive electric market in the State of California began on

March 31, 1998, and was operated by the California Independent Systems

Operator (ISO) and the Power Exchange (now bankrupt). According to the

ISO, the competitive market began smoothly with electricity prices

seemingly just and reasonable, until May 2000, when the first signs of a

market crisis emerged5 . The ISO reports that the California energy crisis

continued until about May 2001. The baseline period used for the PSD

applicability emissions calculations was August 1998 — July 2000, thus, the

end of the 24-month baseline coincides with roughly 3 months at the

beginning of the energy crisis in California.

Reform rules to the New Source Review (NSR) program, which

includes the PSD regulations, promulgated on December 31, 2002 (67

Federal Register 80,186), and implemented March 3, 2003, codified

existing policy for calculating "baseline actual emissions" (40 CFR

§52.21(b)(48)(i)):

"For any electric utility steam generating unit, baseline actual emission

means the average rate, in tons per year, at which the unit actually emitted

http://www.caiso.com/docs/09003a6080/14/c5/09003a608014c508.pdf

5 of 21

total PM (sum of filterable and condensable PM) from natural gas fired 

turbines (0.0066lb/MMBtu), reported in Chapter 3-1 of AP 42, the EPA 

compilation of emission factors. 

PM IO emission limits on the basis oflb/hr and ton per year (tpy) are 

separately enforceable conditions in the PSD permit (Permit Condition 

IX.B). Therefore, if the facility exceeds the PSD permit limits of 11 and 

13.3 lb/hr without and with duct burner firing, or 203.2 tpy PMIO, the 

facility would be out of compliance and subject to enforcement action. 

2.	 The calculation ofthe change in emissions resultingfrom the project uses a baseline period 

(1998 - 2000) that is not representative ofnormal operating conditions. The baseline period 

includes a period ofhigh energy production, fueled by the California Energy Crisis, and thus 

improperly inflates the actual emissions used to calculate the net emissions increase for the 

purpose ofPSD applicability. The MBPP has most recently operated at reduced capacity. 

This recent period is the appropriate baseline period to use for the PSD analysis. (# 12, 29, 

31, 34, 43-46) 

Response to A-2: 

The PSD permit application submitted by Sierra Research, Inc. in 

November 2000 uses a 24-month baseline period from August 1998 - July 

2000. Sierra Research additionally provided emissions data from January 

1997 - July 2000. These data (Appendix 6.2-1.1) show a general pattern of 

higher criteria pollutant emissions during the late summer to early fall 

months. The competitive electric market in the State of California began on 

March 31, 1998, and was operated by the California Independent Systems 

Operator (ISO) and the Power Exchange (now bankrupt). According to the 

ISO, the competitive market began smoothly with electricity prices 

seemingly just and reasonable, until May 2000, when the first signs of a 

market crisis emerged", The ISO reports that the California energy crisis 

continued until about May 2001. The baseline period used for the PSD 

applicability emissions calculations was August 1998 - July 2000, thus, the 

end of the 24-month baseline coincides with roughly 3 months at the 

beginning ofthe energy crisis in California. 

Reform rules to the New Source Review (NSR) program, which 

includes the PSD regulations, promulgated on December 31, 2002 (67 

Federal Register 80,186), and implemented March 3, 2003, codified 

existing policy for calculating "baseline actual emissions" (40 CFR 

§52.21 (b)(48)(i)): 

"For any electric utility steam generating unit, baseline actual emission 

means the average rate, in tons per year, at which the unit actually emitted 

5 hnp://www.caiso.comldocs/09003a6080/14/c5/09003a608014c508.pdf 

50f21 
the pollutant during any consecutive 24-month period selected by the

owner or operator within the 5-year period immediately preceding when

the owner or operator begins actual construction of the project. The

Administrator shall allow the use of a different time period upon a

determination that it is more representative of normal source operation."

Based on the NSR Reform regulations, in determining the

appropriate baseline period for an electric utility steam generating unit, the

source must consider a consecutive 24-month period within the 5-year

period immediately preceding actual construction. The source may select

and EPA may allow the use of a different time period if such period is

determined to be more representative of normal source operation.

The MBPP submitted their Application for Certification (AFC) to

the California Energy Commission (CEC), and their PSD permit

application to EPA, in November 2000 (see Table 1), using a consecutive

24-month baseline period of August 1988 — July 2000, which was within

the 5-year period preceding the scheduled construction date. Although the

baseline period chosen by MBPP was appropriate at the time the

application was submitted in 2000, because the PSD permitting process

has, to date, spanned 7 years, the baseline period must be re-examined,

taking into account the 2002 NSR Reform regulations. Assuming actual

construction on the project begins in 2007, the five year period, within

which to choose the 24-month baseline, incorporates 2002 — 2006.

Beginning in September 2002 — December 2006, MBPP operated at

significantly reduced capacity, with a corresponding significant reduction

in emissions. During this time, MBPP typically operated only two of the

four boilers. Because the boilers are old (circa 1950's -1960's), and MBPP

had applied in 2000 to replace them with new combined cycle gas turbines,

the reduced operation of the old boilers from 2002 - 2006 is not

representative of "normal source operation", as normal operation would not

occur at such significantly reduced capacity (in anticipation of boiler

replacement), for such an extended period of time. By September 2002,

when reduced operation of the boilers first began, the CEC had already

issued their final approval of the Modernization Project in their three part

Final Staff Assessments (April 2002, see Table 1). At that time MBPP did

not expect that the EPA PSD permitting process, and the associated Section

7 ESA Consultation with the U.S. Fish and Wildlife Service, would require

an additional 4 — 5 years. Therefore, MBPP determined that reduced

operation of the boilers, in anticipation of their pending replacement, from

September 2002 — December 2006, is not representative of normal source

operation and hence indicated their desire to select a baseline period

outside of the 2002 — 2006 period.

6 of 21

the pollutant during any consecutive 24-month period selected by the 

owner or operator within the 5-year period immediately preceding when 

the owner or operator begins actual construction ofthe project. The 

Administrator shall allow the use ofa different time period upon a 

determination that it is more representative ofnormal source operation. " 

Based on the NSR Reform regulations, in determining the 

appropriate baseline period for an electric utility steam generating unit, the 

source must consider a consecutive 24-month period within the 5-year 

period immediately preceding actual construction. The source may select 

and EPA may allow the use of a different time period if such period is 

determined to be more representative of normal source operation. 

The MBPP submitted their Application for Certification (AFC) to 

the California Energy Commission (CEC), and their PSD permit 

application to EPA, in November 2000 (see Table 1), using a consecutive 

24-month baseline period of August 1988 - July 2000, which was within 

the 5-year period preceding the scheduled construction date. Although the 

baseline period chosen by MBPP was appropriate at the time the 

application was submitted in 2000, because the PSD permitting process 

has, to date, spanned 7 years, the baseline period must be re-examined, 

taking into account the 2002 NSR Reform regulations. Assuming actual 

construction on the project begins in 2007, the five year period, within 

which to choose the 24-month baseline, incorporates 2002 - 2006. 

Beginning in September 2002 - December 2006, MBPP operated at 

significantly reduced capacity, with a corresponding significant reduction 

in emissions. During this time, MBPP typically operated only two of the 

four boilers. Because the boilers are old (circa 1950's -1960's), and MBPP 

had applied in 2000 to replace them with new combined cycle gas turbines, 

the reduced operation of the old boilers from 2002 - 2006 is not 

representative of "normal source operation", as normal operation would not 

occur at such significantly reduced capacity (in anticipation of boiler 

replacement), for such an extended period of time. By September 2002, 

when reduced operation of the boilers first began, the CEC had already 

issued their final approval of the Modernization Project in their three part 

Final Staff Assessments (April 2002, see Table 1). At that time MBPP did 

not expect that the EPA PSD permitting process, and the associated Section 

7 ESA Consultation with the U.S. Fish and Wildlife Service, would require 

an additional 4 - 5 years. Therefore, MBPP determined that reduced 

operation of the boilers, in anticipation of their pending replacement, from 

September 2002 - December 2006, is not representative of normal source 

operation and hence indicated their desire to select a baseline period 

outside of the 2002 - 2006 period. 

60f21 
Because EPA shall allow use of a different time period upon a

determination that it is more representative of normal source operation, we

examined emissions of CO and NQ from the MBPP over January 1997 —

December 2006, a 10-year period preceding the revised construction date

of 2007. Although we did not have VOC and PK() data for August 2000 —

December 2006, NOx is an appropriate indicator for VOC and PK ° trends

because emissions of VOC and PK° correlated well with NO (R2 = 0.93)

over the period that we had data for all pollutants (January 1997 — July

2000). To determine a representative 24-month baseline within the 10-year

look-back period, we calculated the average annual emissions based on a

24-month rolling average over the entire 10-year period from January 1997

— December 2006. We then selected the 24-month baseline period where

actual annual emissions data most closely match the 10-year average. It is

important to note that the average determined from this methodology still

accounts for the "highs and lows" of operation during the 10-year period,

encompassing both the energy crisis from mid-2000 to mid-2001, and the

recent extended period of reduced operation from mid-2002 to late-2006.

From this analysis, we determined that the period from June 1998 — May

2000 is the most representative period of normal operation over the 10-year

period. This represents a two month shift backwards in time compared to

the baseline period used by the facility in their original application (August

1988 — July 2000).

Using this most representative baseline period, while the proposed

emissions increase from the project (baseline actual emissions to potential

to emit) is higher, it has the same result, relative to PSD applicability, as

the baseline period selected by MBPP. In other words, using the 24-month

baseline period EPA has determined to be most representative of the

previous 10-years, the Modernization Project still triggers PSD only for

PK° emissions, and does not trigger PSD for 502, CO, NO N , and VOC.

Therefore, although a different baseline period is more appropriate than the

one used by MBPP (since the 5-year pre-construction window has shifted),

it does not impact the PSD applicability determination. Additionally, if

ambient air quality models used the lower baseline emission rate from the

more representative 24-month baseline period (June 1998 — May 2000), the

results would show that the Modernization Project has a lower impact on

air quality than projected in the original Ambient Air Quality Impact

Analysis (See Response to Comment C-4).

