CECP Project - PSD Applicability

Tom W. Andrews 

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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 period to use to establish the actual emissions 

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 California 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 

September 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 on 

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 Energy 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 used to calculate the actual emissions 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 

sierra

research

1801 J Street

Sacramento, CA 95811

Tel: (916) 444-6666

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Ann Arbor, MI

Tel: (734) 761-6666

Fax: (734) 761-6755
Shaheerah Kelly -2- March 1, 2010

the 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 reviewed power generation 

forecasts 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 forecasts,

1 the electric energy consumption in the San Diego area 

will continue to increase from approximately 21,100 to 23,535 GWH/year during the period 

from 2010 to 2020. This increase—2,435 GWH/year—is equivalent to a 278 MW power 

plant operating at a 100% capacity factor, 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.

The anticipated future demand for electricity in the San Diego area and the associated 

need for additional electric generation capacity are also reflected in documents prepared 

by the California Independent System Operator. The California Independent System 

Operator is responsible for the reliable operation of the electric grid system in California. 

According to a capacity analysis 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) policy 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 in the shutdown 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 Units 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 

Sunrise 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 of the new Otay Mesa Power Plant. In addition, 

without the installation of the Sunrise Powerlink transmission line no existing power 

plants in the San Diego area, including the Encina Units 1-3, will be able to retire until 

this new generation is built. This SDG&E Company document shows that without 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 (2007 to 2016), SDG&E Company, Dec. 11, 2006, Table IV-4, page 172 

and Exhibit IV-10, page 182.
Shaheerah Kelly -3- March 1, 2010

Sunrise Powerlink transmission line the shortfall in electric generating capacity in the San 

Diego area could be as high as approximately 985 MW over the next few years. This 

shortfall is equivalent to installing two new power plants of approximately the same size 

as the proposed CECP project.

With regards to the status of the installation of the Sunrise Powerlink transmission line, 

there has been significant legal opposition to this project. This opposition includes an 

August 12, 2009 lawsuit5 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, 

2010 lawsuit6

 

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 transmission 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 

good 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 included with the emission decrease associated with the shutdown of 

Encina Units 1-3. As shown in Table 1, the facility-wide net emission increase for the 

proposed CECP project is below PSD significance levels for NOx, CO, PM10, and PM2.5. 

Therefore, the proposed CECP project does not trigger PSD review.

 5 http://www.biologicaldiversity.org/news/press_releases/2009/sunrise-powerlink-08-12-2009.html

6 http://protectourcommunities.org/wp-content/uploads/2009/05/complaint_2-16-10.pdf
Shaheerah 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 

PM2.5 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 POLLUTION CONTROL DISTRICT 

Applications Number 985745, 985747, and 985748 

August 4, 2009 
Project Engineer Camqui Nguyen 

Senior Engineer: Steven Moore 

Application Numbers: 985745, 985747, and 985748 

Site ID Number: 333A 

Fee Schedule: 20F 

BEC: New 

 APPLICATION INFORMATION

 Owner / Operator: Carlsbad Energy Center, LLC 

 Mailing Address: 1817 Aston Ave, Suite 104 

 Carlsbad, CA 92008 

 Equipment Address: 4600 Carlsbad Blvd 

 Carlsbad, CA 92008 

 

 Contact: George Pinanka 

 Company: Carlsbad Energy Center LLC 

Position: Vice President 

 Phone Number: (760) 710-2156 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Rule 20.1(c)(33) – Major Modification .......................................................................... 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 Siting 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 – Reasonably Available Control Technology ........ 48 

Rule 69.3.1 – Stationary Gas Turbines – Best Available Retrofit Control Technology. 49 

Rule 69.4 – Stationary Reciprocating Internal Combustion Engines – Reasonably 

Available Control Technology........................................................................................ 49 

Rule 69.4.1– Stationary Reciprocating Internal 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 .................................................................................. 52 
Title 17 of the California Codes of Regulations (CCR) §93115—Airborne Toxic 

Control Measure (ATCM) for Stationary 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 Emissions Standards for Hazardous Air 

Pollutants for Stationary Compression Ignition Internal Combustion Engines.............. 55 

New Source Performance Standards (NSPS) ..................................................................... 56 

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

Combustion Turbines.......................................................................................................... 56

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

Ignition Internal Combustion (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 Evaporative 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 Credits 
Final Determination of Compliance Page 1 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

I. PROJECT DESCRIPTION 

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

Project (CECP). This project is a combined-cycle power plant with a total nominal base load 

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

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

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

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

turbine (without power augmentation at 61 o

F average ambient temperature). The combustion 

turbines are also equipped with evaporative coolers that can be used 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 HRSG will feed a steam turbine generator (STG) associated 

with that HRSG. This combination of a CTG with a HRSG and STG is referred to as a 1-on1 combined-cycle power plant. By making use of the turbine exhaust heat to generate 

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

efficient than other combustion turbine power plants. 

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

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

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

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

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

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

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

The CECP is located north of the intersection of Carlsbad Boulevard and Cannon Road in the 

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

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

line and Interstate 5 (I-5). The two main power units of the project will be at the location of 
Final Determination of Compliance Page 2 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

previously existing fuel oil tanks, which are currently being removed. Both Carlsbad Energy 

Center, LLC and Cabrillo Power I LLC, are indirect 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 the CECP, three existing utility boilers, known as 

Units 1, 2, and 3, at the Encina Power Station will be retired when the two combined-cycled 

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

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

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

of the natural gas supply are proposed by the Applicant. 
Final Determination of Compliance Page 3 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

II. EQUIPMENT DESCRIPTION

The Applicant has proposed to construct and operate the following equipment at this facility 

under application No. 985745, 985747, and 984748: 

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

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

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

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

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

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

exhaust steam from the steam turbine. 

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

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

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

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

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

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

exhaust steam from the steam turbine. 

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

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

to be determined. 
Final Determination of Compliance 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 from the combustion turbine at full load with 

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

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

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

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

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

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

steam power augmentation is employed. 

The chosen combined-cycle system merges the fast starting capability of a simple-cycle gas 

turbine and the efficiency of a combined-cycle plant. The system is designed to start and reach 

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

minutes for a hot start and approximately 125 minutes for a cold start. The system is also 

designed to typically achieve its emission limits within 22 minutes. Traditional combined-cycle 

systems typically take 3–6 hours to reach comparable emission limits. 

The one-hour averaged NOx emission concentration is controlled to 2.0 parts per million by 

volume on a dry basis (ppmvd) and corrected to 15 percent oxygen (O2) by a combination of the 

ULN combustor in the CTG and the SCR system located in the HRSG. In the SCR, ammonia 

will be injected into the CTG exhaust stream via nozzles located upstream of the catalyst 

module. Ammonia slip, or the concentration of unreacted ammonia in the HRSG exhaust stack, 

is limited to 5.0 ppmvd averaged over one hour. The HRSG is also equipped with an oxidation 

catalyst to control CO emissions leaving the HRSG exhaust stack to 2.0 ppmvd and VOC 

emissions to 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 emission monitoring systems (CEMS) to sample, 

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

percentage of O2 in the exhaust gas from the HRSG stack. The data will be transmitted to a data 
Final Determination of Compliance Page 5 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

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

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

(DCS) when emission limits are approached or exceeded. 

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

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

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

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

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

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

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

presented in Tables 1a and 1b. 

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

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

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

capacity (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 maximum load, depending on the combustion turbine. 

The Applicant has proposed a minimum load threshold for a shutdown to be initiated of 114 

MW. Although typical startups and shutdowns are expected to take 22 minutes and 7 minutes, 

respectively, the permit conditions allow 60 minutes for a startup and 30 minutes for a shutdown 

to allow for contingencies during these operations. 

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

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

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

Applicant estimates that there will be 300 typical startups per turbine per year and 300 typical 

shutdowns per turbine per year. Maximum annual emissions are calculated based on 300 hours 
Final Determination of Compliance 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 expected to end in 2012 with the two combustion 

turbines sequentially achieving full operation. Phase I would consist of bringing one CTG/STG 

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

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

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

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

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

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

operating the existing boilers during the phase-in process when one or both CTG/STG units may 

not be fully operational. 
Final Determination of Compliance Page 7 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

IV. EMISSION ESTIMATES

COMBUSTION TURBINE GENERATOR EMISSIONS—STANDARD OPERATIONS

MAXIMUM HOURLY EMISSIONS

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

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

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

emission limits in the FDOC permit conditions. The startup and shutdown, emission rates were 

provided by the turbine manufacturer. For normal operations, emission rates for NOx, CO, and 

VOCs are calculated based on emission concentration limits (in ppmvd at 15% O2) in the FDOC 

permit conditions and exhaust flow rates 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 Table 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 cubic feet based on the California Public Utility 

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

on vendor supplied guaranteed emission rates. Table 1a presents the hourly emission rates in 
Final Determination of Compliance 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 typically approximately 22 minutes of emission rates higher than 

emissions during normal operation. Therefore, typical 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 emissions 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 calculating the hourly emission rates. 

Table 1b presents the maximum emission rates for each turbine during startup and shutdown in 

pounds per hour. The maximum emission rates of PM10 and PM2.5 are not affected during 
Final Determination of Compliance Page 9 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

startup and shutdown and the emission limit for normal operations remains in effect for these 

periods. The maximum emission rate of SOx is reduced because the turbine operates at low 

loads (and low heat input) during startups and shutdowns. 

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 normal operation at cold ambient temperature, 

as follows: 

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

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

 

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

per day (lbs/day). 
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 per year, of which 300 hours 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 operation emissions, lbs/day) x (3500 hours /years) 

Table 1d presents estimated maximum turbine annual 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 the PUC limit for sulfur content of natural gas. 

Historically, the annual average sulfur content in San Diego natural gas has been significantly 

less. 

EMERGENCY FIRE PUMP ENGINE EMISSIONS

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

standards for EPA certified engines of model year 2009. Daily emissions from the engine are 

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

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

Table 2a – Emergency Fire Pump 

Engine Emissions

Pollutant Engine Hourly Emissions, 

lbs/hr 

Engine Daily Emissions, 

lb/day 

Engine Annual Emissions, 

tons/yr 

NOx 2.08 2.08 0.052 

CO 0.24 0.24 0.006 

VOCs 0.05 0.05 0.00125 

SOx 0.0027 0.0027 0.00007 
Final 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 

PROJECT EMISSIONS—STANDARD OPERATIONS

Standard operations are those operations occurring after of the commissioning period for a 

turbine (see below). Total emissions from the project include emission from both combustion 

turbines and emissions from the emergency fire pump engine. Table 3a and 3b present the 

estimated maximum project total daily and annual emissions pounds per day and tons per year, 

respectively. 

Table 3a – Maximum Project Total Daily Emissions

Pollutant Turbines Total Daily 

Emissions, lbs/day 

Engine Daily Emissions, 

lbs/day 

Project Total Daily 

Emissions, lbs/day 

NOx 1754 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 4569 
Final 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 pollutant emissions, are presented in the Toxic 

Health Risk Assessment Section in Appendix B. 

COMBUSTION TURBINE GENERATOR EMISSIONS—COMMISSIONING PERIOD

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

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

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

commissioning period, because the CTG burners may not yet be tuned for optimal emissions and 

because the postcombustion control equipment will not yet be in full operation, emissions from 

the plant will be higher than standard operating emissions. Each turbine is expected to operate 

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

includes startups and shutdowns, hours of operation at different load levels, and operation with 

and without emission control equipment. Commissioning emission data provided by the turbine 

vendor consist of different emission scenarios corresponding to different phases of the 

commissioning period. Table 4a presents the expected commissioning maximum hourly 

emission rates. In order to minimize emission impacts during the commissioning period, 

emission rates for NOx and CO for both turbines combined will be limited to the levels expected 

for one turbine in commissioning mode and one turbine in 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 maximum 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 commissioning from both turbines for NOx and CO 

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

maximum daily emissions from the other turbine under 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 turning information and making operational 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 turbine vendor projected emission data for the 

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

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

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

period. 

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 

PROJECT EMISSIONS—COMMISSIONING PERIOD

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

and standard operations take place, total maximum project emissions are estimated based on 415 
Final 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 estimated maximum emissions from the emergency fire 

pump engine. Table 4d presents the estimated total maximum annual emissions for the project 

for a year with commissioning. 

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 34.32 
Final Determination of Compliance Page 17 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

V. RULES ANALYSIS

DISTRICT AND FEDERAL NSR AND PSD REGULATIONS

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

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

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

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

 Air Pollutant Emission Rates (tons/yr)

 PM10 100 

 NOx 50 

 VOCs 50 

 SOx 100 

 CO 100 

 Lead (Pb) 100 

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

applicable national air quality standard. Since the District attains all national ambient air quality 

standards with the exception of ozone, major source status is only relevant for NOx and VOCs, 

both of which are ozone precursors. In particular, the major modification thresholds (see below) 

apply for contemporaneous emission increases and associated requirements for NOx and VOCs. 

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

both NOx and VOCs. 

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

40 CFR 52.21

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

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

aggregate potential to emit one or more air contaminants in 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 

 NO2 100 

 VOCs 100 

 SO2 100 

 CO 100 

 Lead (Pb) 100 

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

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

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

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

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

requirement for the CECP under the federal 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 stationary source within the 

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

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

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

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

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

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

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

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 allowed before the actual emission reduction must be 

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

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

reasonable shakedown period for the new equipment. 

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

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

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

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

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

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

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

shutdown completely at the end of Phase II. 

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

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

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

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

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

could proceed in parallel or sequentially. 

