U.S. ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

FACT SHEET AND 

AMBIENT AIR QUALITY IMPACT REPORT 

For a Clean Air Act 

Prevention of Significant Deterioration Permit 

Pio Pico Energy Center 

PSD Permit Number SD 11-01 

June 2012 
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i 

PROPOSED PREVENTION OF 

SIGNIFICANT DETERIORATION PERMIT 

PIO PICO ENERGY CENTER 

Fact Sheet and Ambient Air Quality Impact Report 

(PSD Permit SD 11-01) 

Table of Contents 

Acronyms & Abbreviations ...........................................................................................................iii

Executive Summary ........................................................................................................................ 1

1. Purpose of this Document ......................................................................................................... 1

2. Applicant ................................................................................................................................... 1

3. Project Location ........................................................................................................................ 2

4. Project Description.................................................................................................................... 2

5. Emissions from the Proposed Project ....................................................................................... 4

6. Applicability of the Prevention of Significant Deterioration Regulations................................ 6

7. Best Available Control Technology.......................................................................................... 7

7.1 BACT for Natural Gas Combustion Turbine Generators.................................................... 9

7.1.1 Nitrogen Oxide Emissions .................................................................................... 10

Note: All facilities listed in the table are located in California......................................... 13

7.1.2 PM, PM10 and PM2.5 Emissions............................................................................. 13

7.1.3 GHG Emissions..................................................................................................... 15

7.1.4 BACT During Startup and Shutdown ................................................................... 22

7.2 BACT for Cooling System...................................................................................................... 22

7.3 BACT for Circuit Breakers..................................................................................................... 24

8. Air Quality Impacts................................................................................................................. 26

8.1 Introduction ....................................................................................................................... 26

8.1.1 Overview of PSD Air Impact Requirements......................................................... 26

8.1.2 Identification of PPEC Modeling Documentation ................................................ 27

8.2. Background Ambient Air Quality............................................................................... 28

8.3 Modeling Methodology for Class II areas......................................................................... 30

8.3.1 Model selection ..................................................................................................... 30

8.3.2 Meteorology model inputs .................................................................................... 30

8.3.3 Land characteristics model inputs......................................................................... 30

8.3.4 Model receptors..................................................................................................... 31

8.3.5 Load screening and stack parameter model inputs................................................ 32

8.3.6 Good Engineering Practice (GEP) Analysis ........................................................ 34

8.4 National Ambient Air Quality Standards and PSD Class II Increment Consumption 

Analysis............................................................................................................................. 34

8.4.1 Pollutants with significant emissions.................................................................... 34

8.4.2 Preliminary analysis: Project-only impacts (Normal Operations and Startup)..... 34
ii 

8.4.3 Cumulative impact analysis .................................................................................. 35

8.5 Class I Area Analysis........................................................................................................ 42

8.5.1 Air Quality Related Values...................................................................................... 42

8.5.2 Class I Increment Consumption Analysis............................................................. 43

9. Additional Impact Analysis..................................................................................................... 44

9.1 Soils and Vegetation.......................................................................................................... 44

9.2 Visibility Impairment ........................................................................................................ 47

9.3 Growth............................................................................................................................... 48

10. Endangered Species................................................................................................................. 49

11. Environmental Justice Screening Analysis............................................................................. 50

12. Clean Air Act Title IV (Acid Rain Permit) and Title V (Operating Permit) .......................... 50

13. Comment Period, Procedures for Final Decision, and EPA Contact....................................... 50

14. Conclusion and Proposed Action ............................................................................................ 52
iii 

Acronyms & Abbreviations 

Act Clean Air Act [42 U.S.C. Section 7401 et seq.] 

AFC Application for Certification 

bext Light extinction coefficient 

BA Biological Assessment 

BACT Best Available Control Technology 

BTU British thermal units 

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.] 

CARB California Air Resources Board 

CEC California Energy Commission 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CO2e Carbon Dioxide Equivalent 

CT Combustion Turbine 

GE General Electric 

gr/scf Grains per Standard Cubic Feet 

EAB Environmental Appeals Board 

EPA U.S. Environmental Protection Agency 

ESA Endangered Species Act 

ESP Electrostatic Precipitator 

FWS U.S. Fish and Wildlife Service 

GHG Greenhouse Gases 

HHV Higher Heating Value 

HRSG Heat Recovery Steam Generator 

ISO International Organization for Standards 

km Kilometers 

kW Kilowatts of electrical power 

μg/m3 Microgram per Cubic Meter 

MMBTU Million British thermal units 

MW Megawatts of electrical power 

NAAQS National Ambient Air Quality Standards 

NESHAPS National Emission Standards for Hazardous Air Pollutants 

NO Nitrogen oxide or nitric oxide 

NO2 Nitrogen dioxide 

NOx Oxides of Nitrogen (NO + NO2) 

NP National Park 

NSPS New Source Performance Standards, 40 CFR Part 60 

NSR New Source Review 

O2 Oxygen 

PM Total Particulate Matter 

PM2.5 Particulate Matter less than 2.5 micrometers (μm) in diameter 

PM10 Particulate Matter less than 10 micrometers (μm) in diameter 

PPEC Pio Pico Energy Center 

PPM Parts per Million 
iv 

PSD Prevention of Significant Deterioration 

PTE Potential to Emit 

PUC Public Utilities Commission 

RATA Relative Accuracy Test Audit 

RBLC U.S. EPA RACT/BACT/LAER Information Clearinghouse 

SDAPCD San Diego County Air Pollution Control District 

SIL Significant Impact Level 

SF6 Sulfur Hexafluoride 

SNCR Selective Non-Catalytic Reduction 

SO2 Sulfur Dioxide 

SOx Oxides of Sulfur 

TDS Total Dissolved Solids 

TPY Tons per Year 

VOC Volatile Organic Compounds 

WA Wilderness Area 
1 

Proposed Prevention of Significant Deterioration (PSD) Permit 

Fact Sheet and Ambient Air Quality Impact Report 

PIO PICO ENERGY CENTER 

Executive Summary 

Pio Pico Energy Center, LLC (PPLLC or applicant) has applied to EPA Region 9 (EPA) 

for authorization under the Clean Air Act (CAA) Prevention of Significant Deterioration 

(PSD) program to construct a new power plant that will generate 300 megawatts (MW) of 

electricity using natural gas. The plant, known as the Pio Pico Energy Center (PPEC or 

Project), would be located in San Diego County, California. EPA is issuing a proposed 

PSD permit for the PPEC, which is consistent with the requirements of the PSD program 

for the following reasons: 

ß The proposed PSD permit requires the Best Available Control Technology (BACT) to 

limit emissions of nitrogen oxides (NOx), total particulate matter (PM), particulate 

matter 10 micrometers (μm) in diameter and smaller (PM10), particulate matter 2.5 

μm in diameter and smaller (PM2.5), and greenhouse gases (GHG); 

ß The proposed emission limits will protect the National Ambient Air Quality 

Standards (NAAQS) for nitrogen dioxide (NO2), PM10, and PM2.5. There are no 

NAAQS for PM or Greenhouse Gases; 

ß The facility will not adversely impact soils and vegetation, or air quality, visibility, 

and deposition in Class I areas located within 100 km, which are parks or wilderness 

areas given special protection under the Clean Air Act. 

1. Purpose of this Document 

This document serves as the Fact Sheet and Ambient Air Quality Impact Report (Fact 

Sheet) for the proposed PSD permit for the PPEC. This document describes the legal and 

factual basis for the proposed PSD permit, including requirements under the CAA, 

including CAA section 165 and the PSD regulations at Title 40 of the Code of Federal 

Regulations (CFR) section 52.21. This document also serves as a Fact Sheet for the 

proposed PSD permit per 40 CFR section 124.8. 

2. Applicant 

The name and address of the applicant is as follows: 
Pio Pico Energy Center, LLC

P.O. Box 95592 

2542 Singletree Lane

South Jordan, UT 84095

3. Project Location 

The project site is located in an unincorporated area of San Diego County known as Otay

Mesa. It is comprised of a 9.99 acre parcel located 

Otay Mesa Business Park. The site is located within the San Diego County Air Pollution 

Control District (SDAPCD, or District). 

The map below shows the approximate

4. Project Description 

The applicant has submitted a PSD permit

application materials for the PSD permit for the Project are included in EPA’s 

administrative record for EPA’s proposed PSD permit. 

2 

Pio Pico Energy Center, LLC

South Jordan, UT 84095

The project site is located in an unincorporated area of San Diego County known as Otay

It is comprised of a 9.99 acre parcel located at 7363 Calzada de la Fuente in the 

The site is located within the San Diego County Air Pollution 

Control District (SDAPCD, or District). 

The map below shows the approximate location of the proposed project. 

The applicant has submitted a PSD permit application to EPA for the PPEC. The 

application materials for the PSD permit for the Project are included in EPA’s 

administrative record for EPA’s proposed PSD permit. 

The project site is located in an unincorporated area of San Diego County known as Otay

at 7363 Calzada de la Fuente in the 

The site is located within the San Diego County Air Pollution 

for the PPEC. The 
3 

We note that PPEC also has submitted applications for State and local construction 

approvals for the Project that are separate from EPA’s PSD permitting process. These 

applications are referred to as an Application for Certification (AFC) submitted to the 

California Energy Commission (CEC) and an application for a Determination of 

Compliance (DOC) submitted to the District. The District issued a Final DOC for the 

Project on May 4, 2012. 

The primary equipment for the generating facility will be three General Electric (GE) 

LMS100 natural gas-fired combustion turbine-generators (CTGs) with a total net 

generating capacity of 100 megawatts (MW) each. Table 4-1 lists the equipment that will 

be regulated by this PSD permit: 

Table 4-1: Equipment List 

Equipment Description 

Three natural gas-fired 

GE LMS100 

combustion turbine 

generators (CTG) 

· Each 100 MW CTG, with a maximum heat input rate of 

903 MMBtu/hr (HHV)1

· Emissions of NOx controlled by water injection and 

Selective Catalytic Reduction (SCR) 

Partial Dry Cooling 

System 

· 7,000 gal/min maximum circulation rate (wet) 

· 16,520 gal/min maximum circulation rate (dry) 

· Total dissolved solids (TDS) concentration in makeup 

water of 5,600 ppm (560 mg/L) 

· Drift eliminator with drift losses less than or equal to 

0.001 percent 

Circuit Breakers · 3 switchyard and 2 generator breakers containing SF6 

The simple-cycle turbines will be operated as a peaking facility. Electricity will be 

generated by the combustion turbine generators when the combustion of natural gas turns 

the turbine blades. The spinning blades will drive an electric generator with the potential 

to generate up to 100 megawatts (MW) of electricity from each turbine. 

Air Pollution Control 

The PPEC will use Selective Catalytic Reduction (SCR) to reduce NOx emissions from 

the CTGs. The SCR process will use aqueous ammonia as the reagent, where the catalyst 

facilitates the reaction of the ammonia with NOx to create atmospheric nitrogen (N2) and 

 

1 This heat input occurs when load is at 100% and at an ambient temperature of 63° F. 
4 

water. Pipeline quality natural gas fuel and good combustion practices will be used to 

minimize particulate emissions. Thermal efficiency will be used to minimize GHG 

emissions. 

We note that the PPEC will use an oxidation catalyst to reduce emissions of CO and 

volatile organic compounds (VOC). Although CO and VOC are not regulated in this 

proposed PSD permit, these pollutants will be regulated by the New Source Review 

(NSR) permit issued by the District, as explained in Section 6 below. The federally 

enforceable District permit serves to limit the CO and VOC potential to emit (PTE) to 

less than the PSD significance thresholds. The District permit contains practically 

enforceable short-term and annual emission limits for CO and VOC, and requires the 

installation of post-combustion air pollution control equipment to control emissions of 

these two pollutants. 

Power Plant Startup

The GE LMS100 is an intercooled gas turbine system developed especially for the power 

generation industry. The applicant states that each LMS100 produces approximately 100 

MW at an efficiency rate that is approximately ten percent higher than that of other 

commercial simple-cycle gas turbines. The applicant also notes that the LMS100 is 

specifically designed for cyclic applications; it provides flexible power and, according to 

the manufacturer, can deliver 100 MW of power in 10 minutes.

5. Emissions from the Proposed Project 

This section describes the pollutants that are covered by the PSD program within the 

SDAPCD, which is the area in which the Project is proposed to be located. 

The CAA’s NSR provisions include two preconstruction permitting programs. First, the 

CAA PSD program is intended to protect air quality in “attainment areas,”2 which are 

areas that meet the NAAQS. EPA is responsible for issuing PSD permits for major new 

stationary sources emitting pollutants that are in attainment with (or unclassifiable for) 

the NAAQS, in general, and within the District. 

Second, the CAA nonattainment NSR program applies in areas where pollutant 

concentrations exceed the NAAQS (“nonattainment areas”). The District implements the 

nonattainment NSR program for facilities within its boundaries emitting nonattainment 

pollutants and their precursors (e.g., VOC and NOx, which are precursors to ambient 

ozone). For purposes of nonattainment NSR, PPEC will not be a major source of any 

nonattainment pollutant; therefore requirements of nonattainment NSR, including Lowest 

Achievable Emission Rate (LAER) and emission offsets, do not apply to the Project. 

Instead, the minor NSR permit issued by SDAPCD addresses both attainment and 

nonattainment pollutants. 

 

2 PSD also applies to pollutants where the status of the area is uncertain (unclassifiable) for NAAQS and to any other 

pollutant subject to regulation under the CAA. 
5 

Table 5-1 below describes the regulated pollutants that will be emitted by the Project and 

their attainment status within the District. 

Table 5-1: National Ambient Air Quality Standard Attainment Status for 

San Diego County Air Pollution Control District 

Pollutant Attainment Status Permit Program 

Nitrogen Dioxide (NO2) Attainment/Unclassifiable PSD 

Sulfur Dioxide (SO2) Attainment/Unclassifiable PSD 

Carbon Monoxide (CO) Attainment PSD 

Particulate Matter (PM) n/a3PSD 

Particulate matter under 10 

micrometers diameter (PM10) Attainment PSD 

Particulate Matter under 2.5 

micrometers diameter (PM2.5) Attainment PSD 

Ozone Nonattainment NA-NSR 

Lead (Pb) Attainment/Unclassifiable PSD 

Sulfuric Acid Mist (H2SO4) n/a3PSD 

Hydrogen Sulfide (H2S) n/a3PSD 

Total Reduced Sulfur (TRS) n/a3PSD 

Fluorides n/a3PSD 

Greenhouse Gases (GHG) n/a3PSD 

The PSD program (40 CFR § 52.21) applies to “major” new sources of pollutants for 

which an area has been designated attainment or is unclassifiable. A new source is 

defined as a “major source” if emits or has the potential to emit (depending on the source 

type) either 100 or 250 tons per year (tpy) or more of any “regulated NSR pollutant,” as 

that term is defined in the PSD regulations, including greenhouse gases (GHG) when they 

are emitted by the source in amounts that are “subject to regulation” as defined in 40 CFR 

§ 52.21(b)(49), currently 100,000 tpy or more of GHG on a carbon dioxide equivalent 

(CO2e) basis for new sources such as this Project . 

 

3 There are no national ambient air quality standards (NAAQS) for PM, H2SO4, H2S, TRS, fluorides, or GHGs. 

However, in addition to other pollutants for which no NAAQS have been set, these pollutants are regulated NSR 

pollutants with defined applicability thresholds under the PSD regulations (see 40 CFR §§ 52.21(b)(23), (49), and 

(50)). 
6 

6. Applicability of the Prevention of Significant Deterioration 

Regulations 

This section describes the PSD applicability thresholds, and our conclusion that the 

Project’s emissions of NOx, PM, PM10, PM2.5, and GHG will be regulated by EPA’s 

proposed PSD permit. 

The annual emission data in Tables 6-1 and 6-2 (based on allowable operation up to 

8,760 hours per year) are based on the applicant’s maximum expected emissions, 

including emissions from startup and shutdown cycles. The data submitted by the 

applicant is based on the assumption that all of the Project’s combustion-related 

particulate emissions are PM2.5. As a result, the PTE for PM and PM10 equals the PTE 

for PM2.5. This is a conservative approach, as some particulate emissions may be larger 

than 2.5 micrometers. 

The estimated emissions in Table 6-1 and Table 6-2 show that the PPEC will be a major 

source for GHG. GHG emissions from the Project are a regulated NSR pollutant because 

the emissions exceed the 100,000 tpy CO2e subject to regulation threshold provided in 

40 CFR § 52.21(b)(49), and the GHG emissions on a mass basis exceed the 250 tpy 

major source threshold. Once a source is considered major for at least one regulated 

NSR pollutant, PSD also applies to any other regulated pollutant that the facility has the 

potential to emit in a significant amount, i.e., at or above the significant emission rate. 

The data in Table 6-1 show that the Project has the potential to emit NOx, PM, PM10, and 

PM2.5 in a significant amount; therefore, the Project is subject to PSD review for these 

pollutants in addition to GHG. Estimated emissions of the PSD-regulated pollutants from 

the facility are listed in Table 6-1. 

