CECP Project - PSD Applicability

Tom W. Andrews t o : Shaheerah Kelly 03/01/2010 04:50 PM

Cc: "Tom W. Andrews"

From: "Tom W. Andrews" <TAndrews@sierraresearch.com> To: Shaheerah Kelly/R9/USEPA/US@EPA Cc: "Tom W. Andrews" <TAndrews@sierraresearch.com> History: This message has been replied to.

Ms. Kelly:
Enclosed is a letter regarding the actual emissions for the Encina Power Plant Units 1-3. If you have any

questions, please give me a call at (916) 444-6666.March 1 , 2010

Ms. Shaheerah Kelly Air Division AIR

- 3 U.S. Environmental Protection Agency 75 Hawthorne Street San Francisco, CA 94105
Subject : Encina Power Plant Units 1

- 3 Actual Emissions

Dear Ms. Kelly : On behalf of Carlsbad Energy Center LLC, we are pleased to provide the following response to a recent request by EPA to justify the period used to calculate the actual emissions for Encina Power Plant Units 1, 2, and 3. As discussed in the following paragraphs, we believe that the appropriate pe riod to use to establish the actual e missions for Encina Units 1

- 3 is from 2002 to 2006.



### Background
On September 17, 2007
, an Application for Certification (AFC) for the proposed Carlsbad Energy Center Power (CECP) project was submitted to the Califor nia Energy Commission (CEC). As part of the permitting 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 Sept embe r 12, 2007. The CECP project consists of the proposed replacement of three existing boilers at the Encina Power Plant (Units 1, 2, and 3) with two new rapid startup natural gas

- fired combined cycle gas turbines. The SDAPCD issued the Final Determination of Compliance (FDOC) for the CECP project on August 4, 2009 , and o n November 12, 2009
, the CEC Staff issued the final staff assessment (FSA) for the project.



### Actual Emissions for Encina Units 1

- 3
At the request of EPA, on June 5, 2009
, Carlsbad Ener gy Center LLC submitted a letter to EPA requesting confirmation that the proposed CECP project will not trigger Prevention of Significant Deterioration (PSD) review. In this letter we requested that the period from 2002 to 2006 be us ed to calculate the ac tual em issions for Encina Units 1

- 3 , for two reasons. The first reason was that the 2002 to 2006 period should be used for PSD purposes because it is consistent with the baseline period used by the SDAPCD for New Source Review (NSR) permitting purposes. The second reason this period should be used was that it is the most representative period to calculate actual emissions given 

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- 6666 Fax: (734) 761

- 6755Shaheerah Kell y

- 2

- March 1 , 2010

t he cyclic nature of the historical emissions for Units 1

- 3 over the past several years and due to the uncertainty regarding the future operations/emissions for the units.
Although the exact extent of future operations of Units 1

- 3 is uncertain if CECP were not licensed and built, we can roughly estimate the range of potential operations. In order to estimate the future operation of Encina Units 1

- 3, we have re viewed power generation for e cast s for the San Diego area prepared by the CEC , California Independent System Operator, and the San Diego Gas and Electric (SDG&E) Company. According to the CEC’s energy demand forecast s , 1 the e lectric energy consumption in the San Diego area will continue to increase from approximately 21,100 to 23,535 GWH /year during the period fr om 2010 to 2020. This increase

— 2 , 435 GWH/year

— is equivalent to a 278 MW power plant operating at a 100% capacity fa ctor , or an additional 82% of the capacity of Encina Units 1

- 3

. While not all of this additional energy will come from Encina Units 1

- 3, it is clear that the increase in regional demand over the next 10 years will result in a not insignificant increase in operations of these units as compared with current operating levels.

T he anticipated future de mand for electricity in the San Diego area and the associated need for additional electric generation capacity are also reflected in documents prepared by the C alifornia Independent System Operator. The California Independent System Operator is responsible for the reliable operation of the electric grid system in California. According to a c apacity a nalysis prepared by the California Independent System Operator , 2 to avoid grid reliability issues there is a need beginning in 2011 for additional local electric generating capacity in the San Diego Area.
In parallel, the State Water Resources Control Board has issued its draft Clean Water Act Section 316(b) polic y that lists target compliance dates for coastal steam boiler power plants that rely on once

- through cooling (OTC). This policy targets December 31, 2012
, as the compliance date for the South Bay power plant in the San Diego area , and will likely result i n the shut down of the South Bay plant by that date or earlier

. The loss of in

- basin generation as a result of the South Bay shutdown may in turn increase operations of Encina Unit s 1

- 3 above the more recent years until the on

- line date of the CECP. 3

The increase in demand for electricity and the need for additional electric generating capacity in the San Diego area are also discussed in documents prepared by SDG&E. According to a procurement plan prepared by SDG&E
, 4

1 California Energy Demand 2010

- 2020 Adopted Forecast, California Energy Commission, Dec 2009, CEC

- 200

- 2009

- 012

- CMF, Table 18, page 123, and pages 140

- 141. without the installation of the Sunri se Powerlink transmission line, starting in 2010 there will be a need for additional electric generating capacity in the San Diego area . This requirement for new generating capacity is in addition to the operation o f the new Otay Mesa Power Plant . In add ition, without the installation of the Sunrise Powerlink transmission line no existing power plants in the San Diego area
, i ncluding the Encina Units 1

- 3 , will be able to retire until this new generation is built. This SDG&E Company document shows that wi thout the

2 2011

- 2013 Local Capacity Technical Analysis Report and Study Results , California Independent System Operator , Dec 29, 2008, Section IV.B.10, page 95. 3 State Water Quality Control Policy on the Use of Coastal and Estuarine Water for Power Plant Cooling, Attachment 1, Draft November 23, 2009

. 4 Long

- Term Procurement Plan (2 007 to 2016), SDG&E Company, Dec. 11, 2006, Table IV

- 4, page 172 and Exhibit IV

- 10, page 182.Shaheerah Kell y

- 3

- March 1 , 2010

Sunrise Powerlink transmission line the shortfall in electric generat ing capacity in the San Diego area could be as high as approximately 985 MW over the next few years . This shortfall i s equivalent to installing two new power plants of approxim ately the same size

as the proposed CECP project.
With regards to the status of the installation of the Sunrise Powerlink transmission line, t here has been significant legal opposition to this project . This opposition includes an August 12, 2009 lawsuit 5 filed with the California State Supreme Court by the Center for Biological Diversity (an organization that is also opposing the CECP project) challenging the California Public Utilities Commission’s approval of the project and a February 16, 20 10 lawsuit 6 filed in the Federal Eastern California District Court by several environmental/community groups challenging the U.S. Bureau of Land Management ’s approval of the project. These lawsuits are likely to delay the installation of the Sunrise Powerlink transm ission line beyond the 2012 date originally estimated by the SDG&E Company

.
All of the above electric generation forecasts clearly show a significant need for additional locally generated power in the San Diego area
, including an increase in the future operation of Encina Units 1

- 3

. As shown in our August 24, 2009 letter to the EPA, a review of the actual emissions for Encina Units 1

- 3 over the past 12

- years (1997 to 2008) shows that the annual emissions during the period from 2002 to 2006 represent a g ood average between the higher emissions that occurred in the earlier years (i.e., 1997 to 2001) and the lower emissions that occurred during the later years (i.e., 2007 and 2008). Therefore, given the likelihood of higher operation/emissions for Units 1

- 3 in the future
, we continue to believe that the annual emissions during the period from 2002 to 2006 are the most representative of actual operation and should be used for purposes of PSD applicability for the proposed CECP project.



### PSD Applicability
In the following table, the potential to emit for the new units associated with the proposed CECP project are in cluded with the emission decrease associated with the shutdown of Encina Units 1

- 3 . As shown in Table 1 , the facility

- wide net emission incre ase for the proposed CECP project is below PSD significance levels for NOx, CO
, PM 10 , and PM 2.5 . Therefore, the proposed CECP project does not trigger PSD review.

5 http://www.biologicaldiversity.org/news/press_rele ases/2009/sunrise

- powerlink

- 08

- 12

- 2009.html 6 http://protectourcommunities.org/wp

- content/uploads/2009/05/complaint_2

- 16

- 10.pdfShaheerah Kelly -4- March 1,2010

Table 1 PSD Applicability for CECP Project Potential to Emit Emission Reductions PSD for New for Shutdown of Net Emission Significance Equipment* Encina Units 1-3** Change Levels Pollutant (tons/year) (tons/year) (tons/year) (tons/year)

NOx 72.11 -36.9 35.2 40 CO 339.9 -305.4 34.5 100 PMlO 39.0 -36.5 2.5 15 PM 2

. 5 39.0 -36.4 2.6 10 Notes: 

### * Based on SDAPCD FDOC, August 4,2009, Table 5c, page 26 of 63 (see Attachment). ** Based on SDAPCD FDOC, August 4,2009, Table 5a, page 24 of 63 (average for 2003 and 2004) (see Attachment.

If you have any questions or need any additional information, please do not hesitate to call me at (916) 444-6666.

Sincerely,

# ~~ Tom Andrews Senior Engineer

Attachment

cc: Steve Moore, SDAPCD John McKinsey, Stoel Will Walters, CEC Michael Monasmith, CEC CEC Dockets Office (07-AFC-6)

### ATTACHMENT

SDAPCD FDOC FOR CECP PROJECT

## FINAL DETERMINATION OF COMPLIANCE

CARLSBAD ENERGY CENTER PROJECT

SAN DIEGO AIR POLLUTIO N CONTROL DISTRICT
Applications Number 9857 45, 985747, and 985748

August 4, 2009Project 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: George Pinanka Company: Carlsbad Energy Center LLC Position: Vice President Phone Number: (760) 710-2156 Fax Number: (760) 710-2158TABLE 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 .......................................................................... 29 Rule 20.1(c)(57) PSD Modification and 40 CFR 52.21 ................................................. 30 Rule 20.3(d)(1)- Best Available Control Technology(BACT)/Lowest Achievable Emission Rate(LAER) .................................................................................................... 30 Rule 20.3(d)(2) – Air Quality Impact Analysis (AQIA)................................................. 43 Rule 20.3 (d)(3), (4)-Prevention of Significant Deterioration (PSD) ............................. 44 Rule 20.3(d)(4) – Public Notice and Comment .............................................................. 44 Rule 20.3(d)(5)-Emission Offsets................................................................................... 45 Rule 20.3(e)(1) – Compliance Certification ................................................................... 45 Rule 20.3(e)(2) – Alternative Siti ng and Alternatives Analysis..................................... 46 Rule 20.5 – Power Plants................................................................................................ 46 District Prohibitory Rules ................................................................................................... 46 Rule 50 – Visible Emissions........................................................................................... 46 Rule 51 – Nuisance ......................................................................................................... 47 Rule 53 – Specific Air Contaminants ............................................................................. 47 Rule 68 –Oxides of Nitrogen from Fuel Burning Equipment......................................... 48 Rule 69.3-Stationary Gas Turbines – R easonably Available Control Technology ........ 48 Rule 69.3.1 – Stationary Gas Turbines – Best Available Retrofit Control Technology. 49 Rule 69.4 – Stationary Reciprocating In ternal Combustion E ngines – Reasonably Available Control Technology........................................................................................ 49 Rule 69.4.1– Stationary Reciprocating Intern al combustion Engines – Best Available Retrofit Control Technologies. ....................................................................................... 50 Rule 1200 – Toxic Air Contaminants ............................................................................. 51 Regulation XIV – Title V Operating Permits ................................................................. 52 State Regulations Implemented by the District .................................................................. 52 Health and Safety Code §42301.6 .................................................................................. 52Title 17 of the California Codes of Regulations (CCR) §93115—Airborne Toxic Control Measure (ATCM) for Stationa ry Compression Ignition Engines...................... 52 National Emissions Standards for Hazardous Air Pollutants (NESHAPS)........................ 55 40 CFR Part 63 Subpart YYYY – National Emissions Standards for Hazardous Air Pollutants for Stationary Combustion Turbines.............................................................. 55 40 CFR Part 63 Subpart ZZZZ - National Em issions Standards for Hazardous Air Pollutants for Stationary Compression I gnition Internal Combustion Engines.............. 55 New Source Performance Standards (NSPS) ..................................................................... 56 40 CFR Part 60- Subpart KKKK- National Stan dards of Performance for New Stationary Combustion Turbines.......................................................................................................... 56 40 CFR Part 60 Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combus tion (CIIC) Engines ................................................................ 59 Acid Rain ...................................................................................................................... ...... 59 40CFR Part 72- Subpart A – Acid Rain Program........................................................... 59 40CFR Part 72- Subpart C – Acid Rain Permit Applications......................................... 60 40CFR Part 73- Sulfur Dioxide Allowance System ....................................................... 60 40CFR Part 75 – Continuous Emission Monitoring....................................................... 60 VI. ADDITIONAL ISSUES ................................................................................................ 61 Particulate Emission Relating to the Use of Reclaimed Water for Ev aporative Cooling... 61 Commissioning Period........................................................................................................ 61 VII. CONCLUSIONS AND RECOMMENDATIONS..................................................... 63

APPENDICES
Appendix A – Approval of Air Quality Impact Analysis Appendix B – Approval of Health Risk Assessment Appendix C – Proposed Permit Conditions Appendix D – Emission Reduction CreditsFinal Determination of Complian ce Page 1 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 I. PROJECT DESCRIPTION

Carlsbad Energy Center LLC (A pplicant) proposes to develop the Carlsbad Energy Center Project (CECP). This project is a combined-cycle power plant w ith a total nominal base load gross power output of 558 MW. The CECP will utilize two Siem ens SGT6-5000F Rapid Response Combined-Cycle (R2C2) combustion turbine generators (CTGs) equipped with steam power augmentation. The nominal gross power output is 208 megawatts (MW) with a corresponding heat input of 1976 million Britis h thermal units per hour (MMBtu/hr) per turbine (without power augmentation at 61 o F average ambient temperature). The combustion turbines are also equipped with evaporative coolers that can be used to cool the inlet air to each turbine to increase power during periods of high ambient temperature. Each CTG is followed by a heat recovery steam generator (HRSG) equipped with a selective catalytic reduction (SCR) system to reduce oxides of nitrogen (NOx) emissions and an oxidation catalyst to control carbon monoxide (CO) and volatile organic compounds (VOCs)
emissions. Steam from each HR SG will feed a steam turbine generator (STG) associated
with that HRSG. This combination of a CTG with a HRSG and STG is referred to as a 1-on1 combined-cycle power plant. By making us e of the turbine exhaus t 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 rating gr eater than 50 MW. The Applicant 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 Boulevard and Cannon Road in the city of Carlsbad in San Diego County. The proj ect is proposed to be lo cated in the northeast area of the existing Cabrillo Power I LLC’s Enci na Power Station, between the existing rail line and Interstate 5 (I-5). Th e two main power units of the pr oject will be at the location ofFinal Determination of Complian ce Page 2 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 previously existing fuel oil tanks, which are cu rrently being removed. Both Carlsbad Energy Center, LLC and Cabrillo Power I LLC, are i ndirect wholly owned subsidiaries of NRG Energy, Inc.