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 systems. 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 increases to be reduced by actual emission reductions 

occurring at the stationary source. Rule 20.1(d)(4)(ii)(A) defines actual emission reductions 
Final Determination of Compliance Page 20 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

from the shutdown of an emission unit as those 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 application. Rule 20.1(d)(2)(i)(B) requires the actual emissions to be averaged 

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

operating time period does not exist. Since the Application for Certification (AFC) for 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 typically only called on to operate by the California 

Independent System Operator (ISO) when high electrical demand requires additional power 

beyond that provided by more efficient base-load units. This additional power is necessary to 

provide electrical grid stability. As such, the units’ operation may vary greatly from year to year 

depending on the weather, which largely determines electrical demand, and availability of 

electrical generating assets not only in California but throughout 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 representative two-year operating time period for 

Units 1, 2, and 3 of the Encina Power Station during these five years, the 5-year average of 

emissions determines baseline emissions for these units. 

The five boilers at the Encina Power Station exhaust through a single 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 and 
Final 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 measured by instruments subject to federal Acid 

Rain Program quality assurance and quality control 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 emissions. In 2002, each unit’s fuel flow and power 

output was still measured and recorded for the Acid Rain Program. 

The unit-specific fuel use and power output information 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 purposes of the Acid Rain Program. Because the data is used for 

different purposes and recorded pursuant to different protocols (and also, 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 Program. 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 Program. 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 startup are not reported for 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 applicable standard in 

Rule 69, 0.15 pounds per megawatt-hour (lb/MW-hr), were not allowed for the baseline 

calculations. Therefore, emissions were calculated 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 emissions 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 the 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 procedure 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 pollutants 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 values reported to emission inventory are from the 

North American Electric Reliability Corporation-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 manually 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 appropriate fuel use data for natural 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 than 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, liquid fuel combustion contributes 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 for each year, where available (2003-2006), 

were used to calculate emissions from natural 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 and SOx emissions from No. 6 fuel oil 

combustion in 2005 was used (the corrected 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 above. As compared to the PDOC, this results 

in decreases in baseline emissions for CO and 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 preproject 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 commence full commercial operation in 2012. Full 

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

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

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

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

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

other than the CECP that expect to commence operation at any time in the future. Therefore, the 

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

CECP. 

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

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

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

expected emission increase resulting from the CECP and actual emission reductions due to 

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

the larger of the emissions during a standard operation year or a commissioning year. 
Final Determination of Compliance Page 25 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

 

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

Pollutants Estimated Maximum 

Emission Increases 

from CECP, 

tons/yr 

Actual Emission 

Reductions from 

Units 1, 2, and 3, 

tons/yr 

Maximum Potential 

Emission Increase, 

 tons/yr 

NOx 75.6 32.21 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 increase, which includes limitations on potential 

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

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

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

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

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

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

limit PM2.5, PM10, and PM. 
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 Completion of the Phase I Shakedown Period

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

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

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

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

emergency 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 prevent triggering the PSD modification or major 

modification thresholds. For VOCs, SOx, and PM, the FDOC permit conditions limit the 
Final 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 less 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 modification threshold but does constitute a major 

modification. However, the FDOC permit conditions require surrender of sufficient emission 

reduction credits prior to the new equipment operation to fully offset this increase without 

consideration of actual emission reductions. Therefore, limits on emissions for NOx, VOCs, 

SOx, and PM from Units 1, 2, and 3 are not necessary. 

Consistent with the necessary shakedown period for the CTG/STG system (not to exceed 180 

days), the actual emission reductions need not occur until the end of shakedown period for the 

first turbine to reach full commercial operation (i.e., before that time emissions from the three 

existing utility boilers are not limited other than being prohibited from operation whenever a 

combustion turbine of the CECP is operated during the shakedown period,). Therefore, the 

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

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

engine combined apply from the first date a combustion turbine has an initial startup (also known 

as “first fire”). During the shakedown periods for both turbines the limits on potential to emit for 

both combustion turbines and the emergency engine listed in Table 5c are also in effect, which 

serves to limit the potential to emit of all the emission units associated with the CECP during 

both phases of the shakedown period. 

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

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

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

2, and 3 must permanently cease operation. 

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

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

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

pump engine combined for Phase I. 
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 has agreed to accept annual emission limits for 
Final Determination of Compliance Page 29 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

these pollutants that reflect the lower expected annual emissions. The contemporaneous 

emission increases applicable to postcommissioning 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 precursors NOx and VOCs are evaluated to determine 

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

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

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

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

Therefore, the proposed CECP is a major modification to the facility for NOx. The CECP is not 
Final Determination of Compliance Page 30 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

a major modification for VOCs because the FDOC permit conditions limit VOCs increases to 

less than 25 tons per year. 

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

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

stationary source equal to or greater than the following emission rates: 

 Pollutant Emission Rates (tons/yr)

 PM 25 

PM10 15 

 PM2.5 10 

 NO2 40 

 VOCs 40 

 SO2 40 

 CO 100 

 Lead (Pb) 0.6 

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

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

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

However, the Applicant has accepted a limit of 72.11 tons per year of NOx emissions in the 

FDOC permit to keep the project NOx emissions below the PSD modification threshold. None 

of the other pollutant contemporaneous emission increases exceed the PSD modification level 

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

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

Emission Rate(LAER)

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

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

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

Lowest Achievable Emission Rate (LAER) be installed for a new emission unit which results in 
Final 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 than BACT and is required only for air contaminants and their 

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

Ambient Air Quality Standards (NAAQS) for CO, SO2, PM2.5 and PM10, LAER does not apply 

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

major modification for NOx. For the combustion turbines, BACT applies for 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 emission unit at a PSD stationary 

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

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

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

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

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

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

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

engine, BACT is triggered only for CO as part of the CECP because the potential to emit 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 emission level of 2.0 ppmvd at 15% oxygen at greater 

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

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

and LAER during normal operations. 

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

September 1999, BACT/LAER for NOx emissions from combined-cycle combustion turbine is 
Final Determination of Compliance Page 32 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

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

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

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

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

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

power plants of comparable size were permitted with NOx at 2.5 ppmvd or lower, averaged over 

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

ppmvd at 15% oxygen: 

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

Department of Environmental Protection and has been in commercial operation since 

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

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

this standard. 

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

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

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

ppmvd of NOx averaged over one hour. 

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

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

• The El Segundo Power 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-cycle Siemens turbines identical to the 

combustion turbines proposed for the CECP, and is proposed to be permitted at 2.0 

ppmvd of NOx averaged over one hour. 
Final Determination of Compliance Page 33 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

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

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

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

transients, and tuning of the combustors and the SCR. 

 Based on the above information, the District has 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 stringent emission limitation, 

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

device or technique is not achievable. An emission limit of 2.0 ppmvd NOx at 15% averaged 

over one hour is considered by the District to be the current most stringent emission limit for 

larger combined-cycle combustion turbines that is achievable. Therefore, this standard also 

applies as LAER for NOx for such turbines. 

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

low-NOx combustors and a 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 alternative technologies for control of NOx such as the XONONTM catalytic 

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

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

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

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

Carbon Monoxide (CO)—Combustion Turbines, Normal Operations

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

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

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

as BACT and LAER during normal operations. 
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 this equipment is 6.0 ppmvd based on a 3-hr 

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

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

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

4.0 ppmvd at 15% oxygen: 

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

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

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

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

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

ppmvd of CO averaged over three hours. 

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

District at 2.0 ppmvd CO averaged over one hour. This plant has has been operating 

since 2005. 

• 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-cycle Siemens turbines identical to the 

combustion turbines proposed for the CECP, and is proposed to be permitted at 2.0 

ppmvd of CO averaged over one hour. 

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

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

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

based on CEMS data indicates that it likely achieves 2.0 ppmvd averaged over one hour. 
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 BACT for CO for the CECP combustion turbines 

for normal operation with appropriate exclusion to address technological feasibility for startups 

and shutdowns and other abnormal periods of operation. To meet this requirement, the 

Applicant evaluated the use of an oxidation catalyst, which is the only postlcombustion 

technology currently available to control CO, VOCs, and toxic emissions. This technology is 

acceptable as BACT for CO. The Applicant will therefore 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)—Combustion Turbines, Normal Operations

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

than 60% load with the oxidation catalyst add-on air pollution control system, 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 normal 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 emission limits of 2.0 ppmvd or less at 15% oxygen: 

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

ppmvd 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 compared 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 ppmvd 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-AFC-01]. This plant is proposed to be 

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

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

than 160 MW that are actually operating in the SJVAPCD is 2.0 ppmvd of VOCs 

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

shutdown period excluded. 

• 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-cycle 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, California, has been able to comply with 

2.0 ppmvd VOC limit averaged over three hours during normal operations, excluding 

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

experience based on CO CEMS data indicates that it likely achieves less than 2.0 ppmvd 

averaged over one hour. 

For the FDOC, the District examined the following 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 Environment and Natural Resources for two Siemens 

turbines similar to those proposed for the CECP with a 1.0 ppmvd VOC limit for loads 

greater than 70% and a 5.0 ppmvd VOC limit 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 facility 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 limit 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 initial compliance as been verified by one-time 

source tests at 100% load for four of the combined-cycle turbines and 55% load for three 

of those units in 2009 (the District has not obtained the other source 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 emission limit at low loads, they 

are not expected to operate at low loads, so the practical 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 operate as base-loaded units which, unlike the CECP, 

are expected to typically operate near 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 indicator 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 Carolina project require periodic source testing to verify the VOC 

limit is achieved continuously. While the FDOC permit conditions for the CECP require that the 

VOC limit be verified by periodic source testing and by monitoring of CO emissions on a hourly 

basis as a surrogate for VOC emissions (see below) over the life to the turbine. Using CO 

emission levels as surrogate on an hourly basis is a more robust method of monitoring VOC 

emissions than an initial source test 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 could easily exceed the 1.2 ppmvd 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 high 5 ppmvd at that load. The use of a properly 

designed oxidation catalyst translates into lower VOC emissions at all loads and at all levels of 

VOC concentration in the turbine exhaust. 

Based on the above information and 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 than 60%, measured as methane at 15% O2 over a 

one-hour averaging period for normal operation with appropriate exclusions to address 

technologically feasibility for startups and shutdowns and other 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 establish a correlation between CO emissions and VOC 

emissions to provide an accurate indicator of continued compliance with these limits using 

the CEMS data for CO on a one-hour basis. Compliance will be determined based on both 
Final 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—Combustion Turbines, NOx, CO, and VOCs

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

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

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

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

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

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

time is allowed to address contingencies during startups and shutdowns. 

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

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

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

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

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

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

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

total allowed emissions for NOx are: 

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

operations) 

 = 69.2 lbs 

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

Emissions = 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 shutdown 
Final 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 applicable to the CECP during startups and 

shutdowns of the combustion turbines. 

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

Modern combustion turbines with ultra low NOx combustors normally operate under 

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

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

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

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

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

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

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

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

situations, the NOx, CO, and VOC emissions can be much higher than in the lean premix 
Final Determination of Compliance Page 41 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

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

emission levels applicable to normal operations in such situations. 

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

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

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

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

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

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

Tuning of the combustion-turbine system may be done for many reasons. Tuning may be 

done to ensure continued compliance with applicable 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, even though immediate emission limit compliance or operational 

safety is not in jeopardy. The facility may also wish to improve the turbine combustor 

efficiency and thereby reduce greenhouse gas 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 automatically reduces the turbine load to 

prevent an immediate combustion turbine trip (unplanned shutdown). In most cases, the 

problem is resolved without shutting down the turbine, which avoids the emissions and cost 

of a restart. 

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

operations at a large combined-cycle power plant, the District has 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 minutes in a calendar day nor exceed 40 hours in 

a calendar year for each turbine. 

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

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

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

for one minute or longer. 

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

an aggregate of 780 minutes in any calendar year. 

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

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

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

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

remain in effect. The District’s criteria for a transient events and BACT levels have been 

acceptable to another large combined-cycle facility. 

PM10 and SOx—Combustion Turbines

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

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

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

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

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

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

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

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

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

alternative supplies of natural gas must meet this sulfur content limit. 
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 emergency engines is to use an engine fueled with 

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

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

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

they may compromise the reliability of the fire pump. Therefore, the District has 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 Quality Impact Analysis (AQIA)

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

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

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

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

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

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

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

shutdown, and normal operations. For the FDOC, no additional modeling was performed, 

but some of the ambient background values used in the analysis were adjusted where 

necessary. Additionally, the PM2.5 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 any 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 evaluation be performed for any new PSD stationary 

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

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

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

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

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

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

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

needs to be performed. The Applicant has accepted an annual limit of 72.11 tons per year of 

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

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

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

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

all other pollutants do not exceed the applicable PSD modification thresholds after 

completion of the project. In addition, for Phase I of the project the Applicant has accepted 

permit limits, as necessary, to limit contemporaneous 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 Rule 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 Rule 20.3(d)(3)(iii) are not applicable. 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 period in accordance with Rule 20.3(d)(4). 

Rule 20.3(d)(4)(i) requires that the District consider 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 federal nonattainment criteria pollutant or its 

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

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

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

increases are limited to below the major modification thresholds by the FDOC permit 

conditions without consideration of actual emission reductions. Therefore, offsets are only 

required for NOx emissions. The maximum contemporaneous emission increase of NOx is 

39.9 tons per year for this project. An offset ratio of 1.2 to 1 is required [Rule 

20.3(d)(8)(i)(B)], so a total of 47.88 tons per year of NOx emission offsets will be required. 