3. The PSD analysis fails to consider Emission Reduction Credits, or "offsets" that were used

to show compliance with state and local air quality standards, despite the fact that emissions

would still increase. These offsets hide the real amount of emissions that the public would be

exposed to. (# 44, 46)

Response to A-3:

7 of 21

Because EPA shall allow use of a different time period upon a 

determination that it is more representative of normal source operation, we 

examined emissions of CO and NO x from the MBPP over January 1997 ­

December 2006, a 1O-year period preceding the revised construction date 

of2007. Although we did not have VOC and PM JO data for August 2000­

December 2006, NO x is an appropriate indicator for VOC and PMlO trends 

because emissions ofVOC and PM lO correlated well with NOx (R2 = 0.93) 

over the period that we had data for all pollutants (January 1997 - July 

2000). To determine a representative 24-month baseline within the 10-year 

look-back period, we calculated the average annual emissions based on a 

24-month rolling average over the entire 1O-year period from January 1997 

- December 2006. We then selected the 24-month baseline period where 

actual annual emissions data most closely match the 10-year average. It is 

important to note that the average determined from this methodology still 

accounts for the "highs and lows" of operation during the 10-year period, 

encompassing both the energy crisis from mid-2000 to mid-200!, and the 

recent extended period of reduced operation from mid-2002 to late-2006. 

From this analysis, we determined that the period from June 1998 - May 

2000 is the most representative period of normal operation over the 10-year 

period. This represents a two month shift backwards in time compared to 

the baseline period used by the facility in their original application (August 

1988 - July 2000). 

Using this most representative baseline period, while the proposed 

emissions increase from the project (baseline actual emissions to potential 

to emit) is higher, it has the same result, relative to PSD applicability, as 

the baseline period selected by MBPP. In other words, using the 24-month 

baseline period EPA has determined to be most representative of the 

previous 10-years, the Modernization Project still triggers PSD only for 

PM lO emissions, and does not trigger PSD for S02, CO, NO x, and VOC. 

Therefore, although a different baseline period is more appropriate than the 

one used by MBPP (since the 5-year pre-construction window has shifted), 

it does not impact the PSD applicability determination. Additionally, if 

ambient air quality models used the lower baseline emission rate from the 

more representative 24-month baseline period (June 1998 - May 2000), the 

results would show that the Modernization Project has a lower impact on 

air quality than projected in the original Ambient Air Quality Impact 

Analysis (See Response to Comment C-4). 

3.	 The PSD analysis fails to consider Emission Reduction Credits, or "offsets" that were used 

to show compliance with state and local air quality standards, despite the fact that emissions 

would still increase. These o.fJsets hide the real amount ofemissions that the public would be 

exposed to. (# 44, 46) 

Response to A-3: 

70f21 
The Prevention of Significant Deterioration (PSD) program is the

arm of the New Source Review (NSR) Program that regulates emissions of

air pollutants for which the area is designated attainment or unclassifiable,

from new major stationary sources or major modifications at existing major

sources. The PSD regulations require the application of Best Available

Control Technology (BACT), analyses of the impacts of the project on 1)

PSD increments, 2) ambient air quality, 3) visibility and air quality in Class

I areas, and 4) soils and vegetation. See 42 U.S.C. 7475. Offsets are not

required by PSD; rather they are a component of the Nonattainment New

Source Review (NNSR) Program, the arm of the NSR program that

regulates emissions of air pollutants for which the area is designated

nonattainment. See 42 U.S.C. 7503(a)(1)(A).

San Luis Obispo Air Pollution Control District Rule 204(B) is a

local regulation that requires MBPP to mitigate emissions of any pollutant

emitted above certain thresholds. Based on that regulation, the SLOAPCD

will require offsets for the Modernization Project for emissions of NON,

PM10, SO2, VOC, and CO.

In summary, for PSD purposes, offsets are not required for the

Modernization Project because the project will be located in a Federal

Attainment area for PM1 0. The emission increase considered in the PSD

analysis is based on the difference between the pre- and post-project

emission rates. It would be improper for the PSD analysis to account for

PM1 0 offsets because the purpose of offsets is yield a null net emission

increase from the project. In this case, if the PSD analysis considered full

offsets for PM10, the net emissions increase would be zero. EPA also notes

that the purpose of offsets is not to hide the real amount of emissions, as

stated in the above comment, but to mitigate the effects of emissions

increases in nonattainment areas to allow for new construction without

affecting plans for nonattainment areas to achieve attainment. Offsets are

not used to circumvent PSD or nonattainment NSR review; rather, offsets

are required as a result of nonattainment NSR review or district review of

project applications.

Section B: Best Available Control Technology (BACT)

1. The BACT determination from 2000 is too old, and should be updated. (# 10, 12, 21, 24, 29-

31, 44, 46)

Response to B-1:

EPA agrees that the BACT determination made in 2000 should be

reviewed to ensure that it is consistent with a 2007 BACT Determination.

8 of 21

The Prevention of Significant Deterioration (PSD) program is the 

arm of the New Source Review (NSR) Program that regulates emissions of 

air pollutants for which the area is designated attainment or unclassifiable, 

from new major stationary sources or major modifications at existing major 

sources. The PSD regulations require the application of Best Available 

Control Technology (BACT), analyses of the impacts ofthe project on 1) 

PSD increments, 2) ambient air quality, 3) visibility and air quality in Class 

I areas, and 4) soils and vegetation. See 42 U.S.C. 7475. Offsets are not 

required by PSD; rather they are a component of the Nonattainment New 

Source Review (NNSR) Program, the arm of the NSR program that 

regulates emissions of air pollutants for which the area is designated 

nonattainment. See 42 U.S.c. 7503(a)(l)(A). 

San Luis Obispo Air Pollution Control District Rule 204(B) is a 

local regulation that requires MBPP to mitigate emissions of any pollutant 

emitted above certain thresholds. Based on that regulation, the SLOAPCD 

will require offsets for the Modernization Project for emissions of NO x, 

PM IO, S02, VOC, and CO. 

In summary, for PSD purposes, offsets are not required for the 

Modernization Project because the project will be located in a Federal 

Attainment area for PMIO. The emission increase considered in the PSD 

analysis is based on the difference between the pre- and post-project 

emission rates. It would be improper for the PSD analysis to account for 

PM IO offsets because the purpose of offsets is yield a null net emission 

increase from the project. In this case, ifthe PSD analysis considered full 

offsets for PMIO, the net emissions increase would be zero. EPA also notes 

that the purpose of offsets is not to hide the real amount of emissions, as 

stated in the above comment, but to mitigate the effects of emissions 

increases in nonattainment areas to allow for new construction without 

affecting plans for nonattainment areas to achieve attainment. Offsets are 

not used to circumvent PSD or nonattainment NSR review; rather, offsets 

are required as a result of nonattainment NSR review or district review of 

project applications. 

Section B: Best Available Control Technology (BACT) 

1.	 The BACT determination from 2000 is too old, and should be updated. (# 10,12,21,24,29­

31, 44, 46) 

Response to B-1: 

EPA agrees that the BACT determination made in 2000 should be 

reviewed to ensure that it is consistent with a 2007 BACT Determination. 

80f21 
The BACT determination was reviewed in 2006 prior to the proposal of the

PSD permit, and has been reviewed again in 2007. According to 40 CFR

§52.21(j)(4), BACT determinations must be reviewed and modified as

appropriate at the latest reasonable time which occurs no more than 18

months prior to commencement of construction. Although §52.21(j)(4)

applies to phased construction projects, the 18 month time period provides

a guideline for how often BACT determinations must be revisited, given

the possibility for improvements in technology, and when construction

must be commenced after PSD permit issuance. Because PM10 is the only

criteria pollutant subject to federal PSD requirements, PM10 is the only

pollutant requiring a BACT determination.

BACT determinations may be an emission limitation, a design,

equipment, work practice, operational standard, or combination thereof (40

CFR §52.21(b)(12)). From gas turbines, PM10 is emitted in part from sulfur

in the natural gas, inert trace contaminants, and incomplete combustion of

hydrocarbons. The final PSD permit for MBPP only allows the use of

pipeline quality natural gas with a sulfur content of no more than 0.25

grains per 100 scf, and requires monthly analysis of the sulfur content of

the natural gas combusted.

The EPA RACT/BACT/LAER Clearinghouse (RBLC) 6 provides a

central online database of air pollution control technology determinations

made to satisfy requirements for Reasonably Achievable Control

Technology (RACT), Best Available Control Technology (BACT), and

Lowest Achievable Emission Rate (LAER). We conducted recent searches

(March 20, 2007) of the RBLC database for BACT determinations for

natural gas-fired combined cycle turbines prior to the PSD permit proposal

in May 2006 and recently as a result of public comments. The top BACT

option for controlling PM10 from gas turbines is considered to be a

combination of low or zero ash fuel (i.e., natural gas) and good combustion

practices (See Table 3).

Recent BACT determinations for PM10 emissions from natural gasfired turbines, reported by the EPA RBLC (Table 3) show that the

proposed emissions limits of 11 and 13.3 lb/hr are comparable to facilities

using similar natural gas turbines. A January 22, 2007 search of the

California Air Resources Board (ARB) Statewide BACT Clearinghouse 7

reports three determinations for PM10 from >50 MW combined cycle

natural gas-fired turbines. These emission limits range from 9 lb/hr

(Sacramento Metropolitan Air Quality Management District (AQMD)), to

11.5 lb/hr (Feather River AQMD), to 17.2 lb/hr (San Joaquin Valley Air

Pollution Control District), where the gas turbines from the power plant in

6 http://www.epa.gov/ttn/catc/rblc/htm/welcome_eg.html

http://www.arb.ca.gov/bact/bact.htm

9 of 21

The BACT determination was reviewed in 2006 prior to the proposal of the 

PSD permit, and has been reviewed again in 2007. According to 40 CFR 

§52.21G)(4), BACT determinations must be reviewed and modified as 

appropriate at the latest reasonable time which occurs no more than 18 

months prior to commencement of construction. Although §52.21G)(4) 

applies to phased construction projects, the 18 month time period provides 

a guideline for how often BACT determinations must be revisited, given 

the possibility for improvements in technology, and when construction 

must be commenced after PSD permit issuance. Because PM IO is the only 

criteria pollutant subject to federal PSD requirements, PM 10 is the only 

pollutant requiring a BACT determination. 