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 th e CECP, three existing u tility boilers, known as Units 1, 2, and 3, at the Encina Power Station will be retired when the two combined-cycled turbines are fully operational (t he other two utility boilers 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.Final Determination of Complian ce Page 3 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 II. EQUIPMENT DESCRIPTION

The Applicant has proposed to construct and opera te the 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.Final Determination of Complian ce Page 4 of 63 August 4, 2009 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 combined-cycle system merges the fa st starting capability of a simple-cycle gas turbine and the efficiency of a combined-cycle plan t. The system is designed to start and reach 150 MW in ten minutes for a hot start and opera te with combined-cycled efficiency in 45 minutes for a hot start and approximately 125 minut es for a cold start. The system is also designed to typically achieve its emission limits within 22 minutes. Trad itional combined-cycle systems typically take 3–6 hours to reach comparable emission limits.

The one-hour averaged NOx emission concentra tion is controlled to 2.0 parts per million by volume on a dry basis (ppmvd) and co rrected 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, ammonia will be injected into the CTG exhaust stream via nozzles located upstream of the catalyst module. Ammonia slip, or the concentration of unreac ted ammonia in the HRSG exhaust stack, is limited to 5.0 ppmvd averaged over one hour. Th e HRSG is also equipped with an oxidation catalyst to control CO emissions leaving th e HRSG exhaust stack to 2.0 ppmvd and VOC emissions to 1.5 ppmvd averaged over one hour. Exhaust from each HRSG will be discharged
from individual 21.3-foot diameter stacks proposed to be 139-foot tall.

Each CTG is equipped with a continuous 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 dataFinal Determination of Complian ce Page 5 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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.

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 (114 MW at annual average ambient temperature without steam augmentation)

. Shutdown is a period beginning with the lowering of the output of a combustion turbine below the minimum load necessary to achieve the most stringent emission limits during normal operations of its load capacity and ending when combustion has ceased. The minimum load is typically between 40% and 60% of the maximu m load, depending on the combustion turbine. The Applicant has proposed a minimum load thre shold for a shutdown to be initiated of 114 MW. Although typical startups and shutdowns ar e expected to take 22 minutes and 7 minutes, respectively, the permit conditions allow 60 minut es for a startup and 30 minutes for a shutdown to allow for contingencies during these operations.

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 conventiona l large combined-cycle power plants. The Applicant estimates that there will be 300 typical startups per turbine per year and 300 typical shutdowns per turbine per year. Maximum annua l emissions are calculated based on 300 hoursFinal Determination of Complian ce Page 6 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 with a startup, 300 hours with a shutdown, and 3,500 hours per year at full-load operation under average conditions for both CTGs.

The CECP may be completed in two phases 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/STG 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 process the Applicant has committed to not operating the combustion turbines and the st eam boilers simultaneously, which minimizes emission impacts. However, to maintain grid reliability, maximum flexibility is desired in operating the existing boilers dur ing the phase-in process when one or both CTG/STG units may not be fully operational.Final Determination of Complian ce Page 7 of 63 August 4, 2009 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, sulfur oxides (SOx ), VOCs, particulate matter less than or equal to 10 microns in diameter (PM10), and particulat e 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 the FDOC permit conditions. The startup and shutdown, emission rates were provided by the turbine manufact urer. For normal operations, emission rates for NOx, CO, and
VOCs are calculated based on emission c oncentration limits (in ppmvd at 15% O 2 ) in the FDOC permit conditions and exhaust flow ra tes in dry standard cubic feet per hour (dscfh) at an average ambient temperature of 73.8 ° F with the evaporative cooler operating, but without steam augmentation, for annual emissions (Case 2 in Ta ble 5.1B-5 in the application) and at cold ambient temperature, 37.4 ° F, without steam augmentation, for peak hour and peak day emissions (Case 15 in Table 5.1B-5 in the application):

Emissions, lbs/hr = (concentration, ppmvd) x 10 -6 x (exhaust flow rate , dscfh) x (molecular weight/standard molar volume).

The Case 15 provides the highest emissions among the 21 turbine operating scenarios considered (second highest was Case 1, operations at the average ambient temperature case with steam augmentation). The FDOC conditions limit peak hourly emissions based on this operating scenario. Case 2 is expected to be most representative of annual average emissions.

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 inFinal Determination of Complian ce Page 8 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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.

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 (1-hour average) 9.2 8.6 VOCs 1.5 (1-hour average) 4.0 3.7
PM10 N/A 9.5 9.5
PM2.5 N/A 9.5 9.5
SOx N/A 4.4 4.1

During a CTG startup, there are ty pically approximately 22 minutes of emission rates higher than emissions during normal operation. Therefore, t ypical hourly emission rates during startup are based on 22 minutes of high emission levels followed by 38 minutes of normal operation emission levels. During a typical CTG shutdown, there are approximately 53 minutes of normal operation followed by 7 minutes of higher emission levels. Therefore, typical hourly emission rates during shut down are based on 53 minutes of normal operation emission levels followed by 7 minutes of higher emission levels. For any hour when both a typical startup and a shutdown occur, there would be 22 minutes of startup emissions, 31 minutes of normal emissions and 7
minutes of shutdown emissions. Because there is some variability in emissions during startup and shutdown, the higher startup and shutdown emi ssions for CO and NOx are estimated at twice the expected emission value. Normal operation emissions were assumed to correspond to those at cold ambient temperature with in ca lculating the hourly emission rates.

Table 1b presents the maximum emission rates fo r each turbine during startup and shutdown in pounds per hour. The maximum emission rates of PM10 and PM2.5 are not affected duringFinal Determination of Complian ce Page 9 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 startup and shutdown and the emission limit for nor mal 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) dur ing startups and shutdowns.

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
VOCs 15.5 8.2 19.8
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 maximum norma l 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) + (normal operation 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).Final Determination of Compliance Page 10 of 63 August 4, 2009 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
VOCs 190 380
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 maximum normal 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) + (normal opera tion emissions, lbs/day) x (3500 hours /years)

Table 1d presents estimated maximum turbine an nual emissions in tons per year (tons/yr).Final Determination of Compliance Page 11 of 63 August 4, 2009 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
VOCs 10.03 20.05
PM10 19.48 38.95
PM2.5 19.48 38.95
SOx 8.43 16.9

Note that the annual SOx emissions are based on th e PUC limit for sulfur c ontent of natural gas. Historically, the annual average su lfur content in San Diego natu ral gas has been significantly
less.

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 2009. 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
VOCs 0.05 0.05 0.00125
SOx 0.0027 0.0027 0.00007Final Determination of Compliance Page 12 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 PM10 0.035 0.035 0.0008
PM2.5 0.035 0.035 0.0008

P ROJECT E MISSIONS —S TANDARD OPERATIONS Standard operations are those operations occurring after of the commissioning period for a turbine (see below). Total emissions from th e project include emission from both combustion turbines and emissions from the emergency fire pump engine. Table 3a and 3b present the estimated maximum project total daily and annua l emissions pounds per day and tons per year, respectively.

Table 3a – Maximum Project Total Daily Emissions

Pollutant Turbines Total Daily Emissions, lbs/day Engine Daily Emissions, lbs/day Project Total Daily Emissions, lbs/day

NOx 1754 2.08 17569
CO 10205 0.24 10205
VOCs 439 0.05 439
SOx 211 0.0027 211
PM10 4569 0.035 4569
PM2.5 4569 0.035 4569Final Determination of Compliance Page 13 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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
VOCs 20.05 0.00125 20.05
SOx 16.9 0.00007 16.9
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 the Toxic Health Risk Assessment Section in Appendix B.

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 commissioning period, because the CTG burners may not yet be tuned for optimal emissions and because the postcombustion contro l equipment will not yet be in full operation, emissions from the plant will be higher than standard operating em issions. Each turbine is expected to operate 415 hours over approximately 49 operating days during this commi ssioning period, which includes startups and shutdowns, hours of operation at different load levels, and operation with and without emission control equi pment. Commissioning emission data provided by the turbine
vendor consist of different emission scenario s corresponding to diffe rent phases of the commissioning period. Table 4a presents the expected commissioning maximum hourly
emission rates. In order to minimize em ission impacts during the commissioning period,
emission rates for NOx and CO for both turbines co mbined will be limited to the levels expected for one turbine in commissioning mode and one turb ine in standard mode (including startups and shutdowns) by the FDOC permit conditions.Final Determination of Compliance Page 14 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Table 4a –Maximum Turbine Hourly Emissions During Commissioning Pollutants Single Turbine Emissions, lbs/hr Allowed Combined Turbine Emissions, lbs/hr NOx 200 286
CO 3813 4627
VOCs 164 184
SOx 4.4 8.8
PM10 9.5 19.0
PM2.5 9.5 19.0

For a single combustion turbine, expected ma ximum daily emissions during commissioning are based on the peak emission day for each pollutant as forecast from the projected commissioning schedule. Because of the FDOC hourly limits on NOx and CO emission rates during 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 turb ine under standard operations. For the other pollutants, peak daily commissioning emissions are the sum of peak commissioning emissions for each turbine. Table 4b presents the maximum daily commissioning emissions. The entire commissioning period may take up to 120 calendar days for each turbine to allow time for reviewing test and turn ing information and making operati onal adjustments to the combustion turbines and associated plant equipment.Final Determination of Compliance Page 15 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Table 4b – Maximum Daily Emissions During Commissioning Pollutants Single Turbine Emissions, lbs/day Combined Turbine Emissions, lbs/day NOx 1755 2632
CO 43712 48814
VOCs 1310 1500
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.

Table 4c – Total Annual Turbine Commissioning
Emissions Pollutants Single Turbine Emissions, tons Combined Turbine Emissions, tons NOx 6.24 12.48
CO 65.17 130.34
VOCs 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 standard operations take place, total maxi mum project emissions are estimated based on 415Final Determination of Compliance Page 16 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 at annual average ambient temperature, and estimate d maximum emissions from the emergency fire pump engine. Table 4d presents the estimated total maximum annual emissions for the project for a year with commissioning.

Table 4d – Total Project Emissions During Year With Commissioning

Pollutants Combined Turbine Commissioning Emissions, tons/yr Combined Turbine Standard 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
VOCs 6.96 16.74 23.7
SOx 0.56 13.15 13.71
PM10 3.92 30.40 34.32
PM2.5 3.92 30.40 34.32Final Determination of Compliance Page 17 of 63 August 4, 2009 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
VOCs 50
SOx 100
CO 100 Lead (Pb) 100

Major source status is only relevant for polluta nts for which the District does not attain an applicable national air quality stan dard. Since the District attains all national ambient air quality standards with the exception of ozone, major source status is only relevant for NOx and VOCs, both of which are ozone precursors. In particular, the major modi fication thresholds (see below) apply for contemporaneous emission increases a nd associated requirements for NOx and VOCs. Based on its potential to emit, the Encina Power Station is an exis ting major stationary source for
both NOx and VOCs.

Rule 20.1(c)(58) – Prevention of Significant Deterioration (PSD) Stationary Source and 40 CFR 52.21 Because the Encina Power Station is a fossil fuel fired steam electrical generating plant with a heat input rating greater than 250 MMBtu/hr, PS D Stationary Source status is defined by an aggregate potential to emit one or more air contam inants in amounts equal to or greater than any of the following emission rates:Final Determination of Compliance Page 18 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Air Pollutant Emission Rates (tons/yr)
PM10 100
PM2.5 100
PM 100
NO 2 100
VOCs 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 under the fede ral Operating Permit Program (Title V).