The offsets must be surrendered to the District prior to the initial startup of the equipment for 

which they are required [Rule 20.1(d)(5)(iii)]. Offsets may be actual emission reductions, 

stationary source Class A emission reduction credits (ERCs) issued under District Rules 

26.0-26.10, or mobile source emission reduction credits (MERCs) issued under District Rule 

27 (if approved by ARB and EPA.). The Applicant 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., the Applicant’s parent 

company, currently owns Emission Reduction Credits (ERCs) representing 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 discounted 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 modified stationary source required to satisfy 

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

20.3(d)(8) shall certify that all major sources operated by the applicant in the state are in 
Final Determination of Compliance Page 46 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

compliance with all applicable emissions limitations and standards under the federal Clean 

Air Act. The Applicant is an indirect wholly owned subsidiary of NRG Energy, Inc., which 

also operates the Encina Power Station, which is a major stationary source located in San 

Diego County, and on whose property the CECP will be located. The Encina Power Station 

operation has been regulated by the San Diego Air Pollution Control District under permits to 

operate issued for its five boilers and one gas turbine. Besides the Encina Power Station, 

NRG Energy owns other potential major stationary sources in the state including the El 

Segundo Generating Station in El Segundo California and the Long Beach Generating 

Station in Long Beach California. The required 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 Siting and Alternatives Analysis

The Applicant has provided an analysis of various alternatives to the project. This analysis 

included a No Project alternative, alternative sites, and alternative technologies. Since all of 

San Diego County is currently classified as non-attainment for ozone, an alternative location 

within San Diego would not avoid the project being located in a non-attainment area.

Rule 20.5 – Power Plants

This rule requires that the District submit Preliminary and Final Determinations of 

Compliance reports to the California Energy Commission (CEC). The Final Determination of 

Compliance is equivalent to a District Authority to Construct. This Preliminary 

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

Determination of Compliance will be submitted to the CEC. 

DISTRICT PROHIBITORY RULES

Rule 50 – Visible Emissions

This rule limits air contaminants emissions into the atmosphere of shade darker than 

Ringlemann 1 (20% opacity) to not more than an aggregate of three minutes in any 

consecutive sixty-minute period. 
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 (natural gas), no visible 

emissions at or above this level are expected during operation of the power plant. 

Rule 51 – Nuisance

This rule prohibits the discharge of air contaminants that cause or have a tendency to cause 

injury, nuisance, annoyance to people and/or the public or damage to any business or 

property. 

No nuisance or complaints are expected from this type of equipment. 

Rule 53 – Specific Air Contaminants

This rule limits emissions of sulfur compounds (calculated as SO2) to less than or equal to 

0.05% (500 ppm) by volume, on a dry basis. The rule also limits particulate matter 

emissions from gaseous fuel combustion to less than or equal 0.1 grains per dry standard 

cubic foot of exhaust calculated at 12% CO2. 

Sulfur Compounds

The Applicant proposes to use Public Utilities Commission (PUC) quality natural gas sold in 

San Diego County. Because of the low sulfur content of the fuel, the plant is expected to 

comply with the sulfur emission requirements of Rule 53. The fuel is expected to have a 

sulfur content less than 0.75 grains per 100 dry standard cubic foot (gr/100 dscf). 

Using an F-Factor of 8710 standard cubic feet of exhaust gas per million Btu of heat input for 

natural gas combustion at 0% O2 in the exhaust, assuming all sulfur in the fuel is converted 

into SO2, the concentration by volume of SO2 in the exhaust gas is: 

SO2 concentration = (0.75 grain /100 scf fuel) x (1lb SO2 / 7000 grain) x (385 scf SO2 / 64 lb 

SO2) x (1 scf fuel / 1015 x 10-6 MMBtu) x (1MMBtu / 8710 dscf of exhaust) x (106) = 0.72 

ppm SO2 by volume. 

This is well below the Rule 53 limit of 500 ppm SO2 by volume. Therefore, the project is 

expected to comply with this rule. 
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% CO2, a maximum natural gas usage of 91,454 lbs /hr, and an estimated 

maximum particulate matter emission rate of 9.5 lbs/hr, combustion particulate at maximum 

load are estimated to be: 

Grain loading = [(9.5 lbs/hr)(7,000 gr/lb)] / (198.025 scf/lb fuel)(91,454 lbs fuel/hr)) = 0.004 

gr/dscf 

This is well below the Rule 53 emission limit of 0.1 gr/dscf. Therefore the plant is expected 

comply with this rule. 

Rule 68 –Oxides of Nitrogen from Fuel Burning Equipment

This rule limits NOx emissions from any natural gas fueled combustion equipment to less 

than 125 ppmvd calculated at 3% oxygen on a dry basis. However, this equipment is subject 

to the more stringent requirements of Rule 69.3 and Rule 69.3.1 and is exempt from Rule 68. 

Rule 69.3-Stationary Gas Turbines – Reasonably Available Control Technology

This rule limits NOx emissions from combustion turbines fueled with natural gas greater than 

0.3 MW to 42 ppmvd at 15% oxygen when fired on natural gas. Equipment is exempt from 

the standards during 120 minute startup and shutdown periods. 

The combustion turbines for this project will be equipped with dry ultra low NOx combustors 

and SCR controls for NOx. Proposed permit conditions limit NOx emissions to 2.0 ppmvd 

during normal operations, which is far below the 42 ppmvd rule standard. Maximum 

durations of startups and shutdowns (60 minutes for startup and 30 minutes for shutdown) are 

shorter than Rule 69.3 requirements. However, commissioning, low-load operation, tuning, 

and transient periods are still subject to the rule standards. The facility permit will contain 

conditions to limit emissions below the emissions levels specified in Rule 69.3 (excluding 

startups and shutdown as defined in Rule 69.3). A CEMS will monitor emissions during 

combustion turbine operations. 
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 combustion turbines greater than 10 MW to 15x(E/25) 

ppmvd when operating uncontrolled and 9 x (E/25) ppm at 15% oxygen when operating with 

add-on emission controls and averaged over a one-hour period, where E is the thermal 

efficiency of the unit. The rule also specifies monitoring and record keeping requirements. 

Startups, shutdowns, and fuel changes are defined by the rule and excluded from compliance 

with these limits. Equipment is exempt from the standards during 120 minute startup and 

shutdown periods. 

The thermal efficiency for each turbine, as stated by the Applicant, is 36.5 %. Therefore the 

maximum allowable uncontrolled NOx concentration is 21.9 ppmvd based on a 1-hour 

averaging period at 15% oxygen and the maximum allowable controlled NOx concentration 

is 12.6 ppmvd. The uncontrolled concentration limit would only be applicable prior to 

installation of the SCR system. 

The combustion turbines for this project will be equipped with dry ultra low NOx combustors 

and SCR controls for NOx. The FDOC permit conditions limit NOx emissions to 2.0 ppmvd 

during normal operations, which is far below the 12.6 ppmvd rule standard. Maximum 

durations of startups and shutdowns (60 minutes for startup and 30 minutes for shutdown) are 

shorter than Rule 69.3.1 requirements. However, commissioning, low-load operation, tuning, 

and transient periods are still subject to the rule standards. The facility permit will contain 

conditions to limit emissions below the emissions levels specified in Rule 69.3.1 (excluding 

startups and shutdown as defined in Rule 69.3.1). A CEMS will monitor emissions during 

combustion turbine operations. A CEMS will monitor emissions during combustion turbine 

operations. 

Rule 69.4 – Stationary Reciprocating Internal Combustion Engines – Reasonably 

Available Control Technology

This rule applies to stationary internal combustion engines with brake horsepower rating of 

50 or greater and located at a stationary source with potential to emit of 50 tons per year or 

more of NOx. Since the proposed emergency fire pump engine is subject to Rule 69.4.1, 
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 Internal combustion Engines – Best Available 

Retrofit Control Technologies.

Rule 69.4.1(d)(1) requires the engine to meet the NOx emission standard of 6.9 grams per 

brake horsepower hour (g/bhp-hr). This preliminarily proposed engine is an EPA certified 

engine with NOx emission at 3.92 g/bhp-hr. In addition, the FDOC permit conditions will 

require the engine to meet the more stringent EPA certification requirements for model year 

2009 and later engines. Therefore, the engine is in compliance with this requirement. 

Rule 69.4.1(d)(2) requires the engine to meet CO emission standard of 4500 ppmvd at 15% 

oxygen. This engine is in compliance with this requirement, with a CO emission level of 

61.2 ppmvd at 15% oxygen. 

Rule 69.4.1(d)(4) requires the engine to use only California Diesel fuel. The use of CARB diesel 

is specified in the FDOC permit conditions. 

Rule 69.4.1(e)(3) requires installation of a non-resettable totalizing meter or a non-resettable 

hour meter. The proposed engine has an hour meter. 

Rule 69.4.1 requires the engine operator to conduct periodic maintenance of the engine and its 

control system in accordance with a procedure recommended by the manufacturer or approved 

by the District. Compliance with this requirement is verified through recordkeeping. 

 

Rule 69.4.1(g)(1)(v), (vi) requires the engine operator to keep records of California Diesel 

fuel certification and engine maintenance procedure. Compliance with this requirement is 

verified through recordkeeping. 

Rule 69.4.1(g)(2) requires the engine operator to maintain an operating log of the dates and 

times of engine operation, of the total cumulative hours of operation per calendar year, and of 
Final 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 all records to be kept on site for at least three years and made 

available to the District upon request. The FDOC permit conditions 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 Contaminants 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 Technology (TBACT) must be installed if the HRA shows a cancer 

risk greater than one in a million at a receptor 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. Additional requirements apply if the cancer risk is 

expected to exceed ten in a million. 

An HRA, which was reviewed by the District, 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 emergency fire pump engines were considered. No 

emission decreases from the existing facility were accounted for in the assessment. In 

addition, potential acute health impacts during 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 recent source test of a combined-cycle power 

plant during the first hour of a cold start. The HRA performed shows that the incremental 

cancer risk is 0.47 in a million for exposed residents 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 turbine to 1460 per year. The acute and chronic 
Final Determination of Compliance Page 52 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

incremental health impacts measured by the Health 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 significantly reduces toxic air 

contaminant emissions and would be considered TBACT for this project—if TBACT had 

been required. The health risk analysis of this project is further discussed in Appendix B of 

this document. 

Regulation XIV – Title V Operating Permits

The CECP is co-located with the Encina Power Station and under common control 

ownership. The Encina Power Station currently has a Title V Operating Permit. The 

Applicant has submitted an application to modify this Title V Operating Permit to include the 

CECP project. 

STATE REGULATIONS IMPLEMENTED BY THE DISTRICT

Health and Safety Code §42301.6

This section of the state Health and Safety Code requires the District to notify parents of 

students at a school if a new source of air pollution is within a 1000 feet of the boundary of 

that school. The District has determined that the CECP is not within 1000 feet of any school 

boundary. 

Title 17 of the California Codes of Regulations (CCR) §93115—Airborne Toxic Control 

Measure (ATCM) for Stationary Compression Ignition Engines

The emergency diesel fire pump engine is subject to the Title 17 of the California Codes of 

Regulations (CCR) §93115—Airborne Toxic Control Measure (ATCM) for Stationary 

Compression Ignition Engines. 

Section 93115.5(a)(1) requires that by January 1, 2006, no owner or operator of a new 

stationary CI engine or an in-use prime stationary diesel-fueled CI engine shall fuel the 
Final 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 requirements of the Verification Procedure; or an 

alternative fuel; or CARB Diesel Fuel used with fuel additives that meets the requirements of 

the Verification Procedure; or any combination of the above fuels. The FDOC permit 

conditions required the use of only CARB Diesel Fuel. 

Section 93115.6(a)(1) requires that no owner or operator shall operate a new stationary 

emergency standby diesel-fueled CI engine for nonemergency use, including maintenance 

and testing, during the following periods: whenever there is a school sponsored activity, if 

the engine is located on school grounds; and between 7:30 am and 3:30 pm on days when 

school is in session if the engine is located within 500 feet of school grounds. This 

requirement does not apply if the engine emits no more than 0.01 g/bhp-hr of diesel PM. 

Compliance is required through the FDOC permit conditions. 

Section 93115.6(a)(3)(A)(1) requires that new stationary emergency standby diesel-fueled 

engines (>50 bhp) shall emit diesel PM at a rate less than or equal to 0.15 g/bhp-hr; or meet 

the current model year PM standards specified in the Off-Road Compression Ignition Engine 

Standards for off-road engines with the same maximum rated power (title 13 CCR, section 

2423), whichever is more stringent; and not operate more than 50 hours per year for 

maintenance and testing purposes. The proposed engine PM emission rate is 0.09 g/bhp-hr. 

The engine is limited to 50 hours per year for testing and maintenance operation by the 

FDOC permit conditions. 

Section 93115.6(a)(3)(B) requires that new stationary emergency standby diesel-fueled 

engines (>50 bhp) meet the HC, NOx, NMHC+NOx, and CO standards for off-road engines 

of the same model year and maximum rated power as specified in the Off-Road 

Compression-Ignition Engine Standards (Title 13, CCR, Section 2423). The preliminarily 

proposed engine meets the Tier 2 HC, NOx, NMHC + NOx and CO standards for off-road 

engine of the 2005 model year. 
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 operator of new and in-use stationary CI engines, 

including non-diesel-fueled CI engines, to submit to the District APCO information on 

owner/operator contact information; engine information; fuel used; operation information; 

receptor information; and whether the engine is included in an existing AB2588 emission 

inventory. The District may exempt the owner or operator from providing all or part of this 

information if there is a current record of the information in the owner or operator’s permit to 

operate, permit application, or District records. This information has been provided by the 

Applicant in the application submitted for the CECP.

Section 93115.10(e) requires that a non-resettable hour meter be installed upon engine at 

installation on all engines subject to all or part of the emission standards requirements. The 

engine will be required to have an hour meter by the FDOC permit conditions. 

