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 

Palmdale Hybrid Power Project 

PSD Permit Number SE 09-01 

August 2011 
This page left intentionally blank. 
PROPOSED PREVENTION OF 

SIGNIFICANT DETERIORATION PERMIT 

PALMDALE HYBRID POWER PROJECT 

Fact Sheet and Ambient Air Quality Impact Report 

(PSD Permit SE 09-01) 

Table of Contents 

Acronyms & Abbreviations .......................................................................................................... i

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

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

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

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

4. Project Description................................................................................................................ 3

5. Emissions from the Proposed Project..................................................................................... 7

6. Applicability of the Prevention of Significant Deterioration Regulations................................. 9

7. Best Available Control Technology......................................................................................12

7.1 BACT for Natural Gas Combustion Turbine Generators................................................16

7.1.1 Nitrogen Oxide Emissions......................................................................................16

7.1.2 Carbon Monoxide Emissions..................................................................................20

7.1.3 PM, PM10 and PM2.5 Emissions...............................................................................23

7.1.4 GHG Emissions .....................................................................................................27

7.1.5 BACT During Startup and Shutdown.....................................................................31

7.2. BACT for Auxiliary Boiler and Heater .....................................................................32

7.2.1 Nitrogen Oxide Emissions......................................................................................32

7.2.2 Carbon Monoxide Emissions..................................................................................33

7.2.3 PM, PM10 and PM2.5 Emissions...........................................................................34

7.2.4 GHG Emissions .....................................................................................................37

7.3 BACT for Emergency Internal Combustion Engines.......................................................38

7.3.1 NOX, CO, PM, PM10, PM2.5, and GHG Emissions...............................................38

7.4 BACT for Cooling Tower..............................................................................................40

7.5 BACT for Fugitive Road Dust .......................................................................................43

7.6 BACT for Circuit Breakers............................................................................................45

7.6.1 GHG......................................................................................................................45

8. Air Quality Impacts.............................................................................................................46

8.1 Introduction...................................................................................................................47

8.1.1 Overview of PSD Air Impact Requirements ...........................................................47

8.1.2 Identification of PHPP Modeling Documentation ...................................................48

8.2. Background Ambient Air Quality.............................................................................49

8.3 Modeling Methodology for Class II areas ......................................................................50

8.3.1 Model selection......................................................................................................50

8.3.2 Meteorology model inputs......................................................................................51

8.3.3 Land characteristics model inputs...........................................................................51

8.3.4 Model receptors.....................................................................................................52

8.3.5 Load screening and stack parameter model inputs ..................................................53
ii

8.3.6 Good Engineering Practice (GEP) Analysis...........................................................54

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

Analysis...............................................................................................................................55

8.4.1 Pollutants with significant emissions.......................................................................55

8.4.2 Preliminary analysis: Project-only impacts..............................................................55

8.4.3 Cumulative impact analysis.....................................................................................56

8.5 Class I Area Analysis.....................................................................................................62

8.5.1 Class I Increment Consumption Analysis................................................................63

8.5.2 Visibility and Deposition in Class I areas................................................................63

9. Additional Impact Analysis..................................................................................................65

9.1 Soils and Vegetation......................................................................................................66

9.2 Visibility Impairment......................................................................................................68

9.3 Growth..........................................................................................................................68

10. Endangered Species.............................................................................................................69

11. Environmental Justice Analysis............................................................................................70

12. Clean Air Act Title IV (Acid Rain Permit) and Title V (Operating Permit)...........................70

13. Comment Period, Hearing, Public Information Meeting, Procedures for Final Decision, and 

EPA Contact..............................................................................................................................70

14. Conclusion and Proposed Action.........................................................................................73

 
Acronyms & Abbreviations 

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

ACC Air Cooled Condenser 

AFC Application for Certification 

Agency U.S. Environmental Protection Agency 

AQMD Air Quality Management District 

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.] 

CEC California Energy Commission 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CT Combustion Turbine 

CTG Combustion Gas Turbine 

DLN Dry Low NOx

GE General Electric 

GHG Greenhouse Gas (Greenhouse Gases) 

g/hp-hr grams per horsepower-hour 

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 

HHV Higher Heating Value 

HP Horsepower 

HRSG Heat Recovery Steam Generator 

HTF Heat Transfer Fluid 

IRIS Integrated Risk Information System 

ISO International Organization for Standards 

km Kilometers 

kW Kilowatts of electrical power 

kWhr Kilowatt-hour 

mg/L Milligrams per liter 

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 

NMHC Non-methane Hydrocarbons 
ii

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 

PHPP Palmdale Hybrid Power Project 

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 

PPM Parts per Million 

PPMVD Parts per Million by Volume, on a Dry basis 

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 

SIL Significant Impact Level 

SF6 Sulfur Hexafluoride 

SNCR Selective Non-Catalytic Reduction 

SO2 Sulfur Dioxide 

SOx Oxides of Sulfur 

STG Steam Turbine Generator 

TDS Total Dissolved Solids 

TPY Tons per Year 

VV2 Victorville 2 (Hybrid Power Project) 

WA Wilderness Area 
1

Proposed Prevention of Significant Deterioration (PSD) Permit 

Fact Sheet and Ambient Air Quality Impact Report 

PALMDALE HYBRID POWER PROJECT 

Executive Summary 

The City of Palmdale 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 570 megawatts (MW, nominal) of electricity using 

natural gas and solar energy. The power plant, known as the Palmdale Hybrid Power 

Project (PHPP or Project), will be located in the town of Palmdale, in Los Angeles 

County, California. EPA is issuing a proposed PSD permit for the PHPP, which is 

consistent with the requirements of the PSD program for the following reasons: 

§ The proposed PSD permit requires the Best Available Control Technology 

(BACT) to limit emissions of nitrogen oxides (NOx), carbon monoxide (CO), total 

particulate matter (PM), particulate matter under 10 micrometers (μm) in diameter 

(PM10), particulate matter under 2.5 (μm) in diameter (PM2.5), and greenhouse 

gases (GHG), to the greatest extent feasible; 

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

Standards (NAAQS) for nitrogen dioxide (NO2), CO, PM10, and PM2.5. There are 

no NAAQS for PM or Greenhouse Gases. 

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

and deposition in Class I areas, 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/AAQIR) for the proposed PSD permit for the City of Palmdale’s Project. 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: 
2

City of Palmdale 

38300 Sierra Highway, Suite A 

Palmdale, CA 93550 

3. Project Location 

The proposed location for the Palmdale Hybrid Power Project is 950 East Avenue M, 

Palmdale, California 93550. It is located on an approximately 333-acre parcel west of the 

northwest corner of Air Force Plant 42, and east of the intersection of Sierra Highway and 

East Avenue M. The City of Palmdale is located within the Antelope Valley Air Quality 

Management District (District). 

The map below shows the approximate location of the proposed Project. 
3

4. Project Description 

The City of Palmdale has submitted to EPA an application for a PSD permit for the PHPP. 

 The City of Palmdale’s application materials for the PSD permit for the Project are 

included in EPA’s administrative record for EPA’s proposed PSD permit. The PHPP will 

be owned by the City of Palmdale and the development of the Project will be managed by 

Inland Energy. 

We note that the City of Palmdale 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 13, 2010. The CEC issued its Final Commission Decision 

approving the Project’s Application for Certification on August 10, 2011 (08-AFC-09). 

The PHPP is designed to use solar technology to generate a portion of the Project’s 

output. Primary equipment for the generating facility will include two General Electric 

(GE) Frame 7FA natural gas-fired combustion turbine-generators (CTGs) rated at 154 

megawatt (MW, gross) each, two heat recovery steam generators (HRSGs), one steam 

turbine generator (STG) rated at 267 MW, and 251 acres of parabolic solar-thermal 

collectors with associated heat-transfer equipment. The Project will have an electrical 

output of 570 MW (nominal) or 563 MW (net). The GE CTG incorporates the “Rapid 

Start Process” (RSP), which allows for shorter startup durations of the gas turbines. Table 

4-1 lists the equipment that will be regulated by this PSD permit: 
4

Table 4-1: Equipment List 

Equipment Description 

Two natural gas-fired 

GE 7FA Rapid Start 

Process combustion 

turbine generators 

(CTG) with Heat 

Recovery Steam 

Generators (HRSG) 

• Each 154 MW (gross) CTG, with a maximum heat input 

rate of 1,736 MMBtu/hr (HHV) 

• Equipped with natural gas duct burners, rated at 500 

MMBtu/hr (HHV) for each turbine system 

• Each CTG vented to a dedicated Heat Recovery Steam 

Generator (HRSG) and a shared 267 MW Steam Turbine 

Generator (STG) 

• Emissions of NOX and CO controlled by Dry Low-NOX

(DLN) Combustors, Selective Catalytic Reduction (SCR), 

and an Oxidation Catalyst (Ox-Cat) 

Auxiliary Boiler • 110 MMBtu/hr (HHV) with ultra low-NOX burner, fired 

on natural gas 

Emergency Diesel-fired 

Internal Combustion 

(IC) Engine 

• 2,000 kW (2,683 hp) 

• 40 CFR Part 60, Subpart IIII emission standards 

• California Air Resources Board Tier 2 emission standards 

Emergency Diesel-fired 

IC Firewater Pump 

Engine 

• 182 hp (135 kW) 

• 40 CFR Part 60, Subpart IIII emission standards 

• California Air Resources Board Tier 3 emission standards 

Auxiliary Heater • 40 MMBtu/hr (HHV) with ultra low-NOX burner, fired on 

natural gas 

Cooling Tower • 130,000 gallons per minute maximum circulation rate 

• Total dissolved solids (TDS) concentration in makeup 

water of 5,000 ppm (531 mg/L) 

• Drift eliminator with drift losses less than or equal to 

0.0005 percent based on circulation rate 

Circuit Breakers • Enclosed-pressure SF6 Circuit Breakers 

• 0.5% (by weight) annual leakage rate 

• 10% (by weight) leak detection system 

Maintenance Vehicle 

Traffic Generating 

Fugitive Road Dust 

• Maintenance vehicles generating fugitive road dust when 

traveling on paved and unpaved roadways in the solar field 

with the Project 

• Project Fugitive Dust Control Plan 

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 154 megawatts (MW) of electricity from each turbine. 
5

The facility will be operated in combined-cycle mode because each turbine will connect to 

a dedicated heat recovery steam generator (HRSG), where hot combustion exhaust gas 

will flow through a heat exchanger to generate steam. The facility will be equipped with 

duct burners firing natural gas to increase steam output from the HRSG during periods of 

peak demand. 