Carbon monoxide (CO), and sulfur dioxide (SO2) will be less than the major source 

threshold and less than the significant emission rate for each pollutant. Therefore, PSD 

review does not apply to these pollutants for the PPEC. 

Table 6-1: Estimated Emissions and PSD Applicability 

Pollutant Estimated 

Annual Emissions 

(tons/year)

Major Source 

Threshold 

(tons/year)

Significant 

Emission Rate 

(tons/year)

Does PSD 

apply?

CO 96.4 250 100 No

NO2 70.4 250 40 Yes

PM 37.2 250 25 Yes

PM10 37.2 250 15 Yes

PM2.5 37.2 250 10 Yes

SO2 4.1 250 40 No
7 

Pb 0 250 0.6 No

H2SO4 3.4 250 7 No

H2S (incl. TRS) 0 250 10 No

Fluorides 0 250 3 No

GHG (in mass 

tons) 623,299 250 0 Yes

Table 6-2: Estimated Emissions of PSD-Regulated Pollutants by Unit (tpy) 

CO NOx PM PM10 PM2.5 GHG(a)(c) CO2e

(b)(c)

Total Facility 96.4 70.4 37.2 37.2 37.2 623,299 685,626 

CTG (each unit) 32.1 23.5 11.9 11.9 207,753 228,528 

Circuit Breakers (5) n/a n/a n/a n/a n/a 3.36 lb/yr 40 

Partial Dry Cooling 

System 

n/a n/a 1.4 1.4 n/a n/a 

Notes: 

(a) Represents all GHG emissions on a mass basis. 

(b) Represents the carbon dioxide equivalent (CO2e) of all GHG emissions, rounded to the nearest 1,000 tons. 

(c) The applicant used 2007 California Air Resources Board (CARB) GHG emission factors to calculate its 

GHG emissions. CARB updated its GHG reporting regulations in 2010 to incorporate emission factors 

from EPA’s Mandatory Greenhouse Gas Reporting Rule (40 CFR Part 98). EPA has recalculated the 

applicant’s GHG emissions using emission factors from Part 98. 

7. Best Available Control Technology 

This section describes EPA’s Best Available Control Technology (BACT) analysis for 

the control of NOx, PM, PM10, PM2.5, and GHG emissions from this facility. Section 

169(3) of the Clean Air Act defines BACT as follows: 

"The term 'best available control technology' means an emission limitation based 

on the maximum degree of reduction of each pollutant subject to regulation under 

the Clean Air Act emitted from or which results from any major emitting facility, 

which the permitting authority, on a case-by-case basis, taking into account 

energy, environmental, and economic impacts and other costs, determines is 

achievable through application of production processes and available methods, 

systems, and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of each such pollutant. In no event shall 

application of ‘best available control technology’ result in emissions of any 

pollutants which will exceed the emissions allowed by any applicable standard 
8 

established pursuant to section 111 [New Source Performance Standards or 

NSPS] or 112 [or NESHAPS] of the Clean Air Act." 

See also 40 CFR 52.21(b)(12). In accordance with 40 CFR 52.21(j), a new major 

stationary source is required to apply BACT for each regulated NSR pollutant that it 

would have the potential to emit (PTE) in significant amounts. 

EPA outlines the process it generally uses to do this case-by-case analysis (referred to as 

a “top-down” BACT analysis) in a June 13, 1989 memorandum. The top-down BACT 

analysis is a well-established procedure that EPA’s Environmental Appeals Board (EAB) 

has consistently followed in adjudicating PSD permit appeals. See, e.g., In re Desert Rock 

Energy Center, 14 E.A.D. ___, slip op. at 52-53 (Sept. 24, 2009); In re Knauf, 8 E.A.D. 

121, 129-31 (EAB 1999); In re Maui Electric, 8 E.A.D. 1, 5-6 (EAB 1998). 

In brief, under the top-down process, all available control technologies are ranked in 

descending order of control effectiveness. The PSD applicant first examines the most 

stringent technology. That technology is established as BACT unless it is demonstrated 

that technical considerations, or energy, environmental, or economic impacts, justify a 

conclusion that the most stringent technology is not achievable for the case at hand. If 

the most stringent technology is eliminated, then the next most stringent option is 

evaluated until BACT is determined. The top-down BACT analysis is a case-by-case 

exercise for the particular source under evaluation. In summary, the five steps involved 

in a top-down BACT evaluation are: 

1. Identify all available control options with practical potential for application to 

the specific emission unit for the regulated pollutant under evaluation; 

2. Eliminate technically infeasible technology options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate the most effective control alternative and document results, 

considering energy, environmental, and economic impacts as appropriate; if 

top option is not selected as BACT, evaluate next most effective control 

option; and 

5. Select BACT, which will be the most stringent technology not rejected based 

on technical, energy, environmental, and economic considerations. 

The proposed Project is subject to BACT for NOx, PM, PM10, PM2.5, and GHG 

emissions. A BACT analysis was conducted for the three natural gas combustion 

turbines. Tables 7-1 and 7-2 provide a summary of the BACT determinations for NOx, 

PM, PM10, PM2.5, and GHG from the emission units listed above. 
9 

Table 7-1: Summary of NOx, PM, PM10, and PM2.5 BACT Limits 

and Requirements for Testing and Monitoring 

NOX

PM, PM10, 

and PM2.5 

Restrictions on Usage 

3 Combustion 

Turbines 

(each) 

· 2.5 ppmvd, 15% O2

· 1-hr average 

· 8.18 lb/hr 

· 26.6 lb/hr during 

each startup or 

shutdown 

· 22.5 lb per startup 

event, 6.0 lb per 

shutdown event 

· CEMS 

· quarterly and annual 

RATA for CEMs

· 0.0065 lb/MMBtu 

· 9-hr average 

· PUC natural gas 

(sulphur ≤ 0.25 

gr/dscf on a 12-month 

rolling average, and 

not to exceed of 1.0 

grains per 100 dscf, at 

any time)

· annual performance 

testing

· Maximum of 500 

startups per calendar 

year 

· 30 minute maximum 

startup duration 

· 10.5 minute maximum 

shutdown duration 

Partial Dry 

Cooling 

System 

n/a · drift rate of 0.001% or 

less 

· < 5,600 ppm total 

dissolved solids 

n/a 

Table 7-2: Summary of GHG BACT Limits 

and Requirements for Testing and Monitoring

GHG Testing and Monitoring Restrictions on Usage 

3 Combustion 

Turbines 

(each) 

· initial heat rate limit 

of 9,196 btuhhv/kwhrgross

· 1181 lb CO2/MWh 

net output 

· 8,760 rolling 

operating-hour 

average 

· initial performance test 

· CEMS

n/a 

circuit 

breakers 

· the use of enclosedpressure SF6 circuit 

breakers with a 

maximum annual 

leakage rate of 0.5% 

by weight and a 

10% by weight leak 

detection system 

· emission cap of 40.2 

tpy 

· mass balance n/a 

7.1 BACT for Natural Gas Combustion Turbine Generators 
10 

PPEC has proposed three simple-cycle, natural gas-fired combustion turbines (CTs). 

Each CT has a maximum generating capacity of 103 MW and a maximum heat input 

capacity of 7,815 BTU/kw-hr (LHV) at ISO conditions. The CTs are subject to BACT 

for NOx, PM, PM10, PM2.5, and GHGs. A top-down BACT analysis for each pollutant 

has been performed and is summarized below. 

7.1.1 Nitrogen Oxide Emissions 

Step 1 - Identify All Control Technologies 

The following inherently lower-emitting control options for NOx emissions include: 

· Low NOx burner design (e.g., dry low NOx combustors) 

· Water or steam injection 

· Inlet air coolers 

The available add-on NOx control technologies include: 

· Selective Catalytic Reduction (SCR) system 

· EMxTMsystem (formerly SCONOx) 

· Selective non-catalytic reduction (SNCR)4

Step 2 – Eliminate Technically Infeasible Options 

With the exception of EMxTM, all of the available control options identified in Step 1 are 

technically feasible. EMxTM technology (formerly SCONOx) is a relatively newer 

technology that has yet to be demonstrated in practice on CTs larger than 50 MW. The 

manufacturer has stated that it is a scalable technology and that NOx guarantees of <1.5 

ppm are available. However, this technology is designed to operate at a maximum 

temperature of approximately 700°F. Simple cycle gas turbines operate with exhaust gas 

temperatures of up to 1100° F, which exceeds the maximum temperature that EMx 

catalysts can tolerate while remaining effective. For this reason, we do not consider EMx 

to be technically feasible for simple-cycle gas turbines, and are eliminating this 

technology from further consideration as BACT. We also note that we are not aware of 

any simple-cycle gas turbines currently operating with EMx, or any permit application 

for a simple-cycle gas turbine power plant that proposes the use of EMx to control NOx 

emissions. Therefore we do not consider this technology achievable for simple-cycle gas 

turbines at this time. 

Step 3 – Rank Control Technologies 

 

4 According to the applicant, the PPEC is “designed to directly satisfy the San Diego area peaking and load-shaping 

generation current and long-term requirements. Key among these requirements is supporting wind and solar 

generation, whose overall output varies.” (PPEC PSD permit application, p. PSD – 2.1) The PPEC’s capacity for 

frequent and fast turbine startups will provide necessary power to compensate for the intermittent nature of wind and 

solar generation, and thus will ultimately provide critical support for the growth of renewable energy sources in the 

area. Solar and wind power generation would be incompatible with the applicant’s peaking power generation 

purpose because they are not steady state power sources that can be relied on to generate power during periods when 

intermittent renewable resources cannot. Therefore, we have not included solar and wind in our BACT analyses 

based on our determination that these technologies would fundamentally redefine the source. 
11 

Selective catalytic reduction (SCR) is a well-demonstrated technology for NOX control 

and has specifically achieved NOX emissions of 2.5 ppm on a 1-hr average on large 

simple cycle CTs (greater than 100 MW).5 

The available control technologies are ranked according to control effectiveness in Table 

7-3. Since inlet air cooling reduces the amount of thermal NOx formed during 

combustion and are inherent to the design of all new gas turbines, we have evaluated the 

highest ranked control technologies with the assumption that they will utilize this 

inherent control. A summary of recent BACT limits for similar simple-cycle, natural 

gas-fired CTs is provided in Table 7-4. All recently issued permits for such facilities 

indicate that a limit of 2.5 ppm based on a 1-hr average represents the highest level of 

NOx control. 

Table 7-3: NOx Control Technologies Ranked by Control Effectiveness 

NOx Control Technology 

Emission Rate (ppmvd 

@ 15% O2, 1-hr average)

SCR with water injection 2.5 

SCR with Dry Low NOX combustors 2.5 

SNCR ~4.56

Dry low NOX combustors and inlet air coolers 9 

Water or steam injection >9 

Step 4 – Economic, Energy and Environmental Impacts 

The applicant has proposed SCR, the top-ranked technology, as BACT. We have 

determined that it is appropriate to consider the collateral environmental impacts 

associated with SCR. The SCR system requires onsite ammonia storage and will result in 

relatively small amounts of ammonia slip from the CTs’ exhaust gases. Ammonia has 

the potential to be a toxic substance with harmful side effects, if exposed through 

inhalation, ingestion, skin contact, or eye contact.7 Ammonia has not been identified as a 

carcinogen. It is noted that the applicant will use aqueous ammonia, which is considered 

a safer storage method than anhydrous ammonia. Additionally, we note that the 

California Energy Commission’s Final Staff Analysis for the project proposes to include 

Conditions of Certification to ensure the safe receipt and storage of aqueous ammonia at 

the PPEC.8 

Ammonia slip emissions for the proposed source are limited to 5 ppm by the NSR permit 

 

5 While a NOx emission rate of 2.0 ppm has been demonstrated to achieve with combined cycle gas turbine 

configurations, SCR has not been able to achieve this emission rate on simple cycle turbines due to their higher 

exhaust gas temperatures. EPA is not aware of any source that has proposed or achieved this emission rate with 

SCR on a simple cycle gas turbine power plant. 

6 This is an approximate value that was estimated considering that the control effectiveness of SNCR has been 

demonstrated to be between 40 and 60 percent. 

7 Information is available from the Agency for Toxics Substances and Disease Registry at 

http://www.atsdr.cdc.gov/phs/phs.asp?id=9&tid=2. 

8 This information is available at http://www.energy.ca.gov/sitingcases/piopico/index.html. See conditions HAZ-3 

through HAZ-5. 
12 

issued by the District. The District conducted a Health Risk Assessment (HRA) that 

included ammonia slip emissions. The results of the assessment showed that the 

maximum non-cancer chronic and acute hazard indices were both less than the 

significance level of 1.0 (0.011 and 0.11, respectively).9

Considering the above factors, the possible risks associated with onsite storage and use of 

ammonia do not appear to outweigh the benefits associated with significant NOx 

reductions. 

SCR with Water Injection versus SCR with Low NOx Burners: The applicant has 

proposed to use water injection with SCR to control NOx from the Project. As noted 

above, this technology is expected to achieve the same level of control as would SCR 

with low NOx burners. We have determined that the amount of water needed for water 

injection will not result in a significant environmental impact warranting elimination of 

this technology as BACT for the Project. . Therefore, we concur that the applicant’s 

selection of SCR with water injection as BACT is appropriate in this case.

Step 5 – Select BACT 

Based on a review of the available control technologies for NOx emissions from natural 

gas-fired combustion turbines, we have concluded that BACT for these CTs is the use of 

SCR and water injection with an emissions limit of 2.5 ppm at 15% O2 based on a 1-hr 

average. 

Table 7-4: Summary of Recent NOx BACT Limits for Similar Simple-Cycle, 

Natural gas-fired CTs 

Facility NOX

Limit

Averaging 

Period Control Permit Issuance

Source

El Cajon 

Energy 

2.5 

ppm 

1-hr 

water 

injection and 

SCR 

Dec 2009 RBLC # CA-1174 

Escondido 

Energy Center 

2.5 

ppm

1-hr 

water 

injection and 

SCR 

Jul 2008 RBLC # CA-1175 

Orange Grove 

Energy 

2.5 

ppm

1-hr 

LNB, water 

injection, 

and SCR 

Dec 2008 RBLC # CA-1176 

CalPeak Power 

El Cajon 

3.5 

ppm

1-hr SCR Jun 2001 CARB BACT 

Clearinghouse 

El Colton 

3.5 

ppm

3-hr SCR Jan 2003 CARB BACT 

Clearinghouse

Lambie Energy 

Center 

2.5 

ppm

3-hr SCR Dec 2002 CARB BACT 

Clearinghouse

TID Almond 2 

Power Plant 

2.5 

ppm

1-hr 

LNB, water 

injection, 

and SCR 

Dec 2010 California Energy 

Commission 

Canyon Power 

Plant 

2.5 

ppm

60 minutes 

LNB, water 

injection, 

and SCR 

Mar 2010 California Energy 

Commission 

 

9

See FDOC for PPEC issued by the District on May 4, 2012, Section 8. 
13 

Starwood 

Power – 

Midway 

2.5 

ppm

1-hr 

water 

injection and 

SCR

Jan 2008 California Energy 

Commission

Panoche Energy 

2.5 

ppm

1-hr 

water 

injection and 

SCR

Dec 2007 California Energy 

Commission

San Francisco 

Electric 

Reliability 

Project 

2.5 

ppm

1-hr 

water 

injection and 

SCR

Oct 2006 California Energy 

Commission

Niland Power 

Plant 

2.5 

ppm

1-hr 

water 

injection and 

SCR

Oct 2006 California Energy 

Commission

Miramar 

Energy Facility 

II 

2.5 

ppm 

3-hr 

water 

injection and 

SCR 

Nov 2008 ATC 

Walnut Creek 

Energy Park 

2.5 

ppm 

1-hr 

water 

injection and 

SCR 

May 2011 California Energy 

Commission 

Note: All facilities listed in the table are located in California.

7.1.2 PM, PM10 and PM2.5 Emissions 

Because the applicant has taken the conservative approach and assumed that all 

particulate emissions from the turbines are PM2.5, the BACT analyses for PM, PM10 and 

PM2.5 have been combined. Additionally, the analysis evaluates total particulate 

emissions – condensable and filterable. 

Step 1 – Identify All Control Technologies 

The following inherently lower-emitting control options for PM, PM10, and PM2.5 

emissions include10: 

· Low particulate fuels, low sulfur fuels, and/or pipeline natural gas 

· Good combustion practices (including air inlet filter) 

The available add-on PM, PM10, and PM2.5 control technologies include: 

· Cyclone (including multiclones) 

· Wet scrubber 

· Dry electrostatic precipitator (ESP) 

· Baghouse/fabric filter 

Step 2 – Eliminate Technically Infeasible Control Options 

All of the control technologies identified are technically feasible except for cyclones. 