BACT determinations may be an emission limitation, a design, 

equipment, work practice, operational standard, or combination thereof (40 

CFR §52.2I(b)(l2)). From gas turbines, PM IO is emitted in part from sulfur 

in the natural gas, inert trace contaminants, and incomplete combustion of 

hydrocarbons. The final PSD permit for MBPP only allows the use of 

pipeline quality natural gas with a sulfur content of no more than 0.25 

grains per 100 scf, and requires monthly analysis of the sulfur content of 

the natural gas combusted. 

The EPA RACT/BACT/LAER Clearinghouse (RBLC)6 provides a 

central online database of air pollution control technology determinations 

made to satisfy requirements for Reasonably Achievable Control 

Technology (RACT), Best Available Control Technology (BACT), and 

Lowest Achievable Emission Rate (LAER). We conducted recent searches 

(March 20, 2007) of the RBLC database for BACT determinations for 

natural gas-fired combined cycle turbines prior to the PSD permit proposal 

in May 2006 and recently as a result of public comments. The top BACT 

option for controlling PM IO from gas turbines is considered to be a 

combination oflow or zero ash fuel (i.e., natural gas) and good combustion 

practices (See Table 3). 

Recent BACT determinations for PM IO emissions from natural gasfired turbines, reported by the EPA RBLC (Table 3) show that the 

proposed emissions limits of 11 and 13.3 lb/hr are comparable to facilities 

using similar natural gas turbines. A January 22,2007 search of the 

California Air Resources Board (ARB) Statewide BACT Clearinghouse 

reports three determinations for PM IO from 2:50 MW combined cycle 

natural gas-fired turbines. These emission limits range from 9 lb/hr 

(Sacramento Metropolitan Air Quality Management District (AQMD)), to 

11.5 lb/hr (Feather River AQMD), to 17.2 lb/hr (San Joaquin Valley Air 

Pollution Control District), where the gas turbines from the power plant in 

6 http://www.epa.gov/ttn/catc/rblc/htm/welcome eg.html 

7 http://www.arb.ca.gov/bact/bact.htm ­

90f21 
the Feather River AQMD were most similar to the turbines proposed for

use in the Modernization Project.

Table 3: Recent BACT Determinations from RBLC Database

Date RBLC PK° without PMio with

Facility State Determination duct firing duct firing

last updated (lb/hr) (lb/hr)

Control Method

Description

Rocky Mountain

Energy Center, LLC CO 5/8/06 7.6

Natural Gas Quality

Fuel only and Good

Combustion Practices

Crescent City Power 8 LA 8/30/06 14.7 20.7

Clean Burning Fuel and

Good Combustion

Practices

Tracy Substation CA 8/31/06 11.5 Best Combustion

Practices

Forsythe Energy Plant 9 NV 8/30/06 11.7 12.9

Clean Burning Low

Sulfur Fuel and Good

Combustion Practices

Berrien Energy, LLC MI 1/4/06 19

Natural Gas and State of

the Art Combustion

Techniques

Duke Energy Hanging

Rock Facility OH 7/5/05 15 23.3 Low Sulfur Natural Gas

The BAAQMD BACT workbook shows that the achieved in

practice BACT for PK() from large (> 40MW) combined cycle gas

turbines is natural gas fuel with a sulfur content not to exceed 1.0 grain/100

scf, achieved through the exclusive use of PUC-regulated grade natural

gas. The proposed PSD permit for the Modernization Project restricts the

facility to the use of pipeline-quality natural gas with a sulfur content of no

more than 0.25 grain/100 scf. Thus, the BACT determination made in

2000, which EPA updated for the proposed PSD permit in 2006, is still

consistent with the most recent determinations.

2. Duct burner firing increases emissions of PA°, and should not be considered BACT. (# 12,

44, 46)

8 Emission limits from the RBLC report were inferred to be the total for 2 turbines. The 14.7 and 20.7 lb/hr emission

limits represent limits per individual turbine.

9 The RBLC database reports the emission limit as the total for 3 turbines. The 11.7 and 12.9 lb/hr emission limits

represent limits per individual turbine.

10 of 21

the Feather River AQMD were most similar to the turbines proposed for 

use in the Modernization Project. 

Table 3: Recent BACT Determinations from RBLC Database 

Facility State 

DateRBLC 

Determination 

last updated 

PMIO without 

duct firing 

(lb/hr) 

PMIO with 

duct firing 

(Ib/hr) 

Control Method 

Description 

Rocky Mountain 

Energy Center, LLC CO 5/8/06 7.6 

Natural Gas Quality 

Fuel only and Good 

Combustion Practices 

Clean Burning Fuel and 

Crescent City Power 8 LA 8/30/06 14.7 20.7 Good Combustion 

Practices 

Tracy Substation CA 8/31/06 11.5 Best Combustion 

Practices 

Clean Burning Low 

Forsythe Energy Plant 9 NY 8/30/06 11.7 12.9 Sulfur Fuel and Good 

Combustion Practices 

Natural Gas and State of 

Berrien Energy, LLC MI 1/4/06 19 the Art Combustion 

- Techniques 

Duke Energy Hanging 

Rock Facility OH 7/5/05 15 23.3 Low Sulfur Natural Gas 

The BAAQMD BACT workbook shows that the achieved in 

practice BACT for PM IO from large (2: 40MW) combined cycle gas 

turbines is natural gas fuel with a sulfur content not to exceed 1.0 grain/1 00 

scf, achieved through the exclusive use of PUC-regulated grade natural 

gas. The proposed PSD permit for the Modernization Project restricts the 

facility to the use of pipeline-quality natural gas with a sulfur content of no 

more than 0.25 grain/1 00 scf. Thus, the BACT determination made in 

2000, which EPA updated for the proposed PSD permit in 2006, is still 

consistent with the most recent determinations. 

2.	 Duct burner firing increases emissions ofPMlO, and should not be considered BACT (# 12, 

44,46) 

8 Emission limits from the RBLC report were inferred to be the total for 2 turbines. The 14.7 and 20.7 lb/hr emission
 

limits represent limits per individual turbine.
 

9 The RBLC database reports the emission limit as the total for 3 turbines. The 11.7 and 12.9 lblhr emission limits
 

represent limits per individual turbine.
 

10 of21 
Response to B-2:

The purpose of duct burner firing in the heat recovery steam

generator (HRSG) is to elevate the turbine exhaust temperature, allowing

production of additional power and higher steam cycle efficiency. As such,

duct burners are components of the HRSG used to increase power

generation from the steam turbines, and by definition, are not control

technology to reduce air pollutant emissions. As a component of the

combined cycle system, the gas turbines block units, associated with the

Modernization Project, are subject to BACT emission limits with and

without supplemental firing of the duct burners (11 lb/hr and 13.3 lb/hr,

respectively). A survey of the EPA RBLC shows that two different

emission limits are typically imposed on turbines based on the whether or

not the duct burners are fired.

3. The BACT analysis should require updated information by the owner/operator (given the

extended delay since submission of the application) to address current BACT generally for

CO, NOx, VOC, PM10, and specifically as to the duct burning component of the project. In

recent statements by Mr. Gary Willey of the APCD, Mr. Willey suggested that current BACT

for greenhouse gases would prevent duct burning because other turbines would not produce *

these greenhouse gases, as well as the excess PA() emissions from duct burning, are

commercially available, albeit at an increase up-front capital cost to the owner/operator.

* Mr. Willey has indicated that the APCD will consider any then applicable APCD required

emissions limitations on greenhouse gases in connection with the APCD's final BACT

review, as well as BACT for excessive PM10 emissions resulting from duct burning. (# 12)

Response to B-3:

For a discussion of the BACT determination for PM10, the only criteria

pollutant subject to PSD review, please see our response to comment B-1. For

a general discussion on duct burning, PM10, and BACT, please see our

response to comment B-2.

To the extent the comment raises issues relating to EPA's general

permitting authority for CO2 and other greenhouse gases ("GHGs"), EPA

recognizes the importance of addressing the global challenge of climate

change, and in light of the Supreme Court's decision in Massachusetts v. EPA,

127 S. Ct. 1438 (2007), the Agency is working diligently to develop an overall

strategy for addressing the emissions of CO2 and other GHGs under the Clean

Air Act. See 73 Fed. Reg. 44354, "Regulating Greenhouse Gas Emissions

Under the Clean Air Act" (Advance Notice of Proposed Rulemaking) (July

30, 2008). However, EPA does not currently have the authority to address the

challenge of global climate change by imposing limitations on emissions of

CO2 and other greenhouse gases in PSD permits.

11 of 21

Response to B-2: 

The purpose of duct burner firing in the heat recovery steam 

generator (HRSG) is to elevate the turbine exhaust temperature, allowing 

production of additional power and higher steam cycle efficiency. As such, 

duct burners are components ofthe HRSG used to increase power 

generation from the steam turbines, and by definition, are not control 

technology to reduce air pollutant emissions. As a component of the 

combined cycle system, the gas turbines block units, associated with the 

Modernization Project, are subject to BACT emission limits with and 

without supplemental firing of the duct burners (lllb/hr and 13.3 lb/hr, 

respectively). A survey of the EPA RBLC shows that two different 

emission limits are typically imposed on turbines based on the whether or 

not the duct burners are fired. 

3.	 The BACT analysis should require updated information by the owner/operator (given the 

extended delay since submission ofthe application) to address current BACT generally for 

CO, NOx, VOC, PM lO, and specifically as to the duct burning component ofthe project. In 

recent statements by Mr. Gary Willey ofthe APCD, Mr. Willey suggested that current BACT 

for greenhouse gases • would prevent duct burning because other turbines would not produce 

these greenhouse gases, as well as the excess PM lO emissions from duct burning, are 

commercially available, albeit at an increase up-front capital cost to the owner/operator. 