The hybrid plant design will include a 251-acre solar field that will consist of parabolic 

solar-thermal collectors and associated heat transfer equipment arranged in rows. The 

heat transfer fluid will be circulated to a boiler to supply steam directly to the HRSGs to 

increase electrical generation from the steam turbine. The fluid will then be recirculated to 

the solar arrays. An auxiliary heater will be used to ensure that the heat transfer fluid does 

not freeze and stays above 54 degrees F whenever the solar steam unit is off-line . 

The Project will require periodic vehicle travel over the unpaved portions of the solar field 

to perform routine maintenance including mirror washing, maintenance inspections and 

repairs of the piping network, herbicide application and dust suppressant application. 

Fugitive dust emissions are expected from maintenance vehicle traffic on the unpaved 

areas in the solar fields. 

The steam generated from each of the HRSGs will drive a 267 MW steam turbine. On 

sunny days, the solar array is capable of providing 50 MW of the total electrical generation 

from the steam turbine. Net power plant output, after subtracting electricity used on-site, 

will be 563 MW. 

Exhaust gas exiting the steam turbine will enter a condenser. Cooling water circulating 

through the condenser will condense the steam into water, which will be circulated back to 

each HRSG. The condenser cooling water will then flow through a mechanical draft wet 

cooling tower, where the remaining heat will be dissipated to the atmosphere, and small 

quantities of dissolved solids will become airborne as particulate matter. 

The diagram on the following page shows a simplified diagram of the proposed Palmdale 

Hybrid Power Project. 
6
7

Air Pollution Control 

The PHPP will use Selective Catalytic Reduction (SCR) to reduce NOX emissions from 

the combustion turbine generators. The SCR will use aqueous ammonia as the reagent, 

where the catalyst facilitates the reaction of the ammonia with NOX to create atmospheric 

nitrogen (N2) and water. The PHPP will use an oxidation catalyst to reduce emissions of 

CO and volatile organic compounds (VOCs). Although CO is regulated in this proposed 

PSD permit, VOCs are regulated by the New Source Review (NSR) permit issued by the 

District, as explained in Section 6 below. 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. 

Additional equipment includes a natural gas-fired auxiliary boiler equipped with an ultra 

low-NOX burner, a natural gas-fired auxiliary heater equipped with an ultra low-NOX

burner, a diesel-fired emergency generator and a diesel-fired emergency firewater pump 

engine both fired with ultra-low sulfur diesel fuel and compliant with federal NSPS 

requirements, and SF6 circuit breakers with leak detection systems. 

Power Plant Startup

In a typical combined-cycle gas turbine power plant, components of the steam cycle 

cannot withstand rapid temperature changes, limiting how fast the steam turbine may be 

started. The “rapid start" design of the PHPP is expected to reduce the time required for 

the steam cycle to start up. This is important to air quality for two reasons. First, the 

exhaust gas temperature when the steam cycle is not operating is higher than the design 

temperature window for the SCR and oxidation catalysts. Second, the plant will generate 

more electricity for the amount of fuel burned when the hot gas turbine exhaust is used to 

power the steam generator in combined cycle. 

The auxiliary boiler is primarily designed to shorten the duration of startups as part of 

GE’s RSP technology, thus minimizing emissions during CTG startup. 

5. Emissions from the Proposed Project 

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

Antelope Valley Air Quality Management District (District), which is the area in which the 

Project is proposed to be located. 

The Clean Air Act’s New Source Review (NSR) provisions include two preconstruction 

permitting programs. First, the PSD program is intended to protect air quality in 

“attainment areas,”1 which are areas that meet the National Ambient Air Quality Standards 

(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 

 

1 PSD also applies to pollutants where the status of the area is uncertain (unclassifiable) for NAAQS. 
8

general, and within the District. 

 

Second, the 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., volatile organic compounds and nitrogen oxides are precursors to 

ambient ozone). Therefore, pollutants that are in nonattainment with the NAAQS within 

the District are regulated under a separate nonattainment NSR permit issued by the 

District. 

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 

Antelope Valley Air Quality Management 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/a2PSD 

Particulate matter under 10 

micrometers diameter (PM10) Unclassifiable PSD 

Particulate Matter under 2.5 

micrometers diameter (PM2.5) Attainment/Unclassifiable PSD 

Ozone Nonattainment3 NA-NSR 

Lead (Pb) Attainment4PSD 

Sulfuric Acid Mist (H2SO4) n/a2PSD 

Hydrogen Sulfide (H2S) n/a2PSD 

Total Reduced Sulfur (TRS) n/a2PSD 

Fluorides n/a2PSD 

Greenhouse Gases (GHG) n/a2PSD 

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 fossil fuel-fired steam 

 

2

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 listed as regulated 

pollutants with a defined applicability threshold under the PSD regulations (40 CFR § 52.21). 

3 Because NOx is also a precursor to ozone in this area, it will also be regulated by the separate District ozone nonattainment New Source Review permit in addition to this PSD permit. 

4 Area has not yet been designated for lead and is therefore treated as an attainment area. 
9

electric plant with a heat input capacity of 250 MMBtu/hr or greater, such as the PHPP, 

that emits or has the potential to emit (PTE) 100 tons per year (tpy) or more of any 

pollutant regulated under the Clean Air Act5, is defined as a “major source.” 

6. Applicability of the Prevention of Significant Deterioration 

Regulations 

This section describes the PSD applicability thresholds, and our conclusion that NO2, CO, 

PM, PM10, PM2.5, and GHG will be regulated by EPA’s proposed PSD permit. 

The estimated emissions in Table 6-1 show that the PHPP will be a major source for NOx, 

CO, PM, PM10, PM2.5 and GHG. The annual emission data in Table 3 (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 applicant assumes 

that all combustion-related emissions of PM10 are of diameter less than 2.5 microns (i.e., 

PM2.5), which is a conservative estimate, as some particulate emissions may fall in the size 

fraction between 2.5 and 10 micrometers. 

Once a source is considered major for a PSD pollutant, PSD also applies to any other 

regulated pollutant that is emitted in a significant amount. The data in Table 3 show that 

emissions of sulfur dioxide (SO2) will be less than the major source threshold and less than 

the significant emission rate. Therefore, PSD does not apply for SO2. Estimated emissions 

of the PSD-regulated pollutants from each emission unit are listed in Table 6-1. 

 

5 Other types of “source categories” are subject to either the same 100 tpy threshold, or else a 250 tpy threshold. 
10

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 250.2 100 100 Yes 

NO2 114.9 100 40 Yes 

PM 79.1 100 25 Yes 

PM10 62.5 100 15 Yes 

PM2.5 56.0 100 15 Yes 

SO2 8.9 100 40 No 

Pb 0 0.6 0.6 No 

H2SO4 3.4 7 7 No 

H2S (incl. 

TRS) 0 10 10 

No 

Fluorides 0 3 3 No 

GHG (incl. 

CO2e) 1,913,000 100,000 75,000 Yes 
11

Table 6-2: Estimated Emissions of PSD-Regulated Pollutants by Emission Unit 

CO NOX PM PM10 PM2.5 GHG (a) CO2e (b) 

Total Facility 250.2 tpy 114.9 tpy 79.1 tpy 62.5 tpy 56.0 1,913,376 1,913,000 

CTG+HRSG (2) 248.0 113.7 47.8 47.8 47.8 1,908,074 1,908,000 

Auxiliary Heater 0.74 0.22 0.15 0.15 0.15 2,340 2,000

Auxiliary Boiler 1.01 0.30 0.20 0.20 0.20 2,920 3,000

Emergency Diesel 

Engine 

0.39 0.67 0.02 0.02 0.02 27.6 0 

Emergency Diesel 

Firewater Pump 

0.03 0.03 0.002 0.002 0.002 4.41 0 

Cooling Tower n/a n/a 7.13 7.13 7.13 n/a n/a 

Circuit Breakers n/a n/a n/a n/a n/a 9.56 0 

Maintenance 

Vehicles (c) n/a n/a 23.80 7.16 0.72 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) This category represents fugitive road dust emissions (e.g., particulate matter emissions) that are expected from maintenance 

vehicle traffic on the unpaved areas in the solar fields. 
12

7. Best Available Control Technology 

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

control of NOx, CO, 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 

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 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; 
13

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, CO, PM, PM10, PM2.5, and GHG 

emissions. A BACT analysis was conducted for each of the following emission units: the 

two natural gas combustion turbines, the 40 MMBtu/hr auxiliary process heater, the 110 

MMBtu/hr auxiliary boiler, the two diesel-fired internal combustion engines, the fugitive 

road dust emissions, the cooling tower and the circuit breakers. Tables 7-1 and 7-2 

provide a summary of the BACT determinations for NOX, CO, PM, PM10, PM2.5, and 

GHG from the emission units listed above. 
14

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

and Requirements for Testing and Monitoring6

NOX CO PM, PM10, and PM2.5 Restrictions on 

Usage 

2 Combustion 

Turbines

(each, no duct 

burning)

• 11.55 lb/hr 

• 1-hr average 

• 2.0 ppmvd, 15% O2

• CEMS

• Quarterly and Annual 

RATA for CEMs

• 5.74 lb/hr7

• 1-hr average 

• 1.5 ppmvd, 15% O2

8

• CEMS

• Quarterly and Annual 

RATA for CEMs

• 4.7 lb/hr 

• 3-hr average 

• 0.0027 lb/MMBtu 

• PUC natural gas (Sulfur 

<0.20 gr/100 dscf on 

12-month average and 

not exceed 1.0 gr/dscf 

at anytime)

• Annual Performance 

Testing

n/a

2 Combustion 

Turbines

(each, with 

duct burning) 

• 14.6 lb/hr 

• 1-hr average 

• 2.0 ppmvd, 15% O2

• 8.90 lb/hr 

• 1-hr average 

• 2.0 ppmvd,15% O2

• 8.0 lb/hr 

• 3-hr average 

• 0.0035 lb/MMBtu 

• PUC natural gas (Sulfur 

<0.20 gr/100 dscf on 

12-month average and 

not exceed 1.0 gr/dscf 

at anytime)

• Annual Performance 

Testing

• Total duct 

burning (D3 & 

D4) < 2,000 

hrs/yr 

2 Combustion 

Turbines

(each, startup 

and shutdown)

• Cold Start - 52.4 lb/hr, 

96 lb/event 

• Warm/Hot – 30 lb/hr, 

40 lb/event 

• Shutdown – 114 lb/hr, 

57 lb/event 

• 1-hr average 

• Cold Start - 224 lb/hr, 

410 lb/event 

• Warm/Hot – 247 

lb/hr, 329 lb/event 

• Shutdown – 674 lb/hr, 

337 lb/event 

• 1-hr average 

n/a • Cold Start –110 

minutes 

• Warm/Hot – 80 

minutes 

• Shutdown – 674 

30 minutes 

Heater 

40 MMBtu/hr 

(HHV) 

• 9.0 ppm, 3% O2

• 3-hr average 

• Initial Performance 

Testing and at least 

every 5 years

• 50.0 ppm, 3% O2

• 3-hr average 

• Initial Performance 

Testing and at least 

every 5 years

• 0.3 lb/hr for Heater 

• 0.8 lb/hr for Boiler 

• 3-hr average 

• PUC natural gas (Sulfur 

<0.20 gr/100 dscf on 

12-month average and 

not exceed 1.0 gr/dscf 

at anytime) 

• 1,000 hr/yr 

• Non-resettable 

elapsed time 

meter 

Boiler 

35 MMBtu/hr 

(HHV) 

• 500 hr/yr 

• Non-resettable 

elapsed time 

meter 

 

6

PHPP must keep all records of all testing, fuel use, and fuel testing requirements for a period of five (5) years and must 

report excess emissions to EPA semi-annually, except when: more frequent reporting is specifically required by an 

applicable subpart; or the Administrator, on a case-by-case basis, determines that more frequent reporting is necessary 

to accurately assess the compliance status of the source. . 