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 the FDOC permit limits pursuant to Ru le 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, Units 1, 2, and 3 with District permit Nos. 791, 792, and 793, respectively (the two other utility boilers, Units 4 and 5, will remain in operation).Final Determination of Compliance Page 19 of 63 August 4, 2009 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.

Preproject Actual Emissions 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 system s. In addition, their operations will be limited by permit conditions at the end of Stage I of the project. The limited operation and
eventual shutdown of these boilers will result in an actual emissions reduction at the site. Rule 20.1(c)(16)(i) allows the sum of emission increa ses to be reduced by actual emission reductions occurring at the stationary source. Rule 20.1( d)(4)(ii)(A) defines actu al emission reductionsFinal Determination of Compliance Page 20 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 from the shutdown of an emission unit as t hose calculated based on the emission unit’s preproject actual emissions (baseline emissions).

Baseline emissions are based on actual emissions occurring over the 5-year period preceding the receipt of the applicat ion. Rule 20.1(d)(2)(i)(B) requires the actual emissions to be averaged over the total operational time period within the five-year period if a re presentative two-year operating time period does not exist. Since the A pplication for Certification (AFC) for the CECP was submitted to the CEC in 2007, the preceding five years in consideration for actual emission reduction estimates are 2002, 2003, 2004, 2005, and 2006.

Units 1, 2, and 3 at the Encina Power Station have been used in recent years more as peaking units than base-load units. Peaking units are ty pically only called on to operate by the California Independent System Operator (ISO) when high electrical de mand requires additional power beyond that provided by more effici ent base-load units. This addi tional power is necessary to provide electrical grid stability. As such, the un its’ operation may vary greatly from year to year depending on the weather, which largely determ ines electrical demand, and availability of electrical generating assets not only in California but through out the Western United States. Therefore, the District concluded that, because of the variable nature of the operations, no consecutive two-year period was representative of actual emissions from the three units. Since
the District determined that there was not a re presentative two-year op erating time period for Units 1, 2, and 3 of the Encina Power Station duri ng these five years, the 5-year average of
emissions determines baseline emissions for these units.

The five boilers at the Encina Power Stati on exhaust through a singl e common stack known as the common unit chimney (CUC). For purposes of recording emissions pursuant to the federal Acid Rain Program, there is a NOx CEMS on the CUC. This CEMS was installed prior to 2000. However, this CEMS measures and records NOx emissions from all five boilers combined.

However, each unit is currently equipped with an individual certified CEMS that measures and records NOx emissions for each hour of operation to determine compliance with District Rule 69. In addition, as part of the NOx CEMS system for each unit, the hourly natural gas fuel andFinal Determination of Compliance Page 21 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 liquid fuel use and power output for each unit is m easured by instruments subject to federal Acid Rain Program quality assurance and quality contro l requirements (the information is required both to determine compliance with District Rule 69 and as part of the Acid Rain Program). The individual unit CEMS on Units 1, 2, and 3 were installed in 2003 when selective catalytic reduction (SCR) add-on emission control systems and low-NOx burners were installed on these units, which greatly reduced their NOx emissi ons. In 2002, each unit’s fuel flow and power output was still measured and record ed for the Acid Rain Program.

The unit-specific fuel use and power output in formation is recorded hourly by the individual unit CEMS data acquisition and handling system (DAHS) for purposes of Rule 69 compliance and also transmitted to the Acid Rain Program CEMS on the CUC where it is separately recorded for the purpos es of the Acid Rain Program. Because the data is used for different purposes and recorded pursuant to diffe rent protocols (and als o, possibly, subject to instrument bias), there can be differences in the fuel use and power output recorded for purposes of Rule 69 and the Acid Rain Progr am. Notably, fuel use for Rule 69 is not recorded during the early portions of a unit’s startup when Rule 69 is not applicable while it
is recorded at all times for the Acid Rain Pr ogram. In addition, the Acid Rain Program may employ data substitution algorithms that are not used for Rule 69 and may be less representative of actual fuel use.

Baseline NOx emissions for 2004–2006 are based on the recorded NOx emissions from the individual CEMS on Units 1, 2, and 3 for purposes of Rule 69 compliance. Using the Rule 69 compliance emissions understate actual baseline NOx emissions since, as with fuel use, NOx emissions during the early portions of a unit’s st artup are not reported fo r purposes of Rule 69.

For 2002, the NOx emissions from Units 1, 2, and 3 were much larger since SCR had not yet been installed. However, the NOx emissions in excess of the currently a pplicable standard in Rule 69, 0.15 pounds per megawatt-hour (lb/MW-hr), were not allowed for the baseline calculations. Therefore, emissions were calcu lated based on the hourly power output recorded for each unit by the individual unit CEMS and the Rule 69 emission standard.Final Determination of Compliance Page 22 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 In 2003, the SCR were installed and operational on each unit before the individual unit CEMS
were certified for measurement of NOx emissions. The NOx emissi ons were not recorded by the individual unit CEMS prior to certification. Therefore, NOx emissions for 2003 prior to the
CEMS certification were estimated based on th e hourly power output for each unit and, since SCR was installed, an average emission rate in pounds per megawatt-hour calculated for each unit after CEMS certification (the average was about 0.11 lb/MW-hr for each unit). Emissions
of NOx after the CEMS certification in 2003 is based on the emissions measured by each unit’s CEMS. This was a refinement of the procedur e used in the PDOC which assumed that the emissions prior to CEMS certification were at a rate of 0.15 lb/MW-hr. This refinement in the calculation procedure results in a reduction of the 5-year NOx baseline emissions by about 2% (0.65 tons per year)

For the other criteria pollutants—CO, VOCs, SOx, PM10, PM2.5, and PM—the baseline emissions are calculated by multiplying the fuel use by an appropriate emission factor. For the PDOC, the baseline emissions for these pollutant s were based on the District’s annual emission inventory reports, which in turn are based on fuel use reported by the facility for each year. For the Encina Power Plant, the annual fuel use va lues reported to emissi on inventory are from the North American Electric Reliability Corporatio n-Generating Availability Data System (NERCGADS), which integrates the fuel use for each unit recorded by the individual unit flowmeters. The NERC-GADS system annual fuel use is then ma nually recorded. As noted above, fuel use is also recorded for purposes of Rule 69 by individual unit CEMS and for purposes of the Acid Rain Program by the CUC CEMS.

For this FDOC, after an extensive examination of the three sources of fuel use data, the District has concluded that the most appr opriate fuel use data for natura l gas for purposes of determining preproject actual emissions is that recorded in the individual unit CEMS for purposes of Rule 69 compliance, where available, and the Acid Rain Program fuel use data prior to the certification of the individual CEMS. As noted above, the use of the Rule 69 fuel use likely understates actual fuel use and results in conservatively low (about 1%) emission estimates of baseline emissions. The 5-year average Rule 69 fuel use is about 2% less th an that used in the District
emission inventories.Final Determination of Compliance Page 23 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 For the liquid fuel (No. 6 fuel oil, also referred to as residual fuel oil), the emission inventory fuel use was used. With the exception of SOx, li quid fuel combustion cont ributes very little to emissions from these units (less than 2%).

The District also refined the emission inventory calculations for purposes of determining
baseline emissions as follows:

• The unit-specific annual source tests fo r each year, where available (2003-2006),
were used to calculate emissions from na tural gas combustions for CO and PM for each year (EPA’s preferred method),

• The PM emission factor for residual fuel oil combustion was slightly lowered from the standard emission inventory value to be consistent with the AP-42 emission factor, which was used to calculate PM10 and PM2.5 emissions from No. 6 (residual) fuel oil combustion, and

• A corrected calculation methodology for PM a nd SOx emissions from No. 6 fuel oil combustion in 2005 was used (the corre cted methodology is the same as the methodology used for all other years in the PDOC).

For this FDOC, the District has recalculated estimated emissions for CO, VOCs, SOx, PM10, PM2.5, and PM based on the individual CEMS natural gas fuel use data and with the
refinements in the emission calculations listed ab ove. As compared to the PDOC, this results
in decreases in baseline emissions for CO a nd VOCs of about 5.5% and 2.5%, respectively,
an increase in SOx baseline emissions of about 4%, and almost no change in PM10, PM2.5
and PM emissions.

Table 5a presents the FDOC pr eproject actual emissions.Final Determination of Compliance Page 24 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Table 5a – Boiler Units 1,2, and 3 Preproject 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 39.99 27.7 46 31.73 16.17 32.21
CO 494.59 344.03 266.73 144.25 94.43 268.80
VOCs 16.18 14.83 22.14 15.41 8.11 15.33
SOx 9.53 12.51 2.41 3.69 2.59 6.15
PM10 34.97 27.66 45.28 33.58 15.97 31.49
PM 2.5 34.80 27.43 45.28 33.54 15.93 31.40

PM 35.22 28.01 45.28 33.64 16.02 31.64

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, the only emission increases for contemporaneous emi ssion increases are those associated with the
CECP.

For informational purposes, Table 5b presents the contemporaneous emission increases at the
site without consideratio n of the FDOC permit limits after co mpletion of all phases of the CECP and the retirement of existing Units 1, 2, and 3. The increase is calculated based on the total expected emission increase re sulting from the CECP and act ual emission reductions due to shutting down of the three existi ng utility boilers. The maximum annual emissions are based on the larger of the emissions during a standard op eration year or a commissioning year.Final Determination of Compliance Page 25 of 63 August 4, 2009 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 32.21 43.39
CO 339.9 268.8 71.10
VOCs 23.7 15.33 8.4
SOx 16.9 6.2 10.7
PM10 39 31.5 7.5
PM 2.5 39 31.4 7.6
PM 39 31.64 7.4

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 initial 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.Final Determination of Compliance Page 26 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Table 5c – Contemporaneous Emission Increases

Pollutants Maximum Year Allowed PTE Increases From CECP, tons/yr Actual Emission Reductions from Units 1, 2, and 3, tons/yr Contemporaneous Emission Increase, tons/yr

NOx Standard 72.11 32.21 39.9 CO Commissioning 339.9 268.8 71.10 VOCs Commissioning 23.7 15.33 8.4
SOx Standard 5.6 6.2 -0.6
PM10 Standard 39 31.5 7.5
PM2.5 Standard 39 31.4 7.6
PM Standard 39 31.64 7.4

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 fire pump only.

The Applicant agreed to accept emission limits, as necessary, on the single combustion turbine and emergency fire pump combined and Units 1, 2, and 3 to limit emissions below the PSD modification thresholds for pollutants for which the District attains the national ambient air quality standards, and, in the case of NOx and VOCs, limit emissions to a level below the major
modification threshold or to a level consistent with the emission offsets provided (see below).

Only CO, PM2.5, and PM10 emissions from Units 1, 2, and 3 need to be limited in Phase I to provide actual emission reductions to preven t triggering the PSD modification or major modification thresholds. For VOCs, SOx, a nd PM, the FDOC permit conditions limit theFinal Determination of Compliance Page 27 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 emissions of the new equipment in Phase I to le ss than the major modification threshold (VOCs) or the PSD modification threshold (SOx and PM) without consideration of actual emission reductions from the existing equipment. For NOx, the allowed emission increase for the new equipment in Phase I is less than the PSD modi fication threshold but doe s constitute a major modification. However, the FDOC permit condi tions require surrender of sufficient emission reduction credits prior to the new equipment opera tion to fully offset th is increase without
consideration of actual emission reductions. Th erefore, limits on emissions for NOx, VOCs, SOx, and PM from Units 1, 2, and 3 are not necessary.

Consistent with the necessary shakedown peri od for the CTG/STG system (not to exceed 180 days), the actual emission reductions need not occur until the end of sh akedown period for the first turbine to reach full commercial operation (i.e ., before that time emissions from the three existing utility boilers are not limited other th an being prohibited from operation whenever a combustion turbine of the CECP is operated dur ing the shakedown period ,). 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 co mbustion turbine has an in itial startup (also known as “first fire”). During the shakedown periods fo r both turbines the limits on potential to emit for both combustion turbines and the emergency engine listed in Table 5c are also in effect, which serves to limit the potential to emit of all th e emission units associated with 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.Final Determination of Compliance Page 28 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 32.21 No Limit 0
CO 268.80 198.75 70.05
VOCs 15.33 No Limit 0
SOx 6.15 No Limit 0
PM10 31.49 26.89 4.6
PM2.5 31.40 21.80 9.6
PM 31.64 No Limit 0

Table 5e – Phase I Contemporaneous Emission Increases

Pollutants Allowed Emission Increases from One Turbine and Emergency Fire

Pump Engine, tons/yr Actual Emission Reductions from

Units 1, 2, 3, tons/yr Contemporaneous Emission Increase, tons/yr

NOx 36.05 0 36.05
CO 169.95 70.05 99.9
VOCs 11.85 0 11.85
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

Contemporaneous Emission Increases After Phase II After commissioning of both turbines has been completed (end of Phase II), expected emissions for CO and VOCs are reduced. The Applicant ha s agreed to accept annual emission limits forFinal Determination of Compliance Page 29 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 these pollutants that reflect the lower expect ed annual emissions. The contemporaneous emission increases applicable to postcommi ssioning operations are given in Table 5f.