Section 93115.10(g)(1) requires each owner or operator of an emergency standby dieselfueled CI engine to keep records and prepare a monthly summary that lists and documents 

the nature of use for emergency use hours, maintenance and testing hours, initial start-up 

testing hours, retention of fuel purchase records for CARB diesel fuel. Compliance is 

required through the FDOC permit conditions. 

Section 93115.10(g)(2) requires all records to be retained for a minimum of 36 months. 

Records for the prior 24 months shall be retained on-site, and made immediately available to 

District staff upon request. Records for the prior 25 to 36 months shall be made available to 

District staff within 5 working days from request. Compliance is required through 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 certification test data for the stationary diesel-fueled CI engine. 

B. Engine manufacturer test data. 

C. Emission test data from a similar engine, or 
Final Determination of Compliance Page 55 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

D. Emission test data used in meeting the requirements of the Verification Procedure for 

the emission control strategy implemented. 

Engine manufacturer emission data were used to verify compliance with emission standard 

requirements. 

NATIONAL EMISSIONS STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPS)

The Encina Power Station is an existing major source of hazardous air pollutants (HAPs) 

based on the potential to emit hexane over the 10 ton per year major source threshold for a 

single HAP. Estimated actual emissions of hexane, calculated using an EPA (AP-42) 

emission factor, were about 13.5 tons per year in 2006. Therefore, equipment at the Encina 

Power Station are subject to NESHAPS applicable to major stationary sources of HAPs. 

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

Pollutants for Stationary Combustion Turbines

This subpart establishes national emission limitations and operating limitations for hazardous 

air pollutants (HAP) emissions from stationary combustion turbines located at major sources 

of HAP emissions, and requirements to demonstrate initial and continuous compliance with 

the emissions and operating limitations. However, except for Initial Notification 

requirements [40 CFR §63.6145] EPA has stayed the applicability of this regulation for gasfired combustion turbines [40 CFR §63.6905(d)]. 

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

Pollutants for Stationary Compression Ignition Internal Combustion Engines

This subpart for stationary compression ignition internal combustion engines requires [40 

CFR §63.6590(c)] engines rated less than 500 brake horsepower located at major sources of 

HAP emissions (and also all engines at nonmajor sources of HAPs) to comply with the 

requirements in 40 CFR Part 60 Subpart IIII— Standards of Performance for Stationary 

Compression Ignition Internal Combustion (CIIC) Engines. There are no other requirements 

applicable to such engines. Proposed permit conditions require compliance with Subpart IIII. 
Final Determination of Compliance Page 56 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

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

Stationary Combustion Turbines.

This new source performance standard requires stationary combustion turbines with a heat 

input equal to or greater than 10 MMBtu/hour based on the high heating value of the fuel to 

comply with NOx and SOx emission standards.

 

Section 60.4320 requires new combined-cycle combustion turbines firing natural gas with a 

rated heat input greater than 850 MMBtu/hour to comply with a NOx standard of 15 ppmvd 

at 15% O2 averaged over each 30 operating days, or alternatively, a standard of 0.42 pounds 

per megawatt hour (lb/MWh) during normal operations. During periods of less than 75% 

load the corresponding standards are 96 ppmvd and 4.7 lb/MWh. The actual limit during any 

30-day period is an average of the normal and less than 75% standards. 

With SCR as postcombustion emission control, NOx emissions from this combustion turbine 

are controlled to 2.0 ppm at 15% O2 during normal operation. Information submitted as part 

of the proposed City of Vernon Power Plant (06-AFC-4, Table 8.1B-2) indicates that the 

expected typical maximum NOx level for this model turbine is 50 ppm at less than 50% load 

(as occurs during startup and shutdown). Assuming NOx emission concentration during 

startup and shut down is 50 ppm at 15% O2, the NOx emission concentration averaged over a 

30-day period that has 50 hours of startup, 25 hours of shutdown and 250 hours of normal 

operation is: 

NOx concentration = [50 ppm x (50 startup hours)] x [50 ppm x (25 shutdown 

hours)] + (2 ppm x 250 normal operation hours)] / (325 hours) = 13 ppm 

Therefore, the turbine is expected to comply with the NOx emission standard of this subpart. 

Compliance is required through 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 emissions from combustion turbine in excess of 0.90 

lbs/MW-hour gross output or 0.060 lbs/MMBtu heat input. SO2 emission from the 

combustion turbines of this project is 0.002 lbs/MMBtu. 

SO2 emission rates = (4.4 lbs/hr) x (1 hour/ 1947 MMBtu) = 0.002 lbs/MMBtu 

Therefore, the turbine is in compliance with the SO2 limit requirement. 

Section 60.4340(b) requires turbines not using water injection or steam injection to install, 

calibrate, maintain and operate a continuous emission monitoring system (CEMS) consisting 

of a NOx monitor and a diluent gas (oxygen) or carbon dioxide monitor to determine the 

hourly NOx emission rate in ppmvd or lb/MWh. Turbines complying with concentration 

limit based standards must install calibrate, maintain and operate a fuel flow meter to 

measure heat input. Turbines complying with output-based standards must install, calibrate, 

maintain and operate a watt meter to measure the gross electrical output in megawatt-hours. 

This combustion turbine will be equipped with a CEMS to monitor NOx and CO emissions 

in parts per million and oxygen content in the exhaust gas. In addition, the gross electrical 

output in MWh will also be monitored. 

Section 60.4345 requires the CEMS to be installed and certified according to Performance 

Specification 2 in Appendix B to this part, or according to Appendix A of part 75 of this 

chapter, and each fuel meter and watt meter shall be installed, calibrated, maintained and 

operated according to the manufacturer’s instructions. The turbine operator must develop 

and keep on site a QA plan for all continuous monitoring equipment. The CEMS for this 

combustion turbine will be required to go through Relative Accuracy Test Audit (RATA) and 

all other required certification tests in accordance with 40 CFR Part 75 Appendix A and B. 

The FDOC permit requires continuous monitoring equipment meeting these requirements to 

be installed, calibrated, 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 specific procedures. These requirements are included in the 

FDOC permit conditions. 

Section 60.4365 exempts the requirement to monitor total sulfur content of the fuel if it can 

be demonstrated through a valid purchase contract , tariff sheet or transportation contract for 

the fuel that total sulfur content of natural gas used is 20 grains of sulfur or less per 100 

standard cubic feet. Sulfur content of natural gas fuel used in this turbine is 0.75 grains per 

100 cubic feet of gas or less. Quarterly records of natural gas sulfur content are to be kept on 

site to satisfy this requirement. 

Section 60.4375 requires submittal of reports of excess emissions and monitor downtime for 

all periods of unit operation, including startup, shutdown and malfunction. The FDOC 

permit includes a condition to satisfy these requirements. Annual source tests are not 

required pursuant to Subpart KKKK for combustion turbine equipment with CEMS. Since 

this combustion turbine is subject to a NOx limit that is seven times more stringent than the 

NOx limit of this NSPS, excess emissions are not expected to occur. In addition, reports on 

the CEMS system are to be submitted in accordance with Rule 19.2 requirements and CEMS 

protocol approved by the District and excess emissions and monitoring reports are required 

by the FDOC permit conditions.. 

Section 60.4400 requires that an initial performance test and annual NOx performance test be 

conducted in accordance with certain requirements. Annual source tests are not required 

pursuant to Subpart KKKK for combustion turbine equipment with CEMS. This combustion 

turbine is required to be source tested initially to demonstrate compliance with NOx, CO, 

VOC, and ammonia emission standards. The source tests are to be conducted in accordance 

with the applicable EPA test methods and applicable requirements of 40 CFR 75 Appendix 

B. The FDOC permit contains conditions satisfying 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 hour (g/bhp-hr), CO limit of 2.6 g/bhp-hr and a PM limit of 

0.4 g/bhp-hr. Fire pump engines of model year 2009 and after must comply with NOx + HC 

emission limit of 3 g/bhp and PM emission limit of 0.15 g/bhp-hr. Although the engine 

preliminarily proposed by the Applicant would not comply with model year 2009 standards, 

the Applicant has committed to install a compliant engine and the FDOC permit conditions 

require compliance with the standards of Subpart IIII for model year 2009 and later engines. 

Section 60.4207 requires that beginning October 1, 2007, owners and operators of station 

CIIC engines subject to Subpart IIII to use diesel fuel with a maximum sulfur content of 500 

ppm per gallon; and beginning October 1, 2010, to use diesel fuel with a maximum fuel 

content of 15 ppm per gallon. This engine is required to use CARB diesel fuel, which 

complies with this requirement. 

Section 60.4209 requires that owners or operators of engines subject to Subpart IIII to install 

a non-resettable hour meter prior to startup of the engine. This requirement is included in the 

FDOC permit conditions. 

Section 60.4214 states that owner of engines that are stationary emergency standby engines 

are not required to submit an initial notification 

ACID RAIN

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 affected 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 procedures for the allocation of sulfur dioxide 

emission allowances; the tracking, holding and transfer of allowances; the deduction of 

allowances for purposes of compliance and for purposes of offsetting excess emissions 

pursuant to Parts 72; the sale of allowances through EPA-sponsored auctions and a direct 

sale; the application for allowances from the Conservation and Renewable Energy Reserve; 

and the application for allowances for desulfurization of fuel by small diesel refineries. 

Requirements from this part will be included in evaluation for the Acid Rain program 

application required by Part 72. 

40CFR Part 75 – Continuous Emission Monitoring

This part established requirements for the monitoring, recordkeeping, and reporting of SO2, 

NOx, and CO2 emissions, volumetric flow, and opacity data from emission units under the 

Acid Rain Program. The regulations include general requirements for the installation, 

certification, operation, and maintenance of continuous emission or opacity monitoring 

systems, certification tests and procedures, and quality assurance tests and procedures. 

Subpart B on Monitoring Provisions established general operating requirements for the 

monitoring systems. Subpart C establishes requirements on initial certification and 

recertification procedures. Subparts F and G establish requirements on recordkeeping and 

reporting requirements. All applicable requirements are included in the FDOC permit 

conditions. 
Final Determination of Compliance Page 61 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

VI. ADDITIONAL ISSUES

PARTICULATE EMISSION RELATING TO THE USE OF DESALINATED WATER FOR 

EVAPORATIVE COOLING

The proposed Siemens turbines have inlet air filters located upstream of the evaporative 

coolers. The evaporative cooler is turned on only during normal operation when ambient 

temperature is higher than 60°F. The particulate emission factor of 9.5 lbs/hr provided by the 

turbine vendor includes anticipated particulate matter from the evaporative cooler parameters 

since the water supply is expected to comply with the vendor’s recommended water quality 

standards. Therefore, no further particulate emissions from the evaporative cooler are 

included in the emission calculation. 

COMMISSIONING PERIOD

After construction of the equipment has been completed, the Applicant will be allowed a 

commissioning period of 120 days or 415 operating hours for each turbine, whichever comes 

sooner. During the 120-day commissioning period, the turbines will go through testing and 

tuning to ensure that the equipment is working properly and will be able to comply with all 

the 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 state or national ambient 

air quality standards, and the hourly concentration limits for NOx to ensure compliance with 

the District RACT and BARCT Rules 69.3 and 69.3.1, respectively. A CEMS will be 

required to be installed at the time of initial startup to monitor emissions during the 

commissioning period from each turbine. 

Once the emissions control equipment has been installed and is in good working order, the 

turbines must meet all BACT/LAER standards and permit requirements. CEMS and source 

testing will be used to show compliance with these standards. 
Final Determination of Compliance Page 62 of 63 August 4, 2009 

Applications No. 985745, 985747, and 985748 

SOURCE TEST FREQUENCY

The FDOC permit conditions require that the frequency of annual compliance source testing 

be in accordance with the applicable RATA frequency requirements of the federal acid rain 

program provisions at 40 CFR Part 75, Appendix B, Sections 2.3.1 and 2.3.3. The annual 

source testing is to show compliance with the NOX, CO, VOC, PM10, and ammonia 

emission limits and to verify the accuracy of the continuous emission monitoring system 

(CEMS). At a minimum, the acid rain programs provisions require that a source test be 

performed after four calendar quarters in which 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 operating 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 provisions 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-quarter period. Any such test must be conducted within 720 

operating hours of the end of the eight-quarter period. 

APPENDIX A 

APPROVAL OF AIR QUALITY 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 92131
2

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 NO2, CO, SO2, and PM10 and PM2.5. The applicant and their consultant 

(Sierra Research) worked closely with the District in developing modeling and analysis 

procedures in support of demonstrating compliance with all applicable NSR requirements. 

Modeling was performed in order to determine whether emissions during these time 

periods would impact the State and/or Federal Ambient Air Quality Standards for all 

criteria pollutants. 

The modeling procedures are discussed in the following subsections. 

 

3.1 MODELING METHODOLOGIES

AERMOD was used first to “screen” the different turbine stack emission and ambient 

temperature parameters for the conditions that generate the highest ground-level 

concentrations of criteria pollutants. Gas turbine specifications were developed and 

modeled for four temperature scenarios: extreme hot temperature (104 F), summer 

average temperature (74 F), annual average temperature (61 F) and extreme low 

temperature (37 F). Stack parameters and criteria pollutant emission rates were provided 

at each of these three ambient temperatures. Similarly, stack parameters and emission 

rates were provided at each ambient temperature for the turbines running at 100%, 75%, 
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 impact” turbine stack conditions and emission 

rates to determine the maximum criteria pollutant concentrations for the appropriate 

averaging periods for each criteria pollutant. Table 3-3 shows the inputs for the refined 

modeling. 