• Mr. Willey has indicated that the APCD will consider any then applicable APCD required 

emissions limitations on greenhouse gases in connection with the APCD's final BACT 

review, as well as BACT for excessive PMlO emissions resulting from duct burning. (# 12) 

Response to B-3: 

For a discussion of the BACT determination for PM IO, the only criteria 

pollutant subject to PSD review, please see our response to comment B-1. For 

a general discussion on duct burning, PM IO, and BACT, please see our 

response to comment B-2. 

To the extent the comment raises issues relating to EP A's general 

permitting authority for CO 2 and other greenhouse gases ("GHGs"), EPA 

recognizes the importance of addressing the global challenge of climate 

change, and in light of the Supreme Court's decision in Massachusetts v. EPA, 

127 S. Ct. 1438 (2007), the Agency is working diligently to develop an overall 

strategy for addressing the emissions of CO 2 and other GHGs under the Clean 

Air Act. See 73 Fed. Reg. 44354, "Regulating Greenhouse Gas Emissions 

Under the Clean Air Act" (Advance Notice of Proposed Rulemaking) (July 

30, 2008). However, EPA does not currently have the authority to address the 

challenge of global climate change by imposing limitations on emissions of 

CO 2 and other greenhouse gases in PSD permits. 

11 of21 
While EPA has been implementing voluntary programs aimed at

reducing greenhouse gases for several years, since the Supreme Court

decision, EPA has been exploring the additional tools provided by the Clean

Air Act to help us expand on the solid foundation we have built to achieve the

global goal of reduced greenhouse gas emissions. In fact, EPA has recently

issued an advanced notice of proposed rulemaking (ANPR) seeking public

input regarding issues relating to "the specific effects of climate change and

potential regulation of greenhouse gas emissions from stationary and mobile

sources under the Clean Air Act." 73 Fed. Reg. 44354. While the ANPR is

the first step in developing a regulatory strategy for addressing CO2 and other

GHG emissions under the CAA, the Agency has not yet proposed rules to

regulate these emissions under the Act.

It is well established that "EPA lacks the authority to impose [PSD

permit] limitations or other restrictions directly on the emission of unregulated

pollutants." North County Resource Recovery Assoc., 2 E.A.D. 229, 230

(Adm'r 1986). The Clean Air Act and EPA's regulations require PSD permits

to contain emissions limitations for "each pollutant subject to regulation"

under the Act. CAA § 165(a) (4); 40 CFR § 52.21(b) (12). In defining those

PSD permit requirements, EPA has historically interpreted the term "subject

to regulation under the Act" to describe pollutants that are presently subject to

a statutory or regulatory provision that requires actual control of emissions of

that pollutant. See 43 Fed. Reg. 26388, 26397 (June 19, 1978) (describing

pollutants subject to BACT requirements); 61 Fed. Reg. 38250, 38309-10

(July 23, 1996) (listing pollutants subject to PSD review); In Re Kawaihae

Cogeneration Project, 7 E.A.D. 107, 132 (EAB 1997); Inter power of New

York, 5 E.A.D. 130, 151 (EAB 1994); Memorandum from Jonathan Z.

Cannon, General Counsel to Carol M. Browner, Administrator, entitled EPA's

Authority to Regulate Pollutants Emitted by Electric Power Generation

Sources (April 10, 1998); Memorandum from Lydia N. Wegman, Deputy

Director, Office of Air Quality Planning and Standards, entitled Definition of

Regulated Air Pollutant for Purposes of Title V, at 5 (April 26, 1993). In

2002, EPA codified this approach for implementing PSD by defining the term

"regulated NSR pollutant" and clarifying that Best Available Control

Technology is required "for each regulated NSR pollutant that [a major

source] would have the potential to emit in significant amounts." 40 CFR §

52.21(j) (2); 40 CFR 52.21(b) (50).

In defining a "regulated NSR pollutant," EPA identified such

pollutants by referencing pollutants regulated in three principal program areas

-- NAAQS pollutants, pollutants subject to a section 111 NSPS, and class I or

II substance under title VI of the Act-- as well as any pollutant "that otherwise

is subject to regulation under the Act." 40 CFR 52.21(b)(50)(i)-(iv). As used

in this provision, EPA continues to interpret the phrase "subject to regulation

under the Act" to refer to pollutants that are presently subject to a statutory or

regulatory provision that requires actual control of emissions of that pollutant.

Because EPA has not established a NAAQS or NSPS for CO2, classified CO2

12 of 21

While EPA has been implementing voluntary programs aimed at 

reducing greenhouse gases for several years, since the Supreme Court 

decision, EPA has been exploring the additional tools provided by the Clean 

Air Act to help us expand on the solid foundation we have built to achieve the 

global goal of reduced greenhouse gas emissions. In fact, EPA has recently 

issued an advanced notice of proposed rulemaking (ANPR) seeking public 

input regarding issues relating to "the specific effects of climate change and 

potential regulation of greenhouse gas emissions from stationary and mobile 

sources under the Clean Air Act." 73 Fed. Reg. 44354. While the ANPR is 

the first step in developing a regulatory strategy for addressing CO2 and other 

GHG emissions under the CAA, the Agency has not yet proposed rules to 

regulate these emissions under the Act. 

It is well established that "EPA lacks the authority to impose [PSD 

permit] limitations or other restrictions directly on the emission of unregulated 

pollutants." North County Resource Recovery Assoc., 2 E.A.D. 229,230 

(Adm'r 1986). The Clean Air Act and EPA's regulations require PSD permits 

to contain emissions limitations for "each pollutant subject to regulation" 

under the Act. CAA § 165(a) (4); 40 CFR § 52.21(b) (12). In defining those 

PSD permit requirements, EPA has historically interpreted the term "subject 

to regulation under the Act" to describe pollutants that are presently subject to 

a statutory or regulatory provision that requires actual control of emissions of 

that pollutant. See 43 Fed. Reg. 26388, 26397 (June 19, 1978) (describing 

pollutants subject to BACT requirements); 61 Fed. Reg. 38250, 38309-10 

(July 23, 1996) (listing pollutants subject to PSD review); In Re Kawaihae 

Cogeneration Project, 7 E.A.D. 107,132 (EAB 1997); Inter-power ofNew 

York, 5 E.A.D. 130, 151 (EAB 1994); Memorandum from Jonathan Z. 

Cannon, General Counsel to Carol M. Browner, Administrator, entitled EPA's 

Authority to Regulate Pollutants Emitted by Electric Power Generation 

Sources (April 10, 1998); Memorandum from Lydia N. Wegman, Deputy 

Director, Office of Air Quality Planning and Standards, entitled Definition of 

Regulated Air Pollutant for Purposes of Title V, at 5 (April 26, 1993). In 

2002, EPA codified this approach for implementing PSD by defining the term 

"regulated NSR pollutant" and clarifying that Best Available Control 

Technology is required "for each regulated NSR pollutant that [a major 

source] would have the potential to emit in significant amounts." 40 CFR § 

52.210) (2); 40 CFR 52.21(b) (50). 

In defining a "regulated NSR pollutant," EPA identified such 

pollutants by referencing pollutants regulated in three principal program areas 

-- NAAQS pollutants, pollutants subject to a section 111 NSPS, and class I or 

II substance under title VI of the Act-- as well as any pollutant "that otherwise 

is subject to regulation under the Act." 40 CFR 52.21 (b)(50)(i)-(iv). As used 

in this provision, EPA continues to interpret the phrase "subject to regulation 

under the Act" to refer to pollutants that are presently subject to a statutory or 

regulatory provision that requires actual control of emissions of that pollutant. 

Because EPA has not established a NAAQS or NSPS for CO 2, classified CO2 

120f21 
as a title VI substance, or otherwise regulated CO2 under any other provision

of the Act, CO2 is not currently a "regulated NSR pollutant" as defined by

EPA regulations.

Although the Supreme Court decided the case cited by the commenter

and held that CO2 and other GHGs are air pollutants under the CAA, see

Massachusetts v. EPA, 127 S. Ct. 1438 (2007), that decision does not require

the Agency to set emission limits for CO2 and other GHGs in the Colusa

Generating Station PSD permit. Notably, the Court did not hold that EPA was

required to regulate CO2 and other GHG emissions under Section 202, or any

other section, of the Clean Air Act. Rather, the Court concluded that these

emissions were "air pollutants" under the Act, and, therefore, EPA could

regulate them under Section 202 (the provision at issue in the Massachusetts

case), subject to certain Agency determinations pertaining to mobile sources.

EPA is currently exploring options for addressing GHG emissions in

response to the Supreme Court decision. 73 Fed. Reg. 44354 (July 30, 2008).

However, EPA has not yet issued regulations requiring control of CO2 and

other GHG emissions under the Act generally or the PSD program

specifically. Accordingly, because CO2 is not currently a pollutant regulated

under the CAA, EPA cannot include emissions limitations for CO2 (or other

GHGs that are not otherwise regulated. NSR pollutants) in the PSD permit for

CGS. At this time, we believe that any action EPA might consider taking with

respect to regulation of CO2 or other GHGs in PSD permits or other contexts

should be addressed through notice and comment rulemaking, as we have

recently initiated by publishing the ANPR, allowing for a process which is

public and transparent and based on the best available science. 73 Fed. Reg.

44354 (July 30, 2008).

4. The BACT analysis should consider PM10 emissions from the potential use of cooling towers

as an alternative to once-through sea water cooling. (# 12, 32, 34)

Response to B-4:

Since the PSD permit application specifies the use of once-through

seawater cooling with no resultant emissions of PM10, a BACT

determination for cooling tower options is not triggered. It is our

understanding that the Central Coast Regional Water Quality Control Board

("Water Board") has postponed the issuance of a renewal permit under the

National Pollutant Discharge Elimination System ("NPDES"). Although the

public comment period for the proposed renewal NPDES permit for MBPP

ended on January 26, 2007, the Water Board has placed the NPDES permit

on an administrative extension, pending Water Board review of the recent

EPA action on July 9, 2007 (72 FR 37107) to suspend the Phase II rule

under section 316(b) of the Clean Water Act, regulating cooling water

13 of 21

as a title VI substance, or otherwise regulated CO2 under any other provision 

of the Act, CO 2 is not currently a "regulated NSR pollutant" as defined by 

EPA regulations. 