7 During the initial 3-year demonstration period, the limit will be 7.65 lb/hr. 

8 During the initial 3-year demonstration period, the limit will be 2.0 ppmvd, 15% O2.
15

NOX CO PM, PM10, and PM2.5 Restrictions on 

Usage 

Emergency 

Generator

2000 KW 

(2,683 hp) 

• 6.4 g/KW-hr, 

(4.8 g/hp-hr)9

• 3-hr average

• Initial Performance 

Testing

• 3.5 g/KW-hr, (2.6 

g/hp-hr) 

• 3-hr average 

• Initial Performance 

Testing 

• 0.20 g/KW-hr, (0.15 

g/hp-hr) 

• 3-hr average 

• Exclusive use of ultra 

low sulfur fuel, not to 

exceed 15 ppmvd sulfur 

• Fuel Supplier 

Certification 

• Initial Performance 

Testing 

• 50 hr/year 

• Non-resettable 

elapsed time 

meter 

Firewater 

Pump Engine 

135 KW (182 

hp) 

• 4.0 g/KW-hr, 

(3.0 g/hp-hr)10

• 3-hr test average 

• Initial Performance 

Testing 

• 50 hr/year 

• As required for 

fire testing 

• Non-resettable 

elapsed time 

meter 

Cooling tower 

130,000 gpm 

n/a n/a • 1.6 lb/hr (total PM) 

• < 0.0005% drift 

eliminators 

• < 5000 ppm total 

dissolved solids 

• Weekly water quality 

testing 

n/a 

Circuit 

Breakers 

na/ n/a n/a n/a 

Maintenance 

Vehicle 

n/a n/a • Fugitive Dust Control 

Plan 

n/a 

 

9 Emission standards for NOx in the New Source Performance Standard for stationary compression ignition internal 

combustion engines (40 CFR Part 60 Subpart IIII) and the California Tier Emission Standards are based on the sum of 

NOx and non-methane hydrocarbons (NMHC). For the NOx emission limits, the applicant assumes NMHC + NOx

emissions from the engine are 95% NOX. 

10 Ibid. 
16

Table 7-2: Summary of GHG BACT Limits 

and Requirements for Testing and Monitoring

GHG Testing and 

Monitoring 

Restrictions on 

Usage 

2 Combustion 

Turbines

(each, no duct 

burning)

• 774 lb CO2/MWh 

source-wide net 

output 

• 117 lb CO2/MMBtu 

heat input, each at 

ISO standard day 

conditions 

• 30-day rolling 

average 

• CEMS 

n/a 

2 Combustion 

Turbines

(each, with 

duct burning) 

• Total duct 

burning (D3 & 

D4) < 2,000 

hrs/yr 

2 Combustion 

Turbines

(each, startup 

and shutdown)

• Cold Start –110 

minutes 

• Warm/Hot – 80 

minutes 

Heater 

40 MMBtu/hr 

(HHV) • Annual tune-ups 

• Non-resettable 

elapsed time 

meter 

• 1,000 hr/yr 

Boiler 

35 MMBtu/hr 

(HHV) 

• Non-resettable 

elapsed time 

meter 

• 500 hr/yr 

Circuit 

Breakers 

• 9.56 tpy CO2e 

• 0.5% maximum 

annual leakage rate 

• 10% leak 

detection system 

• Monthly pounds 

of dielectric fluid 

added 

n/a 

7.1 BACT for Natural Gas Combustion Turbine Generators 

The PHPP will have two combined-cycle, natural gas-fired combustion turbines (CTs). Each CT 

has a maximum heat input capacity of 1,736 MMBtu/hr (at ISO conditions) and will have a 

dedicated heat recovery steam generator (HRSG) with a 550 MMBtu/hr duct burner. Each duct 

burner will be limited to 2,000 hours of operation per year. The CTs are subject to BACT for 

NOX, CO, 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 (DLN) combustors) 
17

• 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) 

Step 2 – Eliminate Technically Infeasible Options 

All of the available control options identified in Step 1 are technically feasible. 

Step 3 – Rank Control Technologies 

A summary of recent BACT limits for similar combined-cycle, natural gas-fired CTs is provided in 

Table 7-3. There is one facility that was permitted with a BACT limit less than the limit 

proposed by the applicant. The IDC Bellingham facility in Massachusetts was permitted in 2000 

with a limit of 1.5 ppm. However, this project was cancelled, so this limit has never been 

demonstrated as achievable. All recently issued permits indicate that a limit of 2.0 ppm based on a 

1-hr average represents the highest level of NOX control. The available control technologies are 

ranked according to control effectiveness in Table 7-4. 

SCR and EMxTM for NOX Emissions 

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

specifically achieved NOX emissions of 2.0 ppm on a 1-hr average on large CTs (greater than 100 

MW). 

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.

11 

 As a result, EMxTM is 

considered technically feasible for this facility. However, it is unclear what NOX emission levels 

can actually be achieved by the technology. 

We found only one BACT analysisthat determined that EMxTM/SCONOx was BACT for a large 

CT. However, the accompanying permit for the facility, Elk Hills Power in California, allowed 

the use of SCR or SCONOx (the former name of EMxTM) to meet a permit limit of 2.5 ppm, and 

the actual technology that was installed in that case was SCR. 

We also note that the Redding Power Plant in California, a 43 MW gas-fired CT, was permitted 

with a 2.0 ppm demonstration limit using SCONOx. In a letter dated June 23, 2005 from the 

Shasta County Air Quality Management District (Shasta County AQMD) to the Redding Electric 

Utility, however, it was determined that the unit could not meet the demonstration limit and, as a 

result, the limit was revised to 2.5 ppm. Based on these two examples, it appears EMxTM has 

been demonstrated to achieve only 2.5 ppm and we are therefore evaluating it at this limit. 

 

11 Information available at http://emerachemnew.ciplex.us/emx-product.html. See EMx White Paper 2008. 
18

Table 7-4: NOX Control Technologies Ranked by Control Effectiveness 

NOX Control Technology 

Emission Rate (ppmvd 

@ 15% O2, 1-hr average) 

SCR with dry low NOX combustors and inlet air 

coolers 

2.0 

EMxTMwith dry low NOX combustors and inlet 

air coolers 

2.5 

SNCR with dry low NOX combustors and inlet 

air coolers 

~4.512

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.13 Ammonia has 

not been identified as a carcinogen. It is noted that the applicant will use aqueous ammonia, which 

is considered the safer storage method. Additionally, we note that the California Energy 

Commission’s Presiding Member’s Proposed Decision proposes to include Conditions of 

Certification to ensure the safe receipt and storage of aqueous ammonia at the PHPP.14 

Ammonia slip emissions for the proposed source are limited to 5 ppm by the nonattainment New 

Source Review (NSR) permit 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 (0.0008 and 0.028, respectively).15

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. 

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 CTs is 2.0 ppm at 15% O2 based on a 1-

hr average. Additionally, we are adding a mass emission limit of 11.55 lb/hr without duct firing 

and 14.6 lb/hr with duct firing based on a 1-hr average. 

 

12 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. 

13 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. 

14 This information is available at http://www.energy.ca.gov/2011publications/CEC-800-2011-005/CEC-800-2011-

005-PMPD.pdf. See conditions HAZ-1 through HAZ-6. 

15 See Final Determination of Compliance for Palmdale Hybrid Power Project issued by the District on May 13, 2010, 

Section 8. 
19

Table 7-3: Summary of Recent NOX BACT Limits for Similar Combined-Cycle, Natural gas-fired CTs 

Facility Location NOX Limit Averaging 

Period Control Permit Issuance Source 

Avenal Energy Project16 California 2.0 ppm 1-hr SCR May 2011 PSD Permit 

Warren County Power Station Virginia 2.0 ppm 1-hr SCR/DLN December 2010 PSD Permit 

Carty Power Plant Oregon 2.0 ppm 3-hr rolling SCR Draft December 2010 RBLC # OR-0048 

Langley Gulch Power Plant Idaho 2.0 ppm 3-hr rolling SCR/DLN Draft December 2010 RBLC # ID-0018 

Live Oaks Power Plant Georgia 2.5 ppm 3-hr SCR/DLN April 2010 RBLC # GA-0138 

Colousa Generating Station California 2.0 ppm 1-hr SCR March 2010 PSD Permit 

Victorville II Hybrid Power Project California 2.0 ppm 1-hr SCR February 2010 PSD Permit 

Madison Bell Energy Center Texas 2.0 ppm 24-hr rolling SCR August 2009 RBLC # TX-0548 

Chouteau Power Plant Oklahoma 2.0 ppm 1-hr SCR/DLN January 2009 RBLC # OK-0129 

Kleen Energy Systems Connecticut 2.0 ppm 1-hr SCR/LNB February 2008 RBLC # CT-0151 

PSO Southwestern Power Plant Oklahoma 9.0 ppm -- DLN February 2007 RBLC # OK-0117 