Table 5f –Contemporaneous Emission Increases After Phase II

Pollutants Allowed Emission Increases from One Turbine and Emergency Fire

Pump Engine, tons/yr Actual Emission Reductions from

Units 1, 2, 3, tons/yr Contemporaneous Emission Increase, tons/yr

NOx 72.11 32.21 39.90
CO 217.3 268.80 -51.50
VOCs 20.1 15.33 4.77
SOx 5.6 6.15 -0.55
PM10 39 31.49 7.51
PM2.5 39 31.40 7.60
PM 39 31.64 7.36

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 notFinal Determination of Compliance Page 30 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 a major modification for VOCs because the F DOC permit conditions limit VOCs increases to less than 25 tons per year.

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:

Pollutant Emission Rates (tons/yr)
PM 25
PM10 15
PM2.5 10
NO 2 40
VOCs 40
SO 2 40
CO 100 Lead (Pb) 0.6 (All NOx is considered NO 2 for the purpose of PSD determinations).

Without considering the FDOC annual limits, th e contemporaneous emission increase of NOx is 43.39 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 72.11 tons per year of NOx emissions in the FDOC permit to keep the project NOx emissions below the PSD modifica tion threshold. None of the other pollutant contemporaneous emissi on 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, VOCs 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 inFinal Determination of Compliance Page 31 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 apply 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 VOCs, 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, VOCs, 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 VOCs, 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 isFinal Determination of Compliance Page 32 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 over 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 Redevelopment Project is proposed to be permitted by South Coast Air Quality Management District in a Preliminary Determination of Compliance issued on August 22, 2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two rapid response combined-c ycle Siemens turbines identical to the combustion turbines proposed for the CECP , and is proposed to be permitted at 2.0 ppmvd of NOx averag ed over one hour.Final Determination of Compliance Page 33 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 • 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 determined that BACT for NOx should be 2.0 ppmvd at 15% oxygen, averaged over one hour for normal operation with appropriate exclusions to address technical feasibility for startups and shutdowns and other abnormal periods of operation. As defined in Rule 20.1(c)(32), LAER means the most string ent emission limitation,
or most effective emission control device or co ntrol technique, unless such emission limit , device or technique is not achievable. An em ission limit of 2.0 ppmvd NOx at 15% averaged over one hour is considered by the District to be the current most stringent emission limit for larger combined-cycle combustion turbines that is achievable. Therefore, this standard also applies as LAER for NOx for such turbines.

As proposed by the Applicant, the CECP combus tion turbines will be equipped with dry ultra
low-NOx combustors and a SCR add-on emission control system 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 pr oposed a CO emission limit of 2.0 ppmvd averaged over one hour as BACT and LAER during normal operations.Final Determination of Compliance Page 34 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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:

• 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 has been operating
since 2005.

• The El Segundo Power Redevelopment Proj ect is proposed to be permitted by South Coast Air Quality Management District in a Preliminary Determination of Compliance issued on August 22, 2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two rapid response combined-c ycle Siemens turbines identical to the combustion turbines proposed for the CECP , and is proposed to be permitted at 2.0 ppmvd of CO averaged over one hour.

• The Palomar Energy Center in Escondido 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.Final Determination of Compliance Page 35 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Based on the information above, the District has determined a CO limit of 2.0 ppmvd calculated at 15% oxygen averaged over one hour to be BA CT for CO for the CECP combustion turbines for normal operation with appropriate exclusion to address technological fe asibility for startups and shutdowns and other abnormal periods of operation. To meet this requirement, the Applicant evaluated the use of an oxidation catalyst, which is th e only postlcombustion technology currently available to control CO, VOCs, and toxic em issions. This technology is acceptable as BACT for CO. The Applicant will th erefore use an oxidation catalyst 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 cont rol system, which is the only postcombustion technology currently available to control CO, VOCs, and toxic emissions. The Applicant has proposed a VOC emission limit of 1.5 ppmvd at 15% oxygen averaged over one hour as BACT at greater than 60% load for norma l operations. The limit is to be achieved by use of an oxidation catalyst system. This limit is lower than that the Applicant proposed in the
PDOC

— i.e., 2.0 ppmvd at 15% oxygen.

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. For the PDOC, the District examined the following large combined-cycle combustion turbine projects with VOC emissi on 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 of VOCs averaged over one hour. The Sithe Mystic Power Plant combustion
turbine is a Mitsubishi 501G turbine. This turbine is considerably larger and a newer generation G-class combustion turbine as comp ared the Siemens F-class turbine proposed for this project.Final Determination of Compliance Page 36 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 • The Magnolia Power Project was permitted by the South Coast Air Quality Management District at 2 pp mvd of VOCs averaged over one hour. This plant has been operating since 2005.

• 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 VOCs averaged over three hours, with clock hours that include a portion of a startup or shutdown period excluded.

• The El Segundo Power Redevelopment Proj ect is proposed to be permitted by South Coast Air Quality Management District in a Preliminary Determination of Compliance issued on August 22, 2008 [CEC Docket No. 00-AFC-14C (Amendment Proceeding)]. This plant has two rapid response combined-c ycle Siemens turbines identical to the combustion turbines proposed for the CECP , and is proposed to be permitted at 2.0 ppmvd of VOCs averaged over one hour.

• The Palomar Energy Center in Escondido, Ca lifornia, has been able to comply with 2.0 ppmvd VOC limit averaged over three hours during normal operations, excluding startup and shutdown periods, limited periods of low load operation, and tuning. District experience based on CO CEMS data indicate s that it likely achieves less than 2.0 ppmvd averaged over one hour.

For the FDOC, the District examined the follo wing two additional projects with VOC emission limits of 2.0 ppmvd or less at 15% oxygen:Final Determination of Compliance Page 37 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 • The Ricmond County Combustion Turbine Facility was issued a final PSD permit by the North Carolina Department of Environm ent and Natural Resources for two Siemens turbines similar to those proposed for th e CECP with a 1.0 ppmvd VOC limit for loads greater than 70% and a 5.0 ppmvd VOC lim it for turbine loads between 60% and 70% (excluding startups, shutdowns, and fuel switching). The turbines are permitted for either combined-cycle or simple-cycle operation. This limit is to be verified by a one-time source test on one of the turbines at greater than 75% load. This facility is not required to have an oxidation catalyst. This f acility has not been constructed.

• The P.L. Bartow Power Plant was issued a PSD permit by the Florida Department of
Environmental Protection with a VOC lim it of 1.2 ppmvd (excluding startups, shutdowns, and fuel switching) for four combined -cycle turbines (permitted to operate in simple-cycle mode in rare situations) and one simple-cycle turbine using Siemens turbines similar to those proposed for the CECP. This facility is not required to have an oxidation catalyst although provisions were made during construction so one could be installed if necessary. The limit has initia l compliance as been verified by one-time
source tests at 100% load for four of the comb ined-cycle turbines and 55% load for three of those units in 2009 (the District has not obtained the other sour ce test results). However, the units were not tested at 100% load with steam augmentation, which can
increase CO and VOC emissions.

Although the Florida turbines did comply with the 1.2 ppmvd emissi on limit at low loads, they are not expected to operate at low loads, so the pr actical affect of the limit at loads less than 70% is unclear. In fact, the turbines are prohibited from operating at less than 70% load in simplecycle mode by permit conditions (except for startups , shutdowns, tuning, and fuel switching). In combined cycle mode, they are expected to oper ate as base-loaded units which, unlike the CECP, are expected to typically operate n ear 100% load as much as possible.

No further periodic verification of compliance with the VOC limit is required for the Florida turbines by the permit. The permit notes state that compliance with the CO emission limit (4.1 ppmvd) will be used as an i ndicator of low VOC emissions.Final Determination of Compliance Page 38 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Neither the Florida nor North Caro lina project require periodic sour ce testing to verify the VOC limit is achieved continuously. While the FDOC pe rmit conditions for the CECP require that the VOC limit be verified by periodic source test ing and by monitoring of CO emissions on a hourly basis as a surrogate for VOC em issions (see below) over the life to the turbine. Using CO emission levels as surrogate on an hourly ba sis is a more robust method of monitoring VOC
emissions than an initial source te st and CO compliance with a CO limit. An examination of the summary source test results for the Florida turbines indicates that, based on the VOC/CO ratio at high load, the VOC concentration coul d easily exceed the 1.2 pp mvd limit while the CO concentration remained below 2 ppmvd and in compliance with the 4.1 ppmvd limit for those
turbines.

Since the Florida and North Carolina limits have not been verified as achievable over a long period of time and have not been verified with steam augmentation the District does not consider them achieved in practice for the type of turbine and operations proposed for the CECP. Moreover, a catalytic oxidation system designed to achieve 1.5 ppmvd at 60% load should be designed for at least a 70% VOC reduction at that load level since manufacturer specifications
indicate uncontrolled VOC emissions can be as hi gh 5 ppmvd at that load. The use of a properly designed oxidation catalyst translates into lower VOC emissions at all load s and at all levels of
VOC concentration in the turbine exhaust.

Based on the above information a nd considerations, the District has determined that BACT for the CECP combustion turbines is a properly designed oxidation catalyst combined with a 1.5 ppmvd VOC limit for turbine loads greater th an 60%, measured as methane at 15% O 2 over a one-hour averaging period for normal operation with appropriate exclusions to address technologically feasib ility for startups and shutdowns and ot her abnormal periods of operation.

An initial source test will be used to confirm compliance with these limits. Additionally, the
source test data will be used to establis h a correlation between CO emissions and VOC emissions to provide an accurate indicator of continued compliance with these limits using
the CEMS data for CO on a one-hour basis. Compliance will be determined based on bothFinal Determination of Compliance Page 39 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 source test data and a surrogate relationship with CO because CEMS technology is not yet
available for VOCs.

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 = 4.7 lb for the 7 minute shutdown + (23/60) x 5.3 lbs/hr for normal operations
= 6.22 lbs

Table 6a presents the mass emissions limits during startup and shutdownFinal Determination of Compliance Page 40 of 63 August 4, 2009 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
VOCs 15.5 6.22

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 FDOC permit conditions based on the minimum operating temperature provided by the
manufacturer for the similar SCR associated with the El Segundo Power Redevelopment Project.

The District has determined that the above requirements represent BACT for NOx, CO, and VOCs and LAER, for NOx only, specifically app licable 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, and VOC emissions can be much higher than in the lean premixFinal Determination of Compliance Page 41 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 combustion mode. It is, therefore, not tec hnologically feasible, to achieve the BACT emission levels applicable to norma l operations 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.

Tuning of the combustion-turb ine system may be done for many reasons. Tuning may be done to ensure continued compliance with applic able permit limits. It may also be done to for reasons not directly related to compliance with permit limits . For example, the facility may wish to tune the SCR ammonia injection grid system to reduce ammonia usage, with obvious air quality benefits, ev en though immediate emission lim it compliance or operational safety is not in jeopardy. Th e facility may also wish to improve the turbine combustor efficiency and thereby reduce greenhouse ga s emissions, again without any emission limit compliance or operational safety concerns.

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 combustion turbine trip (unplanned shutdown). In most cases, the problem is resolved without shutting down the tu rbine, 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 determined that following represent BACT for NOx, CO, and VOCs and LAER for NOx during specified abnormal

events:Final Determination of Compliance Page 42 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 • 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.

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 criteria for a transient events and BACT levels have been acceptable to another large combined-cycle facility.

PM10 and SOx—Combustion Turbines
From the ARB Guidance for Power Plant 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 natu ral gas in the local gas distribution system averages well under 0.75 grains per 100 standard cubic feet of gas. The Applicant will be required to maintain documents showing the sulfur content of natural gas used. Any alternative supplies of natural gas must meet this sulfur content limit.Final Determination of Compliance Page 43 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 concluded that BACT for the emergency fire pump engine is an engine certified to the most stringent federal emission standard for fire pump engines (i.e., a 2009 or later model year engine). The fire pump engine must also comply with the requirements of Section 93115 et. seq. of Title 17 of the California Codes of Regulations (CCR)

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 Quality Standards. The modeling was done under expected worst-case hourly and annual emi ssion rates during commissioning, startup and shutdown, and normal operations. For the FDOC, no additional modeling was performed, but some of the ambient background values us ed in the analysis were adjusted where necessary. Additionally, the PM 2.5 impacts were reanalyzed in light of recent (post-PDOC)
EPA actions.

The analysis shows no violation of any Ambient Air Quality Standard. The analysis can be reviewed in more detailed the Appendix A of this determination. The FDOC permit conditions contain hourly and annual emission limits that are applicable at all times to ensure that the project will not cause or contribute to a violation of a ny National Ambient Air Quality Standard or California Ambient Air Quality Standard.Final Determination of Compliance Page 44 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 Rule 20.3 (d)(3) -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 ac cepted an annual limit of 72.11 tons per year of NOx emissions to keep the project NOx emi ssions below the PSD m odification threshold.
Since the annual limit suffices to avoid the PSD modification threshold and NOx emissions are monitored with 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 app licable PSD modification thresholds after completion of the project. In addition, for Phase I of the project the Applicant has accepted permit limits, as necessary, to limit contemporan eous emission increases to less than all PSD modification thresholds (see Tables 5d and 5e). Therefore, the CECP is not subject to the requirements 0f 20.3(d)(3).

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 tha the District 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 was published in the San Diego Daily Transcript and mailed to EPA and ARB air districts for a 30-day comment pe riod in accordance with Rule 20.3(d)(4).