Although cyclones have been identified as being capable of marginal PM2.5 control, the 

 

10 As noted in the footnote 5 above, we have excluded solar and wind generation from our BACT analyses for the 

PPEC based on our determination that these technologies would fundamentally redefine the source. 
14 

low grain loading makes them technically infeasible for this application.

11 EPA’s Air 

Pollution Control Technology Fact Sheet for Cyclones (EPA-452/F-03-005) identifies 

typical grain loading for cyclones as ranging from 1.0 to 100 gr/scf and being as low as 

0.44 gr/scf.12 In contrast, the grain loading for the CTs’ exhaust stream in this case 

would be about 0.0027 gr/scf based on the applicant’s proposed BACT limits. Cyclones 

are generally used in high dust applications where a majority of the particulate emissions 

are filterable emissions. In contrast, the majority of emissions from the CTs will be 

condensable particulate matter. For this reason, we are eliminating cyclones in this step 

due to technical infeasibility. 

Step 3 – Rank Remaining Control Technologies 

The applicant proposed a total PM limit of 0.0065 lb/MMBtu (HHV) to be achieved 

through the use of pipeline-quality natural gas and good combustion practices (including 

air inlet filter). EPA evaluated this proposal by reviewing recent PM performance test 

data from other similar simple cycle plants in southern California. These plants and test 

data are shown in Table 7-5. 

Table 7-5: Southern California Simple Cycle Turbine PM Performance Test Results 

Facility Test Result 

Orange Grove Unit Turbine 1 0.0031 lb/MMBtu 

Orange Grove Unit Turbine 2 0.0049 lb/MMBtu 

El Cajon Energy 0.0008 lb/MMBtu 

Canyon Power Project Unit 1 0.00311 lb/MMBtu 

Canyon Power Project Unit 2 0.00311 lb/MMBtu 

Note: These tests were conducted in 2010 and 2011 on GE LMS 6000 turbines, and represent the test average. 

Based on these test data, we have concluded that the applicant’s proposed PM emission 

limit for this project is reasonable for simple cycle gas turbines located in southern 

California. BACT will be achieved by the use of low sulfur pipeline-quality natural gas 

and good combustion practices. We have included the applicant’s proposed emission 

limit of 0.0065 lb/MMBtu (HHV) in order to ensure the use of low sulfur natural gas and 

good combustion practices. This limit represents the expected PM emissions based on 

the engineering design of this specific model (GE LMS100) of natural-gas fired turbine. 

Step 4 – Economic, Energy and Environmental Impacts 

The applicant provided a cost analysis for PM controls based on information provided in 

Controlling Fine PM. A modified version of this analysis is provided in Table 7-6. The 

amount of PM2.5 removed is based on the manufacturer’s guaranteed emission rate of 5.5 

lb/hr. Because add-on PM controls have not been applied to CTs, the control efficiencies 

evaluated are considered conservative. With cost-effectiveness values ranging between 

$317,902 and $438,860 per ton of PM2.5 removed, add-on controls are considered costprohibitive for the PPEC. Therefore we are eliminating ESP, baghouse, and wet 

 

11 –Information is available at 

http://www.epa.gov/apti/Materials/APTI%20413%20student/413%20Student%20Manual/SM_ch%204.pdf. 

12 Information is available at http://www.epa.gov/ttn/catc/dir1/fcyclon.pdf. 
15 

scrubber technologies in this step due to economic impacts. 

Table 7-6: Cost Analysis for Add-on PM Control Technologies 

Dry ESP Baghouse 

(pulse-jet)

Wet Scrubber 

(venturi)

Flowrate (ft3/min) 915,000 915,000 915,000

Capital Costs ($/scfm) 10 6 2.50

Capital Costs (total $) 9,150,000 5,490,000 2,287,500

Cost Recovery Factor 0.11 0.11 0.11

Annualized Capital Costs ($/yr) 1,006,500 603,900 251,625

O & M Costs ($/scfm) 3 5 4.40

O & M Costs ($/yr) 2,745,000 4,575,000 4,026,000

Total Annualized Costs ($/yr) 3,751,500 5,178,900 4,277,625

Removal Efficiency 99% 99% 90%

Tons of PM2.5 Removed (TPY) 11.80 11.80 10.73

Cost Effectiveness ($/ton 

removed) 317,902 438,860 398,735

Step 5 – Select BACT 

After eliminating ESP, baghouse, and wet scrubber technologies due to economic 

impacts, we have determined that BACT is the use of low sulfur pipeline quality natural 

gas, good combustion practices, and a PM, PM10, and PM2.5 limit of 0.0065 lb/MMBtu 

based on a 9-hr average. By “pipeline quality natural gas” we mean Public Utilities 

Commission (PUC)-quality natural gas. While the PUC sets a sulfur content limit of 5.0 

grains per 100 dscf, the average sulfur content of natural gas in San Diego County is 0.20 

g/100 dscf. Therefore we are proposing a sulfur content limit for the natural gas of 0.25 

grains per 100 dry standard cubic feet on a 12-month rolling average and a sulfur content 

of 1.0 grains per 100 dry standard cubic feet that shall not be exceeded at any time. 

7.1.3 GHG Emissions 

Step 1 – Identify all control technologies

The following control technologies are potentially available for the PPEC: 

· Alternative generating technologies such as combined-cycle gas turbines or 

reciprocating internal combustion (IC) engines. 

Combined-cycle gas turbines recover waste heat from the gas turbine exhaust using a 

heat recovery steam generator (HRSG). In many applications, combined-cycle 

facilities are more efficient than simple-cycle operations because the use of the HRSG 

allows the production of more electricity without additional fuel consumption. 
16 

Reciprocating IC engines consist of one or more cylinders in which the process of 

combustion takes place within the cylinders. Reciprocating IC engines are generally 

well suited for peaking applications such as the proposed Project. 

· Use of the most energy efficient simple-cycle gas turbines. 

· Carbon capture and sequestration (CCS). 

CCS is a technology that involves the capture and storage of CO2 emissions to 

prevent their release to the atmosphere. 

Step 2 – Eliminate technically infeasible control technologies

Reciprocating IC Engines 

As noted above, reciprocating IC engines are well-suited for peaking applications and are 

technically feasible for the proposed Project. 

Combined-Cycle Gas Turbines 

As stated in the permit application, the applicant seeks approval from EPA for 

construction of the PPEC in order to satisfy an obligation to supply electrical capacity 

and energy to San Diego Gas & Electric (SDG&E) under a 20-year Power Purchase 

Agreement (PPA). The purpose of this project is to meet the specific objectives of 

SDG&E’s 2009 Request for Offers (RFO) and the resulting contractual requirements 

contained in the PPA between SDG&E and PPEC LLC. Key among these requirements 

is supporting renewable power generation such as wind and solar, whose overall output 

varies. As output from these renewable resources drops, the PPEC must be able to come 

online quickly to make up the lost grid capacity. Thus, in order to satisfy its business 

purpose, the PPEC must be able to offer units that: 1) are highly flexible and that can 

provide regulation during the morning and evening ramps, 2) can be repeatedly started 

and shut down as needed, and 3) can be brought online quickly, even under cold-start 

conditions. There are a number of issues that make combined-cycle gas turbines 

technically infeasible for such a project. 

The start-up sequence for a combined-cycle plant includes three phases: 1) purging of 

the HRSG; 2) gas turbine speed-up, synchronization, and loading; and 3) steam turbine 

speed-up, synchronization, and loading. The third phase of this process is dependent on 

the amount of time that the plant has been shut down prior to being restarted; the HRSG 

and steam turbine contain parts that can be damaged by thermal stress and they require 

time to heat up and prepare for normal operation. For this reason, the complete startup 

time for a combined-cycle plant is typically longer than that of a similarly-sized simple 

cycle plant. For example, the PPEC can be dispatched from “cold iron” to 300 MW in 

less than 30 minutes13. By comparison, the most likely combined-cycle alternative in 

GE’s product offering – a 107FA power block – would be capable of providing at most 

160 MW in approximately the same amount of time (General Electric Company, n.d.[1]). 

 

13 According to GE, the gas turbine proposed by the applicant (LMS100) offers fast start capability that can deliver 

100 MW in 10 minutes (General Electric Company, n.d.[2]). 
17 

Even with fast-start technology, new combined-cycle units like the GE 7FA may require 

up to 31⁄2 hours to achieve full load under some conditions. These longer startup times 

are incompatible with the purpose of the Project to provide quick response to changes in 

the supply and demand of electricity. Furthermore, gas turbines used in peaking duty 

cycles experience high levels of thermal mechanical fatigue due to the large numbers of 

startups and shutdowns, and the impacts of such fatigue would be even greater in the 

steam-side equipment of a combined cycle plant. Thus, even if the long startup durations 

were not prohibitive in this case, the use of a combined-cycle design would still be 

inconsistent with the PPEC’s stated need for flexibility to start up and shut down multiple 

times in a single day in response to changing demand; such a duty cycle would likely 

result in excessive wear to combined-cycle units. Therefore, EPA has concluded that a 

combined-cycle facility is technically infeasible for the Project as defined by the 

applicant and we have eliminated that control option from further consideration as BACT 

in this case.14 

CCS 

The three main approaches for CCS are pre-combustion capture, post-combustion 

capture, and oxyfuel combustion (IPCC, 2005). Of these approaches, pre-combustion 

capture is applicable primarily to gasification plants, where solid fuel such as coal is 

converted into gaseous components by applying heat under pressure in the presence of 

steam and oxygen (U.S. Department of Energy, 2011). At this time, oxyfuel combustion 

has not yet reached a commercial stage of deployment for gas turbine applications and 

still requires the development of oxy-fuel combustors and other components with higher 

temperature tolerances (IPCC, 2005). The third approach, post-combustion capture, is 

applicable to gas turbines. 

With respect to post-combustion capture, a number of methods may potentially be used 

for separating the CO2 from the exhaust gas stream, including adsorption, physical 

absorption, chemical absorption, cryogenic separation, and membrane separation (Wang 

et al., 2011). Many of these methods are either still in development or are not suitable for 

treating power plant flue gas due to the characteristics of the exhaust stream (Wang, 

2011; IPCC, 2005). Of the potentially applicable technologies, post-combustion capture 

with an amine solvent such as monoethanolamine (MEA) is currently the preferred option 

because it is the most mature and well-documented technology (Kvamsdal et al., 2011), 

and because it offers high capture efficiency, high selectivity, and the lowest energy use 

compared to the other existing processes (IPCC, 2005). Post-combustion capture using 

MEA is also the only process known to have been previously demonstrated in practice on 

gas turbines (Reddy, Scherffius, Freguia, & Roberts, 2003). As such, it is the sole carbon 

capture technology considered in this analysis. 

In a typical MEA absorption process, the flue gas is cooled before it is contacted countercurrently with the lean solvent in a reactor vessel. The scrubbed flue gas is cleaned of 

 

14 We note that although the applicant also submitted an analysis to show that the use of a combined-cycle design for 

the Project would not be cost-effective, we are not relying on that analysis as we have determined that such a design 

is technically infeasible. The applicant’s economic analysis is available in EPA’s administrative record for the 

PPEC for reference. 
18 

solvent and vented to the atmosphere while the rich solvent is sent to a separate stripper 

where it is regenerated at elevated temperatures and then returned to the absorber for reuse. Fluor’s Econamine FG Plus process operates in this manner, and it uses an MEAbased solvent that has been specially designed to recover CO2 from oxygen-containing 

streams with low CO2 concentrations typical of gas turbine exhaust (Fluor, 2009). This 

process has in fact been used successfully to capture 365 tons per day of CO2 from the 

exhaust of a natural gas combined-cycle plant owned by Florida Power and Light in 

Bellingham, Massachusetts. The CO2 capture plant was maintained in continuous 

operation from 1991 to 2005 (Reddy, Scherffius, Freguia, & Roberts, 2003). As this 

technology is commercially available and has been demonstrated in practice on a 

combined-cycle plant, EPA generally considers it to be technically feasible for natural 

gas combined-cycle sources. 

In 2003, Fluor and BP completed a joint study that examined the prospect of capturing 

CO2 from eleven simple cycle gas turbines at a BP gas processing plant in Alaska known 

as the Central Gas Facility (CGF) (Hurst & Walker, 2005; Simmonds et al., 2003). 

Although this project was not actually implemented (S. Reddy, personal communication, 

December 13, 2011; available in EPA’s administrative record for the PPEC), the 

feasibility study provides valuable information about the design of a capture system for 

simple-cycle applications, particularly with respect to flue gas cooling and heat recovery. 

Absorption of CO2 by MEA is a reversible exothermic reaction. Before entering the 

absorber, the turbine exhaust gas must be cooled to around 50 oC to improve absorption 

and minimize solvent loss due to evaporation (Wang, 2011). In the case of the CGF 

design, the flue gas is cooled by feeding it first to a HRSG for bulk removal of the heat 

energy and then to a direct contact cooler (DCC). It should be noted that while Hurst & 

Walker (2005) found that the HRSG could be omitted from the design for another type of 

source studied (heaters and boilers at a refinery), the DCC alone would be insufficient for 

the gas turbines due to the high exhaust gas temperature (480-500 oC). After the MEA is 

loaded with CO2 in the absorber, it is sent to a stripper where it is heated to reverse the 

reaction and liberate the CO2 for compression. The heat for this regeneration stage 

comes from high- and intermediate-pressure steam generated in the HRSG. Excess steam 

from the CGF HRSGs would also be used to export electricity to the local grid. 

The integral nature of the HRSG to the overall process for the CGF is notable because it 

would essentially require conversion of the turbines from simple-cycle to combined-cycle 

operation. Therefore, based on this information, we conclude that while carbon capture 

with an MEA absorption process is feasible for a combined-cycle operation, it is not 

feasible for simple-cycle units (i.e., those without a HRSG). Given that combined-cycle 

gas turbines are not technically feasible for the proposed Project, as discussed above, 

CCS is also technically infeasible for the proposed Project. 

Notwithstanding the foregoing finding that CCS is technically infeasible for the proposed 

Project due to issues associated with flue gas cooling and heat recovery, there is another 

(and perhaps more critical) issue to consider regarding the technical feasibility of CCS in 

the present case. As previously discussed, the PPEC is contracted under a 20-year PPA 

and is designed to directly satisfy the San Diego area peaking and load-shaping 
19 

generation current and long-term requirements. The SDG&E contract for the facility 

allows for 500 startups and shutdowns per unit per year. Thus the operation of the 

facility will be transient in nature as a direct requirement of its fundamental business 

purpose. The high degree of transiency in this case is incompatible with current carbon 

capture systems, which are more suitable for steady-state operations (National Petroleum 

Council, 2007). Chalmers and Gibbins (2007) concluded, for example, that the 

synchronization of power plant startup with capture operations has not yet been fully 

addressed, and that changes in power cycle efficiency as a result of variable steam flow 

and heat integration between the power cycle and CO2 capture plant must be subjected to 

more detailed analysis. Consequently, even if the flue gas cooling and heat integration 

issues could be addressed through a combined-cycle design, CCS would still be 

technically infeasible for this project, given its non-steady state operation. Therefore, we 

have eliminated CCS from further consideration in this analysis. 

Step 3 – Rank Remaining Control Technologies

After elimination of combined-cycle gas turbines and CCS as potential control 

technologies, the use of IC engines and thermally efficient simple-cycle gas turbines are 

the only remaining control methods. These technologies are ranked below by their heat 

rate, which is a measure that reflects how efficiently a generator uses heat energy; the 

heat rate is expressed as the number of BTUs of heat energy required to produce a 

kilowatt-hour of electricity. 

Table 7-7: Ranking of Potential Control Technologies by Heat Rate 

Technology Heat Rate (HHV Basis) 

IC engines ~7,500 Btu/kWh 

Simple-cycle gas turbines ~8,700 to 10,000 Btu/kWh 

Step 4 – Economic, Energy, and Environmental Impacts

Reciprocating IC engines are fast-starting and, as shown above, generally have a lower 

heat rate than simple-cycle gas turbines. From a GHG perspective, these factors may 

make IC engines the preferred generation alternative in some situations. In this case, 

however, there are collateral environmental impacts that we have determined make the 

use of IC engines inappropriate. 

In 2010, Wartsila introduced its 18V50SG gas engine. With a maximum electrical output 

of 18.759 MW, it is the world’s largest engine and it is marketed by Wartsila as a viable 

alternative to gas turbine power plants up to 500 MW (Wideskog, 2011). In order to 

provide the 300 MW of electricity called for by the PPA applicable in this case, 

approximately 16 engines operating in simple cycle mode would be required. Multiengine plants of this scale are feasible and have in fact been built in a number of locations 

(Wartsila, 2011). At this time, however, the NOx rate guaranteed by Wartsila for this 

engine following SCR is 5 ppm, or 2.63 lbs/hr (C. Whitney, personal communication, 

January 25, 2012). Sixteen engines running at full load would therefore emit 

approximately 42 lbs/hr of NOx. In comparison, each of the proposed simple cycle 
20 

LMS100 gas turbines would emit a maximum of 8.18 lbs/hr, for a total maximum NOx

rate of 24.5 lbs/hr. The IC engines would thus emit 71% more NOx at full load than the 

gas turbines. 

