Carlsbad Energy Center LLC 1817 Aston Avenue, Suite 104 Carlsbad, CA 92008
Direct: (760) 710-2146 Fax: (760) 710-2158 

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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. 

### PSD Applicability
For purposes of PSD applicability, the proposed CECP project is a modification to an existing major facility. Therefore, to determine whether the proposed CECP project will trigger PSD review as a major modification to an existing major facility, it is necessary to first determine whether the potential to emit for the proposed new equipment are significant under the PSD regulation. If the emission increase for the new equipment isMr. 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 PM 1 0 39.0 15 Note (Table 1): * See Attachment 1, Table 5c and permit condition 44 for potential to emit levels for new equipment (combined emissions from two gas turbines and fire-pump engine).
To determine the facility-wide net emission change of NOx, CO, and PM, 0 associated with the proposed installation of the new equipment, it is necessary to sum the new equipment emission increases with other emission increases and decreases at the power plant during the contemporaneous period. Under the PSD regulation the contemporaneous period begins five years before the start of construction of the proposed new equipment, and ends

2009-06-05 EPA PSD determination letter 

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### 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.
In the following table, the potential to emit for the new units associated with the proposed CECP project are included with the contemporaneous emission decrease associated with the shutdown of Encina Units 

### 1, 2, and 3 (based on actual emissions during 2004 and 2005). As shown in Table 2, the facility-wide net emission increase for the proposed CECP project is below PSD significance levels for NOx, CO, and PM 10 . Therefore, the proposed CECP project does not trigger PSD review.

2009-06-05 EPA PSD determination letter 

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)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 information, please do not hesitate to call me at (760) 710-2156.
Sincerely,

George L. Piantka, PE Carlsbad Energy Center LLC

2009-06-05 EPA PSD determination letter 

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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)

2009-06-05 EPAPSDdeterminationjetter 

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### ATTACHMENT 1

SDAPCD ENGINEERING EVALUATION PDOC FOR CECPAIR 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 POLLUTIO N CONTROL DISTRICT
Applications Number 9857 45, 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 Em issions—Commissioning period ................................ 13 Project Emissions—Commissioning period ....................................................................... 15 V. RULES ANALYSIS ........................................................................................................ 17 District and Federal NS R 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.................................................................................................................. 1 7 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 Siti ng 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 – R easonably Available Control Technology ........ 42 Rule 69.3.1 – Stationary Gas Turbines – Best Available Retrofit Control Technology. 42 Rule 69.4 – Stationary Reciprocating In ternal Combustion E ngines – Reasonably Available Control Technology........................................................................................ 43 Rule 69.4.1– Stationary Reciprocating Intern al 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 Stationa ry 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 Em issions Standards for Hazardous Air Pollutants for Stationary Compression I gnition Internal Combustion Engines.............. 49 New Source Performance Standards (NSPS) ..................................................................... 49 40 CFR Part 60- Subpart KKKK- National Stan dards of Performance for New Stationary Combustion Turbines.......................................................................................................... 49 40 CFR Part 60 Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combus tion (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 Ev aporative 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 ConditionsPreliminary Determination of Complianc e 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 co mbine 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 nomina l gross power output is 208 megawatts (MW) with a corresponding heat input of 1976 milli on 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 evap orative coolers that can be used cool the inlet air to each turbine to increase power dur ing periods of high ambient temperature. Each CTG is followed by a heat recovery steam ge nerator (HRSG) equipped with a selective catalytic reduction (SCR) system to redu ce oxides of nitrogen (NOx) emission and an oxidation catalyst to control the carbon m onoxide (CO) and volatile organic compounds (VOC) emissions. Steam from each HRSG w ill 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 turb ine 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 En ergy Commission (CEC) because the proposed power plant has a nominal rati ng greater than 50 MW. CECP filed an application for certification (A FC) with the CEC in September 2007 (07-AFC-6). The San Diego Air Pollution Control Distri ct (District) is considered a responsible agency for this approval and is required to submit a Preliminary Determinat ion of Compliance (PDOC) and a Final Determination of Compliance (FDOC) to th e 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 ofPreliminary Determination of Complianc e 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 ex isting utility boilers, known as Units 1, 2, and 3,
at the Encina Power Station will be retired wh en the two combined-cycled turbines are fully operational (the other two utility bo ilers will remain in operation).

The project will be fueled by natural gas, wh ich will be supplied by the San Diego Gas and Electric Company. No provisions fo r use of an alternative fuel in the event of a curtailment of the natural gas supply ar e proposed by the applicant.Preliminary Determination of Complianc e Page 3 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### II. EQUIPMENT DESCRIPTION

CECP has proposed to construct and operate th e following equipment at this facility under application No. 985745, 985747, and 984748:

• Application 985745: Power block Unit #6 c onsisting of one nominal 208 MW (219 MW with steam augmentation) natural- gas fired combined-cycle Siemens SGT6- PAC5000F combustion turbine ge nerator, serial number to be determined, with an ultra low NOx (ULN) combustor, an evapor ative 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 c onsisting of one nominal 208 MW (219 MW with steam augmentation) natural- gas fired combined-cycle Siemens SGT6- PAC5000F combustion turbine ge nerator, serial number to be determined, with an ultra low NOx (ULN) combustor, an evapor ative 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, rate d at 246 brake horsepower, serial number
to be determined.Preliminary Determination of Complianc e 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 fr om 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 natura l gas is converted to mechanical energy to drive the combustion turbine compressor and electr ic generator. The hot CTG exhaust gases at approximately 1,100°F enter the HRSG. In the HR SG, boiler feedwater is converted to steam and delivered to the STG. Steam leaving the stea m 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 fa st starting capability of a s imple-cycle gas turbine and the efficiency of a combined-cycle plant. The syst em is designed to start and reach 150 MW in ten minutes for a hot start and operate with combined-c ycled efficiency in 45 minutes for a hot start and approximately 125 minutes for a cold st art. The one-hour averaged NOx emission concentration is controlled to 2 parts per milli on by volume on a dry basis (ppmvd) and corrected to 15 percent oxygen (O 2 

### ) by a combination of the ULN combustor in the CTG and the SCR system located in the HRSG. In the SCR, ammoni a will be injected into the CTG exhaust stream via nozzles located upstream of the catalyst modu le. 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 em issions to 2.0 ppmvd averaged over one hour. Exhaust from each HRSG will be discharged fr om individual 21.3-foot diameter stacks proposed
to be 139-foot tall.

Each CTG is equipped with a continuous emi ssion monitoring systems (CEMS) to sample, analyze, and record the natural gas fuel flow rate, NOx and CO concentration levels, and percentage of O 2 

### in the exhaust gas from the HRSG stack. The data will be transmitted to a data acquisition and handling system (DAH S) 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 Complianc e 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 a pplicant has provided CTG performance data and emission data based on vendor guarantees for oper ations 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 com bustion turbine and lasting until the turbine can achieve the most stringent em ission limits during normal operations (for this turbine the manufacturer has guaranteed turbine emissions at greater th an 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 nece ssary to achieve the mo st stringent emission limits during normal operations of its load cap acity and ending when combustion has ceased. The minimum load is typically between 40% an d 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 si gnificantly 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 tu rbine per year and 300 shutdowns per turbine per year. Maximum annual emissions are calculat ed based on 300 hours w ith a startup, 300 hours with a shutdown, and 3,500 hours per year at fu ll-load operation under average conditions for
both CTGs.

The CECP may be completed in two phases exp ected to end in 2012 w ith the two combustion turbines sequentially achieving full operation. Ph ase I would consist of bringing one CTG/STGPreliminary Determination of Complianc e Page 6 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### to full operation. Phase II would consist of brin ging the remaining CTG/STG to full commercial operation. The completion of these two phases coul d be separated by as much as six months. Consequently, the three existing utility boilers may also be re tired, or have their operations limited, in two phases. During the phase-in proc ess the applicant has committed to not operating
the combustion turbines and the steam boile rs simultaneously, which minimizes emission impacts. However, to maintain grid reliabilit y, 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 Complianc e Page 7 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### IV. EMISSION ESTIMATES

C OMBUSTION 

### T URBINE 

### G ENERATOR 

### E MISSIONS 

### —S TANDARD OPERATIONS



### M AXIMUM 

### H OURLY 

### E MISSIONS 

### Project emissions of NOx, CO, sulf ur oxides (SOx), VOC, particulat e 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 da ta supplied by the turbine manufacturer and emission limits in proposed permit conditions. The startup and shut down, emission rates are provided by the turbine manufactur er. For steady state operations, emission rates for NOx, CO,
and VOC are calculated based on emission concentration limits (in ppmvd at 15%O 2 