FPL West County Energy Center 

Unit 3 Florida 2.0 ppm 24-hr SCR/DLN July 2008 RBLC # FL-0303 

FMPA Cane Island Power Park Florida 2.0 ppm 24-hr SCR September 2008 RBLC # FL-0304 

Blythe Energy LLC (Blythe II) California 2.0 ppm 3-hr SCR/DLN April 2007 PSD Permit 

Elk Hills Power California 2.5 ppm 1-hr 

SCR/DLN or 

SCONOX January 2006 PSD Permit Modification 

Rocky Mountain Energy Center Colorado 3.0 ppm 1-hr SCR/LNB May 2006 RBLC # C0-0056 

San Joaquin Valley Energy Center California 2.0 ppm 1-hr SCR/DLN August 2006 PSD permit 

Walnut Energy Center California 2.0 ppm 1-hr SCR 2004 California Energy 

Commission 

Donald Von Raesfeld Power Plant California 2.0 ppm 1-hr SCR 2003 California Energy 

Commission 

IDC Bellingham Massachusetts 1.5 ppm 1-hr SCR 2000 SCAQMD - project 

cancelled 

 

16 We note that this permit is currently the subject of an administrative appeal to EPA’s EAB; however, the appeal does not pertain specifically to the BACT analysis 

for NOx or the permit’s emission limits for NOx. 
20

7.1.2 Carbon Monoxide Emissions 

Step 1 – Identify All Control Technologies 

The inherently lower-emitting control options for CO emissions include: 

• Good combustion practices 

The available add-on CO control technologies include: 

• Oxidation catalyst 

• EMxTM

Step 2 – Eliminate Technically Infeasible 

All of the available control options identified in Step 1 are technically feasible. 

Step 3 – Rank Remaining Control Technologies 

A summary of recent BACT limits for similar combined-cycle, natural-gas fired CTs is provided in 

Table 7-5. The applicant proposed using oxidation catalyst with a limit of 2.0 ppm (with and 

without duct burning) based on a 1-hr average. Currently, the lowest permitted limit for 

oxidation catalyst is the Kleen Energy facility in Connecticut, which has a limit of 0.9 ppm (1.8 

ppm with duct firing) based on a 1-hr average. The Kleen Energy facility has recently begun 

commercial operation, but results from compliance demonstration testing are not available at this 

time.17 The next most stringent permitted limit is the Avenal Energy Project in California, which 

has a limit of 1.5 ppm following a demonstration period18 (2.0 ppm with duct burning) and also 

uses oxidation catalyst. The Avenal Energy Project has not begun construction at this time. 

Based on this information, oxidation catalyst is being evaluated at the most stringent control 

option. 

Oxidation Catalyst and EMxTM

Oxidation catalyst is a well-demonstrated technology for large CTs. As discussed in the NOX

BACT analysis, it is clear that EMxTM is an available and technically feasible technology. 

However, it is unclear what level of control would be achieved by the technology on a long-term 

basis with a short (1-hr) averaging period. The manufacturer claims that emission rates below 1 

ppm are achievable, but there is a lack of information that demonstrates this on large CTs. We 

are not aware of any BACT determinations that have required EMxTM for CO emissions. Based 

on the lack of information for similar units, EMxTM is conservatively being compared as equivalent 

to oxidation catalyst. 

 

17 See August 4, 2011 email from Louis Corsino to Lisa Beckham – “Kleen Energy – Middletown, CT”. 

18 This limit becomes effective after a 3-year demonstration period, during which the limit is 2.0 ppm. As noted above, 

this permit is currently the subject of an administrative appeal to EPA’s EAB; however, the appeal does not pertain 

specifically to the BACT analysis for CO or the permit’s emission limits for CO..
21

The available control technologies are ranked according to control effectiveness in Table 7-6. 

Table 7-6: CO Control Technologies Ranked by Control Effectiveness 

CO Control Technology 

Emission Rate 

(ppmvd @ 15% O2, 1-

hr average, without 

duct firing) 

Emission Rate 

(ppmvd @ 15% O2, 

1-hr average, with 

duct firing) 

Oxidation catalyst and good 

combustion practices 

0.9-2.0 ppm 2.0-2.4 ppm 

EMxTMand good combustion 

practices 

0.9–2.0 ppm 2.0-2.4 ppm 

Good combustion practices 8.0 ppm 8.0 ppm 

Step 4 – Economic, Energy and Environmental Impacts 

Although EMxTM is being considered equivalent to oxidation catalyst for controlling CO 

emissions, it was determined to be inferior to SCR for controlling NOX emissions. Because 

EMxTMwould not ensure BACT is achieved for NOX, it is being eliminated in this step due to 

environmental impacts. Overall, better and more reliable pollution control for NOX and CO will 

be achieved for the Project with SCR and oxidation catalyst than with EMX

TM

. We are not aware 

of any significant or unusual adverse environmental impacts associated with good combustion 

practices and an oxidation catalyst. 

Step 5 – Select BACT 

Based on the review of the available control technologies, we have concluded that BACT for CO 

is good combustion practices and an oxidation catalyst with a limit of 1.5 ppm at 15% O2 based 

on a 1-hr average without duct firing, and 2.0 ppm with duct firing. Additionally, we are adding a 

mass emission limit of 5.74 lb/hr without duct firing and 8.90 lb/hr with duct firing based on a 1-

hr average. However, given the lack of long-term compliance data for the lower limits that would 

apply without duct firing, we feel it is appropriate to include permit provisions establishing a 

three-year demonstration period for those limits, during which time the limit will be 2.0 ppm at 

15% O2 and 7.65 lb/hr based on a 1-hr average without duct firing. 

Demonstration period permit provisions will require that, prior to construction, the permittee 

submit design specifications as proof that the gas turbines were designed to achieve 1.5 ppm. The 

permittee must also submit a plan that sets forth the measures that will be taken to maintain the 

system and optimize its performance. The permittee must operate the gas turbines according to 

the design specifications and within the design parameters, and consistent with the maintenance 

and performance optimization plan. Following the first three years of commercial operation, the 

limits of 1.5 ppm (1-hour average) without duct firing will take effect unless the emissions and 

operating data collected by the applicant indicates that these limits are not feasible, and the 

applicant submits an application to EPA no later than the end of the 3-year period requesting a 

revision to the limit. If such a revision is requested but EPA determines that a revision is not 

warranted, the lower emission limit will become applicable. 
22

Table 7-5: Summary of Recent CO BACT Limits for Similar Combined-Cycle, Natural gas-fired CTs

Facility Location 

CO Limit (CO 

Limit with duct 

firing) 

Averaging Period Control Permit Issuance Source 

Avenal Energy Project California 

1.5 ppm

19 (2.0 

ppm) 1-hr 

Oxidation 

catalyst 

June 2011 PSD Permit 

Warren County Power Station Virginia 

1.5 ppm (2.4 

ppm with duct 

burning) 

1-hr 

Oxidation 

catalyst/GCP December 2010 PSD Permit 

Langley Gulch Power Plant Idaho 2.0 ppm 3-hr rolling 

Oxidation 

catalyst/GCP 

Draft December 

2010 RBLC # ID-0018 

Live Oaks Power Plant Georgia 2.0 ppm 3-hr 

Oxidation 

catalyst/GCP April 2010 RBLC # GA-0138 

Colousa Generating Station California 3.0 ppm 3-hr 

Oxidation 

catalyst 

March 2010 PSD Permit 

Victorville II Hybrid Power 

Project 

California 

2.0 ppm (3.0 

ppm) 1-hr 

Oxidation 

catalyst 

February 2010 PSD Permit 

Madison Bell Energy Center Texas 17.5 ppm 1-hr rolling GCP August 2009 RBLC # TX-0548 

Chouteau Power Plant Oklahoma 8.0 ppm 1-hr GCP January 2009 RBLC # OK-0129 

Lamar Power Partners II Texas 15 ppm 24-hr rolling GCP June 2009 RBLC # TX-0547 

Patillo Branch Power Plant Texas 2.0 ppm 3-hr rolling 

Oxidation 

catalyst 

June 2009 RBLC # TX-0546 

Cane Island Power Park Florida 8 ppm 24-hr GCP September 2008 RBLC # FL-0304 

Elk Hills Power California 4.0 ppm 1-hr 

Oxidation 

catalyst 

January 2006 PSD Permit 

Modification 

Kleen Energy Systems Connecticut 

0.9 ppm (1.8 

ppm with duct 

firing) 

1-hr 

Oxidation 

catalyst 

February 2008 RBLC # CT-0151 

 

19 This limit becomes effective after a 3-year demonstration period. During the demonstration period, the limit is 2.0 ppm. 
23

7.1.3 PM, PM10 and PM2.5 Emissions 

Because the applicant has 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 

include: 

• Low particulate fuels, low sulfur fuels, and/or pipeline natural gas (also referred to as 

“clean fuel”) 

• Good combustion practices (including air inlet filter) 

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

• Cyclones (including multiclones) 

• Wet scrubber 

• Dry electrostatic precipitator (ESP) 

• Wet ESP 

• Baghouse/fabric filter. 

Step 2 – Eliminate Technically Infeasible Control Options 

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

multiclones). Although cyclones have been identified as being capable of marginal PM2.5

control20, the low grain loading makes them technically infeasible for this application. 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.21 In 

contrast, the grain loading for the CTs’ exhaust stream would be about 0.0015 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. 

Step 3 – Rank Remaining Control Technologies 

A review of other BACT limits for similar combined-cycle natural gas-fired CTs is provided in 

Table 7-7. We note that many BACT determinations that were concluded prior to January 1, 

2011 included limits only for filterable PM.22 Because our BACT analysis for the Project must 

address total PM (filterable plus condensable), we did not further evaluate PM limits addressing 

 

20 

–Information available at 

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

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

22 See 40 CFR 52.21(b)(50) – On or after January 1, 2011, such condensable particulate matter shall be accounted for in 

applicability determinations and in establishing emissions limitations for PM, PM2.5, and PM10 in PSD permits. 
24

solely filterable PM, which would not be applicable here. The applicant proposed a total PM limit 

of 12 lb/hr without duct firing and 18 lb/hr with duct firing. In order to compare these emission 

rates to similar facilities, these limits were converted to lb/MMBtu – 0.0069 lb/MMBtu, and 

0.0079 lb/MMBtu, respectively. 