In weighing the trade-offs between the lower NOx emissions associated with the gas 

turbines and the lower GHG missions associated with the IC engines, EPA is swayed by 

the fact that San Diego County is currently designated nonattainment for the 1997 8-hour 

ozone standard (69 Fed. Reg. 23858). In addition, both the state of California and EPA 

recently recommended that San Diego County be designated nonattainment for the 

revised 2008 ozone NAAQS (EPA, 2011). Given the current and projected ozone 

nonattainment status of the area, EPA believes it is appropriate in this case to favor the 

technology that reduces NOx emissions over GHG emissions, particularly when the 

difference in NOx emissions between the two technologies is so great. Consequently, 

EPA has eliminated the IC engines as the top control option. After elimination of IC 

engines from the BACT analysis, highly efficient simple-cycle gas turbines represent the 

top control option. 

Step 5 – Select BACT

Based on the foregoing analysis, EPA has concluded that BACT for GHGs for this source 

is the use of new thermally efficient simple-cycle combustion turbines combined with 

good combustion and maintenance practices to maintain optimum efficiency. The GE 

LMS100 gas turbines proposed by the applicant have a maximum efficiency of 44% 

under ISO conditions (General Electric Company, n.d.[2]). This is at the high end of the 

efficiency range for gas turbines of this size category;15 thus, we believe that the 

applicant’s proposal is consistent with the BACT requirement to use highly efficient 

simple-cycle turbines. To ensure that the plant operates as efficiently as possible over its 

entire lifetime, BACT will include a heat rate limit that applies at initial startup in 

addition to a separate emission limit that applies on an ongoing basis. Both the initial 

heat rate limit and the ongoing emission limit must account for a number of factors 

including various tolerances in the manufacturing and construction of the equipment as 

well as actual ambient operating conditions. Based on these factors, and turbine 

performance data provided by GE and the applicant (Hill, 2012), EPA is proposing to 

establish the initial heat rate limit at 9,196 btuhhv/kw-hrgross. This limit reflects the initial 

equipment performance levels provided by GE plus 3% to account for slight variations in 

the manufacturing, assembly, construction, and actual performance of the new turbines. 

Where the long-term emission limit is concerned, EPA is using a slightly higher margin 

of compliance than that used for the initial heat rate limit to account for unrecoverable 

losses in efficiency the plant will experience over its entire lifetime as well as seasonal 

 

15 See, for example, the Siemens product documentation (Siemens, 2008; Siemens, 2011), which states that its gas 

turbine products over 100 MW have efficiencies “approaching 40%” in simple cycle configuration, and that the 112 

MW Siemens SGT6-2000E specifically has an efficiency of 33.9% under ISO conditions. See also the Rolls Royce 

product information (Rolls Royce, n.d.) sating that its Trent 60 gas turbine delivers up to 64 MW in simple cycle 

service with an efficiency of 42%. See also GE’s product information page for the LMS100 (General Electric, 

n.d.[3]), which states that over the course of a peaking season, the high-efficiency LMS100 gas turbine system 

running at full capacity avoids over 34,000 metric tons of CO2 emissions compared to a typical simple cycle system. 

Finally, information on simple-cycle gas turbine efficiency from EPA’s RBLC (see Table 7-8 below) shows 

efficiencies no higher than approximately 37%. 
21 

variation in site-specific factors that affect turbine performance such as temperature and 

humidity. In this instance, we believe a margin of 6% is appropriate. Using this margin 

of compliance and the emissions data provided in the permit application, EPA is 

proposing an emission limit of 1,181 lbs CO2/MWh net output.16 Due to the nature of the 

emissions, GHG BACT limits established thus far have generally been based on an 

annual average such as a 365-day rolling basis. However, as a peaking facility, the PPEC 

will operate intermittently; on some days it may start up and shut down multiple times 

while on others it may not operate at all. Thus, it is preferable to monitor compliance 

with the limit based on actual hours of operation. To achieve this and still afford the 

facility the necessary flexibility of an annual limit, the averaging period for the CO2

emission limit will be a rolling 8,760-operating hour average as monitored by a CO2

CEMS. 

Table 7-8 Simple Cycle Combustion Turbine Efficiency Data from RBLC 

Facility State Description Heat 

Capacity 

MMBtu/hr

(HHV) Net MW 

Heat Rate 

Btu/kWh 

(HHV) 

Calculated 

Efficiency

(%) 

Western 

Farmers 

Electric 

OK 

Simple 

cycle 

combustion 

turbine 

462.7 50 9,254 36.9 

El Colton, 

LLC CA LM6000 456.5 48.7 9,374 36.4 

Bayonne 

Energy 

Center 

NJ 

Rolls Royce 

Trent 

60WLE 

603 64 9,422 36.2 

Creole 

Trail LNG LA 

Simple 

cycle 

combustion 

turbine 

290 30 9,667 35.3 

Arvah B. 

Hopkins 

FL GE 

LM6000PC 489.5 50 9,790 35 

 

16 The pollutant GHGs (or greenhouse gases) that is subject to regulation under the Clean Air Act for PSD 

permitting purposes consists of the combination of six gases (carbon dioxide, methane, nitrous oxide, sulfur 

hexafluoride, hydrofluorocarbons, and perfluorocarbons). However, we are expressing the GHG emission BACT 

limit for the gas turbines in this permit as a CO2 limit because the GHG emissions from the gas turbines are 

overwhelmingly in the form of CO2 and will allow the facility to use a continuous emissions monitoring system for 

compliance monitoring. For example, Table 1C.7 of the permit application shows that, on a tonne/MWh basis, the 

methane and nitrous oxide emissions from the turbines are many orders of magnitude lower than the CO2 emissions. 

Even after accounting for the global warming potential of methane and nitrous oxide, on a ton per year basis, the 

CO2 emissions from the gas turbines represent 99.9% of the total CO2e emissions, and an efficiency-based emission 

limitation that limits CO2 emissions from the combustion of natural gas inherently limits the emission of other 

emissions created through combustion, such as methane and nitrous oxide, from the same units at the same 

efficiency. Accordingly, since BACT for GHGs emissions from the turbines at this facility has been determined to 

be 39.3% combustion efficiency and the CO2 limit selected ensures combustion efficiency at that level, adherence to 

the CO2 limit (which will be determined through the use of CEMS) will also ensure that the BACT (39.3% 

combustion efficiency) is also achieved for emissions of methane and nitrous oxide. 
22 

Generating 

Station 

Indigo 

Energy 

Facility 

CA LM6000 450 45 10,000 34.1 

Lambie 

Energy 

Center 

CA GE 

LM6000PC 500 49.9 10,020 34.1 

7.1.4 BACT During Startup and Shutdown 

It is not technically feasible to use SCR to control NOx emissions when the equipment is 

outside of the manufacturer’s recommended operating temperature ranges. For SCR, this 

occurs during turbine startup or shutdown. Based on vendor information, each turbine 

startup and shutdown is expected to last 30 and 10.5 minutes, respectively. The expected 

NOx emissions associated with individual turbine startup and shutdown events are: 

· Startup: 22.5 pounds of NOx per turbine 

· Shutdown: 6.0 pounds of NOx per turbine 

Since SCR is not effective during startup and shutdown periods, and there are no add-on 

PM controls, EPA has determined that limiting the duration and number of startups and 

shutdowns is BACT for NOx and PM during these transient periods. The permit limits 

the duration of these events to 30 minutes for startups and 10.5 minutes for shutdowns, 

and the total number of startups to 500 per turbine per calendar year. In addition, the 

permit requires the use of SCR as soon as the system reaches the minimum temperature 

to become effective, which occurs when the catalyst temperature exceeds 575 degrees F. 

In order to ensure the lowest level of NOx emissions during startup and shutdown, we 

have also set an emission limit from each CT of 22.5 pounds of NOx per startup event, 

and 6.0 pounds of NOx per shutdown event. Further, in order to ensure compliance with 

the NO2 NAAQS, we have also set a limit requiring that NOX emissions from each CT 

during startup or shutdown not exceed 26.6 lb/hr. 

We have also determined that these startup and shutdown duration limits also constitute 

BACT for GHG emissions during these periods, because the short startup and shutdown 

times will also increase the overall thermal efficiency of the facility. 

7.2 BACT for Cooling System 

Step 1 – Identify All Possible Control Technologies 

Options for controlling PM (including PM10 and PM2.5) emissions from cooling systems 

include: 

· Dry Cooling System 
23 

· Partial Dry Cooling System (including small wet cooling tower) 

· Spray-enhanced Dry Cooling (dry cooling with heat transfer enhanced by spraying 

water on the outside of the heat exchanger tubes) 

· Plume-abated Wet Cooling (wet cooling tower with a dry section that reduces the 

visible plume by heating the wet air from the wet section) 

· Non-Plume-abated Wet Cooling Tower (wet cooling tower) 

· Once-Through Cooling 

Step 2 – Eliminate Technically Infeasible Options 

Once-Through Cooling 

Once-through cooling involves the water withdrawn from rivers, streams, lakes, 

reservoirs, estuaries, oceans, or other waters. In general, once-through cooling is only 

technologically feasible when a large surface water body exists in immediate proximity to 

a power plant. Since this situation does not exist for the PPEC, we conclude that oncethrough cooling is not technologically feasible BACT for the Project. 

Step 3 – Rank Remaining Control Technologies 

After eliminating one technically infeasible option, five options remain. In descending 

order of control effectiveness, these options are: 

· Dry Cooling System 

· Partial Dry Cooling System (including small wet cooling tower) 

· Spray-enhanced Dry Cooling (dry cooling with heat transfer enhanced by spraying 

water on the outside of the heat exchanger tubes) 

· Plume-abated Wet Cooling (wet cooling tower with a dry section that reduces the 

visible plume by heating the wet air from the wet section) 

· Non-Plume-abated Wet Cooling Tower (wet cooling tower) 

The Partial Dry Cooling System proposed by the applicant for the PPEC is comprised of 

two components: a dry cooling component that provides necessary cooling most of the 

time and has zero emissions, and a small (7,000 gpm circulation rate) wet cooling 

component that supplements the dry cooling component when ambient temperatures are 

too high for the dry cooling system to function effectively. Because dry cooling does not 

produce emissions, and the wet cooling portion of the system is much smaller than 

systems designed for condensing steam from a combined cycle unit, the Partial Dry 

Cooling System produces the lowest PM emissions of the six remaining technologies 

except dry cooling, which has zero emissions. 

Step 4 – Economic, Energy and Environmental Impacts 

A technical issue associated with using 100% dry cooling to provide adequate cooling is 

its limited ability to provide adequate cooling under high-temperature conditions. 

Specifically, plant capacity would begin to decrease at ambient temperatures greater than 
24 

70 degrees F, and plant output would be no greater than 284 MW at the plant design 

maximum ambient temperature of 93 degrees F. The additional energy cost of the 

parasitic load required by a 100% dry cooling system would not be cost-effective 

($109,275/ton of PM reduced), given that total PM emissions are not expected to exceed 

1.4 tons per year. Therefore, 100% dry cooling is not cost-effective as BACT for the 

Project, and we are eliminating it as the top-ranked control option due to economic 

infeasibility. 

Step 5 – Select BACT 

EPA concurs with the applicant’s selection of the highest ranked remaining BACT 

option, a Partial Dry Cooling System, with a drift rate of 0.001%, as BACT for the 

cooling system. We note that while drift rates of 0.0005% have been achieved for oncethrough and recirculating water towers, this has occurred at facilities with much larger 

wet cooling components in their cooling towers, with much higher water recirculation 

rates. Because most of the cooling for the PPEC’s cooling towers will be accomplished 

in the dry cooling portion of the system, we have determined that the proposed drift rate 

of 0.001% is sufficiently equivalent to the lower drift rate for a system that relies entirely 

on wet cooling. To ensure this drift rate is achievable, we are proposing a TDS limit not 

to exceed 5,600 ppm. 

7.3 BACT for Circuit Breakers 

The circuit breakers are subject to BACT for GHG emissions. The only GHG emitted 

from circuit breakers is sulfur hexafluoride (SF6). 

Step 1 – Identify all control technologies

The following control technologies are potentially available for the PPEC: 

· Use of dielectric oil or compressed air circuit breakers. These types of circuit 

breakers do not contain any GHG pollutants. 

· Totally enclosed SF6 circuit breakers with leak detection systems. These types of 

circuit breakers have a specified maximum leak rate and have an alarm warning 

when a certain percentage of the SF6 has escaped. The use of an alarm identifies 

potential leak problems before the bulk of the SF6 has escaped. 

No add-on control options for GHG emissions were identified. Additionally, alternative 

gases to SF6 other than compressed air are currently not available (EPRI, 2003; NIST, 

1997). 

Step 2 – Eliminate technically infeasible control technologies 

We assume both control options are technically feasible. 
25 

Step 3 – Rank remaining control technologies 

The expected emissions from the two control options are compared in Table 7-8 below. 

Dielectric oil and compressed air circuit breakers do not contain GHG pollutants and 

therefore would not result in any GHG emissions. As such, these technologies represent 

the top-ranked control option. 

Table 7-8: Circuit Breaker Control Technologies Ranked by Control Effectiveness 

GHG Control Technologies CO2e Emission Rate (tpy) 

Dielectric oil or compressed air circuit 

breakers 0 

Enclosed-pressure SF6 circuit breakers 

with 0.5% (by weight) annual leakage 

rate and leak detection systems 40.2 

Step 4 – Economic, Energy, and Environmental Impacts 

SF6 became commercially available in 1947 and has been used in the utility industry 

since the 1960s (NIST, 1997). Despite efforts over several decades to develop a desirable 

alternative to SF6, none has been found and SF6 is still the preferred gas for electrical 

insulation and for arc quenching and current interruption equipment used in the 

transmission and distribution of electricity. For circuit breakers, for example, SF6 has 

high thermal conductivity and high dielectric strength. These properties along with its 

fast thermal and dielectric recovery are what make SF6-based circuit breakers superior to 

currently available alternative systems (NIST, 1997; EPRI, 2003). Additionally, NIST 

(1997) reports that equipment insulated with SF6 “offers significant savings in land use, is 

aesthetically acceptable, has relatively low radio and audible noise emissions and enables 

substations to be installed in populated areas close to the loads” as compared with 

dielectric oil and compressed air circuit breakers. Therefore, compared to circuit 

breakers with SF6, dielectric oil and compressed air circuit breakers have clear adverse 

environmental and energy impacts, and we are eliminating dielectric oil and compressed 

air circuit breakers as the top-ranked control option. 

Step 5 – Select BACT 

Elimination of dielectric oil or compressed air circuit breakers from consideration leaves 

enclosed-pressure SF6 circuit breakers with leak detection systems as the sole control 

option. A review of recent BACT determinations for this equipment further supports our 

conclusion: 

Table 7-9: Recent BACT Determinations for Circuit Breakers at Electric 

Generating Facilities

Facility Date Issued BACT Determination 

Lower Colorado River 

Authority – Thomas C. 

Ferguson Power Plant 

11/10/11 Enclosed-pressure SF6 circuit breakers with leak detection 

Palmdale Hybrid Power 10/18/11 Enclosed-pressure SF6 circuit breakers with an annual leakage rate 

of 0.5% by weight, a 10% by weight leak detection system 
26 

Based on the above information, we have concluded that GHG BACT for the circuit 

breakers is: 

· the use of enclosed-pressure SF6 circuit breakers with a maximum annual leakage 

rate of 0.5% by weight and a 10% by weight leak detection system, and

· an emission cap of 40.2 tpy

The SF6 emissions from the circuit breakers shall be determined by using the mass 

balance in equation DD-1 at 40 CFR Part 98, Subpart DD. 

8. Air Quality Impacts 

Clean Air Act section 165 and EPA’s PSD regulations at 40 CFR section 52.21 require an 

examination of the impacts of the proposed PPEC on ambient air quality. The applicant 

must demonstrate, using air quality models, that the facility’s emissions of the PSDregulated air pollutants would not cause or contribute to a violation of (1) the applicable 

NAAQS, or (2) the applicable PSD increments (explained below in Sections 8.4 and 8.5). 

These sections of the Fact Sheet include a discussion of the relevant background data and 

air quality modeling, and EPA’s conclusion that the Project will not cause or contribute 

to an exceedance of the applicable NAAQS or applicable PSD increments and is 

otherwise consistent with PSD requirements governing air quality. 