Startup/Shutdown and Commissioning modeling for the elevated emission rates of NOx 

and CO existing during these conditions was also performed. The model inputs used to 

simulate those conditions are provided in Table 3-4. 

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 3-1 

Screening Modeling Impacts 
5

Table 3-2 

Screening Level Modeling Impacts 
6

Table 3-3 

Emission Rates and Stack Parameters for Refined Modeling
7

Table 3-3 (Continued) 

Emission Rates and Stack Parameters for Refined Modeling
8

Table 3-3 (Continued) 

Emission Rates and Stack Parameters for Refined Modeling 
9

Table 3-4

Startup/Shutdown and Commissioning Modeling Inputs
4.0 AIR QUALITY IMPACT ANALYSIS RESULTS

In accordance with EPA and San Diego Air Pollution Control District New Source Review 

Guidance and the modeling methodologies described above, maximum predicted 

concentrations associated with facility operations were determined for each of the required 

criteria pollutant and the applicable averaging period during Normal, Startup/Shutdown 

and Commissioning conditions. The maximum predicted concentrations occurring during 

any of the operating conditions modeled were added to worst-case background 

concentrations for comparison to Federal and State Ambient Air Quality Standards. Worst 

case background concentrations were determined from the review of 3 years (2004-2006) 

of monitoring data taken from the District’s Camp Pendleton, Escondido or San Diego 

monitoring stations, whichever was available for a specific criteria pollutant and deemed 

to be most representative of air quality in the facility area. Table 4-1 summarizes the worst 

case background concentrations. 

The maximum ground-level impacts at any location from normal operations, 

startup/shutdowns and the special circumstances of inversion breakup fumigation are 

given in Table 4-2. 

Table 4-3 provides the summary of project modeled maximum impacts for Commissioning 

period operating conditions. 

Table 4-4 provides the summary of the proposed project modeled maximum impacts, 

including worst case ambient background concentrations, compared with Federal and 

California Ambient Air Quality Standards (AAQS). 

Table 4-5 provides a comparison of maximum modeled impacts during normal operation 

and PSD significant impact levels. 
11

TABLE 4-1 

MAXIMUM BACKGROUND CONCENTRATIONSa

, PROJECT AREA, 2004-2006 

(μg/m3

)—REVISED JUNE 25, 2009 

Pollutant Averaging 

Time 2004 2005 2006 

NO 1-hour 186 145 152 2 (Camp 

Pendleton) Annual 23 23 21 

1-hour 110 105 89 

3-hour 52 68 79 

24-hour 24 24 24 

SO2 (San Diego) 

Annual 10 8 10 

1-hour 7210 6753 6524 CO (Escondido) 8-hour 4361 3548 4136 

24-hour 58 42 52 

PM10 (Escondido) Annual 27 24 24 

24-hourb

 37 32 28 

PM2.5 (Escondido) Annual 14.1 12.3 11.5 

Source: California Air Quality Data, California Air Resources Board website; EPA AIRData website. 

Reported values have been rounded to the nearest tenth of a μg/m3

 except for PM10 which were already 

rounded to the nearest integer. 

Notes: 

a. With the exception of 24-hr PM2.5, bolded values are the highest during the three years and are used to 

represent background concentrations. 

b. 24-hour average PM2.5 concentrations shown are 98th percentile values rather than highest values 

because compliance with the ambient air quality standards is based on 98th percentile readings. Since the 

ambient standard is based on a 3-year average of the 98th percentile readings, the 3-year average of the 

2004 to 2006 98th percentile readings was used to represent the background concentration. 
12

TABLE 4-2 

NORMAL OPERATION AIR QUALITY MODELING RESULTS FOR NEW EQUIPMENT

Modeled Maximum Concentrations (μg/m3

) 

Pollutant 

Averaging 

Time 

Normal 

Operations 

AERMOD 

Startup/Shutdown 

AERMOD 

Fumigation 

SCREEN3 

Shoreline 

Fumigation 

SCREEN3 

Combined Impacts Both CTGs 

NO2 1-hour 

Annual

 13.3 

0.1 

 80.4 

a 

 2.6 

c 

 18.5 

c 

SO2 1-hour 

3-hour 

24-hour 

Annual 

4.3 

2.0 

 0.4 

0.0 

b 

b 

b 

b 

0.8 

0.6 

0.3 

c 

 5.4 

 4.8 

 0.5 

c 

CO 1-hour 

8-hour 

 9.0 

 1.9 

1133.8 

 236.0 

1.6 

1.0 

 11.3 

 3.5 

PM2.5/PM10 24-hour 

Annual 

1.2 

0.1 

b 

b 

 0.9 

c 

 1.7 

c 

Fire pump Engine 

NO2 1-hour 

Annual

108.0 

0.1 

d 

d 

e 

e 

e 

e 

SO2 1-hour 

3-hour 

24-hour 

Annual 

0.2 

0.0 

0.0 

0.0 

d 

d 

d 

d 

e 

e 

e 

e 

e 

e 

e 

e 

CO 1-hour 

8-hour 

18.2 

 1.0 

d 

d 

e 

e 

e 

e 

PM2.5/PM10 24-hour 

Annual 

0.0 

0.0 

d 

d 

e 

e 

e 

e 

Combined Impacts New Equipment 

NO2 1-hour 

Annual

 108.0 

0.1 

f 

f 

f 

f 

f 

f 

SO2 1-hour 

3-hour 

24-hour 

Annual 

 4.3 

 2.0 

 0.4 

0.0 

f 

f 

f 

f 

f 

f 

f 

f 

f 

f 

f 

f 

CO 1-hour 

8-hour 

 18.2 

 1.9 

f 

f 

f 

f 

f 

f 

PM2.5/PM10 24-hour 

Annual 

1.2 

0.1 

f 

f 

f 

f 

f 

f 

a. Not applicable, because startup/shutdown emissions are included in the modeling for annual average. 

b. Not applicable, because emissions are not elevated above normal operation levels during startups/shutdowns. 

c. Not applicable, because inversion breakup is a short-term phenomenon and as such is evaluated only for shortterm averaging periods. 

d. Not applicable, because engine will not operate during CTG startups/shutdowns. 

e. Not applicable, this type of modeling is not performed for small combustion sources with relatively short stacks. 

f. Impacts are the same as shown for CTGs. 
13

TABLE 4-3 

MODELED IMPACTS DURING COMMISSIONING (COMBINED IMPACTS 

BOTH CTGS)

Pollutant/Averaging Period Modeled Concentration, μg/m3 

NO2 – 1-hour 127.5 

CO – 1-hour 3228.0 

CO - 8-hour 675.9 

TABLE 4-4 

MODELED MAXIMUM PROPOSED PROJECT IMPACTS 

REVISED June 25,2009 

Pollutant 

Averaging 

Time 

Maximum 

Project Impact 

(μg/m3

) 

Background 

(μg/m3) 

Total 

Impact 

(μg/m3) 

State 

Standard 

(μg/m3) 

Federal 

Standard 

(μg/m3) 

NO2 1-hour 

Annual 

 127.5a 

 0.1 

186 

23 

 314 

23 

338 

56 

- 

100 

SO2 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 

3,228.0a

 675.9a 

7210 

4361 

10438 

5037 

23,000 

10,000 

40,000 

10,000 

PM10 24-hour 

Annual 

1.2 

0.1 

58 

27 

59 

27 

50 

20 

150 

-- 

PM2.5 24-hour 

Annual 

1.2 

0.1 

32.7b

14.1 

34 

14 

-- 

12 

35 

15 

Notes: 

 a. Impacts during gas turbine commissioning. 

b. Three year average of 98th percentile. 
TABLE 4-5 

COMPARISON OF MAXIMUM MODELED IMPACTS DURING NORMAL OPERATION AND 

PSD SIGNIFICANT IMPACT LEVELS

Pollutant Averaging Time

Significant 

Impact Level, 

μg/m3

Maximum 

Modeled Impact 

for CECP, 

μg/m3

Exceed 

Significant 

Impact Level? 

NO2 Annual 1 0.1 No 

SO2 3-hour 

24-Hour 

Annual 

25 

5 

1 

2.0 

0.4 

0.0 

 No 

CO 1-Hour 

8-Hour 

2000 

500 

1134 

236 

 No 

PM10 24-Hour 

Annual 

5 

1 

1.2 

0.1 

 No 

5.0 CONCLUSION

The results of the modeling indicate that the proposed facility operations including 

Commissioning and Startup/Shutdowns will not cause or contribute to an exceedance of 

the Federal and California Ambient Air Quality Standards for NO2, SO2 and CO. 

For PM10, background concentrations already exceed the annual and 24 hour California 

standard. Since the background is already in exceedance of the annual standard no 

additional violations can be due to facility operations. Additionally the 0.1 μg/m3 predicted 

annual impact is well below PSD significant impact levels shown in Table 4-5. Predicted 

impacts less than SILs are normally considered to not significantly affect compliance with 

Federal Ambient Air Quality Standards regardless of the background level. Specifically in 

non-attainment areas, project impacts less than the SILs are deemed to not significantly 

cause or contribute to violations of, 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 PM10 impacts of approximately 1.2 

μg/m3

, additional AERMOD modeling could be performed for all days in the 2004-2006 

period that 24 Hour PM10 background concentrations were between 49 μ/m3

 and 50 μg/m3

(California Standard) to determine whether additional violations would result from facility 

operations. There were no monitoring days that concentrations were measured within this 

range (highest monitored value less than the California Standard was 44 μg/m3

. Therefore 

it can be concluded that facility operations would not cause or contribute to additional 

violations of the California 24 Hour Ambient Air Quality Standard for PM10. 

The modeling results also indicate that no exceedance of the Federal annual or 24 hour PM2.5 

standard is predicted. Monitored background levels exceeded the California annual standard. Since 

the background is already in exceedance of the annual standard no additional violations can be due 

to facility operations. Additionally the 0.1 μg/m3 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 considered 
15

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 

PM10 LEVELS IN SAN DIEGO COUNTY, ESCONDIDO MONITORING STATION, 1997-2006 (μg/m3)

 199

7 

199

8 

199

9 

200

0 

200

1 

200

2 

200

3 

200

4 

200

5 

200

6 

Highest 24-Hour 

Average 63 51 50 63 72 50 124* 58 42 52

Annual 

Arithmetic Mean 

(State Standard 

= 20 μg/m3) 

29 24 30 30 31 25 33 27 24 24 

Number of Days Exceeding: 

State Standard 

(50 μg/m3, 24-

hour) 

3 1 1 2 2 1 5 1 0 1 

Federal 

Standard 

(150 μg/m3, 24-

hour) 

0 -- 0 0 0 0 3 0 0 0 

Source: California Air Quality Data, California Air Resources Board website 

(http://www.arb.ca.gov/adam/welcome.html; EPA AIRData website (http://www.epa.gov/air/data/index.html). 

*Removed exceptional event value of 179 
16

TABLE 5.1-7 

PM2.5 LEVELS IN SAN DIEGO COUNTY, ESCONDIDO MONITORING STATION, 1997-2006 (μg/m3

)

 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 

Highest 24-Hour Average -- -- 64.0 66.0 60.0 54.0 38.0 67.0 43.0 41.0 

Number of Days Exceeding: 

Federal Standard 

(65 μg/m3, 24-hour) 0 0 0 1 0 0 0 1 0 0 

 (35 μg/m3, 24-hour 

 effective December 17, 

 2006) 

-- -- -- -- -- -- -- -- -- -- 

98th Percentile -- -- 45.0 48.0 41.0 39.0 34.0 37.0 32.0 28.0 

3-yr Average, 98th

Percentile -- -- -- -- 44.7 42.7 38.0 36.7 34.3 32.3 

Annual Arithmetic Mean 

(State Std = 12 μg/m3

) -- -- 18.0 15.8 17.5 16.0 14.1 14.1 12.3 11.5 

3-yr Annual Average 

(Federal Std = 15 μg/m3

) -- -- 18 16 18 16 14 14 12 12 

Source: California Air Quality Data, California Air Resources Board website (http://www.arb.ca.gov/adam/welcome.html; 

EPA AIRData website (http://www.epa.gov/air/data/index.html). 

TABLE 5.1-29 

Maximum Background Concentrationsa

, project area, 2004-2006 (μg/m3) 

Revised June 25, 2009 

Pollutant Averaging Time 2004 2005 2006 

1-hour 186 145 152 NO2 (Camp Pendleton) Annual 23 23 21 

1-hour 110 105 89 

3-hour 52 68 79 

24-hour 24 24 24 

SO2 (San Diego) 

Annual 10 8 10 

1-hour 7210 6753 6524 

CO (Escondido) 8-hour 4361 3548 4136 

24-hour 58 42 52 

PM10 (Escondido) Annual 27 24 24 

24-hourb

 37 32 28 

PM2.5 (Escondido) 

Annual 14.1 12.3 11.5 

Source: California Air Quality Data, California Air Resources Board website; EPA AIRData website. Reported 

values have been rounded to the nearest tenth of a μg/m3

 except for PM10 which were already rounded to the 

nearest integer. 

Notes: 

a. With the exception of 24-hr PM2.5, bolded values are the highest during the three years and are used to 

represent background concentrations. 

b. 24-hour average PM2.5 concentrations shown are 98th percentile values rather than highest values because 

compliance with the ambient air quality standards is based on 98th percentile readings. Since the ambient 

standard is based on a 3-year average of the 98th percentile readings, the 3-year average of the 2004 to 2006 

98th percentile readings was used to represent the background concentration. 
APPENDIX B 

APPROVAL OF HEALTH RISK ASSESSMENT 
Rule 1200 Health Risk Assessment Report 

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 Assessment (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 the associated methodological appendices for the 

revised Technical Support Document (TSD) for the updates. Subsequently, on December 19, 

2008, OEHHA formally adopted the revised Air Toxics 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

SOURCES & OPERATIONS REVIEWED

Rule 1200 requires the HRA address the increases in potential to emit (PTE) associated with any 

new or modified emission units. The only emission 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 oF, 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. 