### ) in proposed permit conditions and exhaust flow rates in dry standard cubic feet per hour (dscfh) at average ambient temperature for annual emission s 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 cu bic feet based on the California Public Utility Commission (PUC) standard for pipeline natural ga s. Emissions of PM10 are calculated based on vendor supplied guaranteed emission rates. Tabl e 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 Complianc e 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 ty pically approximately 22 minutes of emission rates higher than emissions during normal operation. Therefore, h ourly 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 appr oximately 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 opera tion 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 mi nutes of normal emissions and 7 minutes of
shutdown emissions. Because there is some va riability in emissions during startup and shutdown, the hourly emissions for CO and NOx ar e estimated at twice the expected emission value. Table 1b presents the maximum emissi on 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 em ission 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 Complianc e 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) + (shut down emissions, lbs/hr) x (6 hours/day) + (steady state opera tion emissions, lbs/day) x (12 hours /day)

Table 1c presents estimated maximum daily em issions 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 pe r year, of which 300 hour s 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 st ate operation emissions, lbs/day) x (3500 hours /years)

Table 1d presents estimated maximum turbine an nual 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

E MERGENCY 

### F IRE 

### P UMP 

### E NGINE 

### E MISSIONS 

### At a minimum, the diesel emergency fire pump engine must comply with Tier 2 emission standards for EPA certified engines of model y ear 2008. Daily emissions from the engine are
calculated based on one hour of operation and annual emissions ar e 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 0.0008Preliminary Determination of Compliance Page 12 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### P ROJECT 

### E MISSIONS 

### —S TANDARD OPERATIONS 

### Total emissions from the project include emissi on 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 pe r 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 po llutant emissions, are presented in details in
the Toxic Health Risk Assessment Secti on in Appendix B of this determination.Preliminary Determination of Compliance Page 13 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### C OMBUSTION 

### T URBINE 

### G ENERATOR 

### E MISSIONS 

### —C OMMISSIONING 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 tune d 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 plan t is expected to operate 415 hours per turbine over approximately 49 operating days during this commissioning period, wh ich includes hours of operation at different load le vels and with and without em ission control equipment. Commissioning emission data provided by the tu rbine vendor consist of different emission scenarios corresponding to differe nt phases of the commissioning pe riod. Table 4a presents the expected commissioning maximum hourly emission rates. In order to minimize emission impacts during the commissioning period, emissi on 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 (includi ng 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 ma ximum 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 duringPreliminary Determination of Compliance Page 14 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### commissioning, peak daily emissions during commi ssioning 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 tu rbine under normal operatio ns. 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 turb ine vendor projected emission data for the entire commissioning period. The emergency fire pump engine is not exp ected to operate during the turbine commissioning period. Table 4c presents total commi ssioning emissions. Note that
these emissions include all emissions from st artups 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

P ROJECT 

### E MISSIONS 

### —C OMMISSIONING PERIOD 

### For the combustion turbines’ first year of ope ration during which both commissioning operations and normal operations take place, total maximu m 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 emergenc y fire pump engine. Table 4d presents the
estimated total maximum annual emissions for th e 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 34.32Preliminary Determination of Compliance Page 17 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### V. RULES ANALYSIS

D ISTRICT AND 

### F EDERAL 

### NSR AND 

### PSD R EGULATIONS



### 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 gr eater 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 pollutant s 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 particul ar, the major modification thres holds (see below) apply for contemporaneous emission increases and associat ed requirements for NOx and VOCs. Based on its potential to emit, the Encina Power Station is an existing major sta tionary 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, PS D Stationary Source status is defined by an aggregate potential to emit one or more air contam inants 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
NO 2 

### 100
VOC 100
SO 2 

### 100
CO 100 Lead (Pb) 100

Since the Encina Power Station’s potential to em it exceeds the PSD stationary source threshold for at least one pollutant (e.g., NOx, which is considered NO 2 

### for purposes of PSD determinations), it is an existing PSD stationary source. District Ru le 20.1 does not explicitly address PM2.5 or particulate matte r of all sizes (PM). However, those pollutants are addressed by 40 CFR 52.21 et. seq., which is EPA’s implemen tation 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 st ationary source within the calendar year in which the subj ect emission units is expected to “commence operation” and the preceding four calendar years, including all othe r emission units with complete applications
under District review and which are expected to commence operati on 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 exis ting 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 a llowed before the actual em ission reduction must be effective in federal implementations of PSD re gulations [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 Un its 1, 2, and 3 at the Encina
Power Station. At the end of Phase I of th e project, full commercial operation for one of the CTG/STG systems, part of the electrical gene rating 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-i n period and the boilers must be shutdown completely at the end of Phase II.

In this case, 180 days is a reasonable sh akedown 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 operatio nal status including veri fication testing both for emissions and operational reliability. The sh akedown periods for the two CTG/STG systems could proceed in parallel or sequentially.

Postproject Contemporaneous Emission Increase Currently, the proposed CECP is expected to co mmence full commercial operation in 2012. Full commercial operation includes having both CTGs a nd 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 expect ed 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 opera tion at any time in the future. Therefore, thePreliminary Determination of Compliance Page 20 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### only emission increases for contemporaneous emi ssion 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 reducti ons occurring at the stationary source. Rule 20.1(d)(4)(ii)(A) defines actual em ission reductions from the shutdown of an emission unit as
those calculated based on the emissi on unit’s preproject actual emissions.

Preproject actual emissions are based on actua l 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 operati onal time period within the five-y ear period if a representative two-year operating time period doe s not exist. Since the Applicat ion for Certification (AFC) for this CECP was submitted to the CEC in 2007, the pr eceding 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 tw o-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 ac tual emissions for those units. In the case of NOx, the emissions are based on CEMS data. Fo r 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 ex isting 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 th e backup fuel. This necessitates the adjustment of the emission inventory of PM2.5 and PM10 si nce No. 6 fuel oil co mbustion produces some particulate matter greater than 2.5 microns and so me particulate matter gr eater than 10 microns.

Table 5a presents the data used to determ ine 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 comple tion 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 ac tual emission reductions due to shut down of the three existing utility boilers. The maximum annual emissi ons are based on the larger of the emissions during a standard operation y ear 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 Estima ted 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 incr ease, 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 in itial startup. These limits were accepted by the applicant to ensure annual em issions did not exceed those up on 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 Co mpletion of the Phase I Shakedown Period The CECP contemplates starting operation of th e two CTG/STG units se quentially. 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 ope ration of a single com bustion 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, li mit emissions to a level consistent with the emission offsets provided (see below). Consiste nt with the necessary shakedown period for the CTG/STG system (not to exceed 180 days), th e 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 util ity boilers are not limited). Therefore, the emission limits for Units 1, 2, and 3 do not appl y 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 com bustion turbine has an ini tial 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 potentialPreliminary Determination of Compliance Page 24 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### to emit of all the emission units associated wi th the CECP during both phases of the shakedown period.

The Phase I limits in Table 5d and 5e are no long er applicable at the end of the shakedown period for the second CTG/STG system (i.e., the e nd 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 reduc tions from emission limitations on the three existing utility boilers at the end of Phase I a nd 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 0Preliminary 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 Emergenc y 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 precurs ors NOx and VOCs are evaluated to determine whether a major modification occurs. The ma jor modification threshold for both NOx and VOCs is a contemporaneous emission increase of th e 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 modificat ion 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 Modi fication and 40 CFR 52.21 A PSD modification is a contemporaneous emi ssion 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
NO 2 

### 40
VOC 40
SO 2 

### 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 th reshold 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 emi ssions 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 Contro l Technology(BACT)/Lowest Achievable Emission Rate(LAER) Subsection 20.3(d)(1)(i) of the rule requires that Best Availabl e 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 in stalled 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 th an 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, SO 2 

### , PM2.5 and PM10, LAER does not applyPreliminary 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 combusti on 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 em ission unit at a PSD stationary
source with an emission increase of one or mo re air contaminant which constitutes a new PSD stationary source or PSD modifi cation, 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 CE CP 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, SO x, 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 emissi on 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 Availa ble Control Technology, September 1999, BACT/LAER for NOx emissions fr om combined-cycle combustion turbine is either a NOx emission concentration of 2.5 pp mvd based on a one-hour averaging period or 2.0 ppmvd based on a three-hour averaging period, bo th calculated at 15% oxygen. However ARB is revising its BACT/LAER guidance for power plan ts to include limits achieved or proposed by more recent projects. The District consulte d the BACT / LAER Clearinghouses, other air districts, EPA, and ARB for recent BACT/LAER de terminations. A number of combined-cycle power plants of comparable size were permitted with NOx at 2.5 ppmvd or lower, averaged overPreliminary Determination of Compliance Page 28 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### one hour. The District examined the following pr ojects 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 a nd has been in commercial operation since 2002. This plant has been in compliance w ith a 2 ppmvd NOx limit averaged over one hour, excluding startups and s hutdowns, 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 pl ant is proposed to be permitted at 2.0 ppmvd of NOx averag ed 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 pl ant 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 Dete rmination of Compliance issued on August 22, 2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two rapid response combined-cycle Siemens turb ines 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 perm itted by the District has been able to comply with 2.0 ppmvd NOx limit averag ed over one hour during normal operations, excluding startup and shutdown periods, limite d periods of low load operation, rapid transients, and tuning of the combustors and the SCR.