The most recently permitted units with total PM limits using lb/MMBtu are Warren County 

Power Station in Virginia (Warren County) and the Chouteau Power Plant in Oklahoma 

(Chouteau). Of these two facilities, only the Chouteau unit is operational and demonstrated to be 

in compliance with its PM limits.23 The applicant’s proposed emission rates appear to be 

significantly higher on a lb/MMBtu basis when compared to Chouteau (0.0035 lb/MMBtu) and 

Warren County (0.0027 lb/MMBtu without duct burning and 0.0040 lb/MMBtu with duct 

burning). The results from the total PM testing at Chouteau showed total PM emissions to be 

equivalent to 0.0029 lb/MMBtu (with a 99 MMBtu/hr duct burner).24 Therefore, we believe the 

uncontrolled emission rates that should be evaluated are 0.0027 lb/MMBtu without duct burning 

and 0.0035 lb/MMBtu with duct burning. 

 

We were not able to identify any CT using add-on PM controls; however, such controls are 

considered technically feasible and are therefore being further evaluated. Wet ESP has been 

evaluated as the highest performing control option because all particulate emissions are expected 

to be PM2.5 and wet ESP is expected to perform better in this range as compared to the other addon control technologies. The applicant eliminated the wet scrubber as an option due to possible 

increases in PM emissions associated with the total dissolved solids (TDS) content of the water 

available at the facility. However, it is not clear this has ever been demonstrated as a problem and 

therefore we have conservatively included wet scrubber for further consideration in the BACT 

analysis. We identified a control efficiency of 90% for this option based on the document used by 

the applicant for the economic analysis - “Controlling Fine Particulate Matter Under the Clean Air 

Act: A Menu of Options,” prepared by the State and Territorial Air Pollution Program 

Administrators (STAPPA) and Association of Local Air Pollution Control Officials (LAPCO) 

(hereinafter “Controlling Fine PM”). 25 The applicant also conservatively assumed 99% PM2.5

control for baghouse and dry ESP. 

 

23 See August 3, 2011email from Lisa Beckham, EPA Region 9, to Shirley Rivera, EPA Region 9 re: “Chouteau Power 

Plant in Oklahoma”. 

24 See August 8, 2011 emails from Lisa Beckham, EPA Region 9, to Shirley Rivera, EPA Region 9 re: “Chouteau Power 

Plant in Oklahoma”. 

25 Information is available at http://www.4cleanair.org/PM25Menu-Final.pdf. 
25

Table 7-7: Summary of Recent PM BACT Limits for Similar Combined-Cycle, Natural gas-fired CTs 

Facility Location 

PM Limit (PM Limit 

w/Duct Firing) 

Type of PM - 

Filterable(F), 

Total(T) 

Averaging 

Period Control Permit Issuance 

Source 

Avenal Energy Project26 California 

8.91 lb/hr (11.78 

lb/hr)27 TPM10

12-month 

rolling 

Natural Gas 

Fuel June 2011 PSD Permit 

Warren County Power 

Station 

Virginia 8 lb/hr (14 lb/hr) TPM10, TPM2.5 3-hr --- December 2010 PSD Permit 

Warren County Power 

Station 

Virginia 

0.0027 lb/MMBtu 

(0.0040 lb/MMBtu) TPM10, TPM2.5 3-hr --- December 2010 PSD Permit 

Carty Plant Oregon 2.5 lb/MMscf FPM10 --- Clean Fuel Draft December 

2010 RBLC # OR-0048 

Langley Gulch Power 

Plant 

Idaho No limit FPM10 --- GCP Draft December 

2010 RBLC # ID-0018 

Colusa Generating Station California 13.5 lb/hr TPM, TPM10

12-month 

rolling 

Natural Gas 

Fuel March 2010 PSD Permit 

Victorville II Hybrid 

Power Project 

California 12.0 lb/hr (18.0 lb/hr) TPM, TPM2.5 12-month 

rolling 

Natural Gas 

Fuel March 2010 PSD Permit 

Chouteau Power Plant Oklahoma 

6.59 lb/hr, 0.0035 

lb/MMBtu 

TPM10 3-hr 

Natural Gas 

Fuel January 2009 RBLC # OK-0129 

Cane Island Power Park Florida 2 gr S/100 scf TPM10 --- Fuel Spec September 2008 RBLC # FL-0304 

FPL West County Energy 

Center Unit 3 Florida 2 gr S/100 scf PM/PM10/PM2.5 --- Fuel Spec July 2008 RBLC # FL-0303 

Plaquemine Cogeneration 

Facility 

Louisiana 

33.5 lb/hr, 0.02 

lb/MMBtu 

FPM10, TPM --- Clean Fuel July 2008 RBLC # LA-0136 

Aresnal Hill Power Plant Louisiana 24.23 lb/hr FPM --- 

GCP/Pipeline 

NG Mar-08 RBLC # LA-0224 

Kleen Energy Systems Connecticut 11 lb/hr (15.2 lb/hr) FPM10 --- --- February 2008 RBLC # CT-0151 

 

26 As noted above, this permit is currently under administrative appeal; however, the appeal does not pertain specifically to the BACT analysis for PM10 or to the 

permit’s emissions limits for PM10. 

27 These limits are equivalent to 0.0048 lb/MBBtu without duct firing and 0.0049 lb/MMBtu with duct firing, based on the size of the CTs and duct burners. 
Palmdale (SE 09-01) 

Fact Sheet/Ambient Air Quality Impact Report 

August 2011 

26

The available add-on control technologies are ranked according to control effectiveness in 

Table 7-8. 

Table 7-8: PM Control Technologies Ranked by Control Effectiveness 

PM Control Technologies 

Emission Rate 

(lb/MMBtu, 3-hr 

average) 

Emission Rate 

w/Duct Burners 

(lb/MMBtu, 3-hr 

average) 

Wet ESP 0.00004 0.00004 

Dry ESP/Baghouse 0.00004 0.00004 

Wet Scrubber (Venturi) 0.0004 0.0004 

Baseline (Clean Fuel) 0.0027 0.0035 

Step 4 – Economic, Energy and Environmental Impacts 

The applicant provided a cost analysis based on information provided in Controlling Fine PM. A 

modified version of this analysis is provided in Table 7-9. The amount of PM2.5 removed is based 

on the baseline (natural gas) emission rates in Table 7-8. Because add-on PM controls have not 

been applied to CTs, the control efficiencies evaluated are considered conservative. With costeffectiveness values ranging between $109,000 and $193,000 per ton of PM2.5 removed, add-on 

controls are considered cost-prohibitive for the PHPP. 

Table 7-9: Cost Analysis for Add-on PM Control Technologies 

Wet ESP Dry ESP 

Baghouse 

(pulse-jet 

cleaned) 

Wet Scrubber 

(Venturi) 

Flowrate (ft3/min) 946,777 946,777 946,777 946,777

Capital Costs ($/scfm) $20 $10 $6 $3

Capital Costs ($) $18,935,540 $9,467,770 $5,680,662 $2,366,942.50

Cost Recovery Factor 0.11 0.11 0.11 0.11

Annualized Capital Costs ($/yr) $2,082,909 $1,041,454.70 $624,872.82 $260,363.68

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

O & M Costs ($/yr) $4,733,885 $2,840,331 $4,733,885 $4,165,819 

Total Annualized Costs ($/yr) $6,816,794 $3,881,786 $5,358,758 $4,426,182 

Removal Efficiency 99.1% 99% 99% 90%

Tons of PM2.5 Removed (TPY) 35.38 35.34 35.34 32.13

Cost Effectiveness ($/ton 

removed) $192,680 $109,830 $151,620 $137,760 

Step 5 – Select BACT 

After eliminating wet ESP, dry ESP, fabric filter, and wet scrubber due to economic impacts, we 
Palmdale (SE 09-01) 

Fact Sheet/Ambient Air Quality Impact Report 

August 2011 

27

have determined that BACT is clean fuel, good combustion practices, a PM, PM10, and PM2.5

limit of 0.0027 lb/MMBtu without duct burning and a limit of 0.0035 lb/MMBtu with duct 

burning based on a 3-hr average. Additionally, we are setting mass emission limits of 4.7 lb/hr 

without duct firing and 8.0 lb/hr with duct firing based on a 3-hr average. By “clean fuel” we 

mean Public Utilities Commission (PUC)-quality natural gas. PUC-quality pipeline natural gas 

shall not exceed a sulfur content of 0.20 grains per 100 dry standard cubic feet on a 12-month 

rolling average and shall not exceed a sulfur content of 1.0 grains per 100 dry standard cubic feet, 

at any time. This limit is lower than the limit proposed by the applicant. However, when 

comparing the applicant’s proposed emission rates to other recently permitted sources, the 

applicant’s values are in some cases twice as high. The applicant relied solely on the Victorville II 

facility in California in proposing emission rates. While the two facilities are very similar, a BACT 

analysis should be more comprehensive in evaluating proposed limits. A broader review of recent 

BACT determinations demonstrates that BACT is lower than the limits proposed by the applicant. 

7.1.4 GHG Emissions 

Step 1 – Identify all control technologies 

The inherently lower-emitting control options for GHG emissions include28: 

• Use of new thermally efficient combined cycle gas turbines – A combined-cycle gas 

turbine recovers the waste heat from the gas turbine using a heat recovery steam 

generator (HRSG). The use of the HRSG allows more energy to be produced without 

additional fuel use. 

The add-on control options for GHG emissions include: 

• Carbon capture and sequestration (CCS) – CCS is a technology that involves capture and 

storage of CO2 emissions to prevent their release to the atmosphere. For a gas turbine, 

this includes removal of CO2 emissions from the exhaust stream, transportation of the 

CO2 to an injection site, and injection of the CO2 into available sequestration sites. 

Potential CO2 sequestration sites include geological formations (including oil and gas 

fields for enhanced recovery) and ocean storage. 

Step 2 – Eliminate technically infeasible control technologies 

CCS 

As described briefly above, CCS involves three main components: capturing the CO2 emissions 

from the exhaust stream, transporting the captured CO2 to the sequestration site, and injection of 

the CO2 into a geologic reservoir for long-term sequestration. All three of these aspects are 

relevant when determining whether CCS is technically feasible for a particular project. 

 

28 In addition to the measures discussed here specifically for the gas turbines, we note that the project design includes 50 

MW of potential solar thermal power generation, which represents an inherently lower-emitting technology for the 

facility as a whole. 
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The applicant proposed to eliminate CCS because CO2 capture is not technically feasible for CTs. 