Rule 20.3(d)(4)(i) requires that the District c onsider all comments received. The District
considered all comments received before taking this final action.Final Determination of Compliance Page 45 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 precurs ors. For the CECP, VOC annual emission increases are limited to below the major m odification thresholds by the FDOC permit
conditions without consideration of actual emi ssion reductions. Therefore, offsets are only required for NOx emissions. The maximum cont emporaneous emission increase of NOx is 39.9 tons per year for this project. An offset ratio of 1.2 to 1 is required [Rule 20.3(d)(8)(i)(B)], so a total of 47.88 tons per year of NOx emission offsets will be required.
The offsets must be surrendered to the District prior to the initial startup of the equipment for which they are required [Rule 20.1(d)(5)(iii)]. Offsets may be actual emission reductions, stationary source Class A emission reduction credits (ERCs) issued under District Rules 26.0-26.10, or mobile source emission reduction cr edits (MERCs) issued under District Rule 27 (if approved by ARB and EPA.). The Applic ant has agreed to surrender ERCs sufficient to provide all the required offsets for the project prior to the initial operation of first turbine.

Cabrillo II, LLC, a wholly owned subsidiary of NRG Energy, Inc., th e Applicant’s parent company, currently owns Emission Reduction Cr edits (ERCs) representin g 37.6 tons per year of NOx emission offsets and the Applicant has entered a contractual option to purchase up to 24 tons of VOC ERCs to provide the remaining required offsets. Under District Rule 20.1 (d)(v)(6), the VOC ERCs are di scounted by a ratio of 2 to 1 when used to provide NOx offsets. The ERCs to be used as offsets are listed in Appendix D.

Rule 20.3(e)(1) – Compliance Certification This rule requires that, prior to receiving an Authority to Construct (or Final Determination of Compliance), an applicant for any new or m odified stationary sour ce required to satisfy the LAER provisions of Rule 20.3(d)(1) or the major source o ffset requirement of Rule 20.3(d)(8) shall certify that all major sources operated by the applicant in the state are inFinal Determination of Compliance Page 46 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 compliance with all applicable emissions lim itations and standards under the federal Clean Air Act. The Applicant is an indirect who lly owned subsidiary of NRG Energy, Inc., which also operates the Encina Power Station, which is a major stationary source located in San Diego County, and on whose property the CECP w ill be located. The Encina Power Station operation has been regulated by the San Diego Ai r Pollution Control Dist rict under permits to operate issued for its five boilers and one ga s turbine. Besides the Encina Power Station, NRG Energy owns other potential major stati onary sources in the state including the El Segundo Generating Station in El Segundo Calif ornia and the Long Beach Generating Station in Long Beach California. The requi red compliance certifications for all major sources in the state owned by NRG Energy or its subsidiaries, Inc. have been submitted to the
District.

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 was submitted to the CEC on November 20, 2008. This Final Determination of Compliance will be submitted to the CEC.

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.Final Determination of Compliance Page 47 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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.

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 Utilities 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.Final Determination of Compliance Page 48 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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/dscf

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.

The combustion turbines for this project will be equipped with dry ultra low NOx combustors and SCR controls for NOx. Proposed permit conditions limit NOx emissions to 2.0 ppmvd during normal operations, which is far belo w the 42 ppmvd rule standard. Maximum durations of startups and shut downs (60 minutes for startup an d 30 minutes for shutdown) are shorter than Rule 69.3 requirements. Howeve r, commissioning, low-load operation, tuning, and transient periods are still subject to the ru le standards. The facility permit will contain
conditions to limit emissions below the emissi ons 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.Final Determination of Compliance Page 49 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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.

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.

The combustion turbines for this project will be equipped with dry ultra low NOx combustors and SCR controls for NOx. The FDOC permit c onditions limit NOx emissions to 2.0 ppmvd during normal operations, which is far belo w the 12.6 ppmvd rule standard. Maximum durations of startups and shut downs (60 minutes for startup an d 30 minutes for shutdown) are shorter than Rule 69.3.1 requirements. Howeve r, commissioning, low-load operation, tuning, and transient periods are still subject to the ru le standards. The facility permit will contain
conditions to limit emissions below the emissi ons 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,Final Determination of Compliance Page 50 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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, the FDOC permit conditions will 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 FDOC 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 ofFinal Determination of Compliance Page 51 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 request. The FDOC permit cond itions require records to be kept five years.

Rule 69.4.1(i)(1) exempts emergency standby engines from periodic source testing.

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 potential to emit toxic air contaminants will increase. A detailed HRA is necessary if toxics emissions exceed District de minimis levels. Toxic
Best Available Control Technol ogy (TBACT) must be installed if the HRA shows a cancer risk greater than one in a million at a recepto r where a person could be reasonably anticipated to be exposed. The cancer risk is based on a 70-year exposure for a residence and a shorter exposure time for occupational workers. Additiona l requirements apply if the cancer risk is expected to exceed ten in a million.

An HRA, which was reviewed by the Distri ct, was performed using EPA AP-42 emission
factors and California Air Toxics Emission Factors (CATEF) for toxic air contaminant emissions from the project for normal operations . The emission increases from the operation of the two combustion turbines and the emerge ncy fire pump engines were considered. No emission decreases from the existing facility were accounted for in the assessment. In addition, potential acute health impacts dur ing startup shutdown and commissioning operations and the contributions of those operations to chronic impacts and cancer risk were examined using emission factors based on a r ecent source test of a combined-cycle power plant during the first hou r of a cold start. The HRA performed shows that the incremental cancer risk is 0.47 in a million for exposed re sidents and 0.27 for exposed workers if the number of startups per turbine is limited to 1460 per year. The FDOC permit conditions limit the number of startups for each turbin e to 1460 per year. The acute and chronicFinal Determination of Compliance Page 52 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 incremental health impacts measured by the Hea lth Hazard Index (HHI) are also all less than 1.0 at the point of maximum impact (0.01, 0.12, and 0.16 for the chronic, 8-hour, and acute HHIs, respectively) and, therefore, meet Rule 1200 requirements. Although TBACT is not required since the maximum cancer risk is less than one in a million, the oxidation catalyst
installed as BACT for CO and VOC emissions also signi ficantly reduces toxic air
contaminant emissions and would be consider ed TBACT for this project—if TBACT had been required. The health risk analysis of th is project is further di scussed 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.

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 theFinal Determination of Compliance Page 53 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 FDOC 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 the FDOC permit conditions.

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 fo r testing and maintena nce operation by the FDOC 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.Final Determination of Compliance Page 54 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 FDOC 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 documents 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 the FDOC 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 the FDOC 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, orFinal Determination of Compliance Page 55 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 with 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.Final Determination of Compliance Page 56 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 postcombustion emission control, NOx emissions from this combustion turbine are controlled to 2.0 ppm at 15% O 2 during normal operation. Information submitted as part of the proposed City of Vernon Power Plant (06-AFC-4, Table 8.1B-2) indicates that the 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 the FDOC permit conditions.Final Determination of Compliance Page 57 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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.

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 FDOC permit requires conti nuous monitoring equipment meeting these requirements to be installed, calibra ted, and maintained.Final Determination of Compliance Page 58 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 FDOC 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 st artup, shutdown and malfunction. The FDOC 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 FDOC permit conditions..

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 FDOC permit contains conditions sa tisfying these requirements of Subpart KKKK.Final Determination of Compliance Page 59 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 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 A pplicant would not comply with model year 2009 standards, the Applicant has committed to install a comp liant engine and the FDOC permit conditions require compliance with the sta ndards 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 the engine. This re quirement is included in the FDOC 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 notification

A CID R AIN

40 CFR 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).Final Determination of Compliance Page 60 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 40 CFR 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 is included in the FDOC permit conditions. The Applicant submitted the Acid Rain permit application to the District on September 4, 2008.

40 CFR 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.

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 the 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 FDOC permit
conditions.Final Determination of Compliance Page 61 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 VI. ADDITIONAL ISSUES

P ARTICULATE E MISSION R ELATING TO THE U SE OF D ESALINATED 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 particulate matter from the evaporative cooler parameters since the water supply is expected to comply with the vendor’s recommended water quality standards. Therefore, no further particulat e 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 FDOC emission limits. However, during the initial startup, certain emissions standards must remain in effect. These include the 72.11 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.Final Determination of Compliance Page 62 of 63 August 4, 2009 Applications No. 985745, 985747, and 985748 S OURCE T EST F REQUENCY The FDOC permit conditions require that the fr equency of annual co mpliance source testing be in accordance with the appli cable RATA frequency requiremen ts of the federal acid rain program provisions at 40 CFR Part 75, A ppendix B, Sections 2.3.1 and 2.3.3. The annual source testing is to show compliance w ith the NOX, CO, VOC, PM10, and ammonia emission limits and to verify the accuracy of the continuous emi ssion monitoring system (CEMS). At a minimum, the acid rain progr ams provisions require th at a source test be performed after four calendar quarters in wh ich the unit operates at least 168 hours in each quarter (any hour the turbine combusts fuel is considered an operating hour for purposes of Part 75). It is expected that a source test would be required once per year for this facility since the Applicant anticipates about 4000 operati ng hours per year for each turbine, or about 1000 hours per quarter on average.

In cases of where low levels of operation (less than 168 operation hours per quarter) do not trigger a source test, the acid rain program provi sions require a test be conducted every eight calendar quarters even if there have not been four quarters with 168 hours or more of operating time in the eight-quart er period. Any such test mu st be conducted within 720 operating hours of the end of the eight-quarter period.

## APPENDIX A

APPROVAL OF AIR QUAL ITY IMPACT ANALYSIS

## AIR QUALITY IMPACT ANALYSIS

FINAL REVIEW REPORT

CARLSBAD ENERGY CENTER PROJECT APPLICATION 985423

SEPTEMBER 24, 2008 REVISED JULY 27, 2009

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 JULY 27, 2009 AQIA Report Revisions
1. Table 4-1, Maximum Background Concentrations, Project Area, 2004-2006. (Corrected CO background and rounded other background values)
2. Table 4-4, Modeled Maximum Proposed Project Impacts (Corrected CO background and rounded other background values)
3. Table 5.1-29, Maximum Background Concentrations, project areas, 2004-2006 (AFC Table submitted September 2007 and revised September 24, 2008) (Corrected CO background and rounded other background values)
4. Section 5.0, Conclusion (Revised discussion regarding PM10 and PM2.5 SILs)

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%,3 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. 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.Table 3-1Screening Modeling Impacts5Table 3-2Screening Level Modeling Impacts6Table 3-3Emission Rates and Stack Parameters for Refined Modeling7Table 3-3(Continued)Emission Rates and Stack Parameters for Refined Modeling8Table 3-3(Continued)Emission Rates and Stack Parameters for Refined Modeling9Table 3-4Startup/Shutdown and Commissioning Modeling Inputs4.0 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.11 TABLE 4-1 MAXIMUM BACKGROUND CONCENTRATIONS a , PROJECT AREA, 2004-2006 (μg/m 3 )—REVISED JUNE 25, 2009

Pollutant Averaging Time 2004 2005 2006

1-hour 186 145 152 NO 2 (Camp Pendleton) Annual 23 23 21 1-hour 110 105 89 3-hour 52 68 79 24-hour 24 24 24 SO 2 (San Diego)

Annual 10 8 10 1-hour 7210 6753 6524 CO (Escondido) 8-hour 4361 3548 4136 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.12 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.13 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 REVISED June 25,2009

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 0.1 186 23 314 23 338 56 - 100 SO 2 1-hour 3-hour 24-hour Annual 4.3 2.0 0.4 0.0 110 79 24 10 114 81 24 10 650

- 109

- - 1300 365 80 CO 1-hour 8-hour 3,228.0 a 675.9 a 7210 4361 10438 5037 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 b 14.1 34 14 -- 12 35 15
Notes: a. Impacts during gas turbine commissioning. b. Three year average of 98 th percentile.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, or attainment of , of the Federal Ambient Air Quality Standard. This can be considered the case for California PM10 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. Monito red background levels exceeded the Ca lifornia annual standard. Since the background is already in exceedance of the annua l 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 for PM10 and also well below all of the proposed SILs for PM2.5. Predicted impacts less than SILs are normally considered15 to not significantly affect compliance with Federal Ambient Air Quality Standards regardless of the background level. Specifically in non-attainment areas, project impacts less than the SILs are deemed to not significantly cause or contribute to violations of, or attainment of, the Federal Ambient Air Quality Standard. This can be considered the case for California PM2.5 Ambient Air Quality Standards as well.