Based on the above information, the District ha s preliminarily determined that BACT for NOx should be 2.0 ppmvd at 15% oxygen, averaged over one hour for normal operation withPreliminary Determination of Compliance Page 29 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### appropriate exclusions to addr ess technical feasibility for st artups and shutdowns and other abnormal periods of operation. As defined in Ru le 20.1(c)(32), LAER means the most stringent emission limitation, or most effective emission c ontrol device or control technique, unless such emission limit , device or technique is not achiev able. An emission limit of 2.0 ppmvd NOx at 15% averaged over one hour is c onsidered by the District to be the current mo st 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 combus tion turbines will be eq uipped with dry ultra low-NOx combustors and a selective catalytic re duction (SCR) that in combination are designed to achieve 2.0 ppmvd NOx averaged over one hour. The District is unaware of any
demonstrations that alternativ e technologies for cont rol 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 combusto rs and SCR on large (greater than 50 MW) natural-gas-fired combustion turbines. A contin uous emission monitoring system (CEMS) and annual source testing will be used to confirm complian ce with this emission limit.

Carbon Monoxide (CO)—Combustion Turbines, Normal Operations The turbine vendor has guaranteed a CO emissi on 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 em ission 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 th is 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 Clearinghous es, were been consulted for more recent
determinations. The District examined the follo wing 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 pl ant 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 Dete rmination of Compliance issued on August 22, 2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two rapid response combined-cycle Siemens turb ines 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 ha s 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 lik ely achieves 2.0 ppmvd averaged over one hour.

Based on the information above, the District ha s 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 a ppropriate exclusion to address technological feasibility for startups and shutdowns and othe r abnormal periods of ope ration. To meet this requirement, the applicant evaluated the use of an oxidation catalyst, which is the only postcombustion technology currently available to co ntrol CO, VOC, and toxic emissions. This technology is acceptable as BACT fo r CO. The applicant will therefore use an oxidation catalystPreliminary 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)—C ombustion Turbines, Normal Operations The turbine vendor has guaranteed a VOC emissi on 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 fo llowing 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 c onsiderably 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 pp mvd 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-AF C-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 st ringent limit for CTGs larger than 160 MW that are actually operating in the SJVAPCD is 2.0 ppmvd of VOCsPreliminary 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 Dete rmination of Compliance issued on August 22, 2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two rapid response combined-cycle Siemens turb ines 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, excl uding 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 ppm vd averaged over one
hour.

Based on the above information, th e District has preliminarily de termined that BACT for the CECP combustion turbines is 2.0 ppmvd VOC, measured as methane at 15% O 2 

### , based on a onehour averaging period for normal operation with appr opriate exclusion to a ddress technologically feasibility for startups and shutdowns a nd other abnormal periods of operation.

The applicant analyzed the use of an oxidati on catalyst, which is the only post combustion technology currently available to control CO, VOC, and toxic em issions. An initial source test will be used to confirm compliance with th ese 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 wi th these limits using the CEMS data for CO. Compliance will be determined based on both so urce 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—Combusti on Turbines, NOx, CO, and VOCs Startups are limited to 60 minutes and shutdow ns 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 (A mendment Proceeding)]. The expected duration of the turbine startups and shutdowns are 22 minutes and 7 minutes, respectively. The additional time is allowed to address contingenc ies during startups and shutdowns.

Emissions during startup and shutdown are furt her controlled by setting mass emission limits per startup and shutdown event (excluding th e commissioning period) . The mass emission
limits are based on manufacturer emission estimat es 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 th e applicant, to allow for increased emissions during the potential rapid transien ts during these operations. No ad justment factor is used for VOC emissions, also as proposed by the appli cant. 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 shutdownPreliminary 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 S CR 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, speci fically 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 achiev e 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 (u nplanned shutdown) and the resu lting expense and increased emissions from a unplanned startup, automatic c ontrol systems may increa se the fuel to air ratio under some abnormal operati ng 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 combustionPreliminary Determination of Compliance Page 35 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### mode. It is, therefore, not technologically feasible, to ach ieve the BACT emission levels applicable to normal operati ons in such situations.

Startups and shutdowns are abnormal operati ng conditions that are discussed above. The applicant has identified transient events (e xcluding startups and shutdowns) as another abnormal operating condition. Other abnormal ope rating 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 au tomatically reduces the turbine load to prevent an immediate turbine tri p. 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 plan t, 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 minut es in a calendar day nor exceed 40 hours in a calendar year for each turbine.

• The BACT emission limits for normal ope rations with a thr ee-hour-averaging time instead of a one-hour-averaging time are applicab le for any hour in which the change in gross electrical output produced by the co mbustion 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 averag ed and 42 ppmvd averaged over one hour, which correspond to District Rules 69.3.1 and 69.3 st andards, 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 amendm ent 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 a nother large combined-cycle facility.

PM10 and SOx—Combustion Turbines
From the ARB Guidance for Power Plant Siti ng and Best Available Control Technology, September 1999, BACT for this equipment is the us e of natural gas that contains less than 1 grain of sulfur compounds per 100 standard cu bic 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 su lfur compounds per 100 standard cubic feet of natural gas. Therefore, use of PUC quali ty natural gas meeting this 0.75 grains limit is recommended as BACT. In actuality, the natura l gas in the local ga s 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 emergenc y engines is to use an engine fueled with natural gas. However, emergency fire pumps require an independent source of fuel for reliable operation in emerge ncy 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 emer gency fire pump engine is purchase of an engine certified to the most st ringent 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 Qualit y 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 demo nstrate through an AQIA that the project will
not cause or contribute to a violation of a stat e 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 ex ceedance of the National Ambient Air Quality Standards or the State Ambient Air Qua lity Standard. The modeling was done under expected worst-case hourly and annual emi ssion rates during commissioning, startup and shutdown, and normal operations. The analysis shows no violation of any Ambient Air Quality Standard. The analysis can be review ed in the Appendix A of this determination. The proposed permit conditions contain hourly a nd 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 evaluati on be performed for any new PSD stationary source (source that has an aggreg ate 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 uncla ssified 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 applicab le to determining whether a PSD evaluation needs to be performed. The applicant has accep ted that an annual limit of 72.76 tons per year of NOx emissions to keep the project NOx em issions 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 proj ect the applicant hasPreliminary 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 th resholds (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 Ru le 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 Ru le 20.3(d)(3)(iii) are not applic able. 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 fede ral nonattainment criteria pollutant or its precursors which exceed new major source or majo r modification thresholds. The District is a federal nonattainment area only for ozone. Th erefore, 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 modi fication 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 fo r which they are required [Rule 20.1(d)(5)(iii)]. Since the CECP may become operational in two pha ses, 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, th e applicant has accept ed 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 emergenc y fire pump engine. The offsets assigned toPreliminary 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 an y actual emission reducti ons at the facility to reduce the engine’s contemporaneous em ission increase by itself. However, the contemporaneous emission increase for the comb ustion turbine and the emergency fire pump engine combined are limited to a level consis tent with the offsets provided for both emission
units.

Offsets may be actual emission reductions, st ationary source Class A emission reduction credits (ERCs) issued under District Ru les 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 ow ns Emission Reduction Credits (ERCs ) representing 37.6 tons per year
of NOx emission offsets and has identified mo re than 10.3 tons per year of NOx emission offset available for purchase. For the purpose of the PDOC, the Distri ct considers this an adequate demonstration that the a pplicant can obtain sufficient credits.

Rule 20.3(e)(1) – Compliance Certification This rule requires that prior to receiving an Au thority to Construct (or Final Determination of Compliance), an applicant for any new or modifi ed 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 lim itations 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 ope rates the Encina Power Station, which is a major stationary source located in San Die go County, and on whose property the CECP will
be located. The Encina Powe r Station operation has been regulated by the San Diego Air Pollution Control District under permits to oper ate 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 st ate, including the El Segundo Gene rating Station in El Segundo California and the Long Beach Generating Statio n in Long Beach California. A compliance certification for all major sources in the stat e 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 Siti ng and Alternatives Analysis The applicant has provided an analysis of variou s alternatives to the project. This analysis included a No Project alternative, alternative site s, and alternative techno logies. Since all of San Diego County is currently classified as non- attainment for ozone, an alternative location within San Diego would not avoid the proj ect being located in a non-attainment area.

Rule 20.5 – Power Plants This rule requires that the District subm it Preliminary and Final Determinations of Compliance reports to the Calif ornia Energy Commission (CEC). The Final Determination of Compliance is equivalent to a District Au thority 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.