 The applicant identified three potential processes for capturing CO2 from flue gas: solvent-based 

processes, sorbent-based processes, and membrane-based processes. The applicant concluded 

that these processes were not technically feasible due to limited experience in the energy industry 

and lack of commercial demonstrations. However, commercial CO2 recovery plants have been in 

existence since the late 1970s, with at least one plant capturing CO2 from gas turbines.29,30 The 

applicant also identified as a hurdle that commercial demonstrations have only captured a fraction 

of the CO2 in flue gas. This consideration appears to be less of a technical feasibility issue than 

one of cost, which would be more appropriately addressed in Step 4 of the BACT analysis. Based 

on available information, we consider carbon capture from gas turbines to be technically feasible 

for the Project. 

In its application, the applicant identified several geological formations in the lower San Joaquin 

Valley and Ventura County that could potentially provide a suitable site for geologic 

sequestration; a map of those sites provided in the Project application is provided in Figure 7-1. 

While geotechnical analyses have not been conducted to verify the suitability of these sites, other 

proposals have been made to capture and sequester CO2 emissions in the San Joaquin Valley; as a 

result, there is a reasonable presumption that suitable sequestration sites do exist in these areas 

despite the lack of extensive studies prepared for this Project. Nevertheless, the primary issue 

with the feasibility of CCS in this case lies with the location of the PHPP in relation to the 

sequestration sites and the surrounding geography. As shown in the figure above, significant 

mountain ranges lie between the project location and the potential sequestration sites (oil fields, 

gas fields, and ocean storage). Sequestration of CO2 emissions from the Project would require 

construction of CO2 pipelines through these mountains. The offsite logistical barriers of 

constructing such a pipeline (e.g., land acquisition, permitting, liability, etc.) make this technology 

technically infeasible for the Project. 

Because constructing a new CO2 pipeline was determined to be technically infeasible, the 

applicant also evaluated whether CO2 pipelines were already available near the proposed Project. 

The Technical Advisory Committee for the California Carbon Capture and Storage Review Panel 

stated in an August 2010 report that there are no existing CO2 pipelines in California.31 In 

addition, based on a search of the California Environmental Quality Act (CEQA) State 

Clearinghouse database maintained by the California Office of Planning and Research, there are 

no CO2 pipeline projects underway in California subject to CEQA. Last, the applicant also 

contacted the Department of Oil, Gas and Geothermal Resources and facilities operating in Kern 

County, and again, found no existing pipelines in California. 

 

29 Herzog, H.J., “An Introduction to CO2 Separation and Capture Technologies,” Energy Laboratory Working Paper, 

(1999). Available at http://sequestration.mit.edu/pdf/introduction_to_capture.pdf. 

30 Johnson, D., Reddy, S., & Brown, J.H. (2009), Commercially Available CO2 Capture Technology. Power. Retrieved 

from http://www.powermag.com/coal/2064.html. 

31 This information is available at http://climatechange.ca.gov/carbon_capture_review_panel/meetings/2010-08-

18/white_papers/Carbon_Dioxide_Pipelines.pdf. 
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Figure 7-1 Potential CO2 Sequestration Sites in Southern California 

Data source: National Energy Technology Laboratory, Department of Energy. 2010 Carbon 

Sequestration Atlas of the United States and Canada, Third Edition 

In sum, while we have determined that CO2 capture and storage is technically feasible, we 

conclude that transport of the captured CO2 to the potential sequestration sites is not feasible. As 

a result, CCS is not technically feasible for the Project and will not be considered further in the 

BACT analysis. We note that evaluation of long-term CO2 storage is an important part of the 
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technical feasibility analysis. However, because transport of CO2 is not technically feasible, it is 

not necessary to evaluate the feasibility of CO2 storage. 

Step 3 – Rank remaining control technologies 

After elimination of CCS as a potential control technology, the use of a thermally efficient 

combined-cycle gas turbine and a combined-cycle facility are the only control methods remaining. 

 The expected emissions from a facility with these control options is compared with the emissions 

from a simple-cycle gas turbine in Table 7-10. Currently, the only other similar facility with a 

GHG BACT limit is the Russell City Energy Center, to be located in Hayward, California. The 

PSD permit for this facility has a voluntary GHG limit of a heat rate not to exceed 7,730 Btu/kWh 

for each CT and HRSG. 

Table 7-10: GHG Control Technologies Ranked by Control Effectiveness 

GHG Control Technologies 

Emission Rate 

(lb CO2/MWh) 

New combined-cycle gas CT 774 

Existing combined-cycle CTs32 824-996 

Simple-cycle CTs33 1,319 

Step 4 – Economic, Energy, and Environmental Impacts 

The applicant has chosen the highest ranked control option for each unit, and we are not aware of 

any significant or unusual adverse environmental impacts associated with the chosen technology. 

Step 5 – Select BACT 

Based on a review of the available control technologies for GHG emissions from natural gas-fired 

combustion turbines, we have concluded that BACT for this source is the use of new thermally 

efficient CTs and emission limits of 774 lb CO2/MWh for source-wide net output, and 117 lb 

CO2/MMBtu heat input for each gas turbine and duct burner (both based on a 30-day rolling 

average). The emission limits are based on the emission factor provided by the applicant of 53.06 

kg/MMBtu, the 1,736 MMBtu/hr heat input of each CT operating 8,760 hours per year, and the 

550 MMBtu/hr duct burner for each CT operating 2,000 hours per year. 

A number of issues regarding these limits bear clarification. First, the pollutant that is subject to 

regulation under the Clean Air Act for PSD permitting purposes is a group of six gases: carbon 

dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 

As a general matter, it may thus be appropriate to establish BACT limits on a CO2e basis. In this 

case, however, we have elected to establish the BACT limit for CO2 specifically. The purpose of 

this is to enable the use of CO2 CEMS for monitoring purposes. Because the CEMS are required 

for other regulatory purposes, they offer a cost-effective and reliable method for monitoring 

 

32

 These figures are based on GHG performance information provided by the applicant in Tables 3 and 4 to the PHPP 

GHG BACT Analysis dated May 2011. These values are derived from 2008 data from the California Energy 

Commission for similar facilities with energy output of at least 3,000 GWh per year. 

33 These numbers are based on the proposed CTs operating in simple cycle with a gross output of 154 MW each. 
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compliance. Using CO2 as a surrogate for the total emissions on a CO2e basis is appropriate in 

this case because nitrous oxide and methane are emitted from CTs in minor amounts and the 

majority of the GHG emissions actually are CO2. For example, EPA’s emission factors for CO2, 

methane, and nitrous oxide from the combustion of natural gas are 53.06 kg/MMBtu, 0.0059 

kg/MMBtu, and 0.0001 kg/MMBtu, respectively. The emission factor for all GHGs on a CO2e 

basis is 53.21 kg/MMBtu. Thus, even after accounting for the global warming potential of 

methane and nitrous oxide, the CO2 emission factor accounts for 99.7% of the emission on a 

CO2e basis. Further, an emission limitation that limits CO2 emissions from the combustion of 

natural gas inherently limits the emission of methane and nitrous oxide. As a result, we believe 

that for this particular source, formulating the emission limits and monitoring requirements in 

terms of CO2 rather than on a CO2e basis is appropriate. The applicant has proposed a BACT 

limit of 1,020,000 tons of CO2 per year for each CT. However, a limit based on the amount of 

CO2 generated per MWh will ensure that the CTs are operating at peak efficiency. An inputbased limit is also necessary to ensure peak operating efficiency of the gas turbine because the 

solar thermal operation will at times contribute to the electric output. 

7.1.5 BACT During Startup and Shutdown 

It is not technically feasible to use SCR and oxidation catalyst to control NOX and CO emissions 

when the equipment is outside of the manufacturer’s recommended operating temperature ranges. 

For SCR and oxidation catalyst this occurs during turbine startup or shutdown. Therefore, BACT 

is achieved by minimizing the time for startup and shutdown. The PHPP will have a 110 

MMBtu/hr auxiliary boiler that will be used to reduce the startup time for each turbine. The 

applicant has proposed the following NOX and CO emission rate limits for each event: 

• Hot/Warm Startup: 40 pounds of NOX and 329 pounds of CO per turbine 

• Cold Startup: 96 pounds of NOX and 410 pounds of CO per turbine 

• Shutdown: 57 pounds of NOX and 337 pounds of CO per turbine 

An evaluation of startup and shutdown emission limits for other similar sources found a wide 

range of limits. In many cases, limits are based on pounds per hour or pound per event,34 and this 

approach makes it difficult to compare BACT determinations because mass emission rates vary 

based on the size of the unit. Other facilities have longer averaging periods (24-hr), which may 

incorporate startup and shutdown emissions. Because the PHPP has short 1-hour averaging 

periods, it is appropriate to set limits on a mass basis and limit the duration of startup and 

shutdown events. Based on the available information, the emission rate limits and fast startup and 

shutdown times for the CTs represent BACT for NOx and CO during startup and shutdown. 

Therefore, we have determined that BACT during startup and shutdown for NOX and CO for the 

PHPP is as described below in Table 7-11. 

 

34 Recently issued permits with these types of limits include the permits for the Avenal Energy Project in California, the 

Russell City Energy Project in California, the Victorville II Hybrid Power Project in California, and the Colusa 

Generating Station in California. 
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In addition, we have determined that the startup duration limits also constitute BACT for GHG 

emissions, because the shorter startup time increases the overall thermal efficiency of the facility. 

Therefore, BACT for the PHPP’s GHG emissions during startup is 110 minutes for a cold startup 

and 80 minutes for a warm/hot startup. 

Table 7-11: Summary of NOX and CO BACT Limits During Startup and Shutdown 

 

NOX CO Duration 

Cold Startup 

96 lb/event 410 lb/event 

110 minutes 

52.4 lb/hr 224 lb/hr 

Warm/Hot Startup 

40 lb/event 329 lb/event 

80 minutes 

30 lb/hr 247 lb/hr 

Shutdown 

57 lb/event 337 lb/event 

30 minutes 

114 lb/hr 334.6 lb/hr 

7.2. BACT for Auxiliary Boiler and Heater 

The applicant is proposing to construct a 110 MMBtu/hr boiler that will be used to start up the 

CTs, and a 40 MMBtu/hr heat transfer fluid (HTF) heater as part of the solar array system. Both 

units will be fired with natural gas. The boiler will be limited to 500 hours of operation per year 

and the HTF heater will be limited to 1,000 hours of operation per year. The low hours of 

operation and low emission rates proposed result in very low tons per year emission rates for each 

unit. The boiler and HTF heater are subject to BACT for NOX, CO, PM, PM10, PM2.5, and GHGs. 

A top-down BACT analysis for each pollutant has been performed and is summarized below. 