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 17916 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) Revised June 25, 2009
Pollutant Averaging Time 2004 2005 2006

1-hour 186 145 152 NO 2 (Camp Pendleton) Annual 23 23 21 1-hour 110 105 89 3-hour 52 68 79 24-hour 24 24 24 SO 2 (San Diego)

Annual 10 8 10 1-hour 7210 6753 6524 CO (Escondido) 8-hour 4361 3548 4136 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 ASSESSMENTRule 1200 Health Risk Assessment Report

1 of 11 Facility ID: 333A Applications: 985745, 985747, and 985748. Project Engineer: Steve Moore Toxics Risk Analyst: Michael Kehetian HRA Tools Used: AERMOD (Version 07026) and HARP (Version 1.4a) Report Date: 08/03/09

Review of Supplemental Health Risk A ssessment (HRA) evaluation for the Carlsbad Energy Center Project (CECP) dated April 29, 2009

A supplemental health risk assessment (HRA) was performed for the Carlsbad Energy Center Project (CECP), 4600 Carlsbad Blvd, Carlsbad, CA 92008 by Sierra Research and submitted to the District for review on April 29, 2009.
The supplemental HRA evaluation incorporates updates by the Office of Environmental Health Hazard Assessment (OEHHA) to the guidelines for conducting health risk assessments under the Air Toxics Hot Spots Program (Health and Safety Code Section 44360(b)(2)). The guideline methodology was revised to reflect scientific knowledge and techniques developed since the previous guidelines were prepared, and in particular to explicitly include consideration of possible differential effects on the health of infants, children and other sensitive subpopulations, in accordance with the mandate of the Children’ s Environmental Health Protection Act (Senate Bill 25, Escutia, Chapter 731, Statutes of 1999, Health and Safety Code Sections 39669.5 et seq). On June 18, 2008, the Scientific Review Panel on Toxic Air Contaminants (TACs) approved the final versions of the methodology section and th e associated methodological appendices for the revised Technical Support Document (TSD) for the updates. Subsequently, on December 19, 2008, OEHHA formally adopted the revised Air T oxics Hot Spots Program Technical Support Document for the Derivation of Noncancer Reference Exposure Levels (RELs), adopting a new 8-hour REL and revised chronic and acute RELs for acetaldehyde, acrolein, arsenic, formaldehyde, manganese, and mercury. The formal adoption of the new and revised RELs required them to be used in any HRA performed under Rule 1200. Even though an HRA had been performed for the CECP prior to the Preliminary Determination of Compliance (PDOC) issuance on November 20, 2008, Rule 1200 requires that an HRA be performed including the OEHHA updates since final approval of the project had not been granted.
This supplemental HRA has been updated to include the most recent Consolidated Table of OEHHA / Air Resources Board (ARB) Approved Risk Assessment Health Values dated February 9, 2009, which incorporates the OEHHA new and revised RELs. The supplemental HRA also includes additional refinements in the HRA requested by the District. These refinements are detailed in the Sierra Research submittal.Rule 1200 Health Risk Assessment Report

2 of 11 RESULTS & CONCLUSION

S OURCES & O PERATIONS R EVIEWED Rule 1200 requires the HRA address the increases in potential to emit (PTE) associated with any new or modified emission units. The only emissi on increases for the CECP are associated with the following new equipment:

 Two natural gas-fueled combined-cycle combustion turbines each maximally rated at 2085 MMBtu/hr at an ambient temperature of 37 o F, without power augementation, and equipped with an oxidation catalyst to control volatile organic compounds (VOC) and carbon monoxide (CO) emissions. The oxidation catalyst also serves to control toxic air contaminant emissions, which, for this source, are all VOCs. 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 and steam augmentation that also can be used to increase power.

 One diesel-fired emergency fire pump rated at 246 brake horsepower (bhp).
The operating scenarios evaluated included startups, shutdowns, normal full load operations, during the commissioning year and noncommissioning years. The scenarios evaluated were determined to be sufficient in scope to adequately characterize the maximum potential health impacts.

W ORST -C ASE P OTENTIAL H EALTH I MPACTS Based on the review of the applicant’s submittal, 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 the table below. The worst-case residential incremental cancer risk health impacts are based on the evaluation of gas turbines operating 8760 hours during the commissioning year in which both turbines have 1460 starups and shutdowns (excluding commissioning), commissioning operations for 415 hours, and 6662 hours at full load mode. In addition, the diesel-fueled emergency water pump is assumed to operate for 50 hours. Both commissioning and non-commissioning year operating cases used in the modeling to estimate cancer, chronic, 8-hour, and acute health impacts are described further in this report.

Category Health Impact District Rule 1200 Significance Level Maximum Incremental Cancer Risk – Resident (per million) 0.47 1.0 or 10 (with TBACT) Maximum Incremental Cancer Risk – Worker (per million) 0.27 1.0 or 10 (with TBACT) Total Chronic Noncancer Health Hazard Index - Resident 0.01 1.0 Total Chronic Noncancer Health Hazard Index - Worker 0.01 1.0 Total Acute Noncancer Health Hazard Index 0.16 1.0 Total 8-Hour Noncancer Health Hazard Index 0.12 1.0Rule 1200 Health Risk Assessment Report

3 of 11 The major contributors to the risk are:

 Cancer risk is primarily due to noninhalation exposure to polycyclic aromatic hydrocarbons through oral exposure, dermal contact, soil ingestion, and for residential exposure, the non-urban home grown produce pathway. The polycyclic aromatic hydrocarbons were evaluated as benzo[a]pyrene where there was not a risk factor available for the compound, which likely results in conservatively high estimate of their impact.

 The chronic health hazard index (HHI) is primarily due to emissions of formaldehyde from the combustion turbines and diesel particulate matter from the diesel-fueled emergency fire pump.

 The 8-hour hazard index is due mainly to emissions of formaldehyde from the combustion turbines.

 The acute hazard index is primarily due to emissions of formaldehyde and acrolein from the combustion turbines and the emergency fire pump.
It should be noted that the potential health risks presented in the table above are conservatively high due to the conservative assumptions specifi ed in the California Office of Health Hazard Assessment (OEHHA) health risk assessment guidance. In addition, the maximum health risks presented 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.
The reported occupational cancer, chronic, 8-hour, and acute worst-case potential health impacts are at the point of maximum impact (PMI), which is the maximum impact point beyond the facility boundary and although conservative, does not necessarily represent the actual health effects because a person may not reasonably be expected to be present at the PMI location for the exposure period of concern. Although the reported residential cancer risk at the PMI is estimated to be 1.22 in a million, the District has identified the risk to actual exposed residents to be well below the maximum impact point.

C ONCLUSION The indicated health impacts are all less than the Rule 1200 minimum significance levels. The maximum incremental cancer risk for a resident is 0.47 in a million and is 0.27 in a million for a worker. Because the incremental cancer risk is equal to or less than one in a million, the project is approvable without toxic best available c ontrol technology (TBACT) applied. However, the combustion turbines are proposed to be equipped with a standard oxidation catalyst, which would be considered TBACT for this type of equipment if the risk was greater than one in a million.Rule 1200 Health Risk Assessment Report

4 of 11 RISK CHARACTERIZATION
The following assumptions and risk modeling choices were used to characterize the risk in the HRA:

 Mutipathway exposure assumed the OEHHA default deposition rate equal to 0.05 meters per second for emitted particles uncontrolled by a particulate matter control device.

 For calculating residential cancer risk, considering inhalation is not one of the two dominant pathways, the ARB Derived (Adjusted) Analysis Method was used, incorporating the adult high-end breathing rate equal to 393 Liters/Kilogram-day.

 A ground level concentration adjustment factor of 4.2 (24 / 8 hours per day times 7 / 5 days per week) was appropriately applied for the diesel-fueled emergency fire pump to calculate worker cancer risk and the chronic hazard index.

 Estimated cancer risk is conservatively high based on emissions of polycyclic aromatic hydrocarbons (PAHs) being appropriately evaluated as benzo[a]pyrene, referencing the OEHHA Air Toxics Hot Spots Program Guidance Manual for Preparation of Health Risk Assessments, Speciation for Specific Classes of Compounds: Polycyclic Aromatic Hydrocarbons (PAHs) , Section 8.2.3, August 2003.

 In addition, cancer and chronic health impacts include the required noninhalation pathways per the OEHHA Guidance Manual, Determination of Noninhalation (Oral) Cancer Risk , Section 8.2.4, and Noncancer Chronic Health Impacts from the Oral Route
, Section 8.3.2.

 To determine the maximum 8-hour ground level concentration, the possibility that a person may potentially be exposed during any 24-hour period was considered. Thus, three 8-hour daily block periods were modeled (12am-8am, 8am-4pm, and 4pm-12am).

 Although risk characterization for determining noncancer health effects involves the summation of the total hazard index (THI) for each target organ for exposure to a mixture of TACs, the toxicological endpoints for this evaluation are not considered, for the purpose of initially presenting an overly conservative estimate of the potential hazard index impacts.

MODELING PROCEDURES
In the modeling submitted, cancer, chronic, 8-hour, and acute risks were estimated using ARB’s HARP, Version 1.4a, Risk Analysis Module to determine source strengths (g/s per ug/m 3 ) based on emission factors for the equipment and operating scenarios. The source strengths were input into EPA’s AERMOD dispersion model to directly estimate health impacts. The District independently reviewed the AERMOD model inputs for adherence and technical accuracy with ARB and OEHHA guidance and District Rule 1200 standard procedures, incorporating the following references.Rule 1200 Health Risk Assessment Report

5 of 11  OEHHA Air Toxics Hot Spots Program Guidance Manual for Preparation of Health Risk Assessments, August 2003.

 OEHHA Air Toxics Hot Spots Program Techni cal Support Document for the Derivation of Noncancer Reference Exposure Levels, June 2008.

 Consolidated Table of OEHHA / ARB Approved Risk Assessment Health Values updated February 9, 2009.
The following AERMOD model inputs were reviewed:

 Annual and Hourly Emissions Rates (g/s)

 Cancer Potencies (mg/kg-d) -1

 Chronic, 8-Hour, and Acute RELs (ug/m 3 )

 OEHHA Adult High-End Breathing Rate = 393 (L/kg-d)

 Worker Point Estimate Breathing Rate = 149 (L/kg-d)

 Worker Exposure (5 days per week, 245 days per year, 40 years)

 Worker Ground Level Concentration (GLC) Adjustment for the diesel-fueled fire pump = 4.2

 Mutipathway (Dermal Contact, Soil Ingestion, and Home Grown Produce Non-Urban Fraction = 15%)
Receptor Grid
The dispersion modeling included a refined 25-meter receptor grid in addition to fenceline impacts along the property boundary of 25-meter resolution. The grid is sufficiently dense to identify maximum impacts.

OPERATING SCENARIOS
Turbine Startups and Shutdowns
For startup emissions, the HRA addresses the potential impact of low stack exhaust temperatures during the first few minutes of a cold start, which could increase the emission impacts. This was done by using a three phase startup hour: Phase I is the first 12 minutes of the startup, Phase 2 is the succeeding 10 minutes, and Phase 3 is the remainder of the hour. A shutdown was not included in the startup hour since The HRA done in conjunction with the PDOC showed that a startup hour without a shutdown resulted in higher impacts. 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 (no information on stack exhaust temperature was available from the manufacturer).

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

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

6 of 11 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 (38 minutes) 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. Shutdowns were assumed to occur in 7 minutes per the manufacturer information for shutdowns. For shutdowns, the minimum stack exhaust temperature was assumed to be the exhaust temperature at 50% load.
Turbine Commissioning Operations
For commissioning operations, the turbines were assumed to be operating at 50% load for same reasons as 50% load was chosen as the final load for the startup hour.
Turbine Normal Operations
The turbines were assumed to be operating at their maximum load for low ambient temperature (Case 15 in Table 5.1B-5 in the application). This case provides the highest toxic air contaminant emission rate for normal turbine operations. Operating Cases – Potential to Emit (PTE) for Cancer and Chronic Health Impacts
In the annual HRA operating cases evaluated below, the number of operating hours for startup, commissioning, tuning, and low load are based on the FDOC permit limits (1460, 415, 40, and 13 hours per year, respectively). In addition, the applicant evaluated a maximum turbine annual operating case of 8760 hours per year at full load (no startup, shutdown, or commissioning hours).

 Noncommissioning Year: Gas Turbines operate for 8760 hours including 1460 startup hours, 1460 shutdowns, 40 hours of tuning and 13 hours of low-load (50%) operation, and 7077 hours at 100% load. In addition, the diesel-fueled emergency fire pump is assumed to operate for 50 hours.

 Commissioning Year: Gas Turbines operate for 8760 hours including 1460 startup hours, 1460 shutdown hours, 40 hours of combustor tuning and 13 hours of low-load (50%) operation, 415 hours of commissioning, and 6662 hours at 100% load. The diesel-fueled emergency fire pump is assumed to operate for 50 hours.

 Noncommissioning Year: Gas Turbines operate for 8760 hours at 100% load and 50 hours for the diesel-fueled emergency fire pump.Rule 1200 Health Risk Assessment Report

7 of 11 For each case, the impact for each turbine’s operating mode (normal; startup phases 1, 2, and 3; shutdown; commissioning; tuning; and low-load operation) was weighted according to the annual operating hours for each mode. Further details are given in the Sierra Research submittal.
Operating Cases – Acute Health Impacts

 Simultaneous phased startup of gas turbine operating to a final operating load of 50% for the remainder of the hour and the maximum hourly fuel consumption rate (testing) of the emergency water pump.

 Commissioning of one gas turbine, second turbine undergoing phased startup to 50% load, and the maximum hourly fuel consumption rate (testing) of the emergency water pump. For each case, the impact of each phase of the startup was weighted according to the minutes of operation for each phase. Further details are given in the Sierra Research submittal.
Operating Cases – 8 Hour Health Impacts

 During an 8-hour period, two simultaneous pha sed startup hours and 7-minute shutdowns for the gas turbines. For the remaining 346 minutes, the gas turbines operate at 100% load. The 8-hour period also consists of the maximum hourly fuel consumption rate (testing) emissions from the emergency water pump.