D ISTRICT 

### P ROHIBITORY 

### R ULES



### 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 (nat ural gas), no visible
emissions at or above this le vel are expected during operati on of the power plant.

Rule 51 – Nuisance This rule prohibits the discharge of air contam inants 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 expect ed 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 SO 2 

### ) 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 le ss than or equal 0.1 grains per dry standard
cubic foot of exhaust calculated at 12% CO 2 

### .

Sulfur Compounds The applicant proposes to use Public Utilitie s Commission (PUC) quality natural gas sold in San Diego County. Because of the low sulfur c ontent 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% O 2 

### in the exhaust, assuming all su lfur in the fuel is converted
into SO 2 

### , the concentration by volume of SO 2 

### in the exhaust gas is:

SO 2 

### concentration = (0.75 grai n /100 scf fuel) x (1lb SO 2 

### / 7000 grain) x (385 scf SO 2 

### / 64 lb
SO 2 

### ) x (1 scf fuel / 1015 x 10 -6 

### MMBtu) x (1MMBtu / 8710 dscf of exhaust) x (10 6 

### ) = 0.72 ppm SO 2 

### by volume.

This is well below the Rule 53 limit of 500 ppm SO 2 

### 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% CO 2, 

### 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/dscfPreliminary 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 fr om 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 ba sis. 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 – Re asonably 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 equippe d with dry ultra low NOx combustors and SCR controls for NOx. Proposed permit conditions limit NOx emissions to 2.0 ppmvd during normal operatio ns, 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 sh orter than Rule 69.3 requirements. However, commissioning, low-load operation, tuning, and transi ent periods are still subject to the rule standards. The facility permit will contain cond itions 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 combus tion turbines greater th an 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 specifi es 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 fr om the standards during 120 minute startup and shutdown periods. Maximum durations of startu ps 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 stat ed by the applicant, is 36.5 %. Therefore the
maximum allowable uncontrolled NOx concen tration is 21.9 ppmvd based on a 1-hour averaging period at 15% oxygen and the maximu m 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 equippe d with dry ultra low NOx combustors and SCR controls for NOx. Proposed permit conditions limit NOx emissions to 2.0 ppmvd during normal operatio ns, 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, tuni ng, and transient periods are still subject to the rule standards. The facility permit w ill 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 Int ernal Combustion Engines – Reasonably Available Control Technology This rule applies to stationary internal com bustion engines with brake horsepower rating of 50 or greater and located at a st ationary 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 Intern al 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 propose d engine is an EPA certified engine with NOx emission at 3.92 g/bhp-hr. In addition, proposed permit conditions willPreliminary Determination of Compliance Page 44 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### require the engine to meet the more stringen t 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 th is 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-re settable totalizing meter or a non-resettable hour meter. The proposed engine has an hour meter.

Rule 69.4.1 requires the engine opera tor to conduct periodic mainte nance of the engine and its control system in accordance with a procedur e recommended by the manufacturer or approved by the District. Compliance with this requi rement is verified through recordkeeping.

Rule 69.4.1(g)(1)(v), (vi) requires the engine ope rator to keep records of California Diesel fuel certification and engine maintenance proced ure. Compliance with this requirement is verified through recordkeeping.

Rule 69.4.1(g)(2) requires the engi ne operator to maintain an operating log of the dates and times of engine operation, of the total cumula tive 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 a ll records to be kept on site fo r at least three years and made available to the District upon re quest. The proposed permit condi tions 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 Co ntaminants 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 (TBA CT) must be installed if the HRA shows a cancer risk greater than one in a million. Additional requirem ents apply if the cancer risk is expected to
exceed ten in a million.

An HRA was performed using EPA AP-42 em ission factors and California Air Toxics Emission Factors (CATEF) for t oxic air contaminant emissions from the project, which
include the two combustion turbines and the emer gency fire pump engine. The health risk
was determined to be less than one in a m illion at all the receptors located beyond the plant boundary. In addition, a supplementary HRA wa s 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 ex amine acute, chronic, and cancer health risks during startup and commissioni ng operations. The HRA perform ed shows that the cancer
risk is less than one in a million if the numbe r of startups per turbin e is limited to 1460 per year. Proposed permit conditions limit the numb er of startups for each turbine to 1460 per year, so TBACT is not required. The acute a nd chronic health risk s also meet Rule 1200 requirements. Although TBACT is not requir ed for this project, the oxidation catalyst
installed as BACT for CO a nd VOC emissions will also si gnificantly 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 curren tly 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 

### S TATE 

### R EGULATIONS 

### I MPLEMENTED BY THE 

### D ISTRICT



### 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 s ource 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 Regu lations (CCR) §93115—Airborne Toxic Control Measure (ATCM) for Stationary Compression Ignition Engines The emergency diesel fire pump engine is subj ect to the Title 17 of the California Codes of Regulations (CCR) §93115—Airborne Toxic Cont rol 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 sta tionary 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 require ments 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) requi res 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: whenev er 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 e ngine is located within 500 f eet 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 thr ough 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 st ationary 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 Comp ression 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 ra te 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 emer gency standby diesel-fueled engines (>50 bhp) meet the HC, NOx, NMHC+NO x, and CO standards for off-road engines of the same model year and maximum rate d 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, NM HC + NOx and CO standards for off-road engine of the 2005 model year.

Section 93115.10(a) requires each owner or operato r 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 informati on; 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 fro m 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 prepar e a monthly summary that lists and documentsPreliminary 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 fu el purchase records for CARB diesel fuel. Compliance is required through proposed permit conditions.

Section 93115.10(g)(2) requi res all records to be retained for a minimum of 36 months. Records for the prior 24 months shall be retain ed on-site, and made i mmediately available to District staff upon request. Records for the prio r 25 to 36 months shall be made available to District staff within 5 working days from reque st. Compliance is requ ired 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 certificati on test data for the stationa ry 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 re quirements of the Verification Procedure for the emission control strategy implemented. Engine manufacturer emission da ta were used to verify comp liance with emission standard requirements.

N ATIONAL 

### E MISSIONS 

### S TANDARDS FOR 

### H AZARDOUS 

### A IR 

### P OLLUTANTS 

### (NESHAPS) The Encina Power Station is an existing majo r 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 to ns per year in 2006. Therefore, equipment at the Encina Power Station are subject to NESHAPS applicab le to major stationa ry sources of HAPs.

40 CFR Part 63 Subpart YYYY – National Em issions Standards for Hazardous Air Pollutants for Stationary Combustion Turbines This subpart establishes nati onal 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 demons trate initial and con tinuous compliance withPreliminary 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 th e applicability of th is 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 Ig nition Internal Co mbustion Engines This subpart for stationary compression igni tion internal combustion engines requires [40 CFR §63.6590(c)] engines rated le ss than 500 brake horsepower located at major sources of HAP emissions (and also all engines at nonmaj or sources of HAPs) to comply with the requirements in 40 CFR Part 60 Subpart IIII— Standards of Performance for Stationary Compression Ignition Internal Co mbustion (CIIC) Engines. Th ere are no other requirements applicable to such engines. Proposed permit conditions require compliance with Subpart IIII.

N EW 

### S OURCE 

### P ERFORMANCE 

### S TANDARDS 

### (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 ba sed on the high heating value of the fuel to comply with NOx and SOx emission standards.

Section 60.4320 requires new combined-cycle com bustion 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% O 2 

### averaged over each 30 operating days, or alternatively, a standard of 0.42 pounds per megawatt hour (lb/MWh) during normal opera tions. 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 contro l, NOx emissions from this combustion turbine are controlled to 2 ppm at 15% O 2 

### during normal operation. Information submitted as part of the proposed City of Vernon Power Pl ant (06-AFC-4, Table 8.1B-2 ) indicates that thePreliminary Determination of Compliance Page 50 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### expected typical maximum NOx level for this m odel 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% O 2 

### , 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 star tup hours)] x [50 ppm x (25 shutdown hours)] + (2 ppm x 250 normal opera tion hours)] / (325 hours) = 13 ppm

Therefore, the turbine is expect ed to comply with the NOx emi ssion standard of this subpart. Compliance is required thr ough proposed permit conditions.

Section 60.4330 prohibits sulfur dioxide emissi ons from combustion tu rbine in excess of 0.90 lbs/MW-hour gross output or 0.060 lbs/MMBtu heat input. SO 2 

### emission from the
combustion turbines of this project is 0.002 lbs/MMBtu.

SO 2 

### emission rates = (4.4 lbs/hr) x (1 hour/ 1947 MMBtu) = 0.002 lbs/MMBtu

Therefore, the turbine is in compliance with the SO 2 

### limit requirement.

Section 60.4340(b) requires turbin es 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 diluen t 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 ou tput-based standards must install, calibrate, maintain and operate a watt meter to measure th e 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 exha ust 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 inst alled 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 sh all be installed, calibrated, maintained and operated according to the manufact urer’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 accord ance with 40 CFR Part 75 Appendix A and B. The proposed permit requires continuous mon itoring 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 spec ific procedures. These requirements are included in the proposed permit conditions.