8.1 Introduction 

8.1.1 Overview of PSD Air Impact Requirements 

Under the PSD regulations, permit applications for major sources must include an air 

quality analysis demonstrating that the facility’s emissions of the PSD-regulated air 

pollutants will not cause or contribute to a violation of the applicable NAAQS or 

applicable PSD increments. (A PSD increment for a pollutant applies only to areas that 

meet the corresponding NAAQS.) The applicant provides separate modeling analyses for 

each criteria pollutant emitted above the applicable significant emission rate. If a 

preliminary analysis shows that the ambient concentration impact of the project by itself 

is greater than the Significant Impact Level (SIL), then a full or cumulative impact 

analysis is required for that pollutant. The cumulative impact analysis includes nearby 

pollution sources in the modeling, and adds a monitored background concentration to 

account for sources not explicitly included in the model. The cumulative impact analysis 

must demonstrate that the Project will not cause or contribute to a NAAQS or increment 

violation. If a preliminary analysis shows that the ambient concentration impact of the 

project by itself is less than the Significant Impact Level (SIL), then further analysis is 

generally not required. Required model inputs characterize the various emitting units, 

meteorology, and the land surface, and define a set of receptors (spatial locations at 
27 

which to estimate concentrations, typically out to 50 km from the facility). Modeling 

should be performed in accordance with EPA's Guideline on Air Quality Modeling, in 

Appendix W to 40 CFR Part 51 (GAQM or Appendix W). AERMOD with its default 

settings is the standard model choice, with CALPUFF available for complex wind 

situations. 

A PSD permit application typically includes a Good Engineering Practice (GEP) stack 

height analysis, to ensure that a) downwash is properly considered in the modeling, and 

b) stack heights used as inputs to the modeling are no greater than GEP height, so as to 

disallow artificial dispersion from the use of overly tall stacks. The application may also 

include initial “load screening,” in which a variety of source operating loads and ambient 

temperatures are modeled, to determine the worst-case scenario for use in the rest of the 

modeling. 

The PSD regulations also require an analysis of the impact on nearby Class I areas, 

generally those within 100 km, though the relevant Federal Land Manager (FLM) may 

specify additional or fewer areas. This analysis includes the NAAQS, PSD increments, 

and Air Quality Related Values (AQRVs). AQRVs are defined by the FLM, and 

typically limit visibility degradation and the deposition of sulfur and nitrogen. Generally, 

CALPUFF is the standard model choice for Class I analyses, since it can handle visibility 

chemistry as well as the typically large distances (over 50 km) to Class I areas. 

Finally, the PSD regulations require an additional impact analysis, showing the Project's 

effect on visibility, soils, vegetation, and growth. This visibility analysis is independent 

of the Class I visibility AQRV analysis. The additional impact analysis for the PPEC is 

discussed in Section 9 below. 

8.1.2 Identification of PPEC Modeling Documentation 

The PPEC modeling analysis comprises the documents listed in Table 8-1 below. The 

Nearby Sources (July 2011) letter proposes the nearby non-project source inventory for 

use in the cumulative impact modeling. The re-submitted PSD Application and 

associated hard-drive (September 2011) contains the results of the modeling. The 

applicant submitted a letter, Response-EPA Modeling Questions #1 (December 2011) 

addressing EPA’s comments on its choice of background monitors, meteorological data, 

and its justification, procedures and data used in its Tier 3 NO2 analysis. In addition, in 

this letter, the applicant presented results of a PM2.5 increment analysis for Class I and 

Class II areas along with an annual NO2 Class I increment analysis. Clarifying 

Information on 1-hr NO2 Results (December 2011) is an e-mail from the applicant that 

provided information clarifying the method used to obtain NO2 values for compliance 

with the 1-hr NO2 NAAQS. Response-EPA Modeling Questions #2 (January 2012) is a 

letter from the applicant that further clarified the representativeness of the meteorological 

data chosen for the modeling analysis, and addressed the NO2/NOx in-stack ratio for use 

in the NO2 input data. Response-EPA Modeling Questions #1b (February 2012) is a 

letter from the applicant that presented an NO2 compliance demonstration using El Cajon 

as an alternate monitoring site, and, to a limited extent, Otay Mesa, and their data as 
28 

background concentrations. The applicant’s letter Response-EPA Modeling Questions #3

(March 2012) provided further justification for its use of the Tier 3 PVMRM nonregulatory default option for determining NO2 concentrations for compliance with the 

NAAQS. This letter also provided supplementary information about surface roughness 

representativeness between the project site and the meteorological site. In addition, the 

applicant provided EPA with its Class II Level 2 Visibility Response (March 2012), a 

letter presenting the results of a Level 2 VISCREEN screening analysis for two federal 

land manager (FLM) Class II areas within 50 km of the project site. A letter containing 

the results of an alternate modeling analysis based on a corrected in-stack NO2/NOx ratio 

for a nearby facility are given in the applicant’s Response-EPA NO2 Alternate Modeling 

Request (May 2012).

Table 8-1: Modeling Documentation for PPEC Project PSD Application

Short name Citation

Nearby Sources 

Letter from Sierra Research (S. Hill) to EPA (C. Bohnenkamp) on 

nearby sources to be modeled, July 2011

Original PSD Application

Initial PPEC PSD Permit Application, September 2011

Response-EPA Modeling 

Questions #1

Letter from Sierra Research (S. Hill) to EPA (G. Rios) on modeling, 

December 2011 including Class I impact analysis

Clarifying Information on 1-

hr NO2 Results

Email from Sierra Research (S. Hill) to EPA (C. Holladay) forwarding 

NO2 data, both monitoring and modeling results, December 2011

Response EPA Modeling 

Questions #2

Letter from Sierra Research (S. Hill) to EPA (G. Rios) on modeling & 

PM BACT, January 2012.

Response EPA Modeling 

Questions #1b

Letter from Sierra Research (S. Hill) to EPA (G. Rios) on 1-hour ozone 

compliance demonstration and further background NO2 information, 

February 2012.

Response EPA Modeling 

Questions #3

Letter from Sierra Research (S. Hill) to EPA (G. Rios) on SF6 

emissions and modeling, March 2012

Class II Level 2 Visibility

Response

Letter from Sierra Research (S. Hill) to EPA (G. Rios), Class II Level 2 

Visibility Analysis Results, March 2012

Response-EPA NO2 

Alternate Modeling Request 

Letter from Sierra Research (S. Hill) to EPA (G. Rios), Alternative 

Modeling Analysis (Donovan NO2/NOx ratio), May 2012 

8.2. Background Ambient Air Quality 

The PSD regulations require the air quality analysis to contain air quality monitoring data 

as needed to assess ambient air quality in the area for the PSD-regulated pollutants for 

which there are NAAQS that may be affected by the source. In addition, for 

demonstrating compliance with the NAAQS, a background concentration is added to 

represent those sources not explicitly included in the modeling, so that the total accounts 

for all contributions to current air quality. 

Ambient air concentrations of ozone (O3), NO2, PM10 and PM2.5 are recorded at 
29 

monitoring stations throughout San Diego County. The area surrounding the Project site 

(within 1.5-2 miles) is an area with sparse population. Farther out, areas to the north, 

northeast, east, and southeast are all generally vacant, hilly terrain with sparse population. 

However, areas more than 2 miles to the south (Tijuana, Mexico), 5 miles west (Otay 

Mesa West) and northwest (Sunbowl) are urban or suburban areas with moderate to highdensity residential areas. The closest air quality monitoring station to the project site is 

located in Otay Mesa at the Otay Mesa-Paseo International Border crossing 1.2 miles 

south of the Project site. Pollutant concentrations recorded at this station are heavily 

influenced by the emissions from hundreds of vehicles queued and waiting at the Otay 

Mesa-Paseo International border crossing. The San Diego-1110 Beardsley Street 

monitoring station is more than 15 miles away from the Project site, and is located in the 

coastal area. The air quality at this monitoring station is not representative of the greater 

Lower Otay Lake area. In consultation with SDAPCD, the applicant chose the Chula 

Vista monitoring station, which is approximately 9 miles from the Project site, to 

represent background air pollutant concentrations for the area near the Project site. This 

site is further inland than the San Diego-1110 Beardsley Street monitoring station. It is 

also the closest source of existing data that is not heavily impacted by a known nearby 

source. The most recent years of data available at the time SDAPCD recommended the 

site for use for this Project was 2004-2008. However, EPA has added in the results of the 

2009-2010 data to the table below. 

At EPA’s request, the applicant submitted additional NO2 modeling using the El Cajon 

monitoring site located 15 miles to the north as a second site to characterize background 

concentrations for input into the modeling. Also, at EPA’s request, the applicant did 

modeling within 0.5 km of the Otay Mesa monitor to characterize background 

concentrations due to Mexican sources not included in the modeling inputs for the Pio 

Pico modeling analysis. (Letter from Sierra Research (S. Hill) to EPA (G. Rios) on 

modeling, including Class I impact analysis, December, 2011; Letter from Sierra 

Research (S. Hill) to EPA (G. Rios) on modeling & PM BACT, January, 2012). 

Table 8-2 below describes the maximum background concentrations of the PSDregulated pollutants for which there are NAAQS that may be affected by the Project’s 

emissions, and the corresponding NAAQS. 

Table 8-2 Maximum Background Concentrations and NAAQS 

2004-2010-Chula Vista Site 

NAAQS 

pollutant & 

averaging time 

Background 

Concentration, μg/m3 NAAQS, μg/m3

NO2, 1-hr 118(63 ppb) 188 (100 ppb) 

NO2, annual 36(19 ppb) 100 (53 ppb) 

PM10, 24-hr 57 150 

PM2.5, 24-hr 30 35 

PM2.5, annual 12 15 

Note: The PM2.5 24-hr value is 98th percentile averaged over three years rather than maximum 
30 

The NO2 1-hr value is 98th percentile averaged over three years rather than maximum 

8.3 Modeling Methodology for Class II areas 

The applicant modeled the impact of PPEC on the NAAQS and PSD Class II increments 

using AERMOD in accordance with EPA’s GAQM (Appendix W of 40 CFR Part 51). 

The modeling analyses included the maximum air quality impacts during normal 

operations and startups and shut-downs, as well as a variety of conditions to determine 

worst-case short-term air impacts. 

8.3.1 Model selection 

As discussed in the PSD Application (PSD Application p.4.38 pdf.147), the model that 

the applicant selected for analyzing air quality impacts in Class II areas is AERMOD, 

along with AERMAP for terrain processing and AERMET for meteorological data 

processing. This is in accordance with the default recommendations in EPA's GAQM, 

Section 4.2.2 on Refined Analytical Techniques. 

8.3.2 Meteorology model inputs 

AERMOD requires representative meteorological data in order to accurately simulate air 

quality impacts. SDAPCD provided the applicant surface meteorological data collected 

for a five consecutive-year period (2004-2008) at the Otay Mesa/Paseo International 

meteorological monitoring station maintained by the District. The District processed 

these data using EPA’s AERMET data processor and the applicant concurred with the 

processing. This station is located only 1.9 miles (3.0 km) from the Project site, with no 

intervening structures, hills, or water bodies that might significantly affect meteorological 

conditions. The Project site, the meteorological site and the “area of interest” are located 

inland and close to each other. For analyzing the representativeness of the meteorological 

data, the area of interest includes the SIA where screening modeling predicts the Project’s 

pollutant impact to be greater than the SILs, and also includes the sources and receptors 

used in the modeling. Other nearby surface meteorological sites were examined, but the 

Otay Mesa station had sufficient data completeness, is the closest, and is the most 

representative with no intervening high ground between the Project site and the 

meteorological tower. (PSD Application, p.4.41 pdf.150). EPA believes that the chosen 

2004-2008 Otay Mesa data from SDAPCD is the most representative for the PPEC 

analysis. Further discussion of the meteorological data used in the analysis is given in the 

following section on land characteristics. 

For upper air data, the applicant selected 2004-2008 Marine Corps Air Station (MCAS) at 

Miramar, California, located approximately 24 miles (39 km) northwest of the Project 

site as being the most representative site available that had data complete enough to use. 

No other upper air meteorological monitoring stations are located in the San Diego Air 

Basin. (PSD Application, p-PSD-4.41pdf.150). EPA agrees that it is appropriate to use 

the MCAS upper air data for the PPEC analysis. 
31 

8.3.3 Land characteristics model inputs 

Land characteristics are used in the AERMOD modeling system in three ways: 1) via 

elevation within AERMOD to assess plume interaction with the ground; 2) via a choice 

of rural versus urban algorithm within AERMOD; and 3) via specific values of AERMET 

parameters that affect turbulence and dispersion, namely surface roughness length, 

Bowen ratio, and albedo. The surface roughness length is related to the height of 

obstacles to the wind flow and is an important factor in determining the magnitude of 

mechanical turbulence. The Bowen ratio is an indicator of surface moisture. The albedo 

is the fraction of total incident solar radiation reflected by the surface back to space 

without absorption 

The applicant used terrain elevations from United States Geological Survey (USGS) 

National Elevation Dataset (NED) data in the GeoTIFF format (at a horizontal resolution 

of 30 meters), for receptor heights for AERMOD,, which uses them to assess plume 

distance from the ground for each receptor. All coordinates were referenced to UTM 

North American Datum 1983 (NAD83, Zone 11. The AERMOD, receptor elevations 

were interpolated among the Digital Elevation Model (DEM) nodes according to standard 

AERMAP procedure. For determining concentrations in elevated terrain, the AERMAP 

terrain preprocessor receptor-output (ROU) file option was chosen. 

The applicant used surface roughness values in the modeling inputs developed by 

SDAPCD. The District followed EPA's “AERMOD Implementation Guide” (2009 

version) in using EPA's AERSURFACE processor with the National Land Cover Data 

1992 archive to determine surface characteristics for AERMET (Letter from Sierra 

Research (S. Hill) to EPA (G. Rios) on SF6 emissions and modeling, March 2012). The 

surface roughness characteristics are representative of the area surrounding the site where 

the meteorological data is collected. The applicant also used the criteria described in 

Section 3 (Representativeness) from EPA’s Meteorological Monitoring Guidance for 

Regulatory Modeling Applications (2000). AERSURFACE uses a Land Use data base 

from 1992, and does not take buildings into account. In addition, SDAPCD reviewed 

recent aerial photos for the area, which show that the Otay Mesa Meteorological tower is 

surrounded by a light industrial and residential area that includes northern Mexico and 

the United States border area. Using this information, SDAPCD adjusted the surface 

roughness factor from the value of approximately 0.2 meters calculated by 

AERSURFACE to 0.7 meters to more accurately represent the current terrain and 

structures surrounding the Otay Mesa meteorological site. SDAPCD’s adjustment is 

supported by AERSURFACE/AERMOD guidance. 

EPA requested additional detail characterizing the surface roughness surrounding the 

Project site and correspondingly in the “area of interest”. The Meteorological Monitoring 

Guidance referenced above states that a quantitative method does not exist for 

determining representativeness absolutely. The applicant did a qualitative comparison of 

the following factors from the Meteorological Monitoring Guidance (p.3-3) 

recommended for consideration for siting: proximity, height of measurement, boundary 

layer profile considerations, and surface characteristics (Letter from Sierra Research (S. 
32 

Hill) to EPA (G. Rios) on SF6 emissions and modeling, March 2012). Based on this 

comparison, the applicant and EPA conclude that the use of Otay Mesa meteorological 

data is adequately representative of the “area of interest” and the Project site. 

8.3.4 Model receptors 

Receptors in the model are geographic locations at which the model estimates 

concentrations. The applicant places the receptors such that they have good area coverage 

and are closely spaced enough so that the maximum model concentrations can be found. 

At larger distances, spacing between receptors may be greater than it is close to the 

source, since concentrations vary less with increasing distance. The spatial extent of the 

receptors is limited by the applicable range of the model (roughly 50 km for AERMOD), 

and possibly by knowledge of the distance at which impacts fall to negligible levels. 

Receptors need be placed only in ambient air, that is, locations to which the public has 

access, and that are not inside the project fence line. 

The applicant used Cartesian coordinate receptor grids to provide adequate spatial 

coverage surrounding the project area, to identify the extent of significant impacts, and to 

identify maximum impact location. In the screening analyses, the applicant placed over 

11,000 receptors spaced no more than 250 meters apart out to 30 km. The most distant 

receptor with a significant project impact was 24 km east of the project site (1-hour NO2). 

The significant impact receptors were used to define the domain where the cumulative 

impact analysis was be performed. 

For the cumulative impact analyses, the applicant used over 9600 receptors to determine 

NO2 impacts and over 1600 receptors to determine PM2.5 impacts. The applicant 

developed a nested grid to fully represent the maximum impact areas. This grid has 25-

meter resolution along the facility fence-line, 100-meter resolution from 100 meters to 

1,000 meters from the fence-line, and 250-meter spacing out to at least 10 km from the 

most distant source modeled. Additional refined receptor grids with 25-meter resolution 

were placed around the maximum first-high and maximum second-high coarse grid 

impacts and extended out 1,000 meters in all directions. Receptor locations at which the 

model did not predict NO2, PM10/ PM2.5 significant impact level exceedances were not 

included in cumulative analyses for these pollutants. (p.3 of “Additional Clarification 

Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National 

Ambient Air Quality Standard”, Memorandum from Tyler Fox, EPA Air Quality 

Modeling Group to EPA Regional Air Division Directors, March 1, 2011). (PSD 

Application p.PSD-4.40 pdf.149) 

8.3.5 Load screening and stack parameter model inputs 

The applicant performed initial “load screening” modeling, in which six source operating 

loads and ambient temperatures were modeled, to determine the “worst case” stack 

parameter scenario for use in the rest of the modeling, whenever normal operations are 

considered. It modeled two loads: a minimum load of 50% and a maximum load of 

100%. The choice of “worst case” is different for each pollutant and averaging time, 
33 

because different pollutants’ emissions respond differently to temperature and flow rate. 