WORST-CASE POTENTIAL HEALTH IMPACTS

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 1.0 
Rule 1200 Health Risk Assessment Report 

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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 specified 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. 

CONCLUSION

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 control 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 

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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/m3

) 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 

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 OEHHA Air Toxics Hot Spots Program Guidance Manual for Preparation of Health Risk 

Assessments, August 2003. 

 OEHHA Air Toxics Hot Spots Program Technical 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/m3) 

 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 manufacturer1. The load was 

 

1

John Xia and Rick Antos, SGT6-5000F (W501F), 3 Million Hours Fleet Operational Experience, POWER-GEN 

International 2006, Orlando, FL, November 28-30, 2006. 
Rule 1200 Health Risk Assessment Report 

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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 

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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 phased 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. The 
Rule 1200 Health Risk Assessment Report 

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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% O2

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 the 
Rule 1200 Health Risk Assessment Report 

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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 

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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 41.01 
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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 CONDITIONS 
FDOC Conditions Page 1 of 18 July 30, 2009 

Applications No. 985745, 985747, and 985748

CECP PERMIT CONDITIONS

GENERAL CONDITIONS

1. This equipment shall be properly maintained and kept in good operating condition at all times, and, to 

the extent practicable, 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 issued and District Application Nos. 985745, 985747, and 

985748. [Rule 14] 

3. The applicant shall provide access, facilities, utilities, and any necessary safety equipment, with the 

exception of personal protective equipment requiring individual fitting and specialized training, for 

source testing and inspection upon request of the Air Pollution Control District. [Rule 19] 

4. The applicant shall obtain any necessary District permits for all ancillary combustion equipment 

including emergency engines, prior to on-site delivery of the equipment. [Rule 10] 

5. 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 (ERCs) 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 combustion 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 series of successive consecutive 12-calendar-month 

periods. The initial 12-month-calendar period of such a series shall begin on the first day of the month 

in which the applicable beginning date for that series 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 Program, the applicant shall submit an 

application for a Title IV Operating Permit at least 24 months prior to the initial startup of the 

combustion turbines. [40 CFR Part 72] 

8. The applicant shall comply with all applicable provisions of 40 CFR Part 73, including requirements to 

offset, hold and retire sulfur dioxide (SO2) allowances. [40 CFR Part 73] 

9. All records required by this permit shall be maintained on site for a minimum of five years and made 

available to the District upon request. [Rule 1421] 

COMBUSTION TURBINE CONDITIONS

Definitions

10. For purposes of determining compliance with the emission limits of this permit, a shutdown period is the 

period of time that begins with the lowering of the gross electrical output (load) of the combustion 
FDOC 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 consecutive minutes. [Rule 20.3(d)(1)] 

11. A startup period is the period of time that begins when fuel flows to the combustion turbine following a 

non-operational period. For purposes of determining compliance with the emission limits of this permit, 

the duration of a startup period shall not exceed 60 consecutive minutes. [Rule 20.3(d)(1)] 

12. A non-operational period is any five-consecutive-minute period when fuel does not flow to the 

combustion turbine. [Rule 20.3(d)(1)] 

13. Tuning is defined as adjustments to the combustion or emission control system that involves operating 

the combustion turbine or emission control system in a manner such that the emissions control 

equipment may not be fully effective or operational. Only one gas turbine shall be tuned at any given 

time. Tuning events shall not exceed 720 unit operating 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 total unit operating minutes of tuning during the calendar year divided by 

60. [Rule 20.3(d)(1)] 

14. A Continuous Emission Monitoring System (CEMS) protocol is a document approved in writing by the 

District that describes the methodology and quality assurance and quality control procedures for 

monitoring, calculating, and recording stack emissions from the combustion turbine that is monitored by 

the CEMS. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 

75] 

15. A transient hour is a clock hour during which the change in gross electrical output produced by the 

combustion turbine exceeds 50 MW per minute for one minute or longer during any period that is not 

part of a startup or shutdown period. [Rule 20.3(d)(1)] 

16. For each combustion turbine, the commissioning period is the period of time commencing with the 

initial startup of that turbine and ending the sooner of 120 calendar days from the initial startup, after 

415 hours of turbine operation, or the date the pemittee notifies the District the commissioning period 

has ended. For purposes of this condition, the number of hours of turbine operation is defined as the 

total unit operating minutes during the commissioning period divided 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 and ending the sooner of 180 calendar days from the initial startup or the date the 

permittee notifies the District that the shakedown period has ended. [Rules 20.1(c)(16) and 21] 

18. Turbine A is the combustion turbine as described on Applications No. 985745 or No. 985747, as 

applicable, that first completes its shakedown period. If both turbines complete their shakedown period 

on the same date, then Turbine A is the turbine described on Application No. 985745. [Rules 

20.1(c)(16) and 21] 

19. Turbine B is the combustion turbine as described on Applications No. 985745 or No. 985747, as 

applicable, that last completes its shakedown period. If both turbines complete their shakedown period 

on the same date, then Turbine B is the turbine 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 that fuel is continuously combusted during the 

entire period and one or more clock-hour concentration emission limits specified in this permit are 

exceeded as a result of the low-load operation. For 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 height above site base 

elevation. [Rules 20.3(d)(2) and 1200] 

23. The combustion turbines shall be fired on Public Utility Commission (PUC) quality natural gas. The 

permitee shall maintain, on site, quarterly records of the natural gas sulfur content (grains of sulfur 

compounds per 100 dscf of natural gas) and hourly records of the higher and lower heating values 

(btu/scf) of the natural gas; and provide records to District personnel upon request. [Rule 20.3(d)(1)] 

24. Unless otherwise specified in this permit, all continuous monitoring data shall be collected at least once 

every minute. [Rules 69.3, 69.3.1, and 20.3(d)(1)] 

Emission Limits

25. For purposes of determining compliance with emission limits based on source testing, the average of 

three subtests shall be used. For purposes of determining compliance with emission limits based on a 

Continuous Emission Monitoring System (CEMS), data collected in accordance with the CEMS 

protocol shall be used and the averages for averaging periods specified herein shall be calculated as 

specified in the CEMS protocol. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart 

KKKK, and 40 CFR Part 75] 

26. For purposes of determining compliance with emission limits based on CEMS data, all CEMS 

calculations, averages, and aggregates shall be performed in accordance with the CEMS protocol 

approved in writing by the District. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart 

KKKK, and 40 CFR Part 75] 
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 compliance period, compliance shall be based on using data collected at least 

once every minute when compliance is based on CEMS data. [Rules 69.3, 69.3.1, and 20.3(d)(1)] 

28. When a combustion turbine is combusting fuel (operating), the emission concentration of oxides of 

nitrogen (NOx), calculated as nitrogen dioxide (NO2), shall not exceed 2.0 parts per million by volume 

on a dry basis (ppmvd) corrected to 15% oxygen, except during commissioning, low load operation, 

startup, shutdown, or tuning periods for that turbine. For purposes of determining compliance based on 

CEMS data, the following averaging periods calculated in accordance with the CEMS protocol shall 

apply: 

a. For any transient hour, a 3-clock-hour average, calculated as the average of the transient hour, 

the clock hour immediately prior to the transient hour and the clock hour immediately 

following the transient hour. 

b. For all other hours, a 1-clock-hour average. 

[Rule 20.3(d)(1)] 

29. When a combustion turbine is operating, the emission concentration of carbon monoxide (CO) shall not 

exceed 2.0 ppmvd corrected to 15 % oxygen, except during commissioning, low load operation, startup, 

shutdown, or tuning periods for that turbine. For purposes of determining compliance based on CEMS 

data, the following averaging periods calculated in accordance with the CEMS protocol shall apply: 

a. For any transient hour, a 3-clock-hour average, calculated as the average of the transient hour, 

the clock hour immediately prior to the transient hour and the clock hour immediately 

following the transient hour. 

b. For all other hours, a 1-clock-hour average. 

[Rule 20.3(d)(1)] 

30. When a combustion turbine is operating, the volatile organic compound (VOC) concentration, calculated 

as methane, measured in the exhaust stack, shall not exceed 1.5 ppmvd corrected to 15% oxygen, except 

during commissioning, low load operation, startup, shutdown, or tuning periods for that turbine. For 

purposes of determining compliance based on the CEMS, the District approved CO/VOC surrogate 

relationship, the CO CEMS data, and the following averaging periods calculated in accordance with the 

CEMS protocol shall be used: 

a. For any transient hour, a 3-clock-hour average, calculated as the average of the transient hour, 

the clock hour immediately prior to the transient hour and the clock hour immediately 

following the transient hour. 

b. For all other hours, a 1-clock-hour average. 

The CO/VOC surrogate relationship shall be verified and/or modified, if necessary, based on source 

testing. [Rule 20.3(d)(1)] 

31. When a combustion turbine is operating, the ammonia concentration (ammonia slip), shall not exceed 

5.0 ppmvd corrected to 15 % oxygen, except during commissioning, low load operation, startup, 

shutdown, or tuning periods for that turbine. [Rule 1200] 
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 (NO2), shall not exceed 12.9 ppmvd calculated over each clock-hour period and corrected to 

15% oxygen, except for periods of startup and shutdown, as defined in Rule 69.3.1. This limit does not 

apply during any period in which the facility is subject to a variance from the emission limits contained 

in Rule 69.3.1. [Rule 69.3.1] 

33. When a combustion turbine is operating without any post-combustion air pollution control equipment 

that controls oxides of nitrogen (NOx) emissions, the emission concentration of NOx calculated as 

nitrogen dioxide (NO2) from each turbine shall not exceed 21.6 parts per million by volume on a dry 

basis (ppmvd) calculated over each clock-hour period and corrected to 15% oxygen, except for periods 

of startup and shutdown, as defined in Rule 69.3.1. This limit does not apply during any period in which 

the facility is subject to a variance from the emission limits contained in Rule 69.3.1. [Rule 69.3.1] 

34. When a combustion turbine is operating, the emission concentration of oxides of nitrogen (NOx), 

calculated as nitrogen dioxide (NO2) shall not exceed 42 ppmvd calculated over each clock-hour period 

and corrected to 15% oxygen, on a dry basis, except during periods of startup and shutdown, as defined 

in Rule 69.3. This limit does not apply during any period in which the facility is subject to a variance 

from the emission limits contained in Rule 69.3. [Rule 69.3] 

35. For each rolling 30-day-unit-operating-day period, average emission concentration of oxides of nitrogen 

(NOx) for each turbine calculated as nitrogen dioxide (NO2) in parts per million by volume dry (ppmvd) 

corrected to 15% oxygen or, alternatively, as elected by the permittee, the average NOx emission rate in 

pounds per megawatt-hour (lb/MWh) shall not exceed an average emission limit calculated in 

accordance with 40 CFR Section 60.4380(b)(3). The emission concentration and emission rate averages 

shall be calculated in accordance with 40 CFR Section 60.4380(b)(1). The average emission 

concentration limit and emission rate limit shall be based on an average of hourly emission limits over 

the 30-day-unit-operating-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, respectively. The averages shall exclude all clock hours occurring 

before the Initial Emission Source Test but shall include emissions during all other times that the 

equipment is operating including, but not limited to, emissions during low load operation, startup, 

shutdown, and tuning periods. For each six-calendar-month period, emissions in excess of these limits 

and monitor downtime shall be identified in accordance with 40 CFR Sections 60.4350 and 

60.4380(b)(2), except that Section 60.4350(c) shall not apply for identifying periods in excess of a NOx 

concentration limit, and reported to the District and the federal EPA in accordance with Title V 

Operating Permit No. 974488. [40 CFR Part 60 Subpart KKKK] 

36. The emissions of particulate matter less than or equal to 10 microns in diameter (PM10)shall not exceed 

9.5 pounds per hour for each combustion turbine. [Rule 20.3(d)(2)] 

37. The discharge of particulate matter from the exhaust stack of each combustion turbine shall not exceed 

0.10 grains per dry standard cubic foot (0.23 grams/dscm). The District may require periodic testing to 

verify compliance with this standard. [Rule 53] 

38. Visible emissions from the lube oil vents and the exhaust stack of each combustion turbine shall not 

exceed 20% opacity for more than three (3) minutes in any period of 60 consecutive minutes. [Rule50] 
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 NO2; carbon 

monoxide (CO); and volatile organic compounds (VOC), calculated as methane, shall not exceed the 

following limits, except during commissioning, low load operation, startup, shutdown, 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 NO2; 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 period, except during that turbine’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 NO2; 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 any 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 combustion turbines combined shall not exceed 286 

pounds per hour, calculated as nitrogen dioxide and measured over each 1-clock-hour period. These 

emission limits shall apply during all times one or both turbines are operating, including, but not limited 

to, emissions during commissioning, low load operation, startup, shutdown, and tuning periods. [Rule 

20.3(d)(2)] 

43. The carbon monoxide (CO) emissions from each combustion turbine shall not exceed 3813 pounds per 

hour and total aggregate CO emissions from both combustion turbines combined shall not exceed 4627 

pounds per hour measured over each 1-clock-hour period. This emission limit shall apply during all 
FDOC Conditions Page 7 of 18 July 30, 2009 

Applications No. 985745, 985747, and 985748

times that one or both turbines are operating, including, but not limited to emissions during 

commissioning, low load operation, startup, shutdown, and tuning periods. [Rule 20.3(d)(2)(i)] 