Section 60.4365 exempts the requirem ent to monitor total sulfur c ontent 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 ga s used is 20 grains of sulfur or less per 100
standard cubic feet. Sulfur cont ent 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 c ontent 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 star tup, shutdown and malfunction. The proposed permit includes a condition to satisfy these requirements. Annual source tests are not required pursuant to Subpart KKKK for combusti on 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 em issions 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 performa nce test and annual NOx performance test be conducted in accordance with certain requireme nts. Annual source tests are not required pursuant to Subpart KKKK for combustion turbin e equipment with CEMS. This combustion turbine is required to be sour ce tested initially to demonstrate compliance with NOx, CO, VOC, and ammonia emission standards. The sour ce tests are to be conducted in accordance with the applicable EPA test methods and a pplicable requirements of 40 CFR 75 Appendix B. The proposed permit contains conditions sa tisfying 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 hou r (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 standa rds of Subpart IIII for model year 2009 and later engines.

Section 60.4207 requires that beginning Octobe r 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 th e engine. This requirement is included in the proposed permit conditions.

Section 60.4214 states that owne r of engines that are stati onary emergency standby engines are not required to submit an initial notificationPreliminary Determination of Compliance Page 53 of 56 November 20, 2008 Applications No. 985745, 985747, and 985748 

### A CID 

### R AIN



### 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 affect ed 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 pro cedures for the allocation of sulfur dioxide emission allowances; the tracking, holding and transfer of allowan ces; the deduction of allowances for purposes of compliance and fo r purposes of offsetting excess emissions pursuant to Parts 72; the sale of allowances through EPA-spons ored auctions and a direct sale; the application for allowances from the Conservation and Renewable Energy Reserve; and the application for allowances for desulfur ization of fuel by small diesel refineries. Requirements from this part will be include d in evaluation for the Acid Rain program application required by Part 72. The propos ed permit requires co mpliance 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 op acity data from emission units under the Acid Rain Program. The regulations includ e general requirements for the installation, certification, operation, and ma intenance of continuous emission or opacity monitoring systems, certification tests and procedures, a nd quality assurance tests and procedures. Subpart B on Monitoring Provisions establis hed general operating requirements for thePreliminary 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 proce dures. Subparts F and G establish requirements on recordkeeping and reporting requirements. All applicable requ irements 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

P ARTICULATE 

### E MISSION 

### R ELATING TO THE 

### U SE OF 

### R ECLAIMED 

### W ATER FOR 

### E VAPORATIVE 

### C OOLING 

### The proposed Siemens turbines have inlet air filters located upstream of the evaporative coolers. The evaporative cooler is turn ed on only during normal operation when ambient temperature is higher than 60°F. The particulat e emission factor of 9.5 lbs/hr provided by the turbine vendor includes anticipated partic ulate matter from the evaporative cooler parameters. Therefore, no furt her particulate emissions from the evaporative cooler are
included in the emission calculation.

C OMMISSIONING 

### P ERIOD 

### 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 pe riod, 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 th e initial startup, certai n 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 st ate 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 in itial 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 QUAL ITY IMPACT ANALYSIS1 

## 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 921312 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 NO 2 , CO, SO 2, and PM 10 and PM 2.5 . 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 criter ia pollutant emission rates were provided at each of these three ambient temperatur es. 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 im pact” 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.4Table 3-2Screening Level Modeling Impacts5Table 3-3Emission Rates and Stack Parameters for Refined Modeling6Table 3-3(Continued)Emission Rates and Stack Parameters for Refined Modeling7Table 3-3(Continued)Emission Rates and Stack Parameters for Refined Modeling8Table 3-4Startup/Shutdown and Commissioning Modeling Inputs9 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 projec t 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 CONCENTRATIONS a , PROJECT AREA, 2004-2006 (μg/m 3 )

Pollutant Averaging Time 2004 2005 2006

1-hour 185.9 144.6 152.1 NO 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 SO 2 (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 PM 10 (Escondido) Annual 27 24 24 24-hour b 37 32 28 PM 2.5 (Escondido) Annual 14.1 12.3 11.5 Source: California Air Quality Data, California Ai r Resources Board website; EPA AIRData website. Reported values have been rounded to the nearest tenth of a μg/m 3 except for PM 10 which were already rounded to the nearest integer. Notes: a. With the exception of 24-hr PM 2.5 , bolded values are the highest during the three years and are used to represent background concentrations. b. 24-hour average PM 2.5 concentrations shown are 98 th percentile values rather than highest values because compliance with the ambient air quality standards is based on 98 th percentile readings. Since the ambient standard is based on a 3-year average of the 98 th percentile readings, the 3-year average of the 2004 to 2006 98 th percentile readings was used to r epresent the background concentration.11 TABLE 4-2 NORMAL OPERATION AIR QUALITY MODELING RESULTS FOR NEW EQUIPMENT
Modeled Maximum Concentrations (μg/m 3 )

Pollutant Averaging Time Normal Operations AERMOD Startup/Shutdown AERMOD Fumigation SCREEN3 Shoreline Fumigation SCREEN3 Combined Impacts Both CTGs NO 2 1-hour Annual 13.3 0.1 80.4 a 2.6 c 18.5 c SO 2 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 PM 2.5 /PM 10 24-hour Annual 1.2 0.1 b b 0.9 c 1.7 c Fire pump Engine NO 2 1-hour Annual 108.0 0.1 d d e e e e SO 2 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 PM 2.5 /PM 10 24-hour Annual 0.0 0.0 d d e e e e Combined Impacts New Equipment NO 2 1-hour Annual 108.0 0.1 f f f f f f SO 2 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 PM 2.5 /PM 10 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 shor t-term phenomenon and as such is evaluated only for shortterm averaging periods. d. Not applicable, because engine will not operate during CTG st artups/shutdowns. e. Not applicable, this type of modeling is not performed fo r 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/m 3

NO 2 – 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/m 3 ) Background (μg/m 3 ) Total Impact (μg/m 3 ) State Standard

(μg/m 3 ) Federal Standard

(μg/m 3 )
NO 2 1-hour Annual 127.5 a 0.1 185.9 22.5 313 23 338 56 - 100 SO 2 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 3,228.0 a 675.9 a 6,300 3,800 9,528 4,476 23,000 10,000 40,000 10,000
PM 10 24-hour Annual 1.2 0.1 58 27 59 27 50 20 150

-- PM 2.5 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/m 3 Maximum Modeled Impact for CECP, μg/m 3 Exceed Significant Impact Level? NO 2 Annual 1 0.1 No SO 2 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

PM 10 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 NO 2 , SO 2 and CO.

For PM 10 , 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/m 3 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 t han 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 PM 10 impacts of approximately 1.2 μ g/m 3 , additional AERMOD modeling could be performed for all days in the 2004-2006 period that 24 Hour PM 10 background concentrations were between 49 μ /m 3 and 50 μ g/m 3 (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 μ g/m 3 . 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 PM 10 . 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 PM 10 LEVELS IN SAN DIEGO COUNTY, ESCO NDIDO MONITORING STATION, 1997-2006 ( μ g/m 3 )
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/m 3 ) 29 24 30 30 31 25 33 27 24 24

Number of Days Exceeding:
State Standard (50 μg/m 3 , 24- hour) 3 1 1 2 2 1 5 1 0 1

Federal Standard (150 μg/m 3 , 24- hour) 0 -- 0 0 0 0 3 0 0 0

Source: California Air Quality Data, Ca lifornia 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 17915 TABLE 5.1-7 PM 2.5 LEVELS IN SAN DIEGO COUNTY, ESCONDIDO MONITORING STATION, 1997-2006 ( μ g/m 3 )
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/m 3 , 24-hour) 0 0 0 1 0 0 0 1 0 0
(35 μg/m 3 , 24-hour effective December 17, 2006) -- -- -- -- -- -- -- -- -- --

98 th Percentile -- -- 45.0 48.0 41.0 39.0 34.0 37.0 32.0 28.0 3-yr Average, 98 th Percentile -- -- -- -- 44.7 42.7 38.0 36.7 34.3 32.3

Annual Arithmetic Mean (State Std = 12 μg/m 3 ) -- -- 18.0 15.8 17.5 16. 0 14.1 14.1 12.3 11.5
3-yr Annual Average (Federal Std = 15 μg/m 3 ) -- -- 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 Concentrations a , project area, 2004-2006 (μg/m3)
Pollutant Averaging Time 2004 2005 2006