Ambient temperatures modeled were 30°F, 63° F and 110°F. The “worst case” hourly 

scenario (for this project the only hourly pollutant is NO2) is expected to occur under the 

conditions with the highest firing rate: 100% load and 30°F ambient temperature. The 

worst case annual scenario for PM10/PM2.5 is expected under low load, cold temperature 

conditions; for annual NO2 it is the peak load, 63° F case. The “worst case” 24-hour 

average (for this project only PM10/PM2.5) scenario is the same as for the annual average 

(PSD Application p.PSD-4.42 pdf.151). In addition, for the NO2 1-hour averaging time, 

the PPEC’s startup and shutdown emissions would be higher than the normal operating 

emissions because the emission control systems are not fully operational. For the PPEC, 

startup emissions are higher than shutdown emissions. The “worst case” load scenario 

for startup is the low load cold temperature scenario. Further discussion of the impact of 

these emissions is provided in Section 8.4.3.5. The remainder of the modeling done by 

the applicant used the corresponding stack parameters to provide conservative estimates 

of PPEC impacts and are represented in the Table 8.3 below. 

Table 8-3: Load screening and stack parameters 

Screening Modeling Inputs 

Pio Pico Energy Center 

Ambient 

Temp 

Stack 

Height 

Stack 

Diameter 

Stack 

Flow 

Stack 

Velocity 

Stack 

Temp 

Operating Mode degrees F feet feet wacfm ft/sec degrees F 

Startup/shutdown 30 100 14.5 645,580 65.16 820 

Hot Peak 110 100 14.5 877,825 88.60 802 

Average Peak 63 100 14.5 913,777 92.22 785 

Cold Peak 30 100 14.5 909,632 91.81 754 

Hot Low 122 100 14.5 733,309 74.01 825 

Average Low 63 100 14.5 646,428 65.24 831 

Cold Low 30 100 14.5 645,580 65.16 820 

Pollutant NOx PM10/ 

PM2.5

NOx PM10/ 

PM2.5

Operating Mode lb/hr lb/hr g/sec g/sec 

Startup/Shutdown 26.63 5.50 3.36 0.69 

Hot Peak 7.72 5.50 0.97 0.69 

Average Peak 8.18 5.50 1.03 0.69 

Cold Peak 8.07 5.50 1.02 0.69 

Hot Low 5.92 5.50 0.75 0.69 

Average Low 4.94 5.50 0.62 0.69 

Cold Low 4.92 5.50 0.62 0.69 

Startup Modeling Inputs 

Ambient 

Temperature 

Stack 

Height 

Stack 

Diameter 

Stack 

Flow 

Stack 

Velocity 

Stack Temp 

Case degrees F feet feet wacfm ft/second degrees F 

Cold Low 30 100 14.5 645,580 65.16 820 

Source: PSD Application Appendix Table 1D.1 and 1D.2, p.PSD-App-1.57-1.58pdf.370-371 
34 

8.3.6 Good Engineering Practice (GEP) Analysis 

The applicant performed a Good Engineering Practice (GEP) stack height analysis, to 

ensure that a) downwash is properly considered in the modeling, and b) stack heights 

used as inputs to the modeling are no greater than GEP height, so as to disallow artificial 

dispersion from the use of overly tall stacks. As is typical, the GEP analysis was 

performed with EPA’s BPIP (Building Profile Input Program) software, which uses 

building dimensions and stack heights as inputs. Based on the analysis, the applicant 

shows that the GEP stack height for the main combustion turbines was greater than 65 m 

(213 ft), which is greater than the planned actual height of 30.4 m (100 ft). The applicant 

showed that the GEP stack height for the other equipment was similarly greater than the 

planned heights. So, for all emitting units, the applicant used the planned actual stack 

heights for inputs in AERMOD modeling, and included wind direction-specific 

Equivalent Building Dimensions to properly account for downwash. (PSD Application 

p.PSD 4-39 pdf.148) 

8.4 National Ambient Air Quality Standards and PSD Class II Increment 

Consumption Analysis 

8.4.1 Pollutants with significant emissions 

40 CFR 52.21 requires an air quality impact analysis for each PSD-regulated pollutant 

(for which there is a NAAQS) that a major source has the potential to emit in a 

significant amount, i.e., an amount greater than the Significant Emission Rate for the 

pollutant. Applicable PPEC emissions and the Significant Emission Rates are shown in 

Table 8-4 (derived from PSD Application Table 1-1, p.PSD1.1 pdf.11). As shown in 

Table 8-4, EPA does not expect PPEC to emit CO, Pb and SO2 in significant amounts. 

However, based on the estimates submitted by the applicant EPA expects the PPEC to 

emit NOX, PM10, and PM2.5 in significant amounts. Therefore, this project triggers the air 

impact analyses for NO2, PM10 and PM2.5. 

Table 8-4: PSD Applicability to PPEC: Pollutants Emitted in Significant Amounts 

Criteria Pollutant 

PPEC Emissions, 

tons/year 

Significant Emission 

Rate, tons/year PSD applicable? 

CO 96.4 100 No 

NOX 70.4 40 Yes 

PM10 37.2 15 Yes 

PM2.5 37.2 10 Yes 

SO2 4.1 40 No 

Pb 0.0 0.6 No 

Source: PSD Application Table 1-1, p.PSD1.1 pdf.11 

8.4.2 Preliminary analysis: Project-only impacts (Normal Operations and Startup) 

EPA has established Significant Impact Levels (SILs) to characterize air quality impacts. 
35 

A SIL is the ambient concentration resulting from the facility’s emissions, for a given 

pollutant and averaging period, below which the source is considered to have an 

insignificant impact. For maximum modeled concentrations below the SIL, further air 

quality analysis for the pollutant may not be necessary. For maximum concentrations 

that exceed the SIL, EPA requires a cumulative modeling analysis which incorporates the 

combined impact of nearby sources of air pollution to determine compliance with the 

NAAQS and PSD increments. 

Table 8-5 shows the results of the preliminary or Project-only analysis based on normal 

operations for the PPEC. Startup emissions are used for determining the maximum 1-hr 

NO2 impacts with maximum project impacts from normal operations included in 

parentheses. PPEC impacts are significant only for 1-hour NO2 and 24-hour PM2.5, and 

we have determined that cumulative impact analyses are required for only these two 

pollutants. 

Table 8-5: PPEC Significant Impacts 

NAAQS pollutant & 

averaging time 

Project-only 

Modeled Impact 

ug/m3

Significant Impact 

Level (SIL), μg/m3

Project impact 

significant? 

NO2, 1-hr 111 (27) 7.5 (4 ppb) Yes 

NO2, annual 0.3 1 No 

PM10, 24-hr 3 5 No 

PM2.5, 24-hr 2.6 1.2 Yes 

PM2.5, annual 0.26 0.3 No 

Sources: PSD Application Table 4-24, p.PSD 4-43pdf.152 

8.4.3 Cumulative impact analysis 

A cumulative NAAQS or PSD increment impact analysis considers impacts from nearby 

sources in addition to impacts from the Project itself. In addition, for demonstrating 

compliance with the NAAQS, the applicant adds a background concentration to represent 

those sources not explicitly included in the modeling, so that the total accounts for all 

contributions to current air quality. In this case, the applicant submitted cumulative 

impact analyses demonstrating compliance with the annual PM2.5 NAAQS, the 24-hour 

PM2.5 NAAQS and the 1-hour NO2 NAAQS. 

For demonstrating compliance with the PSD increment, only increment-consuming 

sources need to be included, because the increment concerns only changes occurring 

since the applicable baseline date. In this analysis, there is no 1-hour NO2 PSD 

increment; therefore, only 24-hour PM2.5 requires a cumulative PSD increment analysis. 

With respect to the PSD increment analysis for PM2.5, the applicable trigger date is 

October 20, 2011. In general, for PM2.5, the minor source baseline date is the earliest 

date after the trigger date of a complete PSD permit application for a source with a 

proposed increase in emissions of PM2.5 that is significant. No source triggered the minor 
36 

source baseline date in the area at issue prior to the submittal of PPEC’s complete PSD 

permit application. Thus, the first source to submit a complete PSD permit application in 

the area at issue is PPEC, and the applicable minor source baseline date for PM2.5 is the 

date on which the PPEC PSD permit application was complete, i.e., June 14, 2012. The 

minor source baseline area established by this source for the PM2.5 increment is San 

Diego County; PPEC will not have an air quality impact equal to or greater than 0.3 

ug/m3(annual average) for PM2.5 in any other intrastate area designated attainment or 

unclassifiable. (See 40 C.F.R. 52.21(b)(15)(i).) There have been no actual emissions 

changes of PM2.5 from any new or modified major stationary source on which 

construction commenced after October 20, 2010, the major source baseline date for 

PM2.5, for purposes of analyzing PM2.5 increment consumption here. Therefore, the 

applicant considered only the allowable emissions increase from PPEC in the 24-hour 

PM2.5 increment analysis. 

8.4.3.1 Nearby source emission inventory 

For both the PSD increment and NAAQS analyses, there may be a large number of 

sources that could potentially be included, so judgment must be applied to exclude small 

and/or distant sources that have only a negligible contribution to total concentrations. 

Only sources with a significant concentration gradient in the vicinity of the source need 

be included; the number of such sources is expected to be small except in unusual 

situations. (GAQM 8.2.3) 

SDAPCD provided a list of all stationary sources within the District and within 80 km of 

the project (approximate distance to the farthest significant impact plus 50 km). A 

comprehensive procedure was used to determine which sources were included in the 

emissions inventory. 

It should be noted that short-term maximum emission rates rather than annual emission 

rates determine the distance over which a facility might have a significant impact for 

short-term standards (e.g., hourly NO2). Peak rates that occur during startup determine 

the PPEC significant impact area for hourly NO2. 

The applicant identified five facilities nearby for inclusion in the emission inventory for 

the cumulative analysis, based on discussions with SDAPCD. The following non-PPEC 

facilities and their NOx and PM2.5 emissions are included in the cumulative compliance 

demonstration: Larkspur Energy Facility (a small peaking plant 2.5 km west of the 

Project site); Pacific Recovery Corp. (a landfill gas waste-to-energy facility 9.2 km west 

of the Project site); Calpeak Border (a 50 MW peaking plant located 2.6 km southwest of 

the Project site); Donovan Correctional Facility (a small turbine 1.5 km northwest of the 

Project site) and Otay Mesa Energy Center (a baseload power plant located adjacent to 

the Project site). These facilities are large enough and close enough to the Project site to 

have the potential to directly impact the Project’s significant impact area. (PSD 

Application, p. App-1.134 pdf.451). 

Current EPA NO2 guidance suggests that emphasis on determining which nearby sources 
37 

to include in the nearby source inventory should focus on the area within about 10 

kilometers of the project location in most cases, which indicates that the PPEC inventory 

is adequate for performing these cumulative analyses (p.16 of “Additional Clarification 

Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National 

Ambient Air Quality Standard”, Memorandum from Tyler Fox, EPA Air Quality 

Modeling Group to EPA Regional Air Division Directors, March 1, 2011). 

Nevertheless, as an additional factor, the applicant also considered emission levels and 

distance as factors for determining which sources with small emissions and/or at large 

distances would be reasonable to exclude from the analysis. The applicant proposed that 

NO2 sources with a ratio less than 70 TPY/24 km=2.9 and PM2.5 sources with a ratio less 

than 35.8TPY/3.8 km = 9.4 (based on the ratio of annual emissions to the distance to the 

limits of significant impact) be eligible for consideration for exclusion from the relevant 

inventories. This ratio was used to classify non-Project sources into three categories: 

those that could clearly be excluded, those that clearly should be included and those 

where additional judgment is required. 

Therefore, taking into consideration the current EPA guidance suggesting a focus on 

sources within 10 km, EPA concludes that the combination of a representative 

background monitored concentration, and the additional consideration of emission levels 

and distance, provide sufficient justifications for the inventory used in the cumulative 

analysis. 

8.4.3.2 PM2.5-specific issues 

EPA has issued guidance on how to combine modeled results with monitored background 

concentrations, which the applicant adequately followed. (“Modeling Procedures for 

Demonstrating Compliance with PM2.5 NAAQS”, memorandum from Stephen D. Page, 

Director, EPA OAQPS, March 23, 2010.) 

The applicant provided a cumulative PM2.5 analysis. The applicant’s analysis 

conservatively assumed that all PM10 emissions were also PM2.5 emissions, and therefore 

made use of PM10 emissions data as input to the modeling, so actual PM2.5 impacts would 

be expected to be lower than those indicated in the model results. 

PM2.5 is either directly emitted from a source (primary emissions) or formed through 

chemical reactions with pollutants already in the atmosphere (secondary formation). 

EPA has not developed and recommended a near-field model that includes the necessary 

chemistry algorithms to estimate secondary impacts in an ambient air analysis. 

The PPEC application does not specifically address secondarily formed PM2.5 (as 

distinguished from directly emitted primary PM2.5). Secondary PM2.5 is formed through 

the emission of non-particulates (i.e., gases) – such as SO2 and NOX – that turn into fine 

particulates in the atmosphere through chemical reactions or condensation. Using the 

results for PM2.5 impacts given in Tables 8-5 and 8-7 and the projected emission rates of 

SO2, NOX and PM2.5, EPA notes that the PPEC emissions of 4.1 TPY SO2 are less than 
38 

the SO2 SER of 40 TPY, and would not be expected to result in significant secondary 

PM2.5. The PPEC NOX emissions of 70.4 TPY are above the NOX SER of 40 TPY. 

However, secondary PM2.5 formation occurs only as a result of chemical transformations 

that would affect only a portion of those emissions, and which occur gradually over time 

as the plume travels and becomes increasingly diffuse, and would be expected to be 

considerably smaller than the impacts from the 37.2 TPY of directly emitted primary 

PM2.5. The maximum impact of source primary PM2.5 was 2.6 ug/m3

for 24-hour PM2.5

and 0.26 ug/m3

for annual PM2.5. The PM2.5 cumulative impacts analysis indicates that at 

least 7.3 ug/m3and 2.5 ug/m3remain available for the 24-hour and annual averaging 

times, respectively, before the NAAQS is challenged (35 ug/m3

– 27.7 ug/m3 for the 24-

hour averaging time, and 15 ug/m3

– 12.5 ug/m3

for the annual averaging time). Because 

the secondary PM2.5 formation from PPEC’s NOX emissions would be expected to be 

considerably smaller than the primary PM2.5 impacts, they would also be smaller than the 

additional 7.3 ug/m3or 2.5 ug/m3needed to cause or contribute to a PM2.5 NAAQS 

violation. In addition, because most of these chemical transformations in the atmosphere 

occur slowly (over hours or even days, depending on atmospheric conditions and other 

variables), secondary PM2.5 impacts generally occur at some distance from the source of 

its gaseous emissions precursors, and are unlikely to overlap with maximum primary 

PM2.5 impacts that are close by. 

8.4.3.3 NO2-specific issues 

While the new 1-hour NO2 NAAQS is defined relative to ambient concentrations of NO2, 

the majority of NOx emissions from stationary sources are in the form of nitric oxide 

(NO) rather than NO2. Appendix W notes that the impact of an individual source on 

ambient NO2 depends in part “on the chemical environment into which the source’s 

plume is to be emitted” (see Section 5.1.j). Because of the role NOx chemistry plays in 

determining ambient impact levels of NO2 based on modeled NOx emissions, Section 

5.2.4 of Appendix W recommends a three-tiered screening approach for NO2 modeling. 

Later guidance documents issued by EPA expand on this approach. Tier 1 assumes full 

conversion of NO to NO2. Tiers 2 and 3 are refinements of the amount of conversion of 

NO to NO2. The applicant used the Tier 3 Plume Volume Molar Ratio Method 

(PVMRM) option in AERMOD, which simulates the interaction of NO with ambient O3

to form NO2. The PVMRM determines the conversion rate for NOx to NO2 based on a 

calculation of the NOx emitted into the plume, and the number of O3 moles contained 

within the volume of the plume between the source and receptor. In addition to requiring 

monitored ozone, the method requires specification of an in-stack NO2/NOX ratio. The 

following presents a discussion of the in-stack NO2/NOx ratios used in PVMRM for the 

proposed turbines and nearby sources for the cumulative impact analysis. 