44. Beginning with the earlier of the initial startup dates for either combustion turbine, aggregate emissions 

of oxides of nitrogen (NOx), calculated as nitrogen dioxide (NO2); carbon monoxide (CO); volatile 

organic compounds (VOCs), calculated as methane; particulate matter less than or equal to 10 microns 

in diameter (PM10); and oxides of sulfur (SOx), calculated as sulfur dioxide (SO2), from the 

combustion turbines described in District Applications No. 985745 and 985747 and the emergency fire 

pump described in Application No. 985748, except emissions or emission units excluded from the 

calculation of aggregate potential to emit as specified in Rule 20.1 (d) (1), shall not exceed the following 

limits for each rolling 12-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 turbines have completed their commissioning periods 

aggregate emissions of CO and VOC from the equipment 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. [Rules 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 calendar month of NOx (calculated as NO2), CO, VOCs 

(calculated as methane), PM10, and SOx (calculated as SO2), in tons, from each emission unit described 

in District Applications No. 985745, 985747, and 985748, except for emissions or emission units 

excluded from the calculation of aggregate potential to emit as specified in Rule 20.1 (d) (1). These 

records shall be made available for inspection within 15 calendar days after the end of each calendar 

month. [Rules 20.3(d)(3), 20.3(d)(8) and 21] 

46. For each calendar month and each rolling 12-calendar-month period, the applicant shall maintain 

records, as applicable, on a calendar monthly basis, of aggregate mass emissions of NOx (calculated as 

NO2), CO, VOCs (calculated as methane), PM10, and SOx (calculated as SO2) in tons for the emission 

units described in District Applications No. 985745, 985747, and 985748, except for emissions or 

emission units excluded from the calculation of aggregate potential to emit as specified in Rule 20.1 (d) 

(1). These records shall be made available for inspection within 15 calendar days after the end of each 

calendar month. [Rules 20.3(d)(3), 20.3(d)(8) and 21] 

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 construction, the applicant shall submit to the District 

the final selection, design parameters and details of the selective catalytic reduction (SCR) and oxidation 

catalyst emission control systems for the combustion turbines including, but not limited to, the minimum 

ammonia injection temperature for the SCR; the catalyst volume, space velocity and area velocity at full 

load with and without steam injection; 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 Rules 175 and 176. [Rules 20.3(d)(1) and 14] 

49. When a combustion turbine is operating, ammonia shall be injected at all times that the associated 

selective catalytic reduction (SCR) system outlet temperature is 450 degrees Fahrenheit or greater. 

[Rules 20.3(d)(1)] 

50. Continuous monitors shall be installed on each SCR system prior to their initial operation to monitor or 

calculate, and record the ammonia solution injection rate in pounds per hour and the SCR outlet 

temperature in degrees Fahrenheit for each unit operating minute. The monitors shall be installed, 

calibrated and maintained in accordance with a District approved protocol, which may be part of the 

CEMS protocol. This protocol, which shall include the calculation methodology, shall be submitted to 

the District for written approval at least 90 days prior to initial startup of the gas turbines with the SCR 

system. The monitors shall be in full operation at all times when the turbine is in operation. [Rules 

20.3(d)(1)] 

51. Except during periods when the ammonia injection system is being tuned or one or more ammonia 

injection systems is in manual control for compliance with applicable permit conditions, the automatic 

ammonia injection system serving the SCR system shall be in operation in accordance with 

manufacturer's specifications at all times when ammonia is being injected into the SCR system. 

Manufacturer specifications shall be maintained on site and made available to District personnel upon 

request. [Rules 20.3(d)(1)]

52. The concentration of ammonia solution used in the ammonia injection system. Shall be less than 20% 

ammonia by weight. Records of ammonia solution concentration shall be maintained on site and made 

available to District personnel upon request. [Rule 14] 

Testing

53. All source test or other tests required by this permit shall be performed by the District or an independent 

contractor approved by the District. Unless otherwise specified in this permit or authorized in writing 

by the District, if testing will be performed by an independent contractor and witnessed by the District, a 

proposed test protocol shall be submitted to the District for written approval at least 60 days prior to 

source testing. Additionally, the District shall be notified a minimum of 30 days prior to the test so that 

observers may be present unless otherwise authorized in writing by the District. [Rules 20.3(d)(1) and 

1200 and 40 CFR Part 60 Subpart KKKK and 40 CFR §60.8] 

54. Unless otherwise specified in this permit or authorized in writing by the District, within 45 days after 

completion of a source test or RATA performed by an independent contractor, a final test report shall be 

submitted to the District for review and approval. [Rules 20.3(d)(1) and 1200 and 40 CFR Part 60 

Subpart KKKK, 40 CFR §60.8, and 40 CFR Part 75] 
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 platforms shall be constructed in accordance with District Method 3A, Figure 

2, and approved by the District. Ninety days prior to construction of the turbine stacks the project owner 

shall provide to the District for written approval detailed plan drawings of the turbine stacks that show 

the sampling ports and demonstrate compliance with the requirements of this condition. [Rule 20] 

56. Not later than 60 calendar days after completion of the commissioning period for each combustion 

turbine, an Initial Emissions Source Test shall be conducted on that turbine to demonstrate compliance 

with the NOX, CO, VOC, PM10, and ammonia emission standards of this permit. The source test 

protocol shall comply with all of the following requirements: 

a. Measurements of NOX and CO concentrations and emissions and oxygen (O2) concentration 

shall be conducted in accordance with U.S. Environmental Protection Agency (EPA) methods 

7E, 10, and 3A, respectively, and District source test Method 100, or alternative methods 

approved by the District and EPA; 

b. Measurement of VOC emissions shall be conducted in accordance with EPA 

Methods 25A and/or 18, or alternative methods approved by the District and EPA; 

c. Measurements of ammonia emissions shall be conducted in accordance with Bay Area Air 

Quality Management District Method ST-1B or an alternative method approved by the District 

and EPA; 

d. Measurements of PM10 emissions shall be conducted in accordance with EPA Methods 201A 

and 202 or alternative methods approved by the District and EPA; 

e. Source testing shall be performed at the normal load level, as specified in 40 CFR Part 75 

Appendix A Section 6.5.2.1 (d), provided it is not less than 80% of the combustion turbine’s 

rated load unless it is demonstrated to the satisfaction of the District that the combustion 

turbine cannot operate under these conditions. If the demonstration is accepted, then emissions 

source testing shall be performed at the highest achievable continuous power level. The 

District may specify additional testing at different load levels or operational conditions to 

ensure compliance with the emission limits of this permit and District Rules and Regulations. 

f. Measurements of particulate matter emissions shall be conducted in accordance with SDAPCD 

Method 5 or an alternative method approved by the District and EPA; and 

g. Measurements of opacity shall be conducted in accordance with EPA Method 9 or an 

alternative method approved by the District and EPA 

h. Unless otherwise authorized in writing by the District, testing for NOX, CO, VOC, PM10, and 

ammonia concentrations and emissions, as applicable, shall be conducted concurrently with the 

NOx and CO continuous emission measurement system (CEMS) Relative Accuracy Test Audit 

(RATA). 

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

57. A renewal source test and a NOX and CO Relative Accuracy Test Audit (RATA) shall be periodically 

conducted on each combustion turbine to demonstrate 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 renewal source test and the NOX and CO RATAs shall 
FDOC Conditions Page 10 of 18 July 30, 2009 

Applications No. 985745, 985747, and 985748

be conducted in accordance with the applicable RATA frequency requirements of 40 CFR75, Appendix 

B, Sections 2.3.1 and 2.3.3. The renewal source test shall be conducted in accordance with a protocol 

complying with all the applicable requirements of the source test protocol for the Initial Emissions 

Source Test. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 

75] 

58. Relative Accuracy Test Audits (RATAs) and all other required certification tests shall be performed and 

completed on the NOx CEMS in accordance with applicable provisions of 40 CFR Part 75 Appendix A 

and B and 40 CFR §60.4405 and on the CO CEMS in accordance 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 commissioning period for each combustion 

turbine, an initial emission source test for toxic air contaminants shall be conducted on that turbine to 

determine the emissions of toxic air contaminants from the combustion turbines. At a minimum the 

following compounds shall be tested for, and emissions, if any, quantified: 

a. Acetaldehyde 

b. Acrolein 

c. Benzene 

d. Formaldehyde 

e. Toluene 

f. Xylenes 

This list of compounds may be adjusted by the District based on source test results to ensure compliance 

with District Rule 1200 is demonstrated. The District may require one or more or additional compounds 

to be quantified through source testing as needed to ensure compliance with Rule 1200. Within 60 

calendar days after completion of a source test performed by an independent contractor, a final test 

report shall be submitted to the District for review and approval. [Rule 1200] 

60. The District may require one or more of the following compounds, or additional compounds, to be 

quantified through source testing periodically to ensure compliance with rule 1200: 

a. Acetaldehyde 

b. Acrolein 

c. Benzene 

d. Formaldehyde 

e. Toluene 

f. Xylenes 

If the District requires the permittee to perform this source testing, the District shall request the testing in 

writing a reasonable period of time prior to the testing date. [Rule 1200] 

 
FDOC Conditions Page 11 of 18 July 30, 2009 

Applications No. 985745, 985747, and 985748

61. The higher heating value of the combustion turbine fuel shall be measured by ASTM D1826–94, 

Standard Test Method for Calorific Value of Gases in Natural Gas Range by Continuous Recording 

Calorimeter or ASTM D1945–96, Standard Method for Analysis of Natural Gas by Gas 

Chromatography or an alternative test method approved by the District and EPA. [Rules 69.3, 69.3.1, 

and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

62. The sulfur content of the combustion turbine fuel shall be sampled 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 Method for Determination of Sulfur Compounds in Natural Gas and 

Gaseous Fuels by Gas Chromatography and Flame Photometric Detection; or ASTM D6667–04, 

Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and 

Liquefied Petroleum Gases by Ultraviolet Fluorescence or an alternative test method approved by the 

District and EPA. [Rule 20.3(d)(1), 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) shall be installed on each combustion turbine and 

properly maintained and calibrated to measure, calculate, and record the following, in accordance with 

the District approved CEMS protocol: 

a. Hourly average(s) concentration of oxides of nitrogen (NOX) uncorrected and corrected to 

15% oxygen, in parts per million (ppmvd), necessary to demonstrate compliance with the NOx 

limits of this permit; 

b. Hourly average concentration of carbon monoxide (CO) uncorrected and corrected to 15% 

oxygen, in parts per million (ppmvd), necessary to demonstrate compliance with the CO limits 

of this permit; 

c. Percent oxygen (O2) in the exhaust gas 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 nitrogen (NOX) in each startup and shutdown period, 

in pounds; 

g. Daily mass emissions of oxides of nitrogen (NOX), in pounds; 

h. Calendar monthly mass emissions of oxides of nitrogen (NOX), in pounds; 

i. Rolling 30-unit-operating-day average concentration of oxides of nitrogen (NOX) corrected to 

15% oxygen, in parts per million (ppmvd); 

j. Rolling 30-unit-operating-day average oxides of nitrogen (NOx) emission rate, in pounds per 

megawatt-hour (MWh); 

k. Calendar quarter, calendar year, and rolling 12-calendar-month 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 (CO) in each startup and shutdown period, in 

pounds; 

m. Hourly mass emissions of carbon monoxide (CO), in pounds; 

n. Daily mass emission of carbon monoxide (CO), in pounds; 

o. Calendar monthly mass emission of carbon monoxide (CO), in pounds; 

p. Rolling 12-calendar-month period mass emission of carbon monoxide (CO), in tons; 

q. Average concentration of oxides of nitrogen (NOX) and carbon monoxide (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 Part 60 Subpart KKKK, and 40 CFR Part 75] 

65. No later than 90 calendar days prior to initial startup of each combustion turbine, the applicant shall 

submit a CEMS protocol to the District, for written approval that shows how the CEMS will be able to 

meet all District monitoring requirements. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 

Subpart KKKK, and 40 CFR Part 75] 

66. No later than the earlier of 90 unit operating days or 180 calendar days after each combustion turbine 

commences commercial operation, a Relative Accuracy Test Audit (RATA) and other required 

certification tests shall be performed 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. Additionally, the District and U.S. EPA shall be notified a 

minimum of 45 calendar days prior to the test so that observers may be present. Within 45 calendar 

days of completion of this test, a written test report shall be submitted to the District for approval. For 

purposes of this condition, commences commercial operation 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 Relative Accuracy Test Audit (RATA), as required in 40 

CFR 75.62. [40 CFR Part 75] 

68. The oxides of nitrogen (NOX) and oxygen (O2) components of the CEMS shall be certified and 

maintained in accordance with applicable Federal Regulations including the requirements of sections 

75.10 and 75.12 of title 40, Code of Federal Regulations Part 75 (40 CFR 75), the performance 

specifications of appendix A of 40 CFR 75, the quality assurance procedures of Appendix B of 40 CFR 

75 and the CEMS protocol approved by the District. The carbon monoxide (CO) components of the 

CEMS shall be certified and maintained in accordance with 40 CFR 60, Appendices B and F, unless 

otherwise specified in this permit, and the CEMS protocol approved by the District. [Rules 69.3, 69.3.1, 

and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

69. The CEMS shall be in operation in accordance with the District approved CEMs protocol at all times 

when the turbine is in operation a copy of the District approved CEMS monitoring protocol shall be 

maintained on site and made available to District personnel upon request. [Rules 69.3, 69.3.1, and 

20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 
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 combustion turbine is operating, hourly NOx emissions 

for purposes of calendar year and 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, recorded CEMS data, and fuel consumption data, in terms 

of pounds per hour of CO for the gas turbine. Emission calculations used to determine hourly emission 

rates shall be reviewed and approved by the District, in writing, before the hourly emission rates are 

incorporated into the CEMS emission data. [Rules 20.3(d)(3) and 21 and 40 CFR Part 75] 

71. Any violation of any emission standard as indicated by the CEMS shall be reported to the District's 

compliance division within 96 hours after such occurrence. [Rule 19.2] 

72. The CEMS shall be maintained and operated, and reports submitted, in accordance with the 

requirements of rule 19.2 Sections (d), (e), (f) (1), (f) (2), (f) (3), (f) (4) and (f) (5), and a CEMS protocol 

approved by the District. [Rule 19.2] 

73. Except for changes that are specified in the initial approved CEMS protocol or a subsequent revision to 

that protocol that is approved in advance, in writing, by the District, the District shall be notified in 

writing at least thirty (30) calendar days prior to any planned changes made in the CEMS or Data 

Acquisition and Handling System (DAHS), including, but not limited to, the programmable logic 

controller, software which affects the value of data displayed on the CEMS / DAHS monitors with 

respect to the parameters measured by their respective sensing devices or any planned changes to the 

software that controls the ammonia flow to the SCR. Unplanned or emergency changes shall be 

reported within 96 hours. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 

40 CFR Part 75] 

74. At least 90 calendar days prior to the Initial Emissions Source Test , the applicant shall submit a 

monitoring protocol to the District for written approval which shall specify a method of determining the 

CO/VOC surrogate relationship that shall be used to demonstrate compliance with all VOC emission 

limits. This protocol can be provided as part of the Initial Source 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 turbine. Correction factors and constants shall be 

maintained on site and made available to the District upon request. The fuel flowmeters shall meet the 

applicable quality assurance requirements of 40 CFR Part 75, Appendix D, and Section 2.1.6. [Rules 

69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

76. Each combustion turbine shall be equipped with continuous monitors to measure, calculate, and record 

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 based the fuels higher heating 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 operating minute in megawatts hours (MWh). 