7.2.1 Nitrogen Oxide Emissions 

Step 1 - Identify All Control Options 

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

• Low NOX burner design (e.g. low NOX burners, flue gas recirculation) 

• Limited use of equipment (limits on the hours of operation) 

The available add-on NOX control technologies include: 

• Selective Catalytic Reduction (SCR) system 

• EMxTMsystem (formerly SCONOx) 

• Selective non-catalytic reduction (SNCR) 

Step 2 – Eliminate Technically Infeasible Options 

SCR, EMxTM, and SNCR are considered technically infeasible control options. The applicant 

estimated the exhaust temperature for each unit at 300°F. This is below the temperature 

operating range for SCR, EMxTM, and SNCR, which are all generally above 400°F. 
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Step 3 – Rank remaining control technologies 

The applicant proposed a NOX emission limit of 9 ppm at 3% O2 based on a 3-hr average using 

ultra-low NOX burner design. With the proposed low NOX burner designs and limited hours of 

operation the auxiliary boiler will emit up to 0.30 TPY of NOX and the heater will emit up to 0.22 

TPY. A review of other BACT determinations was not performed because it is very unlikely that 

a more detailed review would change the final determination due to the limited use and low ton 

per year emission rates associated with the proposed limits. 

Table 7-12: .NOX Control Technologies Ranked by Control Effectiveness 

NOX Control Technologies 

Emission Rate 

(ppmvd @ 3% O2)

Low NOX burners and limited use 9 

Step 4 – Economic, Energy, and Environmental Impacts 

The applicant has chosen the highest ranked control option for each unit, and we are not aware of 

any significant or unusual environmental impacts associated with the chosen technology. 

Step 5 – Select BACT 

Based on the review of the available control technologies, we have concluded BACT is the limited 

hours of operation, ultra-low NOX burners and an emission rate of 9.0 ppm at 3% O2 based on a 

3-hr test average. 

7.2.2 Carbon Monoxide Emissions 

Step 1 – Identify All Control Technologies 

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

• Good combustion practices 

• Limited use (limits on the hours of operation) 

The available add-on CO control technologies include: 

• Oxidation catalyst 

• EMxTM (formerly SCONOX) 

Step 2 – Eliminate Technically Infeasible 

Oxidation catalyst and EMxTMare considered technically infeasible control options. The applicant 

estimated the exhaust temperature for each unit at 300F. This is below the temperature operating 

range for oxidation catalyst and EMxTM, which are generally above 400F. 

Step 3 – Rank Remaining Control Technologies 

The applicant proposed a CO limit of 50 ppm at 3% O2 based on a 3-hr average using good 

combustion practices. With the proposed good combustion practices and limited hours of 

operation, the auxiliary boiler will emit up to 1.01 TPY, and the heater will emit up to 0.74 TPY, 

of CO. A review of other BACT determinations was not performed because it is very unlikely 
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that a more detailed review would change the final determination due to the limited use and low 

ton per year emission rates associated with the proposed limits. 

Table 7-13: CO Control Technologies Ranked by Control Effectiveness 

CO Control Technologies 

Emission Rate 

(ppmvd @ 3% O2)

Good combustion practices and 

limited use 

50 

Step 4 – Economic, Energy and Environmental Impacts 

The applicant has chosen the highest ranked control option for each unit, and we are not aware of 

any significant or unusual adverse environmental impacts associated with the chosen technology. 

Step 5 – Select BACT 

Based on the review of the available control technologies, we have concluded that BACT is the 

limited hours of operation, good combustion practices and an emission rate of 50.0 ppm at 3% O2 

based on a 3-hr test average. 

7.2.3 PM, PM10 and PM2.5 Emissions 

The applicant has assumed that all particulate emissions from the auxiliary boiler and process 

heater are PM2.5. As a result, the BACT analyses for PM, PM10 and PM2.5 have been combined. 

Additionally, the analysis evaluates total particulate matter – filterable and condensable. 

Step 1 – Identify All Control Technologies 

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

include: 

• Low particulate fuels, low sulfur fuels, and/or pipeline natural gas (also referred to as 

“clean fuel”) 

• Good combustion practices (including air inlet filter) 

• Limited use (limits on the hours of operation) 

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

• Cyclones (including multiclones) 

• Wet scrubber 

• Dry electrostatic precipitator (ESP) 

• Wet ESP 

• Baghouse/fabric filter. 

Step 2 – Eliminate Technically Infeasible Control Options 
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All of the control technologies identified are technically feasible except for cyclones (including 

multiclones). As evaluated for the CTs, the low grain loading associated with natural gas 

emissions makes cyclones technically infeasible for this application. 

Step 3 – Rank Remaining Control Technologies 

We were not able to identify any CT using add-on PM controls; however, they are considered 

technically feasible and are therefore being further evaluated. The available control technologies 

are ranked according to control effectiveness in Table 7-14. This analysis is based on the PM, 

PM10, and PM2.5 analysis for the CTs. 

With the proposed good combustion practices and limited hours of operation, the auxiliary boiler 

will emit up to 0.25 TPY of PM, PM10, and PM2.5 and the heater will emit up to 0.15 TPY. A 

review of other BACT determinations was not performed because it is very unlikely that a more 

detailed review would change the final determination due to the limited use and low ton per year 

emission rates associated with the proposed limits. 

Table 7-14: PM Control Technologies Ranked by Control Effectiveness 

PM Control Technologies 

Control 

Efficiency 

Wet ESP 99.1% 

Dry ESP/baghouse 99% 

Wet Scrubber (Venturi) 90% 

Clean fuel, good combustion 

practices, and limited use 0% (baseline) 

Step 4 – Economic, Energy and Environmental Impacts 

The applicant eliminated the use of add-on PM controls for each unit because of the associated 

economic impacts. The 110 MMBtu/hr auxiliary boiler is limited to 500 hours of operation per 

year and has a potential to emit 0.2 TPY of PM, PM10, and PM2.5. The 40 MMBtu/hr heater is 

limited to 1,000 hours of operation per year and has a potential to emit 0.15 TPY of PM, PM10, 

and PM2.5. Due to the limited hours of operation and limited environmental benefit it would be 

impractical to require add-on controls to remove less than 0.45 TPY of PM, PM10, and PM2.5. 

However, the applicant also provided an economic analysis for add-on controls, which is provided 

in Tables 7-15 and 7-16. 
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Table 7-15: Cost Analysis for Add-on PM Control Technologies for the Auxiliary Boiler 

Control Device Wet ESP Dry ESP Pulse Jet 

Fabric Filter 

Wet 

Scrubber 

Flowrate (scfm) 28416 28416 28416 28416

Capital Costs ($/scfm) $20 $10 $6 $3

Capital Costs ($) $568,320 $284,160 $170,496 $71,040.00

Cost Recovery Factor 0.11 0.11 0.11 0.11

Annualized Capital Costs ($/yr) $62,515 $31,257.60 $18,754.56 $7,814.40

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

O & M Costs ($/yr) $142,080 $85,248 $142,080 $125,030 

Total Annualized Costs ($/yr) $204,595 $116,506 $160,835 $132,845 

Removal Efficiency 99.1% 99% 99% 90%

Tons of PM2.5 Removed (TPY) 0.20 0.20 0.20 0.18

Cost Effectiveness ($/ton 

removed) $1,032,300 $588,400 $812,300 $738,000 

Table 7-16: Cost Analysis for Add-on PM Control Technologies for the HTF Heater 

Control Device Wet ESP Dry ESP 

Baghouse 

(pulse- jet 

cleaned) 

Wet 

Scrubber 

Flowrate (scfm) 10612 10612 10612 10612

Capital Costs ($/scfm) $20 $10 $6 $3

Capital Costs ($) $212,240 $106,120 $63,672 $26,530.00

Cost Recovery Factor 0.11 0.11 0.11 0.11

Annualized Capital Costs ($/yr) $23,346 $11,673.20 $7,003.92 $2,918.30

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

O & M Costs ($/yr) $53,060 $31,836 $53,060 $46,693 

Total Annualized Costs ($/yr) $76,406 $43,509 $60,064 $49,611 

Removal Efficiency 99.1% 99% 99% 90%

Tons of PM2.5 Removed (TPY) 0.15 0.15 0.15 0.14

Cost Effectiveness ($/ton 

removed) $514,000 $293,000 $404,500 $367,500 

Step 5 – Select BACT 

Based on the review of the available control technologies, we have concluded BACT is the limited 

hours of operation, good combustion practices, and clean fuel. By “clean fuel” we mean Public 

Utilities Commission (PUC)-quality natural gas. PUC-quality pipeline natural gas shall not exceed 

a sulfur content of 0.20 grains per 100 dry standard cubic feet on a 12-month rolling average and 

shall not exceed a sulfur content of 1.0 grains per 100 dry standard cubic feet, at any time. 
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Additionally, based on the PTE for each unit, we are setting a PM, PM10, and PM2.5 limit of 0.8 

lb/hr for the boiler and 0.3 lb/hr for the HTF heater based on a 3-hr average. 

7.2.4 GHG Emissions 

Step 1 – Identify all control technologies 

The applicant generally assumed that the auxiliary boiler and HTF heater would incorporate the 

newest designs that increase thermal efficiency, such as new burner technologies and modern 

optimized instrumentation and controls. 

The inherently lower-emitting control options for GHG emissions include: 

• Conducting an annual boiler tune-up – this would ensure that optimal thermal efficiency 

is maintained. Maintaining higher thermal efficiency reduces the amount of fuel 

combusted, which helps to minimize GHG emissions.

The add-on control options for GHG emissions include: 

• CCS – CCS is a technology that involves capture and storage of CO2 emissions to prevent 

their release to the atmosphere. For a gas turbine, this includes removal of CO2 emissions 

from the exhaust stream, transportation of the CO2 to an injection site, and injection of the 

CO2 into available sequestration sites. Potential CO2 sequestration sites include 

geological formations (including oil and gas fields for enhanced recovery) and ocean 

storage. 

Step 2 – Eliminate technically infeasible control technologies 

CCS 

The GHG BACT analysis for the CTs, discussed above, concluded that although CO2 capture and 

storage is technically feasible, transport of the captured CO2 to the potential sequestration sites is 

not technically feasible. Using this same analysis, CCS is also not technically feasible for the 

auxiliary boiler and HTF heater and will not be considered further in the BACT analysis. 

Step 3 – Rank remaining control technologies 

After elimination of CCS as a potential control technology, the purchase of thermally efficient 

units and annual boiler tune-ups are the remaining technologies. Both of these options will be 

required.