Although the Supreme Court decided the case cited by the commenter 

and held that CO2 and other GHGs are air pollutants under the CAA, see 

Massachusetts v. EPA, 127 S. Ct. 1438 (2007), that decision does not require 

the Agency to set emission limits for CO 2 and other GHGs in the Colusa 

Generating Station PSD permit. Notably, the Court did not hold that EPA was 

required to regulate CO2 and other GHG emissions under Section 202, or any 

other section, of the Clean Air Act. Rather, the Court concluded that these 

emissions were "air pollutants" under the Act, and, therefore, EPA could 

regulate them under Section 202 (the provision at issue in the Massachusetts 

case), subject to certain Agency determinations pertaining to mobile sources. 

EPA is currently exploring options for addressing GHG emissions in 

response to the Supreme Court decision. 73 Fed. Reg. 44354 (July 30, 2008). 

However, EPA has not yet issued regulations requiring control of C02 and 

other GHG emissions under the Act generally or the PSD program 

specifically. Accordingly, because C02 is not currently a pollutant regulated 

under the CAA, EPA cannot include emissions limitations for CO 2 (or other 

GHGs that are not otherwise regulated NSR pollutants) in the PSD permit for 

CGS. At this time, we believe that any action EPA might consider taking with 

respect to regulation of CO2 or other GHGs in PSD permits or other contexts 

should be addressed through notice and comment rulemaking, as we have 

recently initiated by publishing the ANPR, allowing for a process which is 

public and transparent and based on the best available science. 73 Fed. Reg. 

44354 (July 30, 2008). 

4.	 The BACT analysis should consider PMlO emissions from the potential use ofcooling towers 

as an alternative to once-through sea water cooling. (# J2, 32, 34) 

Response to B-4: 

Since the PSD permit application specifies the use of once-through 

seawater cooling with no resultant emissions of PM 10, a BACT 

determination for cooling tower options is not triggered. It is our 

understanding that the Central Coast Regional Water Quality Control Board 

("Water Board") has postponed the issuance of a renewal permit under the 

National Pollutant Discharge Elimination System ("NPDES"). Although the 

public comment period for the proposed renewal NPDES permit for MBPP 

ended on January 26,2007, the Water Board has placed the NPDES permit 

on an administrative extension, pending Water Board review of the recent 

EPA action on July 9,2007 (72 FR 37107) to suspend the Phase II rule 

under section 316(b) of the Clean Water Act, regulating cooling water 

13 of21 
intake structures for existing large power plants. The suspension of the rule

by EPA implements the decision from the 2 nd Circuit U.S. Court of Appeals

in Riverkeeper, Inc. v. EPA, issued January 25, 2007, remanding several

provisions in the rule, including Best Technology Available determinations,

restoration provisions, and performance standard ranges.

The EPA action retains a provision (40 CFR 125.90(b)) of the Phase

II rule that requires permitting authorities to develop "Best Professional

Judgment" controls for existing facility cooling water intake structures that

reflect the best technology available for minimizing adverse environmental

impact. If the Water Board determines that once-through cooling by MBPP

will not be allowed, and a different cooling method, such as dry cooling or

cooling towers, is required, MBPP must apply for a revised PSD permit to

include analyses of PM10 emissions from the cooling system, ensure that the

new cooling system complies with all PSD requirements, including BACT,

and specify revised PM10 emission limits in the new PSD permit.

Section C: Modeling and Ambient Air Quality Impact Analysis (AAQIR)

1. The use of upper air data from Vandenberg Air Force Base is not appropriate. (# 12, 29-30,

44, 46)

Response to C-1:

The upper air meteorological data from Vandenberg Air Force Base

(VAFB) was used in the modeling analyses to determine atmospheric

mixing heights, which impact the dispersion of pollutants (page 6.2-11).

Vandenberg Air Force Base (VAFB) was the closest upper air

meteorological station to MOM) Bay (45 miles southeast). Given that

marine climates influence mixing depths, the proximity of VAFB to the

Pacific Ocean and to the project site makes the upper air data from

Vandenberg appropriate for estimating mixing heights in Mono Bay.

The surface meteorological measurements were collected at the

Morro Bay Power plant, and therefore are representative of the

meteorological conditions at the proposed modification.

2. Modeling scenarios examining a six-mile radius from the MBPP does not represent actual

regional impacts of PMio emissions. (# 12, 15, 44, 46)

Response to C-2:

We agree that the PM10 emissions may have regional as well as

local-scale impacts. Local-scale impacts typically result from primary

14 of 21

intake structures for existing large power plants. The suspension of the rule 

by EPA implements the decision from the 2 nd Circuit U.S. Court of Appeals 

in Riverkeeper, Inc. v. EPA, issued January 25, 2007, remanding several 

provisions in the rule, including Best Technology Available determinations, 

restoration provisions, and performance standard ranges. 

The EPA action retains a provision (40 CFR 125.90(b)) of the Phase 

II rule that requires permitting authorities to develop "Best Professional 

Judgment" controls for existing facility cooling water intake structures that 

reflect the best technology available for minimizing adverse environmental 

impact. If the Water Board determines that once-through cooling by MBPP 

will not be allowed, and a different cooling method, such as dry cooling or 

cooling towers, is required, MBPP must apply for a revised PSD permit to 

include analyses ofPMlO emissions from the cooling system, ensure that the 

new cooling system complies with all PSD requirements, including BACT, 

and specify revised PM lO emission limits in the new PSD permit. 

Section C: Modeling and Ambient Air Quality Impact Analysis (AAQIR) 

1.	 The use ofupper air data from Vandenberg Air Force Base is not appropriate. (# J2, 29-30, 

44,46) 

Response to C-1: 

The upper air meteorological data from Vandenberg Air Force Base 

(VAFB) was used in the modeling analyses to determine atmospheric 

mixing heights, which impact the dispersion of pollutants (page 6.2-11). 

Vandenberg Air Force Base (VAFB) was the closest upper air 

meteorological station to Morro Bay (45 miles southeast). Given that 

marine climates influence mixing depths, the proximity of VAFB to the 

Pacific Ocean and to the project site makes the upper air data from 

Vandenberg appropriate for estimating mixing heights in Morro Bay. 

The surface meteorological measurements were collected at the 

Morro Bay Power plant, and therefore are representative of the 

meteorological conditions at the proposed modification. 

2.	 Modeling scenarios examining a six-mile radius from the MBPP does not represent actual 

regional impacts ofPM JO emissions. (# J2, J5, 44, 46) 

Response to C-2: 

We agree that the PMlO emissions may have regional as well as 

local-scale impacts. Local-scale impacts typically result from primary 

140f21 
emissions of PM10, or PM1 0 emitted directly into the atmosphere. Regional

impacts typically result from secondary PM10, or PM10 formed in the

atmosphere from chemical reactions. The MBBP's analyses considered

both types of impacts. As required, the MBBP's source impact analysis

predicted, through modeling, the local-scale ambient air quality impacts of

the direct emissions of PM 10 from the MBPP within the source's area of

significant impact, as a result of the proposed modification. The analyses

demonstrate that the proposed emissions increase from the modification

will not cause or contribute to a violation of the NAAQS or PSD Class II

increments for PM1 0.

The MBBP's analysis of impacts beyond the local-scale impacts

involved modeling the impacts of the source's emissions on the San Rafael

Wilderness Class I area. The visibility analysis evaluates the visibility

degradation that is caused by secondary particulate matter formed from

NO„ and SO„, as well as primary PM10. The maximum impact on visibility

in the San Rafael Wilderness Class I area meets the Federal Land

Manager's criteria for the level of acceptable change. The air quality

analysis demonstrates that the proposed modification will not cause or

contribute to a violation of the NAAQS or PSD Class I increments for PM10

in the San Rafael Wilderness Class I.

3. Meteorological conditions from 1994 — 1996 do not adequately address meteorological

variability, including fog events, winter time inversions, and El Nino / La Nina phenomena.

(# 9, 11-13, 27, 29, 35, 43-44, 46)

Response to C-3:

The applicant reported in the Air Quality Analysis (page 6.2-49)

that the meteorological conditions used in the modeling were obtained from

data collected by PG&E at the MBPP site from 1994 — 1996. From the

1994 dataset, MBPP reported that the meteorological conditions expected to

produce fog (relative humidity greater than 91.7%) were identified in 29%

of all hours, representing roughly 51% of all days in 1994 experiencing at

least one hour of fog, which is consistent with the long-term fog statistics

from the National Weather Service Point Mugu station (page 6.2-58). The

three years of real meteorological data were collected during actual

conditions from 1994 — 1996, including foggy and non-foggy conditions

and winter time inversions.

The three year data period from 1994 — 1996 was selected by the

District to provide a variety of meteorological conditions (page 6.2-49).

The District recommended use of data from 1994 — 1996 because they

judged 1997 and 1998 to be highly unusual El Nitio and La Niiia years, and

thus inappropriate to assure normal seasonal and short-term variations in

15 of 21

emissions ofPM IO, or PM IO emitted directly into the atmosphere. Regional 

impacts typically result from secondary PM IO, or PMIO formed in the 

atmosphere from chemical reactions. The MBBP's analyses considered 

both types of impacts. As required, the MBBP's source impact analysis 

predicted, through modeling, the local-scale ambient air quality impacts of 

the direct emissions ofPM IO from the MBPP within the source's area of 

significant impact, as a result ofthe proposed modification. The analyses 

demonstrate that the proposed emissions increase from the modification 

will not cause or contribute to a violation of the NAAQS or PSD Class II 

increments for PM IO. 