 One gas turbine undergoing commissioning for 8-hours while the other turbine operating with two simultaneous startup and two shutdown phases. In addition, the maximum hourly fuel consumption rate (testing) emissions from the emergency water pump.

 Both gas turbines operating at 100% load and the maximum hourly fuel consumption rate (testing) emissions from the emergency water pump.
For each case, the impact for each turbine operating mode (normal; startup phases 1, 2, and 3; shutdown; and commissioning) was weighted according to the minutes of operation for each mode. Further details are given in the Sierra Research submittal.

EMISSION FACTORS

Emissions Control – Gas Turbines
Since the gas turbines are proposed with an oxidation catalyst, the toxic air contaminant emission factors were reduced by 50% during normal operations.
Emission Factors – Gas Turbines during Normal Operation
With the exception of ammonia and formaldehyde, these emission factors are taken from AP-42 unless an AP-42 emission factor is not available. A uniform control factor of 50% to account for the use of an oxidation catalyst is applied to all emission factors except ammonia. TheRule 1200 Health Risk Assessment Report

8 of 11 formaldehyde emission factor is taken from CATEF since the controlled emission factor is most representative of recent compliance source tests for a large combined-cycle turbine. The emission factor for ammonia is calculated from the proposed permit limit of 5 ppmd ammonia at 15% O 2 All PAHs listed in CATEF are represented. Those without an approved URF are quantified as composite PAHs.
The normal operation emission factors are shown below.

Toxic Air Contaminant Emission Factor Uncontrolled

(lb/MMscf) Emission Factor Controlled (lb/MMscf) Source

ACETALDEHYDE 4.08E-02 2.04E-02 AP-42 ACROLEIN 6.53E-03 3.27E-03 AP-42 AMMONIA 6.95 6.95 SDAPCD Permit 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 PAHs -- -- -- ACENAPHTHENE -- 9.50E-06 CATEF ACENAPTHYENE -- 7.34E-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[e]PYRENE -- 2.72E-07 CATEF BENZO[b]FLUORANTHENE 1.13E-05 5.65E-06 CATEF BENZO[k]FLUORANTHENE 1.10E-05 5.50E-06 CATEF BENZO[g,h,i]PERYLENE -- 6.85E-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 PROPYLENE 7.71E-01 3.86E-01 SDAPCD 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

Emission Factors – Gas Turbines during Startup and Shutdown
For startup and shutdown emissions, the emission factors in the table below were used in the HRA. 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-fueled 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 an oxidation catalyst. During the first hour of theRule 1200 Health Risk Assessment Report

9 of 11 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.

Toxic Air Contaminant Emission Factor (lb/MMscf) Source

ACETALDEHYDE 1.28E+00 Source Test ACROLEIN 6.89E-02 Source Test AMMONIA 6.95 Permit 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 PAHs -- -- ACENAPHTHENE 1.90E-05 CATEF ACENAPTHYENE 1.47E-05 CATEF ANTHRACENE 3.38E-05 CATEF BENZO[a]ANTHRACENE 2.25E-05 Source Test (ND) a BENZO[a]PYRENE 1.39E-05 Source Test (ND) a BENZO[e]PYRENE 5.44E-07 CATEF BENZO[b]FLUORANTHENE 1.13E-05 CATEF BENZO[k]FLUORANTHENE 1.10E-05 CATEF BENZO[g,h,i]PERYLENE 1.37E-05 CATEF CHRYSENE 2.25E-05 Source Test (ND) a DIBENZ[a,h]ANTHRACENE 2. 25E-05 Source Test (ND) a FLUORANTHENE 4.32E-05 CATEF FLUORENE 5.80E-05 CATEF INDENO(1,2,3-cd)PYRENE 2.25E-05 Source Test (ND) a PHENANTHRENE 3.13E-04 CATEF PYRENE 2.77E-05 CATEF PROPYLENE 7.71E-01 CATEF PROPYLENE OXIDE 2.96E-02 AP-42 TOLUENE 9.28E-02 Source Test XYLENES 3.48E-03 Source Test

a These compounds were tested for but not detected during the source test. The emission factor is based on one half the detection limit.Rule 1200 Health Risk Assessment Report

10 of 11 Emission Factors – Diesel Emergency Fire Pump

Toxic Air Contaminant Emission Factor (lbs/1000 gal)* Source
DIESEL PARTICULATE MATTER 3.53E-02 (lbs/hr) Manufacturer ACROLEIN 3.39E-02 SDAPCD ARSENIC 1.60E-03 SDAPCD BENZENE 1.86E-01 SDAPCD COPPER 4.10E-03 SDAPCD FORMALDEHYDE 1.73 SDAPCD HYDROGEN CHLORIDE 1.86E-01 SDAPCD MERCURY 2.00E-03 SDAPCD NICKEL 3.90E-03 SDAPCD TOLUENE 1.05E-01 SDAPCD XYLENES 4.24E-02 SDAPCD

*Unless otherwise noted.

RELEASE PARAMETERS The following release parameters were used in the HRA. They are based on the operating scenarios considered in the HRA.
Release Parameters – Gas Turbines (Potential to Emit, 100% Base Load)

Release Parameter Value Stack Height (ft) 139 Stack Diameter (ft) 21.3 Temperature deg F 361 Exhaust Velocity (fps) 68.44

Release Parameters – Gas Turbines (Startup, Shutdown, and Commissioning)

Operating Mode Duration (Minutes) Fuel Heat Input (MMBTU/hr) Temperature (deg F) Exhaust Velocity (fps) Startup Phase 1 12 780 138 26.48 Phase 2 10 1257 281 37.70 Phase 3 38 1257 346 41.01 Shutdown 7 568.5 346 33.37 Commissioning N/A 1257 346 41.01Rule 1200 Health Risk Assessment Report

11 of 11 Release Parameters – Diesel Emergency Fire Pump

Release Parameter Value Stack Height (ft) 30 Stack Diameter (ft) 0.33 Temperature deg F 938 Exhaust Velocity (fps) 253.63

PROCESS DATA
Process Data – Gas Turbines (Potential to Emit, 100% Base Load)
Operation Parameter Value Fuel Usage (MMBTU/hr) 2,085 Maximum annual hours of operation 8,760

Process Data – Diesel Emergency Fire Pump
Operation Parameter Value Engine horsepower (bhp) 246 Fuel Consumption (gal/hr) 12.2 Annual hours of operation 50

## APPENDIX C

PERMIT CONDITIONSFDOC Conditions Page 1 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 CECP PERMIT CONDITIONS
G ENERAL C ONDITIONS

1. This equipment shall be properly maintained and ke pt in good operating conditi on at all times, and, to the extent practicable, the applicant shall maintain and operate the equipment and any associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. [Rule 21 and 40 CFR §60.11]

2. The applicant shall operate the project in accordance with all data and specifications submitted with the application under which this license is issu ed and District Application 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. Prior to the earlier of the initial startup dates for either of the two combustion turbines, the applicant shall surrender to the District Class A Emission Reduction Credits (E RCs) in an amount equivalent to 47.9 tons per year of oxides of nitrogen (NOx) to offset the net maximum allowable increase of 39.9 tons per year of NOx emissions for the two combus tion turbines and the emergency fire pump engine described in District Application Nos. 985745, 985747, and 985748. [Rule 20.3(d)(8)]

6. A rolling 12-calendar-month period is one of a seri es of successive cons ecutive 12-calendar-month periods. The initial 12-mont h-calendar period of such a series shal l begin on the first day of the month in which the applicable beginning date for that seri es occurs as specified in this permit. [Rule 20.3 (d)(3), Rule 20.3(d )(8) and Rule 21].

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 combustionFDOC Conditions Page 2 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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)]

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 unit operat ing minutes in a calendar day nor exceed 40 hours in a calendar year for each turbine. The District compliance division shall be notified at least 24 hours in advance of any tuning event. For purposes of this condition, the number of hours of tuning in a calendar year is defined as the to tal unit operating minutes of tuning during the calendar year divided by 60. [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. For purposes of this co ndition, the number of hours of tu rbine operation is defined as the total unit operating minutes dur ing the commissioning period di vided by 60. [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 District th at the shakedown period has ende d. [Rules 20.1(c)(16) and 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]

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 B is the turb ine described on Application No. 985747. [Rules 20.1(c)(16) and 21]FDOC Conditions Page 3 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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 are exceeded as a result of the low-load operation. Fo r each combustion turbine, periods of operation at low load shall not exceed 130 unit operating minutes in any calendar day nor an aggregate of 780 unit operating minutes in any calendar year. No low load operation period shall begin during a startup period. [Rule 20.3(d)(1)]

21. For each combustion turbine, a unit operating day, hour, and minute mean the following:

a. A unit operating day means any calendar day in which the turbine combusts fuel.
b. A unit operating hour means any clock hour in which the turbine combusts fuel.

c. A unit operating minute means any clock minute in which the turbine combusts fuel and any clock minute that is part of a shutdown period. [Rule 21, 40 CFR Part 75, Rule 20.3(d)(1), 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, quar terly records of the natural gas su lfur content (grains of sulfur compounds per 100 dscf of natural gas) and hourly records of the higher a nd 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]FDOC Conditions Page 4 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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.
[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. Fo r 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 1.5 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]FDOC Conditions Page 5 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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. This 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 defined 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-day period. The hourly emission concentration limit and emission rate limit shall be 15 ppmvd corrected to 15% oxygen and 0.43 lb/MWh, respectively, for clock hours when the combustion turbine load is equal to or greater than 156 megawatts at all times during the clock hour, respectively, and 96 ppmvd corrected to 15% oxygen and 4.7 lb/MWh for all other clock hours when the combustion turbine is operating, 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-month period, emi ssions 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]FDOC Conditions Page 6 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 39. Mass emissions from each combustion turbine of oxides of nitrogen (NOx), calculated as NO 2 ; carbon monoxide (CO); and volatile organic compounds (VOC), calculated as methane, shall not exceed the following limits, except during commissioning, low load operation, startup, shut down, or tuning periods for that turbine. A 1-clock-hour averaging period for these limits shall apply to CEMS data except for emissions during transient hours when a 3- clock-hour averaging period shall apply.

Pollutant Emission Limit, lb

a. NOx 15.1 b. CO 9.2

c. VOC 4.0
[Rule 20.3(d)(2)]

40. Excluding any minutes that are coincident with a shutdown period, cumulative mass emissions of oxides of nitrogen (NOx), calculated as NO 2 ; carbon monoxide (CO); and volatile organic compounds (VOC), calculated as methane, during a combustion turbine’s startup period shall not exceed the following limits during any startup peri od, except during that turbin e’s commissioning period.

Pollutant Emission Limit,lb

a. NOx 69.2 b. CO 545

c. VOC 15.5
[Rule 20.3(d)(1)]

41. Cumulative mass emissions of oxides of nitrogen (NOx), calculated as NO 2 ; carbon monoxide (CO); and volatile organic compounds (VOC ), calculated as methane,during a combustion turbine’s shutdown period shall not exceed the following limits during a ny shutdown period, except during that turbine’s commissioning period.

Pollutant Emission Limit,lb

a. NOx 25.7 b. CO 277

c. VOC 6.2
[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 allFDOC Conditions Page 7 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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), calculated as methane; par ticulate matter less than or equal to 10 microns in diameter (PM10); and oxides of sulfur (SOx), calculated as sulfur dioxide (SO 2 ), from the combustion turbines described in District Appl ications No. 985745 and 985747 and the emergency fire pump described in Application No. 985748, except emissions or em ission units excluded from the calculation of aggregate potential to emit as specified in Rule 20.1 (d) (1), shall not exceed the following limits for each rolling 12 -calendar-month period:

Pollutant Emission Limit, tons per year

a. NOx 72.11 b. CO 339.9

c. VOC 23.7 d. PM10 39.0

e. SOx 5.6
In addition, beginning with the date on which both tu rbines have completed their commissioning periods aggregate emissions of CO and VOC from the equi pment specified above in this condition shall not exceed 217.3 and 20.1 tons per year, respectively, for each rolling 12-calendar-month period.
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. [Rul es 20.3(d)(3), 20.3( d)(8) and 21]

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 (calculated as methane), PM10, and SOx (calculated as SO 2 ), in tons, from each emission unit described in District Applications No. 985745, 985747, and 985748, except for emissions or emission units excluded from the calculation of aggr egate potential to emit as specifi ed in Rule 20.1 (d) (1). These records shall be made available for inspection with in 15 calendar days after the end of each calendar month. [Rules 20.3(d)(3), 20.3(d)(8) and 21]

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 (calculated as methane) , PM10, 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 aggreg ate potential to emit as sp ecified in Rule 20.1 (d) (1). These records shall be made available for inspection within 15 calendar days after the end of each calendar month. [Rules 20.3( d)(3), 20.3(d )(8) and 21]

47. For each combustion turbine, the number of startup periods occurring in each calendar year shall not exceed 1460. [Rules 1200 and 21]FDOC Conditions Page 8 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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; the catal yst volume, space velocity and area velocity at full load with and without steam injectio n; and control efficiencies of the SCR and the oxidation catalyst CO at temperatures between 100 oF and 1000 oF at space velocities corresponding to 100% (with steam injection) and 60% load. 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 for each unit oper ating minute. The monito rs shall be installed, calibrated and maintained in accordance with a Distri ct approved protocol, which may be part of the CEMS protocol. This protocol, which shall include the calculati on methodology, shall be submitted to the District for written approval at least 90 days prior to initial startup of the gas turbines with the SCR system. The monitors shall be in full operation at all times when the turbine is in op eration. [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 permit conditions, the automatic ammonia injection system serving the SCR syst em shall be in operation in accordance with manufacturer's specifications at all times when ammonia is being injected into the SCR system. Manufacturer specifications shall be maintained on s ite and made available to District personnel upon request. [Rules 20.3(d)(1)]

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 prior 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 performed by an independent contractor, a fi nal test report shall be submitted to the District for review and approva l. [Rules 20.3(d)(1) and 1200 and 40 CFR Part 60 Subpart KKKK, 40 CFR §60.8, and 40 CFR Part 75]FDOC Conditions Page 9 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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 platform s shall be constructed in accordan ce with District Method 3A, Figure 2, and approved by the District. Ninety days prior to construction of the turbin e 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. Not later than 60 calendar days after completion of the commissi oning period for each combustion turbine, an Initial Emissions Sour ce Test shall be conducted on that turbine to demonstrate compliance with the NOX, CO, VOC, PM10, and ammonia emission standards of this permit. The source test protocol shall comply with all of the following requirements:

a. Measurements of NOX and CO concen trations and emissions and oxygen (O 2 ) concentration shall be conducted in accordance with U.S. Environmental Protection Agency (EPA) methods 7E, 10, and 3A, respectively, and District so urce 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 demonstrati on is accepted, then emissions source testing shall be performed at the highe st achievable continuous power level. The 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 conducted 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 the District and EPA
h. Unless otherwise authorized in writing by the District, test ing for NOX, CO, VOC, PM10, and ammonia concentrations and emissions, as applic able, shall be conducted concurrently with the NOx and CO continuous emission measurement sy stem (CEMS) Relative Accuracy Test Audit (RATA).