1-hour 185.9 144.6 152.1 NO 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 SO 2 (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 PM 10 (Escondido) Annual 27 24 24 24-hour b 37 32 28 PM 2.5 (Escondido) Annual 14.1 12.3 11.5 Source: California Air Quality Data, California Air Resources Board webs ite; EPA AIRData w ebsite. Reported values have been rounded to the nearest tenth of a μg/m 3 except for PM 10 which were already rounded to the nearest integer. Notes: a. With the exception of 24-hr PM 2.5 , bolded values are the highest during the three years and are used to represent background concentrations. b. 24-hour average PM 2.5 concentrations shown are 98 th percentile values rather than highest values because compliance with the ambient air quality standards is based on 98 th percentile readings. Since the ambient standard is based on a 3-year average of the 98 th percentile readings, the 3-y ear average of the 2004 to 2006 98 th percentile readings was used to r epresent 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

S UMMARY 

### 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 o 

### F average ambient temperature). At 37 o 

### F 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 emerge ncy 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

2 of 19 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

C ONCLUSION 

### 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

3 of 19 II. EMISSION FACTORS

C OMBUSTION 

### T URBINE 

### G ENERATOR FACTORS 

### —S TANDARD 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

4 of 19 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 Factor s 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 emi ssion 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 cont rolled emission factor is most representative of recent compliance source tests for a large combined-c ycle 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

5 of 19 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

C OMBUSTION 

### T URBINE 

### G ENERATOR 

### E MISSION FACTORS 

### —S TARTUP 

### , S HUTDOWN 

### , AND 

### C OMMISSIONING


### Startup and Shutdown Emission Factors For startup and shutdown emissions, the emission f actors 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

6 of 19 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

7 of 19 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 load s 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 factor s applicable to commissioning operations at loads of 50% or less.

### Rule 1200 Health Risk Assessment Report

8 of 19 Emergency Pump Engine Emission factors The emission factors proposed by the applicant for th e 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/m 3 

### ] based on emission factors for the equipment proposed and operating scenarios. The source strengths were input in to 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 shutdow n 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

9 of 19 • 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 e quivalent 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

10 of 19 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/m 3 

### ) 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/m 3 

### )(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 Co mmissioning 1.52E-02 3.55E-04 5.11E-05

S UPPLEMENTAL 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 fe w 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

11 of 19 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 manufacturer 1 

### . 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 Milli on Hours Fleet Operational Experience, POWER-GEN International 2006, Orlando, FL, November 28-30, 2006.

### Rule 1200 Health Risk Assessment Report

12 of 19 IV. POTENTIAL HEALTH IMPACTS

N ORMAL 

### O PERATIONS


### 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

13 of 19 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

S TARTUP 

### , 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 fr actional 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

14 of 19 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 we re 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 turbin e 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

15 of 19 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

C OMBINED 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] R n 

### + (S/8760)R s 

### + (C/8760)R c 

### 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;

R n 

### is the maximum estimated potential health impact for 8760 hours of normal operations for both turbines combined;

R s 

### is the maximum estimated potential health impact for 8760 hours of startups for both turbines combined; and

R c 

### is the maximum estimated potential health impact for 8760 hours of commissioning for both turbines combined

### Rule 1200 Health Risk Assessment Report

16 of 19 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] R n 

### + (S/8760)R s 

### + (1/70)(C/8760)R c 

### 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

17 of 19 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

18 of 19 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

19 of 19 

### ATTACHMENT A

As part of this review following submittals and documents were reviewed:

• Carlsbad Energy Center Project, Califor nia 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 Mode ling Inputs for Gas Turbines during Startup Phases 1 plus 4 using SDAPCD Emission Factors.

o Table A-5, 9/24/08: Calculation of HHI Mode ling Inputs for Gas Turbines during Startup Phases 2 plus 3 using SDAPCD Emission Factors.

• SDAPCD Air Quality Impact Analysis, Fina l Review Report, Carlsbad Energy Center Project (Application 985423). September 24, 2008.

## APPENDIX C

PROPOSED PERMIT CONDITIONSProposed Conditions Page 1 of 17 November 14, 2008 Applications No. 985745, 985747, and 985748 

### CECP PROPOSED PERMIT CONDITIONS
G ENERAL 

### C ONDITIONS



### 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 equi pment and any associated air pollution control equipment in a manner consistent with good air pollu tion 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 li cense is issued and District Applications Nos. 985745, 985747 and 985748. [Rule 14]

3. The applicant shall provide access, facilities, utiliti es, 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-si te delivery of the equipment. [Rule 10]

5. For each combustion turbine, prior to the initial startup date of that tu rbine, the applicant shall surrender to the District Class A Emission Reduction Credits (ERCs) in an am ount 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 date s for the initial startup date of th e 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 emergenc y fire pump engine. [Rule 20.3(d)(8)]

7. Pursuant to 40 CFR §72.30(b)(2)(ii) of the Federal Acid Rain Progr am, the applicant shall submit an application for a Title IV Operating Permit at leas t 24 months prior to the initial startup of the combustion turbines. [40 CFR Part 72]

8. The applicant shall comply with all applicable pr ovisions of 40 CFR Part 73, including requirements to offset, hold and retire sulfur dioxide (SO 2 

### ) allowances. [40 CFR Part 73]

9. All records required by this permit shall be maintain ed on site for a minimum of five years and made available to the District upon request. [Rule 1421]

C OMBUSTION 

### T URBINE 

### C ONDITIONS



### Definitions

10. For purposes of determining compliance with the emissi on limits of this permit, a shutdown period is the period of time that begins with the lowering of th e 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 consecuti ve 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 tim e that begins when fuel flows to the combustion turbine following a non-operational period. For purposes of determining comp liance with the emission li mits of this permit, the duration of a startup peri od shall not exceed 60 consecutive minutes. [Rule 20.3(d)(1)]

12. A non-operational period is any five-consecutive-mi nute 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 su ch 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 divisi on shall be notified at leas t 24 hours in advance of any tuning event. [Rule 20.3(d)(1)]

14. A Continuous Emission Monitoring System (CEMS) prot ocol is a document approved in writing by the District that describes the me thodology and quality assurance and quality control procedures for monitoring, calculating, and r ecording stack emissions from the com bustion 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 electri cal 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 shutdo wn period. [Rule 20.3(d)(1)]

16. For each combustion turbine, the commissioning pe riod is the period of time commencing with the initial startup of that turbine a nd ending the sooner of 120 calendar da ys from the initial startup, after 415 hours of turbine operation, or the date the pemittee notifies the Di strict 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 an d ending the sooner of 180 calendar days from the initial startup or the date the permittee notifies the Distri ct 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 desc ribed on Applications No. 985745 or No. 985747, as applicable, that first completes it s shakedown period. If both turbines complete their shakedown period on the same date, then Turbine A is the turb ine 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 desc ribed on Applications No. 985745 or No. 985747, as applicable, that last completes it s shakedown period. If both turbines complete their shakedown period on the same date, then Turbine A is the turb ine 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 th at fuel is continuously combusted during the entire period and one or more clock-hour concentration emission lim its specified in this permit areProposed Conditions Page 3 of 17 November 14, 2008 Applications No. 985745, 985747, and 985748 

### exceeded as a result of the low-load operation. Pe riods 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 he ight 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 re cords of the natural gas su lfur content (grains of sulfur compounds per 100 dscf of na tural gas) and hourly records of th e higher and lower heating values (btu/scf) of the natural gas; and provide records to Dist rict 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 emi ssion limits based on source testing, the average of three subtests shall be used. For purposes of de termining compliance with emission limits based on a Continuous Emission Monitoring System (CEMS), da ta collected in accordance with the CEMS protocol shall be used and the averages for averag ing periods specified herein shall be calculated as specified in the CEMS protoc ol. [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 Distri ct. [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 complian ce 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 (ope rating), the emission concentration of oxides of nitrogen (NOx), calculated as nitrogen dioxide (NO 2 

### ), shall not exceed 2.0 parts per million by volume on a dry basis (ppmvd) corrected to 15% oxygen, ex cept 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 calculat ed in accordance with the CEMS protocol shall apply:

A. For any transient hour, a 3-clock-hour average, ca lculated 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 oper ating, 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, ca lculated 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) c oncentration, 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, shutdow n, 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, an d the following averaging periods ca lculated in accordance with the CEMS protocol shall be used:

A. For any transient hour, a 3-clock-hour average, ca lculated 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 modifi ed, if necessary, based on source testing. [Rule 20.3(d)(1)]

31. When a combustion turbine is operating, the ammonia concentration (ammonia sl ip), shall not exceed 5.0 ppmvd corrected to 15 % oxygen, except du ring 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 (NO 2 

### ), shall not exceed 12.9 ppmvd calculated over each clock-hour period and corrected to 15% oxygen, except for periods of startup and shut down, as defined in Rule 69.3.1. This limit does not apply during any period in which the f acility 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 a ny post-combustion air pollution control equipment that controls oxides of nitrogen (NOx) emissions, the emission concentration of NOx calculated as nitrogen dioxide (NO 2 