A. In-stack NO2/NOx ratio 

Defining source-specific in-stack NO2/NOx ratios is part of the refinement of the Tier 3 

PVMRM. An in-stack NO2/NOx ratio of 0.50 is the default value and can be used 

without further justification. This applies not only for the proposed LMS100 turbines but 

also for the other sources used in the cumulative impacts analysis. As discussed in 
39 

Section 8.4.3.1, five facilities (with ten emission units among them) were included in the 

cumulative impacts analysis. For the proposed turbines and units in the cumulative 

impacts analysis, the applicant did not use the default value of 0.50. Therefore, to 

determine whether the proposed values would be acceptable, we requested additional 

information from the applicant, obtained available source test summary results for the 

five facilities’ emission units, and further discussed the selection of the ratios with the 

applicant and the SDAPCD. Table 8-6 presents the resulting PVMRM in-stack 

NO2/NOx ratios. 

Table 8-6: In-stack NO2/NOx Ratios 

Source / Emission Units

NO2 / NOx 

ratio

Pio Pico turbines – startup operations 0.24

Pio Pico turbines – normal operations 0.13

CalPeak Border 0.10

Otay Mesa, Units #1, #2 0.05

Pacific Recovery Landfill, Units #1, #2, #3, #4 0.75

Larkspur, Units #1, #2 0.10

Donovan Detention Center 0.56

1. Proposed Turbines 

The applicant proposed an in-stack NO2/NOx of 0.13 for normal operations and 0.24 for 

startup, when the SCR is not fully operational. Absent available ratios specific for 

LMS100 turbine operations, the SDAPCD recommended these two ratios based on 

source test results of gas turbines with operations considered similar to a LMS100 

turbine. For normal operations, the average of source test results from four LM6000 PC 

SPRINT turbines were used to establish the 0.13 ratio. These turbines were selected by 

the SDAPCD because, similar to the LMS100, the LM6000PC SPRINT turbines are 

aeroderivative turbines with diffusion flame combustors, operating in simple-cycle mode 

with add-on catalyst system controls. While the LM6000PC SPRINT uses water 

injection to reduce combustion temperatures and the formation of thermal NOx by 

cooling, the LMS100 interstage cooling system achieves a similar and more effective 

outcome. For startup operations when the SCR is not fully operational, the average of 

source test results from eleven natural gas-fired, water injection-only GE Frame 5 

turbines without SCR and oxidation catalyst add-on controls were used to establish the 

0.24 ratio. 

2. Nearby Sources for Cumulative Impacts Analysis 

The applicant performed a full impacts analysis, which included the ten emission units at 

the five nearby facilities. In-stack ratios for these emission units were based on available 

SDAPCD historical source test data. In a January 2012 response to an EPA December 

2011 request for additional information,17 the applicant presented its approach for 

 

17 Letter from Sierra Research (S. Hill) to EPA (G. Rios) on modeling & PM BACT, January, 2012. 
40 

selecting the in-stack NO2/NOx ratios. After review of this data, we requested further 

clarification in March 201218 including more details about the source test data. In May 

2012, we reviewed additional source test summary results. We further discussed the 

selection of the ratios with the applicant and the SDAPCD and requested that an alternate 

modeling evaluation be performed replacing an originally proposed ratio of 0.10 with 

0.56 for the Donovan Detention Center to reflect the average of seven source tests for this 

emission unit. Table 8-7 in Section 8.4.3.5 presents the modeling results. 

B. NO2 monitor representativeness/conservativeness 

As mentioned above, the applicant chose the Chula Vista monitor for background NO2

concentrations. This monitor is 9 miles from the PPEC site. As mentioned in Section 8.2, 

EPA requested that the applicant perform additional modeling using background 

concentrations from El Cajon and, to a limited extent, from Otay Mesa. 

C. O3 background monitor representativeness 

The applicant notes that since O3 is a regionally-formed pollutant, the nearness of the 

monitoring site to the Project is the most important criterion for representativeness (NO2

Memo #1 p.10 pdf.10). The Chula Vista monitor is 9 miles away from the PPEC site, 

and EPA agrees that it is adequately representative. 

D. Missing O3 data procedure 

The applicant reported and provided the procedure that SDAPCD used to fill in missing 

ozone data to ensure that NO to NO2 conversion is not underestimated. 

EPA concurs that SDAPCD followed a reasonable and conservative procedure for filling 

in missing ozone values. 

E. Combining modeled and monitored values 

Originally, the applicant proposed to combine each modeled concentration with the 

background concentration from the corresponding hour (“hour-by-hour” approach). The 

applicant later switched to a variant of EPA’s March 2011 memo’s19 “first tier” approach: 

it used month by hour-of-day temporal pairing. The applicant correctly used the first 

highest values from the distribution for each temporal combination. (The EPA March 

2011 memo’s “first-tier” approach uses the 98th percentile of the annual distribution of 

daily maximum 1-hour values averaged across the most recent three years of monitored 

data as a uniform background contribution but also mentions the above procedure as a 

 

18 Email from EPA (C.Holladay) to Sierra Research (S. Hill), NO2/NOx In-Stack Ratio Documentation and Test 

Results for Pio Pico, March, 2012. 

19 “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 National 

Ambient Air Quality Standard”, Memorandum from Tyler Fox, EPA Air Quality Modeling Group to EPA Regional 

Air Division Directors, March 1, 2011. 

http://www.epa.gov/ttn/scram/Additional_Clarifications_AppendixW_Hourly-NO2-NAAQS_FINAL_03-01-

2011.pdf 
41 

suggested temporal pairing option on p.20.) This procedure is based on a conservative 

assumption. 

EPA believes that the applicant’s overall approach to the 1-hour NO2 analysis for the 

PPEC, including the emission inventory, background concentrations of NO2 and O3, and 

method for combining model results with monitored values, is adequately conservative. 

8.4.3.4 Startup and shutdown analyses 

As stated in Section 8.3.5, the applicant estimated combustion turbine NOX emissions 

during startup and shutdown to be substantially higher than during normal operations, 

and thus the applicant also modeled for startup (as emissions are highest during startup). 

The stack parameters input into the model such as exit temperature and exhaust velocity 

were consistent with a 50% operating load; the ambient temperature the applicant used 

represented worst-case meteorological conditions, i.e., emission into a cold morning 

stable layer. Since startup duration may not exceed half an hour, worst case hourly 

emissions consist of a half-hour of startup emissions followed by a half hour of normal 

operations. For NOX, this is 1/2 of 45.0 (22.5) lb/hr, plus 4.1 lb/hr, for a combined rate 

of 26.6 lb/hr per turbine (PSD Application Tables 4-18 and 4-19. p.PSD-4.33-4.34 

pdf.142-143). This 1-hour NO2 startup analysis continues to use the conservative 

assumptions discussed above for the analysis of normal operations. The model results are 

shown in Table 8-6 for the cumulative impacts analysis. The results demonstrate that 

emissions from PPEC will also comply with the 1-hour NO2 NAAQS during startup and 

shutdown conditions. 

8.4.3.5 Results of the cumulative impacts analysis 

The results of the PSD cumulative impacts analysis for PPEC’s normal operations for 

PM2.5 and startup emissions for 1-hr NO2 are shown in Table 8-6. In addition, the results 

include additional modeling using background NO2 concentrations from the El Cajon 

monitor to the north of the Project site and from the Otay Mesa monitor 2 miles to the 

southwest. The analysis demonstrates that emissions from PPEC will not cause or 

contribute to exceedances of the NAAQS for 1-hour NO2 or 24-hour PM2.5 or for any 

applicable PSD increments. As discussed above, PPEC’s maximum modeled 

concentrations are below the SILs for annual NO2, 24-hour PM10, and annual PM2.5; 

therefore, a cumulative impacts analysis was not required to demonstrate compliance for 

these pollutants/averaging times. A cumulative impacts analysis was also done for PM2.5

annual, however, and the results included in the table. 

EPA also considered additional information to ensure that the Project would not be 

responsible for causing a new NAAQS exceedance outside this modeling area. EPA 

considered sources in San Diego County (no sources of interest were located outside of 

the county) that were not included, but which had been evaluated for inclusion/exclusion, 

in the cumulative impacts modeling above. EPA concluded that these sources are either 

small enough or distant enough that the Project’s expected emissions along with 

emissions from these sources would not create any new NAAQS exceedance in the 
42 

modeling area outside of the SIA. 

Table 8-7: PPEC Compliance with Class II PSD Increments and NAAQS 

NAAQS 

pollutant & 

averaging 

time 

All 

Sources 

Modeled 

Impact 

PSD 

Increment 

Consumption

Background 

Concentration

Cumulative 

impact w/ 

background

NAAQS 

(ug/m3) 

PSD 

Increment

NO2, 1-hr 111 NA (hourly) 179 188 (100 

ppb) NA 

PM2.5, 24-hr 0.7 2.6 27.0 27.7 35 9 

PM2.5, annual 1.9 0.3 12.5 14.4 15 4 

Notes: - There are no PSD increments defined for 1-hour NO2. 

Sources:

NO2, PM2.5 (NAAQS): PSD Application Table 4-25, p. PSD-4.45 pdf154 and Letter from Sierra Research (S. Hill) 

to EPA (G. Rios), Alternative Modeling Analysis (Donovan NO2/NOx ratio), May 2012 

PM2.5 (PSD increment): Letter from Sierra Research (S. Hill) to EPA (G. Rios) on modeling, December 2011 

8.5 Class I Area Analysis 

8.5.1 Air Quality Related Values 

The two nearest Class I areas are listed below, with only one being located within 100 km 

of the Project site: 

· Agua Tibia Wilderness (91 km) 

· San Jacinto Wilderness (122 km) 

Based on the most recent Federal Land Managers’ Air Quality Related Values (AQRV) 

Work Group (FLAG) published guidance20 the following screening approach is used to 

determine whether a more refined Class I Air Quality Analysis is required. This 

approach, which only applies to projects located more than 50 km from a Class I area, 

requires adding all of the visibility-related emissions (SO2, NOx, PM10 and sulfuric acid 

mist) from a project (based on 24-hour maximum allowable emissions expressed in units 

of tons per year) and dividing the sum by the distance between the project and the Class I 

area. If the result is less than 10, the project is presumed to have negligible impacts to 

Class I AQRVs. The table below shows that the Project’s emissions are well below the 

FLAG screening criteria. Therefore, no further Class I AQRV analysis is required. 
43 

8.5.2 Class I Increment Consumption Analysis 

EPA requires an analysis addressing Class I increment impacts for the applicable 

pollutants regardless of the results of the Class I AQRV analysis. This analysis was not 

in the original application. EPA requested that the applicant provide an analysis to 

address increment consumption in the Class I areas within 300 km of the project site. 

The applicant provided an analysis (Letter from Sierra Research (S. Hill) to EPA (G. 

Rios) on modeling, including Class I impact analysis, December 2011) using AERMOD 

to show that the most distant location where the impacts of NO2 or PM2.5 emissions from 

the Project exceed the Class I SILs is 52 km. The closest Class I area, the Agua Tibia 

Wilderness, is 91 km from the Project site. Impacts from the Project would continue to 

decrease as the distance from the Project site increases. As shown in Table 8-8, for the 

PSD pollutants for which there are applicable increments, PPEC impacts are less than the 

Class I SILs almost 40 km away from the nearest Class I area. 

As discussed above, PPEC’s complete application on June 14, 2012 established the minor 

source baseline date and established San Diego County as the minor source baseline area 

for the PM2.5 increment. As noted previously, there have been no changes in actual 

emissions of PM2.5 from any major stationary source on which construction commenced 

after October 20, 2010, the major source baseline date for PM2.5, for purposes of 

analyzing PM2.5 increment consumption here. Therefore, for purposes of this Class I 

PM2.5 increment analysis, we consider only PPEC’s increment consumption. Because 

PPEC impacts are less than the Class I SILs at a substantial distance from the closest 

Class I area, and the Class I SILs are much lower than the increments, EPA has 

determined that PPEC’s maximum impacts are well below the PM2.5 increments. 

Therefore, the applicant has demonstrated that the Project will not cause or contribute to 

any Class I PSD increment violation for PM2.5. 

For NO2 annual increment impacts, extrapolating the Project’s predicted impacts out to 

the border of the closest Class I area would result in extremely low impacts since the 

significant impact distance is only 7 km. In addition, with the continued NOx reductions 

since the NOx baseline date (1988), EPA concludes no increment violation is likely even 
44 

if other sources outside of the significant impact distance were to be modeled. 

Table 8-8: PPEC Class I Increment Impacts 

Class I Area 

Pollutant and 

averaging time 

Project Impact, 

less than SIL, 

distance km SIL, μg/m3

Class I PSD 

Increment, 

μg/m3

Agua Tibia 

(91 km) 

NO2, annual 7 0.1 2.5 

PM2.5, 24-hr 52 0.07 2 

PM2.5, annual 6 0.06 1 

Source: Letter from Sierra Research (S. Hill) to EPA (G. Rios) on modeling, including Class I impact analysis, 

December 2011 

9. Additional Impact Analysis 

In addition to assessing the ambient air quality impacts expected from a proposed new 

source, the PSD regulations require that EPA evaluate other potential impacts on 1) soils 

and vegetation; 2) growth; and 3) visibility impairment. 40 CFR § 52.21(o). The depth 

of the analysis generally depends on existing air quality, the quantity of emissions, and 

the sensitivity of local soils, vegetation, and visibility in the source's impact area. 

9.1 Soils and Vegetation 

The additional impact analysis includes consideration of potential impacts to soils and 

vegetation associated with the PPEC’s emissions. 40 CFR § 52.21(o). This component 

generally includes: 

· a screening analysis to determine if maximum modeled ground-level 

concentrations of project pollutants could have an impact on plants; and 

· a discussion of soils and vegetation that may be affected by proposed project 

emissions and the potential impacts on such soils and vegetation associated with 

such emissions. 

The PPEC is proposed within an industrial park, the Otay Mesa Business Park, in the 

County of San Diego, with the majority of the area being previously disturbed or 

developed with commercial and public infrastructure. The industrial park developer 

graded the Project property, which was planned prior to the inception of, and would have 

occurred regardless of, the proposed PPEC. The applicant presented its discussion of the 

potential impacts on soils and vegetation in Section 5.0 of its PSD permit application. 

Section 5.0 included a discussion of the existing setting, nitrogen deposition potential, 

modeled impacts, and biological resources (including observed vegetation 

communities/land cover types and plants). 

The initial application (dated September 2011) presents the applicant’s use of EPA’s 
45 

"Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils and 

Animals" (1980)20 to determine if maximum modeled ground-level concentrations of 

SO2, NO2 and CO from the PPEC could have an impact on plants, soils, and animals. In 

addition, the applicant submitted information that included a discussion of the Project 

location and adjacent areas, the observed vegetation communities/land cover types, the 

observed plants, and soil types as part of the description of the various vegetation 

communities/land cover types and plant habitat observed within the project study area. 

The modeled impacts of SO2, NO2, and CO emissions from the facility, individually, and 

in addition to the background concentrations of NO2 and CO,21 are well below the 

minimum impact levels/screening concentrations identified in the Screening Procedure 

for sensitive plants. The following table summarizes information in this regard from 

Section 5.0 (Impacts on Soils and Vegetation) in the PSD application (Table 5-1, p. PSD5.4). 

Table 9. 1 Project Maximum Concentrations and EPA Guidance Levels 

for Screening Concentrations for Ambient Exposures 

Criteria Pollutant 

and Guidance 

Averaging Time 

EPA Screening 

Concentration 

(μg/m3) 

Modeled Maximum 

Concentrations

(μg/m3) 

Modeling 

Averaging 

time 

SO2 1-Hour 917 6 1 hour 

SO2 3-Hours 

786 

(0.30 ppm) 

3 

(0.0011 ppm) 3 hour 

SO2 Annual 18 <0.1 Annual 

NO2 4-Hours 3,760 111 1 hour 

NO2 8-Hours 3,760 111 1 hour 

NO2 1-Month 564 111 1 hour 

NO2 Annual 94 

(0.05 ppm) 

0.3 

(0.00016 ppm) Annual 

CO Weekly 1,800,000 52 8 hour 

For most types of soils and vegetation, ambient concentrations of criteria pollutants 

below the secondary NAAQS will not result in harmful effects because the secondary 

NAAQS are set to protect public welfare, including animals, plants, soils, and materials. 

The modeled maximum concentrations of SO2, NO2, PM2.5

22 

and PM10

23 are also 

significantly below the secondary NAAQS that have been established by EPA:24 

 

20 “Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals,” EPA 450/2-81-078, 

December 1980. 

21

 The PPEC is not subject to PSD review for SO2, and therefore background data is not included. 

22

 The modeled maximum concentrations for the annual and 24-hour secondary PM2.5 standards are 0.26 μg/m3 and 

2.6 μg/m3, respectively. 

23

 The modeled maximum concentrations for the 24-hour secondary PM10 standard is 57 μg/m3. 