[Rules 20.3(d)(1) and 1200]

57. A renewal source test and a NOX and CO Relative A ccuracy Test Audit (RATA) shall be periodically conducted on each combustion turbine to demonstr ate compliance with the NOX, CO, VOC, PM10, and ammonia emission standards of this permit and applicable relative accuracy requirements for the CEMS systems using District approved methods. The rene wal source test and the NOX and CO RATAs shallFDOC Conditions Page 10 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 be conducted in accordance with the applicable RA TA frequency requirements of 40 CFR75, Appendix B, Sections 2.3.1 and 2.3.3. The renewal source test shall be conducted in accordance with a protocol complying with all the applicable requirements of 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 Audits (RATAs) and all othe r required certification test s shall be performed and completed on the NOx CEMS in accordance with app licable provisions of 40 CFR Part 75 Appendix A and B and 40 CFR §60.4405 and on the CO CEMS in acco rdance with applicable provisions of 40 CFR Part 60 Appendix B and F. [Rule 21, Rule 20.3 (d)(1), 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75]

59. Not later than 60 calendar days after completion of the commissi oning period for each combustion turbine, an initial emission source te st for toxic air contaminants shal l 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:

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]FDOC Conditions Page 11 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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 not less than once each calendar quarter in accordance with a protocol approved by the District, which shall be submitted to the District for approval not later than 90 days before the earlier of the initial startup dates for either of the two combustion turbines and measured with ASTM D1072

– 90 (Reapproved 1994), Standard Test Method for Total Sulfur in Fuel Gases; ASTM D3246

– 05, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry; ASTM D4468

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

– 98 (Reapproved 2003), Standard Test Me thod for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Flam e Photometric Detection; or ASTM D6667

– 04, Standard Test Method for Determination of Tota l Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence or an alternative test method approved by the District and EPA. [Rule 20.3(d)(1 ), Rule 21, and 40 CFR Part 75]

CONTINUOUS MONITORING

63. The applicant shall comply with the applicable continuous emission monitoring requirements of 40 CFR Part 75. [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, calcul ate, and record the following, in accordance with the District approved CEMS protocol:

a. Hourly average(s) concentration of oxides of nitrogen (NOX) uncorrected and corrected to 15% oxygen, in parts per million (ppmvd), necessary to demonstrate compliance with the NOx limits of this permit; b. Hourly average concentration of carbon monoxide (CO) uncorre cted 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 for each unit operating minute; d. Average concentration of oxides of nitrogen (NOX) for each continuous rolling 3-hour period, in parts per million (ppmv) corrected to 15% oxygen;

e. Hourly mass emissions of oxides of nitrogen (NOX), in pounds; f. Cumulative mass emissions of oxides of nitroge n (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 concentrati on 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. Calendar quarter, calendar ye ar, and rolling 12-calendar-mon th period mass emissions of oxides of nitrogen (NOX), in tons;FDOC Conditions Page 12 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 l. Cumulative mass emissions of carbon monoxide (C O) 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. Rolling 12-calendar-month period mass emi ssion of carbon monoxide (CO), in tons; q. Average concentration of oxides of nitroge n (NOX) and carbon monoxi de (CO)uncorrected and corrected to 15% oxygen, in parts per million (ppmvd), during each unit operating minute;

r. Average emission rate in pounds per hour of oxides of nitrogen (NOX) and carbon monoxide (CO) during each unit operating minute.
[Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Pa rt 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 the earlier of 90 unit operating days or 180 calendar days after each combustion turbine commences commercial operation, a Relative Accur acy Test Audit (RATA) and other required certification tests shall be performe d an completed on the that turbine’s NOx CEMS in accordance with 40 CFR Part 75 Appendix A and on the CO CEMS in accordance with 40 CFR Part 60 Appendix B. The RATAs shall demonstrate that the NOx and CO CEMS comply with the applicable relative accuracy requirements. At least 60 calendar days prior to the test date, the applicant shall submit a test protocol to the District for written approval. Add itionally, the District and U.S. EPA shall be notified a minimum of 45 calendar days prior to the test so th at observers may be present. Within 45 calendar days of completion of this test, a written test report shall be submitted to the District for approval. For purposes of this condition, commences commercial ope ration is defined as the first instance when power is sold to the electrical grid. [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 Re lative Accuracy Test Audit (RATA), 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 be 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]FDOC Conditions Page 13 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 70. When the CEMS is not recording data and the co mbustion turbine is operating, hourly NOx emissions for purposes of calendar year a nd rolling 12-calendar-month period emission calculations shall be determined in accordance with 40 CFR 75 Subpart C. Additionally, hourly CO emissions for rolling 12- calendar-month period emission calculations shall be determined using CO emission factors to be determined from source test emission factors, record ed CEMS data, and fuel consumption data, in terms of pounds per hour of CO for the gas turbine. Emi ssion calculations used to determine hourly emission rates shall be reviewed and approved by the District , in writing, before the hourly emission rates are incorporated into the CEMS emission data. [Rules 20.3(d)(3) and 21 and 40 CFR Part 75]

71. Any violation of any emission 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 (DAHS), includi ng, but not limited to, the programmable logic controller, software which affect s the value of data displayed on the CEMS / DAHS monitors with respect to the parameters measured by their respec tive sensing devices or a ny planned changes to the software that controls the ammonia flow to the SCR. Unplanned or emergency changes shall be reported within 96 hours. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75]

74. At least 90 calendar days prior to the Initial 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 provi ded as part of the Initial Source Emissions 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 conti nuous monitors to measure, calculate, and record unit operating days and hours and the following operational characteristics:

a. Date and time; b. Natural gas flow rate to the combustion turbine during each unit operating minute, in standard cubic feet per hour;

c. Total heat input to the combustion turbine base d the fuels higher hea ting value during each unit operating minute, 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 during each unit operating minute, in degrees Fahrenheit;FDOC Conditions Page 14 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 f. Combustion turbine energy output during each unit operating minute in megawatts hours (MWh); and g. Steam turbine energy output during each unit oper ating minute in megawatts hours (MWh).
The values of these operational characteristics sh all be recorded each unit operating minute. The monitors shall be installed, calibrated, and maintained in accordance with a turbine operation monitoring protocol, which may be part of the CEMS protocol , approved by the District, which shall include any relevant calculation methodologies. The monitors shall be in full operation at all times when the combustion turbine is in operation

. Calibration records fo r the continuous monitors shall be maintained on site and made available to the District upon request. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75]

77. At least 90 calendar days prior to initial startup of the each combustion 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 operation each day; a nd hours of operation during each calendar year. For purposes of this condition, the hours of turbine operation is defined as the total minutes the turbine is combusting fuel during the calendar year divi ded by 60. [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 e quipment on that turbine to mini mize 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 Di strict. 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, except for cumulative mass emissions, averaged over each hour of operation:

a. Concentration of oxides of nitrogen (NOX) unco rrected and corrected to 15% oxygen, in parts per million (ppmvd); b. Concentration of carbon monoxide (CO) uncorrect ed 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;FDOC Conditions Page 15 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 e. Cumulative mass emissions of oxides of nitroge n (NOX) in each startup and shutdown period, in pounds; f. Cumulative mass emissions of carbon monoxide (C O) in each startup and shutdown period, in pounds g. Mass emissions of carbon monoxide (CO), in pounds; h. Total heat input to the combustion turbine based on the fuel’s higher heating value, in million British thermal units per hour (MMBtu/hr); i. Higher heating value of the fuel on an hourly basis, in million British thermal units per standard cubic foot (MMBtu/scf); j. Gross electrical power output of the turbine, in megawatts hours (MWh) for each hour; and k. SCR outlet 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 ar e operating. [Rules 20.3(d)(3), 20.3(d)(8) and 21]

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), calculated as methane; particulate matter less than or equal to 10 microns in diameter (PM10); and oxides of sulfur (SOx), calcu lated as sulfur dioxide (SO 2 ), from Turbine A and the emergency fire pump described in Application No. 985748, except emissions or em ission units excluded from the calculation of aggregate potential to emit as specified in Rule 20.1 (d) (1), shall not exceed the following limits for each rolling 12 -calendar-month period:

Pollutant Emission Limit, tons per year

a. NOx 36.05 b. CO 169.95

c. VOC 11.85 d. PM10 19.5

e. SOx 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]

83. Beginning with the date Turbine A completes its shakedown period, aggregat e emissions of carbon monoxide (CO); particulate matter less than or equal to 2.5 microns in diameter (PM2.5); and particulate matter less than or equal to 10 microns in diameter (PM10) from the three utility boilers described on District Permits to Operate No. 791, 792, and 793, sha ll not exceed the following limits for each rolling 12-calendar-month period:

Pollutant Emission Limit, tons per year

a. CO 198.75FDOC Conditions Page 16 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 b. PM2.5 21.80

c. PM10 26.89
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]

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 sh all not operate. [Rules 20.3(d)(3), 20.3(d)(8) and]

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]

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]

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 inspec tion within 15 calendar days after the end of each calendar month. [Rules 20.3( d)(3), 20.3(d )(8) and 21]

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]

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 star tup of the turbine.FDOC Conditions Page 17 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 In addition, the applicant shall not ify the District when: (1) constr uction is complete by submitting a Construction Completion Notice before operating any un it that is the subject of this permit, (2) each combustion turbine first combusts fuel by submitting a First Fuel Fire Notice within five calendar days of the initial operation of the unit, and (3) each combustion turbine first generates electrical power that is sold by providing written notice within 5 days of th is event. [Rules 24 and 21 and 40 CFR Part 75, 40 CFR Part 60 Subpart KKKK, 40 CFR Part §60.7, 40 CF R Part 63 Subpart YYY Y, 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 shall 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]FDOC Conditions Page 18 of 18 July 30, 2009 Applications No. 985745, 985747, and 985748 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]

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]

A DDITIONAL T ITLE V C ONDITIONS

100. The Permittee shall submit to the District and to the federal EPA a compliance certification for the new equipment subject to this permit, in a manne r or form approved in writi ng by the District, within one year of completing construction of that equipment, that includes th e identification of each applicable term or condition of the final permit for which the compliance status is being certified, the current compliance status and whether the modified equipm ent was in continuous or intermittent compliance during the certification period, iden tification of the applicable pe rmitted method used to determine compliance during the certificati on period, and any other informati on required by the District to determine the compliance status. [Rule 1421]

## APPENDIX D

EMISSION REDUCTION CREDITSSummary of Emission Reduction Credits (ERCs) Proposed as OffsetsERCCertificateNo.OriginalIssue DateType Pollutant ERCAmount,tons peryearNOxEquivalentAmount, tonsper yearLocation of EmissionReductionsDescriptionEmissionReductionCurrentOwner978938-05 6/30/2004 Class A NOx 35.3 35.3 Naval Air Station—NorthIsland; Foot of NevilleRoad, Naval TrainingCenter, San Diego; VestaStreet & Ward RoadNaval Station San DiegoPermanentshutdown ofpeakingcombustionturbinesCabrilloPower II,LLC981518-01 8/01/2006 Class A NOx 2.3 2.3 3200 Harbor Drive, SanDiegoPermanentshutdown ofpeakingcombustionturbinesCabrilloPower II,LLC070823-02 11/19/99 Class A VOCs 5.3 2.65 850 Lagoon Drive, ChulaVistaShutdown ofVaporDegreasers andCold SolventCleanersElementMarkets,LLC080212-01 9/22/2006 Class A VOCs 18.7 9.35 7757 Andrews Avenue,San DiegoShutdown andrestrictedoperation ofwood coatingand adhesiveapplicationoperationsInland GasandElectric GP,LLC