The MBBP's analysis of impacts beyond the local-scale impacts 

involved modeling the impacts ofthe source's emissions on the San Rafael 

Wilderness Class I area. The visibility analysis evaluates the visibility 

degradation that is caused by secondary particulate matter formed from 

NO xand sax, as well as primary PM IO. The maximum impact on visibility 

in the San Rafael Wilderness Class I area meets the Federal Land 

Manager's criteria for the level of acceptable change. The air quality 

analysis demonstrates that the proposed modification will not cause or 

contribute to a violation of the NAAQS or PSD Class I increments for PM IO 

in the San Rafael Wilderness Class 1. 

3.	 Meteorological conditions from 1994 -1996 do not adequately address meteorological 

variability, including fog events, winter time inversions, and El Nino / La Niiia phenomena. 

(# 9, 11-13,27,29,35, 43-44, 46) 

Response to C-3: 

The applicant reported in the Air Quality Analysis (page 6.2-49) 

that the meteorological conditions used in the modeling were obtained from 

data collected by PG&E at the MBPP site from 1994 - 1996. From the 

1994 dataset, MBPP reported that the meteorological conditions expected to 

produce fog (relative humidity greater than 91.7%) were identified in 29% 

of all hours, representing roughly 51% of all days in 1994 experiencing at 

least one hour of fog, which is consistent with the long-term fog statistics 

from the National Weather Service Point Mugu station (page 6.2-58). The 

three years of real meteorological data were collected during actual 

conditions from 1994 - 1996, including foggy and non-foggy conditions 

and winter time inversions. 

The three year data period from 1994 - 1996 was selected by the 

District to provide a variety of meteorological conditions (page 6.2-49). 

The District recommended use of data from 1994 - 1996 because they 

judged 1997 and 1998 to be highly unusual EI Nino and La Nina years, and 

thus inappropriate to assure normal seasonal and short-term variations in 

150f21 
meteorology (November 28, 2000 letter from Paul H. Allen III, SLOAPCD

Supervising Air Quality Specialist to Kae Lewis, CEC Project Manager).

Additionally, the Pacific Marine Laboratory (PMEL) of the National

Oceanic and Atmospheric Administration (NOAA), part of the U.S.

Department of Commerce, reported that weaker El Nifio and La Nina years

occurred in 1994 and 1995 — 1996, respectively 10 . Thus, data from 1994 —

1996 incorporated an El Nino year as well as two La Nina years. Therefore,

because the meteorological data collected from 1994 — 1996 did

incorporate fog events, and winter inversions, and El Nitio Southern

Oscillation (ENSO) events that were not as unusual as those experienced in

1997 — 1998, we determined that the data was representative of natural

variability for Morro Bay.

4. Assuming that the baseline emissions are estimated to be too high (Section A.2), the changes

in emissions resulting from the project are larger than estimated and thus, do not adequately

represent the impact of the project on the PSD increment and visibility. (# 12, 29, 31, 44, 46)

Response to C-4:

This comment is confusing. The commenter seems to be implying

that by overestimating the baseline emissions, the emissions increase and

hence the projected impacts have been underestimated. The change in

emissions resulting from the Modernization Project was only used to

determine applicability of the Modernization Project to the PSD permitting

program. The modeling analyses for this project submitted by the applicant

(page 6.2-8) accounted for emissions from the proposed new turbines as

well as from the existing boilers. Because the existing boilers will be

shutdown as a result of the Modernization Project, by including the

emissions from the existing boilers in the model, the impacts of the facility

are modeled conservatively. Therefore, even if the baseline emissions were

estimated to be too high, the impact of the project would not be

underestimated, because the baseline emissions were not subtracted in the

analysis. Thus, the applicant's analysis adequately estimates potential

impacts from the facility.

5. The additional impacts analysis states that MBPP operated without incident in proximity to

agricultural uses. This does not adequately reflect the history of complaints by neighbors (#

1, 12, 29, 44, 46). The existence of historical complaints regarding fallout from the MBPP

was highlighted in an article from the Fall 1967 issue of Cry California: The Journal of

California Tomorrow (See Comment #29). The article describes an incident that occurred on

May 20, 1966, where an increase in energy demand and natural gas consumption resulted in

the combustion of fuel oil, rather than natural gas, by MBPP. The May 26, 1966 issue of the

Morro Bay Sun newspaper reported resident complaints of damage to cars, house paint,

1(.1 http://www.pmel.noaa.gov/tao/elnino/el -nino-story.html

16 of 21

meteorology (November 28, 2000 letter from Paul H. Allen III, SLOAPCD 

Supervising Air Quality Specialist to Kae Lewis, CEC Project Manager). 

Additionally, the Pacific Marine Laboratory (PMEL) of the National 

Oceanic and Atmospheric Administration (NOAA), part of the U.S. 

Department of Commerce, reported that weaker EI Nino and La Nina years 

occurred in 1994 and 1995 - 1996, respectively'". Thus, data from 1994 -

1996 incorporated an EI Nino year as well as two La Nina years. Therefore, 

because the meteorological data collected from 1994 - 1996 did 

incorporate fog events, and winter inversions, and El Nino Southern 

Oscillation (ENSO) events that were not as unusual as those experienced in 

1997 - 1998, we determined that the data was representative of natural 

variability for Morro Bay. 

4. Assuming that the baseline emissions are estimated to be too high (Section A.2), the changes 

in emissions resulting from the project are larger than estimated and thus, do not adequately 

represent the impact ofthe project on the PSD increment and visibility. (# 12, 29, 31, 44, 46) 

Response to C-4: 

This comment is confusing. The commenter seems to be implying 

that by overestimating the baseline emissions, the emissions increase and 

hence the projected impacts have been underestimated. The change in 

emissions resulting from the Modernization Project was only used to 

determine applicability of the Modernization Project to the PSD permitting 

program. The modeling analyses for this project submitted by the applicant 

(page 6.2-8) accounted for emissions from the proposed new turbines as 

well as from the existing boilers. Because the existing boilers will be 

shutdown as a result of the Modernization Project, by including the 

emissions from the existing boilers in the model, the impacts of the facility 

are modeled conservati vely. Therefore, even if the baseline emissions were 

estimated to be too high, the impact of the project would not be 

underestimated, because the baseline emissions were not subtracted in the 

analysis. Thus, the applicant's analysis adequately estimates potential 

impacts from the facility. 

5. The additional impacts analysis states that MBPP operated without incident in proximity to 

agricultural uses. This does not adequately reflect the history ofcomplaints by neighbors (# 

1, 12, 29, 44, 46). The existence ofhistorical complaints regardingfalloutfrom the MBPP 

was highlighted in an article from the Fall 1967 issue ofCry California: The Journal of 

California Tomorrow (See Comment #29). The article describes an incident that occurred on 

May 20, 1966, where an increase in energy demand and natural gas consumption resulted in 

the combustion offuel oil, rather than natural gas, by MBPP. The May 26, 1966 issue ofthe 

Morro Bay Sun newspaper reported resident complaints ofdamage to cars, house paint, 

10 http://www.pmel.noaa.gov/tao/elnino/el-nino-story.html 

160f21 
clothes out to dry, flowers, and vegetables. The Cry California article cites the combustion of

fuel oil as the cause of the fallout experienced in 1966. The article further stated that fuel oil

combustion at the MBPP should be discontinued to avoid future fallout incidents (# 40).

Response to C-5:

The current Modernization Project proposes to remove the existing

fuel oil tanks and replace the old fossil fuel oil-fired steam generators with

combined cycle natural gas-fired turbines. Implementation of the proposed

project will result in reduced emissions of NO,,, CO, and VOC, and an

emissions increase of SO2 that does not exceed the PSD significance

threshold. Emissions of PM10 exceed the PSD significance threshold and

are subject to the PSD regulations, requiring application of BACT, and

impact analyses on ambient air (including national ambient air quality

standards (NAAQS), PSD increments, visibility, soil, and vegetation). The

modeling analyses have shown that PM10 emissions from the MBPP will

comply with the NAAQS, the allowable PSD increment, and the allowable

PSD Class I increment. Additionally, modeling has shown that visibility

will not be adversely impacted by the Modernization Project, and the

discontinued use of fuel oil by the MBPP will eliminate potential adverse

impacts on soils and vegetation.

6. The central and uncontested fact is that ground-level concentrations of particulate matter

would rise 60% in Morro Bay, partly because of increased operating capacity and the

reduction in stack height. (# 44, 46)

Response to C-6:

EPA disagrees with the statement that it is a central and uncontested

fact that ground level concentrations of particulate matter will increase by

60%. The change in emissions of PM10 resulting from the Modernization

Project, calculated as the difference between the potential to emit (PTE) of

the new turbines (203.2 tpy PM10) and the baseline actual emissions of the

existing boilers (127.2, tpy PM10), is 76 tpy of PM10. This increase of 76

tpy represents a 60% increase in potential PM10 emissions. Although

potential emissions of PM10 from the facility will increase by 60%, the

maximum modeled impact of the facility, estimated as the worst-case

ground level concentration over a 24-hour averaging period (the averaging

time for the National Ambient Air Quality Standard, or NAAQS), will

increase by 24.2 micrograms of PM 10 per cubic meter of air (μg/m3). This

represents a 42% increase over the background PM10 concentration (57

gg/m3). It is important to note that 1) this modeled impact represents the

maximum worst-case ground level concentration under fumigation

conditions, and 2) the impact of the Modernization Project combined with

the background PM10 concentration results in a total impact (81.2 μg/m 3 )

17 of 21

clothes out to dry, flowers, and vegetables. The Cry California article cites the combustion of 

fuel oil as the cause ofthe fallout experienced in 1966. The article further stated that fuel oil 

combustion at the MBPP should be discontinued to avoidfuturefallout incidents (# 40). 

Response to C-5: 

The current Modernization Project proposes to remove the existing 

fuel oil tanks and replace the old fossil fuel oil-fired steam generators with 

combined cycle natural gas-fired turbines. Implementation ofthe proposed 

project will result in reduced emissions of NOx- CO, and VOC, and an 

emissions increase of S02 that does not exceed the PSD significance 

threshold. Emissions of PMIO exceed the PSD significance threshold and 

are subject to the PSD regulations, requiring application of BACT, and 

impact analyses on ambient air (including national ambient air quality 

standards (NAAQS), PSD increments, visibility, soil, and vegetation). The 

modeling analyses have shown that PM IO emissions from the MBPP will 

comply with the NAAQS, the allowable PSD increment, and the allowable 

PSD Class I increment. Additionally, modeling has shown that visibility 

will not be adversely impacted by the Modernization Project, and the 

discontinued use of fuel oil by the MBPP will eliminate potential adverse 

impacts on soils and vegetation. 