### ) from each turbine shall not exceed 21.6 parts per million by volume on a dry basis (ppmvd) calculated over each clock-hour peri od and corrected to 15% oxygen, except for periods of startup and shutdown, as defined in Rule 69.3.1. Th is limit does not apply dur ing any period in which the facility is subject to a variance from the emission limits c ontained 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 (NO 2 

### ) 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 definedProposed 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 facil ity is subject to a variance from the emission limits contai ned in Rule 69.3. [Rule 69.3]

35. For each rolling 30-day-unit-operating-day period, av erage emission concentration of oxides of nitrogen (NOx) for each turbine calculated as nitrogen dioxide (NO 2 

### ) in parts per million by volume dry (ppmvd) corrected to 15% oxygen or, alternat ively, as elected by the permittee, the average NOx emission rate in pounds per megawatt-hour (lb/MWh) shall not ex ceed an average emission limit calculated in accordance with 40 CFR Section 60.4380(b)(3). The em ission concentration and emission rate averages shall be calculated in accordance with 40 CF R 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 em ission rate limit shall be 15 ppmvd corrected to 15% oxygen and 0.43 lb/M Wh, 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, re spectively. The averag es 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-m onth period, emissions in excess of these limits and monitor downtime shall be identified in accordance with 40 CF R Sections 60.4350 and 60.4380(b)(2), except that Section 6 0.4350(c) shall not apply for identif ying 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 exhaus t stack of each combustion turbine shall not exceed 0.10 grains per dry standard cubic f oot (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 consec utive 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 limit s shall apply to CEMS data exce pt for emissions during transient hours when a 3-clock-hour av eraging period shall apply.

Pollutant Emission Limit, lb i. Oxides of Nitrogen, NOx (calculated as NO 2 

### ) 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 exce ed the following limits during any startup period, except during that turbin e’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 NO 2 

### ) 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 tu rbine’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 NO 2 

### ) 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 co mbustion turbines combin ed shall not exceed 286 pounds per hour, calculated as nitrogen dioxide a nd measured over each 1-clock-hour period. These emission limits shall apply during all times one or bot h turbines are operating, including, but not limited to, emissions during commissioning, low load operation, startup, shutdo wn, 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 co mbustion turbines combined shall not exceed 4627 pounds per hour measured over each 1-clock-hour peri od. This emission limit shall apply during all times that one or both turbines are operati ng, including, but not limited to emissions during commissioning, low load operation, startup, shutdo wn, and tuning periods. [Rule 20.3(d)(2)(i)]

44. Beginning with the earlier of the in itial startup dates for either combustion turbine, aggregate emissions of oxides of nitrogen (NOx), cal culated as nitrog en dioxide (NO 2 

### ); carbon monoxide (CO); volatile organic compounds (VOCs); particulat e matter less than or equal to 10 microns in diameter (PM10); and oxides of sulfur (SOx), calcu lated as sulfur dioxide (SO 2 

### ), from the combustion turbines described in District Applications No. 985745 and 985747 and the em ergency 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 NO 2 

### ) 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 SO 2 

### ) 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 cal endar month of NOx (calculated as NO 2 

### ), CO, VOCs, PM10, PM2.5, and SOx (calculated as SO 2 

### ), in tons, from each emission unit de scribed in District Applications No. 985745, 985747, and 985748, except for emissions or emi ssion units excluded from the calculation of aggregate potential to emit as sp ecified in Rule 20.1 (d) (1). These records sh all be made available for inspection within 15 calendar days after the end of each cale ndar 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-cale ndar-month period, the applicant shall maintain records, as applicable, on a calenda r monthly basis, of aggregate ma ss emissions of NOx (calculated as NO 2 

### ), CO, VOCs, PM10, PM2.5, and SOx (calculated as SO 2 

### ) 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 poten tial to emit as specified in Rule 20.1 (d) (1). These records shall be made available for inspection within 15 calendar da ys 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 c onstruction, the applicant shall submit to the District the final selection, design paramete rs and details of the selective catalytic reduc tion (SCR) and oxidation catalyst emission control systems for the combustion tu rbines 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 Rule s 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 reduct ion (SCR) system outlet temperature is 450 degrees Fahrenheit or greater. [Rules 20.3(d)(1)]

50. Continuous monitors shall be installed on each SCR syst em prior to their initial operation to monitor or calculate, and record the ammoni a solution injection rate in po unds 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 ma y 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 tu rbines with the SCR system. The monitors shall be in full operation at all times when the turb ine is in operation. [Rules 20.3(d)(1)]

51. Except during periods when the ammonia injection sy stem 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 be ing injected into the SCR system. Manufacturer specifications shall be maintained on site and made available to District pers onnel 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 c oncentration shall be maintained on site and made available to District pers onnel upon request. [Rule 14]
Testing

53. All source test or other te sts required by this permit shall be perf ormed by the District or an independent contractor approved by the Di strict. Unless otherwise specified in this permit or authorized in writing by the District, if testing will be performed by an i ndependent contractor and witnessed by the District, a proposed test protocol shall be submitted to the District for wr itten approval at least 60 days prior to source testing. Additionally, the District shall be notifie d a minimum of 30 days prio r to the test so that observers may be present unless otherwise authorized in writing by the Distri ct. [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 authori zed in writing by the Distri ct, within 45 days after completion of a source test or RATA test performe d by an independent contra ctor, 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 th e turbine stacks the project owner shall provide to the District for wr itten 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 co mmissioning period for each combustion turbine, an Initial Emissions Source Test shall be conducted on that turbine to demonstr ate compliance with the NOX, CO, VOC, PM10, and ammonia emi ssion 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 O 2 

### concentration shall be conducted in accordance with U.S. Environmen tal 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 c onducted in accordance with EPA Methods 201A and 202 or alternative methods a pproved 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 th e combustion turbine’s rated load unless it is demonstrated to the sa tisfaction of the District that the combustion turbine cannot operate under thes e conditions. If the demonstration is accepted, then emissions source testing shall be performed at the highe st achievable continuous power level. TheProposed Conditions Page 9 of 17 November 14, 2008 Applications No. 985745, 985747, and 985748 

### District may specify additional testing at diffe rent load levels or operational conditions to ensure compliance with the emission limits of this permit and District Rules and Regulations.
F. Measurements of particulate ma tter emissions shall be conduct ed in accordance with SDAPCD Method 5 or an alternative method a pproved 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 th e 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 turbin e to demonstrate compliance with the NOX, CO, VOC, PM10, and ammonia emission st andards of this permit, using Di strict 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 sh all be conducted in accordance with a protocol complying with all the applicable requirements of th e 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 cert ification tests shall be performed and completed on the CEMS in accordance with app licable 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 co mmissioning 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 adjust ed by the District base d on source test results to ensure compliance with District Rule 1200 is demonstrated. The Distri ct may require one or more or additional compounds to be quantified through source test ing as needed to ensure complia nce with Rule 1200. Within 60 calendar days after completion of a source test perf ormed by an independent c ontractor, 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 tes ting 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 Di strict shall request the testing in writing a reasonable period of time prio r to the testing date. [Rule 1200]

61. The higher heating value of the combustion tu rbine fuel shall be measured by ASTM D1826

– 94, Standard Test Method for Calorific Value of Ga ses 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 a pproved by the District an d EPA. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 S ubpart 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 Petroleu m Gas by Oxidative Microcoulometry; ASTM D4468

– 85 (Reapproved 2000), Standard Test Method for Total Sulfur in Gaseous Fuel s by Hydrogenolysis and Rateometric Colorimetry; ASTM D6228

– 98 (Reapproved 2003), Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fu els by Gas Chromatography and Flame Photometric Detection; or ASTM D6667

– 04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefi ed Petroleum Gases by Ultr aviolet Fluorescence or an alternative test method approve d 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 emi ssion monitoring requirements of 40 CFR Part 75. []

64. A continuous emission monitoring system (CEMS) sh all be installed on each combustion turbine and properly maintained and calibrated to measure, calc ulate and record the follo wing, 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 concentrati on of carbon monoxide (CO) unc orrected and corrected to 15% oxygen, in parts per million (ppmvd), necessary to demonstrate compliance with the CO limits of this permit; C. Percent oxygen (O 2 

### ) in the exhaust gas; D. Average concentration of oxides of nitr ogen (NOX) for each continuous rolling 3-hour period, in parts per million (ppm v) 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 nitr ogen (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 con centration 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 prio r 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 af ter 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 ot her required certification tests sh all 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 applican t shall submit a test protocol to the District for written approval. Additionally, the Di strict 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 te st 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 Rela tive Accuracy Test Audit te st, as required in 40 CFR 75.62. [40 CFR Part 75]

68. The oxides of nitrogen (NOX) and oxygen (O 2 

### ) 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 Regula tions 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 (C O) components of the CEMS shall be certified and maintained in accord ance 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 S ubpart KKKK, and 40 CFR Part 75]