The values of these operational characteristics shall 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 for the continuous monitors shall be maintained 

on site and made available to the District upon request. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR 

Part 60 Subpart KKKK, and 40 CFR Part 75] 

77. At least 90 calendar days prior to initial startup of the each combustion turbine, the applicant shall 

submit a turbine monitoring protocol to the District for written approval. This may be part of the CEMS 

protocol. [Rules 69.3, 69.3.1, and 20.3(d)(1) and 40 CFR Part 60 Subpart KKKK, and 40 CFR Part 75] 

78. Operating logs or Data Acquisition and Handling System (DAHS) records shall be maintained to record 

the beginning and end times and durations of all startups, shutdowns, and tuning periods to the nearest 

minute, quantity of fuel used in each clock hour, calendar month, and 12-calendar-month period in 

standard cubic feet; hours of operation each day; and 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 divided 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 combustion turbine, the applicant shall install postcombustion air pollution control equipment on that turbine to minimize NOx and CO emissions. Once 

installed, the post-combustion air pollution control equipment shall be maintained in good condition and 

shall be in full operation at all times when the turbine is combusting fuel and the air pollution control 

equipment is at or above its minimum operating temperature. [Rule 20.3(d)(1)] 

80. Thirty calendar days after the end of the commissioning period for each combustion turbine, the 

applicant shall submit a written progress report to the District. This report shall include, a minimum, the 

date the commissioning period ended, the periods of startup and shutdown, the emissions of NOx and 

CO during startup and shutdown, and the emissions of NOx and CO during steady state operation. This 

report shall also detail any turbine or emission control equipment malfunction, upset, repairs, 

maintenance, modifications, or replacements affecting emissions of air contaminants that occurred 

during the commissioning period. All of the following continuous monitoring information shall be 

reported for each minute and, except for cumulative mass emissions, averaged over each hour of 

operation: 

a.Concentration of oxides of nitrogen (NOX) uncorrected and corrected to 15% oxygen, in parts 

per million (ppmvd); 

b.Concentration of carbon monoxide (CO) uncorrected and corrected to 15% oxygen, in parts per 

million (ppmvd); 

c.Percent oxygen (O2) in the exhaust gas; 

d.Mass emissions of oxides of nitrogen (NOX), in pounds; 
FDOC Conditions Page 15 of 18 July 30, 2009 

Applications No. 985745, 985747, and 985748

e.Cumulative mass emissions of oxides of nitrogen (NOX) in each startup and shutdown period, 

in pounds; 

f. Cumulative mass emissions of carbon monoxide (CO) in each startup and shutdown period, in 

pounds 

g.Mass emissions of carbon monoxide (CO), in pounds; 

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 electronic format approved by 

the District. The minute-by-minute information shall be submitted in an electronic format approved by 

the District. [Rules 69.3, 69.3.1, 20.3(d)(1)and 20.3(d)(2)] 

81. The three utility boilers described on District Permits to Operate No. 791, 792, and 793 shall not operate 

at any time one or both combustion turbines are operating. [Rules 20.3(d)(3), 20.3(d)(8) and 21] 

82. Beginning with the initial startup of Turbine A, aggregate emissions of oxides of nitrogen (NOx), 

calculated as nitrogen dioxide (NO2); carbon monoxide (CO); volatile organic compounds (VOCs), 

calculated as methane; particulate matter less than or equal to 10 microns in diameter (PM10); and 

oxides of sulfur (SOx), calculated as sulfur dioxide (SO2), from Turbine A and the emergency fire 

pump described in Application No. 985748, except emissions or emission units excluded from the 

calculation of aggregate potential to emit as specified in Rule 20.1 (d) (1), shall not exceed the following 

limits for each rolling 12-calendar-month period: 

 Pollutant Emission Limit, tons per year

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, aggregate 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, shall not exceed the following limits for each rolling 

12-calendar-month period: 

 Pollutant Emission Limit, tons per year

a. CO 198.75 
FDOC 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 during 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 shall not operate. [Rules 20.3(d)(3), 20.3(d)(8) 

and] 

85. For each calendar month and each rolling 12-calendar-month period, the applicant shall maintain records 

on a calendar monthly basis, of aggregate mass emissions of NOx (calculated as NO2), CO, and PM10, 

in tons, for Turbine A and the emergency generator described on Application No. 985748, except for 

emissions or emission units excluded from the calculation of aggregate potential to emit as specified in 

Rule 20.1 (d) (1). These records shall be made available for inspection within 15 calendar days after the 

end of each calendar month. [Rules 20.3(d)(3), 20.3(d)(8) and 21] 

86. For each calendar month, the applicant shall maintain records on a calendar monthly basis, of mass 

emissions during each calendar month of NOx (calculated as NO2), CO, PM10, and PM2.5, in tons, 

from each emission unit described on District Permits to Operate No. 791, 792, and 793. These records 

shall be made available for inspection within 15 calendar days after the end of each calendar month. 

[Rules 20.3(d)(3), 20.3(d)(8) and 21] 

87. For each calendar month and each rolling 12-calendar-month period, the applicant shall maintain records 

on a calendar monthly basis, of aggregate mass emissions of NOx (calculated as NO2), CO, PM10, and 

PM2.5, in tons, for the emission units described in District Permits to Operate No. 791, 792, and 793. 

These records shall be made available for inspection within 15 calendar days after the end of each 

calendar month. [Rules 20.3(d)(3), 20.3(d)(8) and 21] 

88. No later than 18 months before the initial startup of either combustion turbine, the applicant shall 

submit an application to the District for a significant Title V permit modification to limit the aggregate 

emissions of oxides of nitrogen (NOx), calculated as nitrogen dioxide; carbon monoxide (CO); 

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

or equal to 2.5 microns in diameter (PM2.5), from the three utility boilers described on District Permits 

to Operate No. 791, 792, and 793 in each rolling 12-calendar-month period as specified in this permit. 

The application shall include a proposed emission calculation protocol to calculate the emissions from 

each emission unit. Where applicable, this protocol may rely in whole or in part on the CEMS or other 

monitoring protocols required by this permit. [Rules 20.3(d)(3), 20.3(d)(8), 1410, and 21] 

89. For each combustion turbine, the applicant shall submit the following notifications to the District and U. 

S. EPA, Region IX: 

a. A notification in accordance with 40 CFR Section 60.7(a)(1) delivered or postmarked not later 

than 30 calendar days after construction has commenced; 

b. A notification in accordance with 40 CFR Section 60.7(a)(3) delivered or postmarked within 

15 calendar days after initial startup; and 

c. An Initial Notification in accordance with 40 CFR Section 63.6145(c) and 40 CFR Section 

63.9(b)(2) submitted no later than 120 calendar days after the initial startup of the turbine. 
FDOC Conditions Page 17 of 18 July 30, 2009 

Applications No. 985745, 985747, and 985748

In addition, the applicant shall notify the District when: (1) construction is complete by submitting a 

Construction Completion Notice before operating any unit 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 this event. [Rules 24 and 21 and 40 CFR Part 75, 40 

CFR Part 60 Subpart KKKK, 40 CFR Part §60.7, 40 CFR Part 63 Subpart YYYY, and 40 CFR Part 

§63.9] 

CONDITIONS FOR EMERGENCY FIRE PUMP ENGINE

90. The engine shall be EPA certified to the 2009 model year or later requirements for emergency fire pump 

engines of 40 CFR Part 60 Subpart IIII, Standards of Performance for Stationary Compression Ignition 

Internal Combustion Engines. [Rule 20.3(d)(1), 40 CFR Part 60 Subpart IIII, and 40 CFR Part 63 

Subpart ZZZZ] 

91. Engine operation for maintenance and testing purposes shall not exceed 50 hours per calendar year. 

(ATCM reportable) [Rule 20.3(d)(1) and 17 CCR §93115] 

92. The engine shall only use CARB Diesel Fuel. [Rules 20.3(d)(1), 69.4.1, and 17 CCR §93115] 

93. Visible emissions including crankcase smoke shall comply with Air Pollution Control District Rule 50. 

[Rule 50] 

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

95. This engine shall not operate for non-emergency use during the following periods, as applicable: 

A. Whenever there is any school sponsored activity, if engine is located on school grounds or 

B. Between 7:30 and 3:30 PM on days when school is in session, if the engine is located within 500 

feet of, but not on school grounds. 

This condition shall not apply to an engine located at or near any school grounds that also serve as the 

student’s place of residence. (ATCM reportable) [17 CCR §93115] 

96. A non-resettable engine hour meter shall be installed on this engine, maintained in good working order, 

and used for recording engine operating hours. If a meter is replaced, the Air Pollution Control 

District’s Compliance Division shall be notified in writing within 10 calendar days. The written 

notification shall include the following information: 

A. Old meter’s hour reading. 

B. Replacement meter’s manufacturer name, model, and serial number if available and current hour 

reading on replacement meter. 

C. Copy of receipt of new meter or of installation work order. 

 A copy of the meter replacement notification shall be maintained on site and made available to the Air 

Pollution Control District upon request. [Rule 69.4.1, 17 CCR §93115, and 40 CFR Part 60 Subpart IIII] 
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 engine and add-on control equipment, 

if any, as recommended by the engine and control equipment manufacturers or as specified by the 

engine servicing company’s maintenance procedure. The periodic maintenance shall be conducted at 

least once each calendar year. [Rule 69.4.1] 

98. The owner or operator of the engine shall maintain the following records on site for at least the same 

period of time as the engine to which the records apply is located at the site: 

 A. Documentation shall be maintained identifying the fuel as CARB diesel; 

 B. Manual of recommended maintenance provided by the manufacturer, or maintenance procedures 

specified by the engine servicing company; and 

 C. Records of annual engine maintenance, including the date the maintenance was performed. 

These records shall be made available to the Air Pollution Control District upon request. [Rule 69.4.1] 

99. The owner or operator of this equipment shall maintain a monthly operating log containing, at a 

minimum, the following: 

 

A. Dates and times of engine operation, indicating whether the operation was for maintenance and 

testing purposes or emergency use; and, the nature of the emergency, if known; 

B. Hours of operation for all uses other than those specified above and identification of the nature of 

that use. 

 

 [Rule 69.4.1 and 17 CCR §93115] 

ADDITIONAL TITLE V CONDITIONS

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 manner or form approved in writing by the District, within 

one year of completing construction of that equipment, that includes the 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 equipment was in continuous or intermittent compliance 

during the certification period, identification of the applicable permitted method used to determine 

compliance during the certification period, and any other information required by the District to 

determine the compliance status. [Rule 1421] 
APPENDIX D 

EMISSION REDUCTION CREDITS 
Summary of Emission Reduction Credits (ERCs) Proposed as Offsets 

ERC Certificate No. 

Original 

Issue Date 

Type Pollutant ERC 

Amount, 

tons per 

year 

NOx 

Equivalent 

Amount, tons 

per year 

Location of Emission 

Reductions 

Desc

Emi

Redu

978938-05 6/30/2004 Class A NOx 35.3 35.3 Naval Air Station—North 

Island; Foot of Neville 

Road, Naval Training 

Center, San Diego; Vesta 

Street & Ward Road 

Naval Station San Diego 

Perm

shutd

pea

comb

turb

981518-01 8/01/2006 Class A NOx 2.3 2.3 3200 Harbor Drive, San 

Diego 

Perm

shutd

pea

comb

turb

070823-02 11/19/99 Class A VOCs 5.3 2.65 850 Lagoon Drive, Chula 

Vista 

Shutd

Va

Degrea

Cold 

Cle

080212-01 9/22/2006 Class A VOCs 18.7 9.35 7757 Andrews Avenue, 

San Diego 

Shutdo

rest

opera

wood 

and ad

appli

oper