6. The central and uncontested fact is that ground-level concentrations ofparticulate matter 

would rise 60% in Morro Bay, partly because ofincreased operating capacity and the 

reduction in stack height. (# 44, 46) 

Response to C-6: 

EPA disagrees with the statement that it is a central and uncontested 

fact that ground level concentrations of particulate matter will increase by 

60%. The change in emissions ofPMIO resulting from the Modernization 

Project, calculated as the difference between the potential to emit (PTE) of 

the new turbines (203.2 tpy PM IO) and the baseline actual emissions of the 

existing boilers (127.2, tpy PM1o), is 76 tpy ofPM IO. This increase of76 

tpy represents a 60% increase in potential PM IO emissions. Although 

potential emissions ofPM IO from the facility will increase by 60%, the 

maximum modeled impact of the facility, estimated as the worst-case 

ground level concentration over a 24-hour averaging period (the averaging 

time for the National Ambient Air Quality Standard, or NAAQS), will 

increase by 24.2 micrograms of PM IO per cubic meter of air (ug/rrr'). This 

represents a 42% increase over the background PMIO concentration (57 

ug/m '). It is important to note that 1) this modeled impact represents the 

maximum worst-case ground level concentration under fumigation 

conditions, and 2) the impact of the Modernization Project combined with 

the background PM IO concentration results in a total impact (81.2 ug/rrr') 

170f21 
that is 46% lower than the PM10 NAAQS of 150 μg/m3 . Therefore, the 60%

increase in potential emissions results in a modeled maximum worst-case

scenario increase in ground level concentration of 42%, which does not

result in any violations of the PM10 NAAQS.

7. The current applicable National Ambient Air Quality Standard (NAAQS) for PM10 cited in

the AAQIR is out of date compared to a new NAAQS for PM1 0 adopted September 16, 1997.

The new NAAQS should be implemented immediately. (#44, 46)

Response to C-7:

The 24-hour and annual National Ambient Air Quality Standards

for PM10 cited in the AAQIR (150 μg/m3) were, and are up-to-date with the

PM NAAQS promulgated on July 18, 1997 (68 FR 38652) and effective

September 16, 1997. The 1997 standard for PM10 was revised from the

previous standard to be based on the 3-year average of the 99th percentile

of 24-hour PM10 concentrations at each monitor within an area. The

numerical level of the standard 150 μg/m3 was not changed in the 1997

rule. The annual PM 1 0 standard was retained in the 1997 rule to be based

on the 3-year average of the annual arithmetic mean PM10 concentration at

each monitor in an area.

The 1997 PM Rule also created NAAQS for PM2 5. However, due

to the technical limitations associated with the monitoring, emissions

estimation, and modeling of PM2 5, EPA issued a guidance memorandum

from John S. Seitz, Director, Office of Air Quality Planning and Standards,

to Regional Air Directors (October 13, 1997), regarding interim

implementation of the New Source Review Requirements for PM2 5. This

guidance applies to the PSD program and recommends interim use of PM10

emissions as a surrogate for PM2. 5 until the PM2.5 final NSR

implementation rule is promulgated. Thus, if emissions of PM10 are

determined to be in compliance with BACT and the air quality impacts

analyses, then the source can be considered to be in compliance for PM2 , 5

emissions. This guidance was reaffirmed in an additional guidance

memorandum from Stephen D. Page, Director, Office of Air Quality

Planning and Standards to Regional Air Directors (April 5, 2005).

The modeled impacts of the Modernization Project on the 24-hour

and annual average NAAQS are in compliance with the appropriate air

quality standards for PM10, promulgated July 18, 1997 and effective

September 16, 1997. Therefore, the Modernization Project is in compliance

with respect to both PM 1 0 and PM2. 5 NAAQS.

Section D: PSD Permit Conditions

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that is 46% lower than the PM IO NAAQS of 150 ug/rrr', Therefore, the 60% 

increase in potential emissions results in a modeled maximum worst-case 

scenario increase in ground level concentration of 42%, which does not 

result in any violations of the PMIO NAAQS. 

7. The current applicable National Ambient Air Quality Standard (NAAQS) for PM/ o cited in 

the AAQIR is out ofdate compared to a new NAAQS for PMlo adopted September 16, 1997. 

The new NAAQS should be implemented immediately. (#44, 46) 

Response to C-7: 

The 24-hour and annual National Ambient Air Quality Standards 

for PM IO cited in the AAQIR (150 ug/rrr') were, and are up-to-date with the 

PM NAAQS promulgated on July 18, 1997 (68 FR 38652) and effective 

September 16, 1997. The 1997 standard for PM IO was revised from the 

previous standard to be based on the 3-year average of the 99 th percentile 

of 24-hour PM IO concentrations at each monitor within an area. The 

numerical level of the standard 150 ug/m" was not changed in the 1997 

rule. The annual PM IO standard was retained in the 1997 rule to be based 

on the 3-year average of the annual arithmetic mean PM IO concentration at 

each monitor in an area. 

The 1997 PM Rule also created NAAQS for PM 2.5. However, due 

to the technical limitations associated with the monitoring, emissions 

estimation, and modeling of PM2.5, EPA issued a guidance memorandum 

from John S. Seitz, Director, Office of Air Quality Planning and Standards, 

to Regional Air Directors (October 13, 1997), regarding interim 

implementation of the New Source Review Requirements for PM 2.5. This 

guidance applies to the PSD program and recommends interim use ofPMlO 

emissions as a surrogate for PM 2.5 until the PM2.5 final NSR 

implementation rule is promulgated. Thus, if emissions ofPMIO are 

determined to be in compliance with BACT and the air quality impacts 

analyses, then the source can be considered to be in compliance for PM 2.5 

emissions. This guidance was reaffirmed in an additional guidance 

memorandum from Stephen D. Page, Director, Office of Air Quality 

Planning and Standards to Regional Air Directors (April 5,2005). 

The modeled impacts ofthe Modernization Project on the 24-hour 

and annual average NAAQS are in compliance with the appropriate air 

quality standards for PM IO, promulgated July 18, 1997 and effective 

September 16, 1997. Therefore, the Modernization Project is in compliance 

with respect to both PMIO and PM 2.5 NAAQS. 

Section D: PSD Permit Conditions 

l80f21 
1. Limits placed on PM10 emission rates are ineffective and unenforceable due to the lack of

continuous in-stack monitoring of PMio. (# 12, 23, 44, 46)

Response to D-1:

Performance tests for PK() emissions from the turbine exhaust

stacks are required within 60 days after achieving maximum load, but no

later than 180 days after initial startup, and annually thereafter. The PSD

permit specifies that these tests must use the EPA-approved methods,

Methods 5 and 202, for measuring PM10 emissions. Monthly samples of

the natural gas combusted will monitor the sulfur content of the fuel, which

is limited by the PSD permit to 0.25 gr/100 scf. Noncombustible trace

constituents of fuel and the sulfur content of the fuel contribute to PMio

emissions from the natural gas-fired turbines. The use of low sulfur,

pipeline quality natural gas fuel limits PM10 emissions to negligible

amounts, as reported in AP 42, Chapter 3-1 (Stationary Gas Turbines) .

The reporting and record-keeping requirements regarding date,

time, and total duration of startups and shutdowns of each turbine, and

firing hours and fuel flow rates from each turbine and duct burner, will

provide the necessary information to determine compliance with the annual

PM1 0 emission limit based on the measured PM10 emission rate from the

performance tests. PM 10 continuous emission monitoring systems (CEMS)

are typically used at coal-fired power plants to monitor primary PM10.

Emissions of PM 10 from natural gas-fired power plants are dominated by

condensable particulates (secondary PM 10), and the concentration of

primary PM10 emissions from natural gas fired power plants are too low to

be reliably measured with CEMS. Thus, annual performance testing using

EPA Methods 5 and 202, and monthly testing of the fuel sulfur content, are

the most reliable methods for ensuring compliance with PM 10 emission

limits.

Section E: Human and Ecosystem Health

1. The Modernization Project, particularly the proposal to shorten the stack height, will pose a

health threat to the local community as well as to bird populations that use the Morro Bay

Estuary. (# 2-8, 14-16, 18-20, 22, 24-28, 32, 33, 35-36, 38-39, 42, 44-46)

Response to E-1:

New stack heights of 145 feet (reduced from previous heights of

450 feet) were proposed by the applicant as a balance between engineering,

public health, and aesthetic considerations. The new stack heights are in

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1. Limits placed on PM fO emission rates are ineffective and unenforceable due to the lack of 

continuous in-stack monitoring ofPMfO. (# 12,23, 44, 46) 

Response to D-l : 

Performance tests for PM IO emissions from the turbine exhaust 

stacks are required within 60 days after achieving maximum load, but no 

later than 180 days after initial startup, and annually thereafter. The PSD 

permit specifies that these tests must use the EPA-approved methods, 

Methods 5 and 202, for measuring PM 10 emissions. Monthly samples of 

the natural gas combusted will monitor the sulfur content of the fuel, which 

is limited by the PSD permit to 0.25 gr/l 00 scf. Noncombustible trace 

constituents of fuel and the sulfur content ofthe fuel contribute to PM lO 

emissions from the natural gas-fired turbines. The use of low sulfur, 

pipeline quality natural gas fuel limits PM lO emissions to negligible 

amounts, as reported in AP 42, Chapter 3-1 (Stationary Gas Turbines) . 

The reporting and record-keeping requirements regarding date, 

time, and total duration of startups and shutdowns of each turbine, and 

firing hours and fuel flow rates from each turbine and duct burner, will 

provide the necessary information to determine compliance with the annual 

PM lO emission limit based on the measured PM lO emission rate from the 

performance tests. PM lO continuous emission monitoring systems (CEMS) 

are typically used at coal-fired power plants to monitor primary PM lO . 