69. The CEMS shall be in operation in accordance with the District a pproved CEMs protocol at all times when the turbine is in operation a copy of the Dist rict approved CEMS mon itoring protocol shall beProposed Conditions Page 12 of 17 November 14, 2008 Applications No. 985745, 985747, and 985748 

### maintained on site and made available to Di strict personnel upon reque st. [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 co mbustion 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 emi ssion 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 fo r the gas turbine. Emissi on calculations used to determine hourly emission rates shall be reviewed a nd approved by the District, in writing, before the hourly emission rates are incorporat ed into the CEMS emission data . [Rules 20.3(d)(3) and 21 and 40 CFR Part 75]

71. Any violation of any emission standa rd 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, an d 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 (inc luding the programmable logic cont roller) software which affects the value of data displayed on the CEMS / DAHS mon itors with respect to the parameters measured by their respective sensing devi ces or any planned changes to the soft ware that controls the ammonia flow to the SCR. Unplanned or emergency changes sh all be reported within 96 hours. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 S ubpart KKKK, and 40 CFR Part 75]

74. At least 90 calendar days prior to the Initial Em issions Source Test , the applicant shall submit a monitoring protocol to the District for written approval which shall sp ecify 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 provide d 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 turbin e. Correction factors and constants shall be maintained on site and made available to the Distri ct upon request. The fuel fl owmeters shall meet the applicable quality assurance requ irements of 40 CFR Part 75, Appe ndix 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 con tinuous monitors to measure, calculate and record the following operational characteristics:

A. Hours of operation, in hours; B. Natural gas flow rate to the combustion tu rbine, in standard cubic feet per hour; C. Total heat input to the combustion turbine base d 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 CE MS protocol, approved by th e 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 th e 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 turb ine, the applicant shall submit a turbine monitoring protocol to the District fo r written approval. This may be part of the CEMS protocol. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CF R Part 60 Subpart KKKK, and 40 CFR Part 75]

78. Operating logs or Data Acquisition and Handling Syst em (DAHS) records shall be maintained to record the beginning and end times and dura tions 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 cumula tive 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 co mbustion turbine, the applicant shall install postcombustion air pollution control equipment on that turbine to mi nimize NOx and CO emissions. Once installed, the post-combustion air poll ution control equipment shall be maintained in good condition and shall be in full operation at all times when the tu rbine is combusting fuel a nd 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 tu rbine or emission control equipm ent malfunction, upset, repairs, maintenance, modifications, or replacements affec ting emissions of air contaminants that occurred during the commissioning period. All of the follo wing continuous monitoring information shall be reported for each minute and averaged over each hour of operation:

A. Concentration of oxides of nitrogen (NOX) unc orrected and corrected to 15% oxygen, in parts per million (ppmvd); B. Concentration of carbon monoxide (CO) unco rrected and corrected to 15% oxygen, in parts per million (ppmvd); C. Percent oxygen (O 2 

### ) in the exhaust gas; D. Mass emissions of oxides of nitrogen (NOX), in pounds; E. Cumulative mass emissions of oxides of nitr ogen (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 ba sed 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 electr onic 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 Pe rmits 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 (NO 2 

### ); 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 (SO 2 

### ), from Turbine A and the emergency fire pump described in Application No. 985748, except emissions or emission uni ts 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 NO 2 

### ) 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 SO 2 

### ) 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 sh akedown period, aggregate emissions of oxides of nitrogen (NOx), calculated as nitrogen dioxide (NO 2 

### ); carbon monoxide (C O); volatile organic compounds (VOCs); particulate matter less than or e qual to 10 microns in diameter (PM10); and oxides of sulfur (SOx), calculated as SO 2 

### , from the three utility boilers desc ribed 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 NO 2 

### ) 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 26.91Proposed 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 duri ng 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 sha ll 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-m onth period, the applicant shall maintain records on a calendar monthly basis, of aggregat e mass emissions of NOx (calculated as NO 2 

### ), CO, and PM10, in tons, for Turbine A and the emergency genera tor described on Application No. 985748, except for emissions or emission units excluded from the calcula tion of aggregate potential to emit as specified in Rule 20.1 (d) (1). These records shall be made ava ilable 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 mo nth of NOx (calculated as NO 2 

### ), 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 insp ection 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-m onth period, the applicant shall maintain records on a calendar monthly basis, of aggregat e mass emissions of NOx (calculated as NO 2 

### ), 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 inspecti on 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 signific ant Title V permit modification to limit the aggregate emissions of oxides of nitrogen (NOx), calcu lated as nitrogen dioxi de; carbon monoxide (CO); particulate matter less than or equal to 10 microns in diameter (PM10); and part iculate matter less than or equal to 2.5 microns in diameter (PM2.5), from th e three utility boilers desc ribed on District Permits to Operate No. 791, 792, and 793 in each rolling 12-calenda r-month period as specified in this permit. The application shall include a proposed emission calcu lation protocol to calcu late 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 app licant shall submit the following notifi cations to the District and U. S. EPA, Region IX:

A. A notification in accordance with 40 CFR Secti on 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 Secti on 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 startu p 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]

C ONDITIONS FOR 

### E MERGENCY 

### F IRE 

### P UMP 

### E NGINE



### 90. The engine shall be EPA certified to the 2009 model year or later re quirements 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 III I, and 40 CFR Part 63 Subpart ZZZZ]

91. Engine operation for maintenance and testing purpos es 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 comp ly with Air Pollution Control District Rule 50. [Rule 50]

94. The equipment described above sh all not cause or contribute to public nuisance. [Rule 51]

95. This engine shall not operate for non-emergency use during the following pe riods, 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 sc hool 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 cale ndar 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 replacem ent 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 engi ne 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 calenda r 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 th e 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, indica ting whether the operation was for maintenance and testing purposes or emergency use; and, th e nature of the emergency, if known; B. Hours of operation for all uses other than those specified above a nd identification of the nature of that use.
[Rule 69.4.1 and 17 CCR §93115]

### ATTACHMENT 2

EPA MORRO BAY POWER PLANT PSD DETERMINATIONMorro 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

lof21correspondence 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

20f21Table 2: Reference Numbers for Comments on the Mono Bay Power Plant (MBPP)

No. Commenter Format 3 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

October 24, 2006 34 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 ISection 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. P MiO 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 i O. (# 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. gOY 1 sitingcases/morrobay 1 docum entsl index.html

40f21total 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 emerged 5 . 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 of the change in emissions resultingfrom 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 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 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

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 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.

60f21Because 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, NO x is an appropriate indicator for VOC and PK ° trends because emissions of VOC and PK° correlated well with NO (R 2 = 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 NO x (R 2 = 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 of emissions that the public would be exposed to. (# 44, 46)
Response to A-3:

70f21The 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 PM 1 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 PM 1 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 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)(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, if the 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.

80f21The 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

­

90f21the 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 PM io 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 PM IO without duct firing

(lb/hr) PM IO 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 of 

### PMlO, 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 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 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 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 (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 of the application) to address current BACT generally for CO, NOx, VOC, PM lO , 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 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 PM lO 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 of21While 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 CO 2 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 § 52.210) (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 CO 2

120f21as 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 CO 2 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 CO 2 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 CO 2 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 CO 2 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 PM lO emissions from the potential use of cooling towers
as an alternative to once-through sea water cooling. (# J 2, 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 of21intake 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 of upper air data from Vandenberg Air Force Base is not appropriate. (# J 2, 

### 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 of PM JO 

### emissions. (# J 2, J 5, 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

140f21emissions 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 PM 1 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 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 PM IO.

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 

## x and 

## 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

150f21meteorology (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 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 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 of complaints by neighbors (# 1, 12, 29, 44, 46). The existence of historical complaints regardingfalloutfrom 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 offuel 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,

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/m 3 ). This represents a 42% increase over the background PM10 concentration (57 gg/m 3 ). 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 of the 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 NO x- 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 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 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')

170f21that is 46% lower than the PM10 NAAQS of 150 μg/m 3 . 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 PM 1 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/m 3 ) 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 99 th percentile of 24-hour PM10 concentrations at each monitor within an area. The numerical level of the standard 150 μg/m 3 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

18 of 21 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 of date compared to a new NAAQS for P 

### Mlo 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 PM 2

. 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 of the 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

l80f211. 

### 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 PM 10 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 1 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 PM 10 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

19 of 21 1. Limits placed on PM fO emission rates are ineffective and unenforceable due to the lack of continuous in-stack monitoring of PM fO

. (# 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

190f21compliance 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/m 3 ), which is lower than the PM10 increment of 30μg/m 3 . 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 PM 10 NAAQS of 150 μg/m 3

. 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

20 of 21 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 of PM IO 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

200f21reporting 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 PM 10 satisfies requirements for PSD review for PM. The final PSD permit was modified to replace references to "PM10" with "PM/PM1o".

21 of 21 

### 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 "PM IO" with 

### "PM/PM IO " .



### 21 of21