24 EPA has not promulgated secondary NAAQS for CO. 
46 

· secondary 3-hour NAAQS for SO2 = 0.5 ppm 

· secondary annual NAAQS for NO2 = 0.053 ppm 

· secondary annual NAAQS for PM2.5 = 15 μg/m3

· secondary 24-hour NAAQS for PM2.5 = 35 μg/m3, and 

· secondary 24-hour NAAQS for PM10 = 150 μg/m3

The applicant’s description of the soils and vegetation that may be affected by the Project 

included a discussion of the Project location and adjacent areas, the observed vegetation 

communities/land cover types, and the observed plants in the Project’s biological study 

area or study area. The study area includes the physical ground disturbance footprint 

(i.e., generating facility site, construction laydown area, transmission line pole locales, 

gas line) plus a 1,000-foot buffer (Section 5.0, p. PSD 5-6) as presented in Figure 5.6-1 

(Section 5.0, p. PSD-5.43). A description of soil types was part of the description of the 

various vegetation communities/land cover types and plant habitat observed within the 

study area. Types of soils identified include loam or clay, sandy, serpentine/serpentinite, 

gabbroic, metavolcanic, mesic, and alkaline soils. Thirty-nine special-status plant species 

were identified in the study area (Section 5.0, Table 5.6-4, pp. PSD-5.14 to 5.17). All 39 

special-status plant species were determined not to occur within the project disturbance 

footprint or were negligible within the project disturbance footprint. 

The applicant’s discussion of impacts associated with potential nitrogen deposition from 

the Project included the following: 

· For characterizing a threshold of significance for sensitive habitats, the applicant 

chose a nitrogen deposition rate of 5 kg/ha/yr that is based on a threshold used by 

the California Energy Commission (CEC). (Section 5.0, p. PSD-5.2, p. PSD5.87). 

· The estimated Project contribution is 1.6 kg/ha/yr compared to the CEC-specified 

regional background deposition (Section 5.0, p. PSD-5.97) estimate of 11.56 

kg/ha/yr (without the Project). 

· The applicant estimated a 6% Project contribution to the area as a percentage of 

the total cumulative nitrogen deposition. (Section 5.0, p. PSD-5.2, p. PSD-5.98). 

· The applicant provided cumulative nitrogen deposition isopleths showing a 19 

kg/ha modeled maximum cumulative impact in the area presented in Figure DRBIO 29.1 (Section 5.0, p. PSD-5.99), which included nitrogen deposition impacts 

from four nearby sources. 

The applicant discussed other activities contributing to (although not initiated specifically 

for the purposes of) the minimization of impacts to soils and vegetation. NOx emission 

offsets from the decommissioning of a power plant located 10 miles west of the Project 

site were provided, as required by the local air agency permitting requirements. 

The applicant has also agreed to voluntarily contribute to funds in support of weeding 

efforts at an approved research and habitat management area that would include periodic 

weeding of non-native plants to minimize potential impacts associated with nitrogen 

deposition. As discussed in Section 10 of this Fact Sheet, the applicant and EPA 
47 

identified one plant species listed under the federal Endangered Species Act (ESA), the 

Otay tarplant (Deinandra conjugens), that might be affected by the proposed PSD 

permitting action for the Project due to nitrogen deposition. The applicant submitted a 

Biological Assessment (BA) to EPA in December 2011, in which the applicant addressed 

the possible cumulative effects of nitrogen deposition on this and other Federally-listed 

species. In a letter to the U.S. Fish & Wildlife Service (FWS or Service) dated December 

23, 2011, EPA requested the initiation of formal consultation to address potential effects 

to these species including the Otay tarplant. EPA will proceed with its final PSD permit 

decision after making a determination that issuance of the permit will be consistent with 

ESA requirements, including the requirement that impacts to the Otay tarplant are 

satisfactorily addressed pursuant to the requirements of the ESA. In making this 

determination, EPA will consider actions taken, or to be taken, by the applicant to ensure 

ESA compliance. 

In sum, based on our consideration of the information and analysis provided by the 

applicant, and other relevant information, we do not believe that emissions associated 

with the Project will generally result in adverse impacts to soils or vegetation. While 

nitrogen deposition from the Project has the potential to impact the Otay tarplant, those 

potential impacts are being appropriately considered and addressed through the ESA 

consultation process with the FWS. 

9.2 Visibility Impairment 

The additional impact analysis also evaluates the potential for visibility impairment (e.g., 

plume blight) associated with PPEC. 40 CFR § 52.21(o). Using procedures from EPA’s 

Workbook for Plume Visual Impact Screening and Analysis25, the potential for visibility 

impairment is characterized for: 

· Class I areas located within 50 km of the proposed PPEC; and 

· Class II areas identified as potentially sensitive state or federal parks, forests, 

monuments, or recreation areas. 

There are no Federal Class I areas located within 50 km of the Project site; the nearest 

Class I area is Agua Tibia (91 km away), as presented in Section 8.5.1. For Class II 

areas, the applicant evaluated visibility impairment for two federal Class II areas within 

50 km of the project site: 

· Cleveland National Forest (23 km away) 

· Cabrillo National Monument (33 km away) 

Because EPA has not yet established a quantitative visibility impairment threshold for 

Class II areas (similar to what exists for Class I areas), the applicant proposed a threshold 

and methodology to demonstrate whether the two Class II areas would be affected by 

visibility impairment from the Project. The applicant concluded that although the results 

 

25 “Workbook for Plume Visual Impact Screening and Analysis (Revised)”, EPA, EPA–454/R–92–023, 1992. 
48 

of the Level 1 VISCREEN screening analysis for these two areas exceeded the 

established Class I threshold, the results were below the applicant’s proposed Class II 

threshold. 

At EPA’s request, the applicant subsequently provided a Level 2 VISCREEN screening 

analysis for these two areas. The results of the Level 2 analysis show that maximum 

predicted visual impacts inside these two Class II areas are below the Class I significance 

criteria. Consequently, EPA guidance indicates that these results may be used to 

determine that the project will not contribute to visibility impairment, and no further 

analysis is required. 

9.3 Growth 

The growth component of the additional impact analysis involves a discussion of general 

commercial, residential, industrial, and other growth associated with the PPEC. 40 CFR 

§ 52.21(o). This analysis considers emissions generated by growth that will occur in the 

area due to the source. In conducting this review, we focus on residential, commercial 

and industrial growth that is likely to occur to support the source under review including, 

for example, employment expected during construction and operations and potential 

growth impacts associated with such employment, such as impacts to local population 

and housing needs. 

Construction on PPEC is projected by the applicant to begin in February 2013, with 

commercial operations beginning May 2014. For the periods of construction and plant 

operations, the applicant provided a discussion of potential growth impacts in Section 6.0 

(Growth-Inducing Impacts) of its PSD application submitted to EPA in September 2011. 

This information included a discussion of the socioeconomics of the project. Topics 

included population, housing, economic base, employment, public services and utilities 

(e.g., fire protection, medical facilities, law enforcement, schools and libraries, water 

supply and sewage services, electrical power and natural gas), and fiscal resources. The 

applicant also provided a description of the Project in Section 2.0 (Executive Summary) 

and Section 3.0 (Project Description) of the PSD permit application. 

As noted above, the PPEC is proposed within an industrial park, the Otay Mesa Business 

Park, in the County of San Diego. During the construction and commissioning phase, the 

applicant estimates a required average of 148 workers, with a peak workforce of 284 

workers in the eighth month of construction. The applicant estimates that the maximum 

percentage of nonlocal workers (excluding management) supporting the Project during 

construction would be five percent. During construction, these workers are expected to 

temporarily lodge in hotels and motels within the project vicinity; following construction, 

the nonlocal workers are expected to return to their existing residences. During 

commercial operations, 12 full-time employees are expected. Operation of the PPEC is 

not expected to cause an influx of operation workers to relocate to the local area and, 

therefore, will have no significant impact on the population and housing in the region. 
49 

With respect to public services and utilities, additional medical facilities, schools and 

libraries, water supply and sewage services, and electrical power and natural gas are not 

needed as a result of the proposed PPEC. PPEC is designed and intended to use recycled 

water. For recycled water, the Otay Water District is in the process of completing the 

planned Otay Mesa area recycled water system. Connections will be made to existing 

infrastructure, e.g., the San Diego County sewer lines, utility natural gas transmission 

pipelines, and electrical transmission lines. The existing Otay Water District will supply 

the facility’s potable water needs and fire protection water; if recycled water is not 

available upon start-up of the Project, potable water would be used until recycled water is 

available. 

With respect to fire protection, there are existing San Diego Rural Fire Protection District 

(RFPD) fire stations in the East Otay Mesa Planning area where the PPEC is proposed; 

one interim fire station and a permanent station are located within 0.25 mile of the 

Project. With respect to law enforcement, no sheriff facilities are located within East 

Otay Mesa where the Project is located; the nearest sheriff station is approximately 11.5 

miles west of the site. Patrol functions in the East Otay Mesa area (which includes the 

Project area) are performed by several patrol units assigned to the East Otay Mesa area. 

Independent of the proposed Project, a permanent facility less than one mile from the site 

is currently being planned for both RFPD and sheriff stations. 

In sum, based on our consideration of the information and analysis provided by the 

applicant, we do not expect the Project to result in any significant growth. 

10. Endangered Species 

Pursuant to section 7 of the ESA, 16 U.S.C. § 1536, and its implementing regulations at 

50 CFR Part 402, EPA is required to ensure that any action authorized, funded, or carried 

out by EPA is not likely to jeopardize the continued existence of any endangered or 

threatened species or result in the destruction or adverse modification of such species’ 

designated critical habitat. EPA has determined that this PSD permitting action is subject 

to ESA section 7 requirements. 

The applicant and EPA identified three federally-listed species, the Otay tarplant 

(Deinandra conjugens), the Quino Checkerspot butterfly (Euphydryas editha quino), and 

coastal California gnatcatcher (Polioptila californica californica), that might be affected 

by the proposed PSD permitting action for the Project. The applicant submitted a 

Biological Assessment (BA) to EPA in December 2011, in which the applicant addressed 

the possible cumulative effects of nitrogen deposition on these species. In a letter to the 

FWS dated December 23, 2011, EPA requested the initiation of formal consultation for 

PPEC to address potential impacts to the Quino Checkerspot butterfly, the Otay tarplant, 

and the coastal California gnatcatcher. That consultation is ongoing. 

As noted above, EPA will proceed with its final PSD permit decision after making a 

determination that issuance of the permit will be consistent with ESA requirements. In 
50 

making this determination, EPA will consider actions taken, or to be taken, by the 

applicant to ensure ESA compliance. 

11. Environmental Justice Screening Analysis 

Executive Order 12898, entitled “Federal Actions To Address Environmental Justice in 

Minority Populations and Low-Income Populations,” states in relevant part that “each 

Federal agency shall make achieving environmental justice part of its mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human 

health or environmental effects of its programs, policies, and activities on minority 

populations and low-income populations.” Section 1-101 of Exec. Order 12898, 59 Fed. 

Reg. 7629 (Feb. 16, 1994). 

EPA determined that there may be minority or low-income populations potentially 

affected by its proposed action on the PPEC PSD permit application, and determined that 

it would be appropriate to prepare an Environmental Justice Analysis for this action. 

EPA therefore prepared an Environmental Justice Analysis, which is included in the 

administrative record for EPA’s proposed PSD permit for the Project. EPA’s analysis 

concludes that the Project will not cause or contribute to air quality levels in excess of 

health standards for the pollutants regulated under EPA’s proposed PSD permit for the 

Project, and that therefore the Project will not result in disproportionately high and 

adverse human health or environmental effects with respect to these air pollutants on 

minority or low-income populations residing near the proposed Project, or on the 

community as a whole. 

12. Clean Air Act Title IV (Acid Rain Permit) and Title V 

(Operating Permit) 

The applicant must apply for and obtain an acid rain permit and a Title V operating 

permit from the SDAPCD. The Title V permit application is due within 12 months of the 

date that the new facility commences operation, while acid rain permit applications for 

new units are due 24 months before the applicant commences operation of the new units. 

The District has jurisdiction to issue the Acid Rain Permit and the Operating Permit for 

the facility. 

13. Comment Period, Procedures for Final Decision, and EPA 

Contact 

The comment period for EPA’s proposed PSD permit for the Project begins on June 20, 

2012. Any interested person may submit written comments on EPA’s proposed PSD 

permit for the Project. All written comments on EPA’s proposed action must be received 

by EPA via email by July 24, 2012, or postmarked by July 24, 2012. Comments must be 

sent or delivered in writing to Roger Kohn at one of the following addresses: 
51 

E-mail:R9airpermits@epa.gov

U.S. Mail: Roger Kohn (AIR-3) 

 U.S. EPA Region 9 

 75 Hawthorne Street 

 San Francisco, CA 94105-3901 

 Phone: (415) 972-3811 

Comments should address the proposed PSD permit and facility, including such matters 

as: 

1. The Best Available Control Technology (BACT) determinations; 

2. The effects, if any, on Class I areas; 

3. The effect of the proposed facility on ambient air quality; and 

4. The attainment and maintenance of the NAAQS. 

Alternatively, written or oral comments may be submitted to EPA at the Public Hearing 

for this matter that EPA will hold on July 24, 2012, pursuant to 40 CFR § 124.12, to 

provide the public with further opportunity to comment on the proposed PSD permit for 

the Project. At this Public Hearing, any interested person may provide written or oral 

comments, in English or Spanish, and data pertaining to the proposed permit. 

The date, time and location of the Public Hearing are as follows: 

Date: July 24, 2012 

Time: 6:00 p.m. – 8:00 p.m. 

Location: San Ysidro High School 

Performing Arts Center 

5353 Airway Road 

San Diego, California 92154 

English-Spanish translation services will be provided at the Public Hearing. If you 

require a reasonable accommodation, by July 10, 2012 please contact Philip Kum, EPA 

Region 9 Reasonable Accommodations Coordinator, at (415) 947-3566, or 

kum.philip@epa.gov. 

All information submitted by the applicant is available as part of the administrative 

record. The proposed air permit, Fact Sheet, permit application and other supporting 

information are available on the EPA Region 9 website at 

http://www.epa.gov/region09/air/permit/r9-permits-issued.html#pubcomment. The 

administrative record may also be viewed in person, Monday through Friday (excluding 

Federal holidays) from 9:00 AM to 4:00 PM, at the EPA Region 9 address above. Due to 

building security procedures, please call Roger Kohn at (415) 972-3973 at least 24 hours 

in advance to arrange a visit. Hard copies of the administrative record can be mailed to 

individuals upon request in accordance with Freedom of Information Act requirements as 

described on the EPA Region 9 website at http://www.epa.gov/region9/foia/. 
52 

Additional information concerning the proposed PSD permit may be obtained between 

the hours of 9:00 a.m. and 4:00 p.m., Monday through Friday, excluding holidays, by 

contacting Roger Kohn at the telephone and email address listed above. 

EPA’s proposed PSD permit for the Project and the accompanying Fact Sheet are also 

available for review at the following locations: SDAPCD, 10124 Old Grove Road, San 

Diego, California 92131, (858) 586-2600; San Ysidro Library in San Diego, CA; Otay 

Mesa Nestor Library in San Diego, CA; Civic Center Branch Library in Chula Vista, CA; 

National City Public Library in National City, CA; and Central Library in San Diego, 

CA. 

All comments that are received will be included in the public docket without change and 

will be available to the public, including any personal information provided, unless the 

comment includes Confidential Business Information (CBI) or other information whose 

disclosure is restricted by statute. Information that is considered to be CBI or otherwise 

protected should be clearly identified as such and should not be submitted through e-mail. 

If a commenter sends e-mail directly to the EPA, the e-mail address will be automatically 

captured and included as part of the public comment. Please note that an e-mail or postal 

address must be provided with comments if the commenter wishes to receive direct 

notification of EPA’s final decision regarding the permit. 

EPA will consider all written comments submitted during the public comment period and 

all written and oral comments submitted during the public hearing before taking final 

action on the PSD permit application and will send notice of the final decision to each 

person who submitted comments and contact information during the public comment 

period or requested notice of the final permit decision. EPA will respond to all 

substantive comments in a document accompanying EPA’s final permit decision and will 

make the Public Hearing proceedings available to the public. 

EPA’s final permit decision will become effective 30 days after the service of notice of 

the decision unless: 

1. A later effective date is specified in the decision; or 

2. The decision is appealed to EPA’s Environmental Appeals Board pursuant to 40 CFR 

124.19; or 

3. There are no comments requesting a change to the proposed permit decision, in which 

case the final decision shall become effective immediately upon issuance. 

14. Conclusion and Proposed Action 
53 

EPA is proposing to issue a PSD permit for the PPEC. We believe that the proposed 

Project will comply with PSD requirements, including the installation and operation of 

BACT, and will not cause or contribute to a violation of the applicable NAAQS or 

applicable PSD increments. We have made this determination based on the information 

supplied by the applicant and our review of the analyses contained in the permit 

application and other relevant information contained in our administrative record. EPA 

will make this proposed permit and this Fact Sheet available to the public for review, and 

make a final decision after considering any public comments on our proposal. 
1 

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