Emissions ofPM 1o from natural gas-fired power plants are dominated by 

condensable particulates (secondary PM lO) , and the concentration of 

primary PM IO emissions from natural gas fired power plants are too low to 

be reliably measured with CEMS. Thus, annual performance testing using 

EPA Methods 5 and 202, and monthly testing of the fuel sulfur content, are 

the most reliable methods for ensuring compliance with PM lO emission 

limits. 

Section E: Human and Ecosystem Health 

1. The Modernization Project, particularly the proposal to shorten the stack height, will pose a 

health threat to the local community as well as to bird populations that use the Morro Bay 

Estuary. (# 2-8, 14-16, 18-20,22,24-28,32,33,35-36,38-39,42,44-46) 

Response to E-l : 

New stack heights of 145 feet (reduced from previous heights of 

450 feet) were proposed by the applicant as a balance between engineering, 

public health, and aesthetic considerations. The new stack heights are in 

190f21 
compliance with Good Engineering Practice (GEP) stack height, as defined

in 40 CFR § 51.100 (ii), and the GEP provisions of 40 CFR § 51.118.

The change in air quality resulting from the increase in emissions at

the facility was modeled with the shorter stack height of 145 feet. The

maximum modeled impact of the facility, estimated as the worst-case

ground level concentration over a 24-hour averaging period (the averaging

time for the National Ambient Air Quality Standard, or NAAQS), will

increase by 24.2 micrograms of PM10 per cubic meter of air (μg/m3 ), which

is lower than the PM10 increment of 30μg/m3 . The impact of the

Modernization Project combined with the background PM10 concentration

results in a total impact of 81.2 [ig/m 3 , which is lower than the PM10

NAAQS of 150 μg/m3 .

Because the ambient air quality analyses, based on worst-case

ground level conditions using the new (lower) stack heights of 145 feet,

showed that the Modernization Project would not result in concentrations

that exceed the NAAQS or PSD increments, EPA finds the proposed stack

height acceptable because public health and welfare remain protected.

2. What will the impact of PM10 be on endangered species? (# 31)

Response to E-2:

Pursuant to Section 7 of the Endangered Species Act ("ESA"), 16

USC § 1536 and 50 CFR Part 402, EPA consulted with the National Marine

Fisheries Service ("NMFS") and the Fish and Wildlife Service ("FWS"). In

a letter dated May 17, 2002 from Rodney R. McInnis, Acting Regional

Administrator for the NMFW Southwest Region, to Gerardo C. Rios, Chief

of the EPA Region IX Air Permits Office, NMFS concluded that the

Modernization Project is not likely to adversely affect federally threatened

steelhead (Oncorhynchus mykiss).

The FWS issued a Biological Opinion ("BO") on the proposed

project on May 23, 2003. The BO concluded that the Modernization

Project is not likely to jeopardize the continued existence of the federally

threatened California red-legged frog (Rana aurora draytonii), the

endangered Morro shoulderband snail (Helminthoglypta walkeriana), or

the tidewater goby (Eucyclogobius newberryi). The BO included

reasonable and prudent measures ("RPMs") that are necessary to minimize

impacts of the Modernization Project on these listed species. In a letter

dated June 23, 2005, and submitted as an addendum to the PSD permit

application, Duke Energy Morro Bay, LLC, from Randall J. Hickok, Vice

President of California Assets, to Gerardo C. Rios, stated that the

Modernization Project will implement the RPMs, terms, conditions, and

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compliance with Good Engineering Practice (GEP) stack height, as defined 

in 40 CFR § 51.100 (ii), and the GEP provisions of 40 CFR § 51.118. 

The change in air quality resulting from the increase in emissions at 

the facility was modeled with the shorter stack height of 145 feet. The 

maximum modeled impact of the facility, estimated as the worst-case 

ground level concentration over a 24-hour averaging period (the averaging 

time for the National Ambient Air Quality Standard, or NAAQS), will 

increase by 24.2 micrograms of PMIO per cubic meter of air (ug/rrr'), which 

is lower than the PM IO increment of 30llg/m3. The impact of the 

Modernization Project combined with the background PM 10 concentration 

results in a total impact of 81.2 ug/rrr', which is lower than the PM IO 

NAAQS of 150 ug/nr'. 

Because the ambient air quality analyses, based on worst-case 

ground level conditions using the new (lower) stack heights of 145 feet, 

showed that the Modernization Project would not result in concentrations 

that exceed the NAAQS or PSD increments, EPA finds the proposed stack 

height acceptable because public health and welfare remain protected. 

2. What will the impact ofPMIO be on endangered species? (# 31) 

Response to E-2: 

Pursuant to Section 7 of the Endangered Species Act ("ESA"), 16 

USC §1536 and 50 CFR Part 402, EPA consulted with the National Marine 

Fisheries Service ("NMFS") and the Fish and Wildlife Service ("FWS"). In 

a letter dated May 17,2002 from Rodney R. McInnis, Acting Regional 

Administrator for the NMFW Southwest Region, to Gerardo C. Rios, Chief 

of the EPA Region IX Air Permits Office, NMFS concluded that the 

Modernization Project is not likely to adversely affect federally threatened 

steelhead (Oncorhynchus mykiss). 

The FWS issued a Biological Opinion ("BO") on the proposed 

project on May 23, 2003. The BO concluded that the Modernization 

Project is not likely to jeopardize the continued existence ofthe federally 

threatened California red-legged frog (Rana aurora draytonii) , the 

endangered Morro shoulderband snail (Helminthoglypta walkeriana), or 

the tidewater goby (Eucyclogobius newberryi). The BO included 

reasonable and prudent measures ("RPMs") that are necessary to minimize 

impacts ofthe Modernization Project on these listed species. In a letter 

dated June 23, 2005, and submitted as an addendum to the PSD permit 

application, Duke Energy Morro Bay, LLC, from Randall J. Hickok, Vice 

President of California Assets, to Gerardo C. Rios, stated that the 

Modernization Project will implement the RPMs, terms, conditions, and 

200f21 
reporting requirements contained in the BO into the project description.

The Morro Bay Power Plant changed names in 2006 to LSP Morro Bay,

LLC, and in 2007 to Dynegy Morro Bay, LLC. In letters submitted to

Gerardo C. Rios on May 8, 2006 and May 30, 2007, LSP and Dynegy

notified EPA of the name change, and reaffirmed the facility's previous

commitments related to compliance with the PSD permit, including the

requirements of the Biological Opinion.

Section F: Changes to the proposed PSD permit unrelated to comments received

1. The proposed PSD permit did not include an averaging time associated with the PM 1 0

emission limit of 11 and 13.3 lb/hr. The final PSD permit states that each turbine is subject to

the pound per hour PM10 emission limits on a six-hour rolling average basis.

2. The proposed PSD permit was modified to specify a required test method for the monthly

fuel sulfur analyses. The permit will require use of ASTM D5504, one of the fuel sulfur test

methods acceptable under NSPS Subpart KKKK. EPA or District approved alternative test

methods for fuel sulfur content may be used in lieu of ASTM D5504 upon EPA approval.

3. Emissions of particulate matter (PM) are subject to PSD review when emitted at rates

exceeding the significance level of 25 tons per year (tpy). Emissions of particulate matter less

than 10 microns in aerodynamic diameter (PM10) are regulated by PSD when emitted at rates

exceeding the significance threshold of 15 tpy. Because a natural gas-fired power plant is not

expected to emit course particulate matter (PM greater than 10 microns in aerodynamic

diameter), emissions of PM are expected to be equivalent to emissions of PM10. The PSD

permit proposed in May 2006 addressed only PM10, and did not address PM; however, PM is

subject to PSD review because emissions will exceed 25 tpy. Since no distinct air quality

standard exists for PM, and since emissions of PM and PM10 will be equivalent, PSD review

for PM10 satisfies requirements for PSD review for PM. The final PSD permit was modified

to replace references to "PM10" with "PM/PM1o".

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reporting requirements contained in the BO into the project description. 

The Morro Bay Power Plant changed names in 2006 to LSP Morro Bay, 

LLC, and in 2007 to Dynegy Morro Bay, LLC. In letters submitted to 

Gerardo C. Rios on May 8,2006 and May 30, 2007, LSP and Dynegy 

notified EPA of the name change, and reaffirmed the facility's previous 

commitments related to compliance with the PSD permit, including the 

requirements of the Biological Opinion. 

Section F: Changes to the proposed PSD permit unrelated to comments received 

1. The proposed PSD permit did not include an averaging time associated with the PM IO 

emission limit of 11 and 13.3 lb/hr. The final PSD permit states that each turbine is subject to 

the pound per hour PM IO emission limits on a six-hour rolling average basis. 

2. The proposed PSD permit was modified to specify a required test method for the monthly 

fuel sulfur analyses. The permit will require use of ASTM D5504, one of the fuel sulfur test 

methods acceptable under NSPS Subpart KKKK. EPA or District approved alternative test 

methods for fuel sulfur content may be used in lieu of ASTM D5504 upon EPA approval. 

3. Emissions of particulate matter (PM) are subject to PSD review when emitted at rates 

exceeding the significance level of25 tons per year (tpy). Emissions of particulate matter less 

than 10 microns in aerodynamic diameter (PM IO) are regulated by PSD when emitted at rates 

exceeding the significance threshold of 15 tpy. Because a natural gas-fired power plant is not 

expected to emit course particulate matter (PM greater than 10 microns in aerodynamic 

diameter), emissions of PM are expected to be equivalent to emissions ofPMIO. The PSD 

permit proposed in May 2006 addressed only PMIO, and did not address PM; however, PM is 

subject to PSD review because emissions will exceed 25 tpy. Since no distinct air quality 

standard exists for PM, and since emissions of PM and PM IO will be equivalent, PSD review 

for PM IO satisfies requirements for PSD review for PM. The finalPSD permit was modified 

to replace references to "PMIO" with "PM/PM IO" . 

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