Step 4 – Economic, Energy, and Environmental Impacts 

The applicant has chosen the highest ranked control option for each unit, and we are not aware of 

any significant or unusual adverse environmental impacts associated with the chosen technology. 
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Step 5 – Select BACT 

Based on a review of the available control technologies for GHG emissions from natural gas-fired 

boilers and process heaters, we have concluded that BACT for this source is the purchase of 

thermally efficient units, conducting annual boiler tune-ups on each unit, limiting the auxiliary 

boiler to a heat input of 110 MMBtu/hr and 500 hours of operation per year based on a 12-month 

rolling total, and limiting the HTF heater to 40 MMBtu/hr and 1,000 hours of operation per year 

based on 12-month rolling total. Currently, there are no other facilities with GHG BACT limits 

for limited use natural gas-fired boilers and process heaters. 

7.3 BACT for Emergency Internal Combustion Engines 

The project includes a 2,862 HP (2134 kW) diesel-fired emergency generator and a 182 HP 

(138kW) diesel-fired emergency fire pump engine. Each engine will be limited to 50 hours of 

operation each year. The low hours of operation result in very low tons per year emission rates 

for each unit. This equipment is subject to BACT for NOX, CO, PM, PM10, PM2.5, and GHGs. A 

top-down BACT analysis has been performed and is summarized below. 

7.3.1 NOX, CO, PM, PM10, PM2.5, and GHG Emissions 

Step 1 -- Identify all control technologies 

The control options for NOX emissions from engines include SCR, NOX reducing catalyst, NOX

adsorber, catalyzed diesel particulate filter, catalytic converter, and oxidation catalyst.35 A 

catalytic converter and oxidation catalyst are also control options for CO emissions. For PM, 

PM10, and PM2.5 emissions, a diesel particulate filter/trap can be added on. 

Unlike other combustion equipment (e.g., CTs and boilers), new engines are required to be 

certified in compliance with NSPS requirements, including emission limits, upon purchase. 

Different types of engines have different emission requirements based on the type of engine being 

purchased (emergency engine, emergency fire pump engine, or non-emergency engine). Engine 

manufacturers may need to employ some of the control technologies identified above in order to 

comply with the NSPS emission limits, depending on the type of engine and the applicable limits. 

The applicant is proposing to construct an emergency engine and an emergency fire pump engine. 

As a result, to comply with NSPS the applicant must purchase engines that meet the emission 

requirements for emergency engines and emergency fire pump engines. However, we note that the 

applicant could purchase engines that meet the NSPS standards for non-emergency engines, 

which have more stringent limits, and operate them as emergency engines. In addition, the 

applicant must comply with California Air Resources Board (CARB) emission standards (Tier 2 

standards for the emergency generator and Tier 3 standards for the emergency fire pump engine); 

however, the CARB standards are the same as the applicable NSPS requirements. As a result, 

this review identifies the control technologies to be: 

 

35 The applicant discusses these control options in Section 8.4 of the “Supplemental Information for the Application for 

PSD Permit” dated July 21, 2010. 
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• NSPS-compliant emergency engine and NSPS-compliant emergency fire pump engine 

• Engines that meets NSPS for non-emergency engines 

• Limiting use (limits on the hours of operation) 

Step 2 – Eliminate technically infeasible control options 

All of the control technologies identified are assumed to be technically feasible. 

Step 3 – Rank remaining control technologies 

The available control technologies are ranked according to control effectiveness in Table 7-17.36

Table 7-17: Emergency Engine Control Technologies Ranked by Control Effectiveness 

Engine Type 

NMHC+NOX

(g/kW-hr) 

PM 

(g/kW-hr) 

CO 

(g/kW-hr) 

NSPS-Non-emergency (for 

135 kW) 0.0237 0.59 5.0 

NSPS-Non-emergency (for 

2000 kW) 1.0738 0.10 3.5 

NSPS-Fire Pump Engines 

(for 135 kW) 4.0 0.20 3.5 

NSPS-Emergency (for 

2000 kW) 6.4 0.20 3.5 

Step 4 – Economic, energy and environmental impacts 

Due to economic impacts and limited environmental benefit, the applicant eliminated add-on 

controls for the engines. We agree that the top-ranked control technology (purchasing engines 

that meet NSPS standards for non-emergency engines and operating them as emergency engines) 

would be impractical in this case. This is illustrated in Table 7-18 by the potential emissions from 

these units (based on 50 hours of operation per year and complying with the NSPS for emergency 

engines and emergency fire pump engines). Requiring the additional reductions in emissions that 

would be gained by use of engines that meet NSPS standards for non-emergency engines would 

have very little environmental benefit, which would not justify the cost. While the potential CO2e 

emissions associated with this equipment are higher than those of the other pollutants, they still 

represent less than 0.01% of source-wide CO2e emissions. A review of other BACT 

determinations was not performed because it is very unlikely that a more detailed review would 

change the final determination due to the limited use and low ton per year emission rates 

associated with the proposed limits. 

 

36 CARB-compliant engines are not listed in the rankings because the emission limitations are the same as for NSPScompliant engines. 

37 The actual applicable NSPS limits are 0.40 g/kW-hr for NOX and 0.19 g/kW-hr for NMHC. The tow limits were 

added together in order to compare them to the other types of engines 

38 The actual applicable NSPS limits are 0.67 g/kW-hr for NOX and 0.40 g/kW-hr for NMHC. The two limits were 

added together in order to compare them to the other types of engines. 
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Table 7-18: Summary of Potential to Emit for Emergency Engines 

Pollutant 

Emergency 

Generator 

(TPY) 

Emergency Fire 

Pump Engine 

(TPY) 

NOX 0.67 0.03 

CO 0.39 0.03 

PM, PM10, PM2.5 0.02 <0.01 

CO2e 27.6 4.41 

Step 5 – Select BACT 

Based on the review of the available control technologies, we have concluded that BACT is the 

limited hours of operation and the emission limits listed in Table 7-19 based on a 3-hour 

average.39 The NSPS for engines does not currently regulate GHG emissions, but a separate 

GHG limit is not being proposed. It is assumed that newly purchased engines would be the most 

energy efficient available and that operating in compliance with NSPS requirements will ensure 

that each engine is properly maintained and as efficient as possible. 

Table 7-19: Summary of BACT Emission Limits for Emergency Engines 

Engine 

NMHC+NOX 

(g/kW-hr) 

PM 

(g/kW-hr) 

CO 

(g/kW-hr) 

135 kW Emergency Fire 

Pump Engine 

4.0 0.20 3.5 

2000 kW Emergency 

Engine 

6.4 0.20 3.5 

7.4 BACT for Cooling Tower 

The PHPP includes a 130,000 gallons per minute (gpm), ten-cell evaporative (wet) cooling tower. 

Fugitive particulate emissions are generated from the cooling tower due to the total dissolved 

solids (TDS) in the water. The cooling tower is subject to BACT for PM, PM10, and PM2.5. A 

top-down BACT analysis has been performed and is summarized below. The applicant 

conservatively assumed PM, PM10 and PM2.5 emissions from the cooling tower were equivalent. 

Step 1 – Available Control Technologies 

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

include: 

• Dry cooling - uses an air cooled condenser (ACC) that cools the steam turbinegenerators’ exhaust steam using a large array of fans that force air over finned tube heat 

exchangers. The exhaust from the steam turbine flows through a large diameter duct to the 

ACC where it is condensed inside the tubes through indirect contact with the ambient air. 

The heat is then released directly to the atmosphere. 

 

39 These limits are the same as the applicable CARB Tier 2 and Tier 3 standards. 
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• Wet-dry hybrid cooling – uses wet and dry cooling technologies in parallel, and uses all of 

the equipment involved in both wet and dry cooling. Hybrid cooling technology divides 

the cooling function between the wet and dry systems depending on the capabilities of 

each system under different environmental and operational conditions. 

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

• Drift eliminators 

Step 2 – Eliminate Technically Infeasible 

All of the available control options identified in Step 1 are technically feasible. 

Step 3 – Rank Remaining Control Technologies 

The types of cooling towers are ranked according to control effectiveness in Table 7-20. 

Table 7-20: Cooling Tower Control Technologies Ranked by Control Effectiveness 

Control Technologies 

Emission Rate 

(TPY of 

PM/PM10/PM2.5) 

Dry cooling 0 

Wet-dry hybrid cooling 3.640

Wet cooling with 0.0005% drift 

eliminators 

7.1 

Step 4 – Economic, Energy and Environmental Impacts 

The applicant eliminated the use of both a dry cooling system and wet-dry hybrid cooling system 

due to the associated economic and environmental impacts. The use of a dry or hybrid wet-dry 

system would reduce the overall efficiency of the facility, due to the additional energy 

requirements for the wet and hybrid systems. The applicant also conducted an economic analysis 

comparing the annual operation costs of wet and dry cooling systems. The applicant’s analysis is 

reproduced in Table 7-21. 

Table 7-21: Wet and Dry Cooling Tower Cost Analysis Provided by the Applicant 

 

Wet Cooling 

Tower 

Dry Cooling 

Tower 

Required Power 

Fan Power(e) 1,700 kW 6,350 kW

Circulating Pump Power 2,400 kW 0 kW

 

40 The applicant did not estimate potential emissions from a wet-dry hybrid system. We have approximated emissions 

from such a system to be one-half of those from a wet cooling system. 
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Wet Cooling 

Tower 

Dry Cooling 

Tower 

Power Loss Due to High Steam Turbine 

Backpressure 0 kW 536 kW

Water Treatment Power Consumption 

(Zero Liquid Discharge) 850 kW <200 kW

Total Net Power Loss Effect 12,798 kW 14,042 kW

Costs 

Direct Capital Cost $26,000,000 $59,000,000(e)

Water Pipeline Installation(f)~$1,400,000 $0 

Annualized Cost 

 Capital Recovery

(a) $1,940,000 $3,680,000 

 Equivalent Electrical Power Cost(b) $16,816,500 $18,451,000 

 Treatment Chemical Addition(c) $250,000 $0 

 Makeup Cooling Water

(d) $824,200 ~$100,000

Total $/year $19,830,700 $22,231,000 

Notes: 

a) Assumes a 30-year lifetime with a 5.75% interest rate. 

b) Assumes the facility operates 8,760 hour/yr and a power cost of $0.15/kWh. 

c) Assumes that water treatment chemicals would be needed in a wet tower to prevent 

corrosion, bio-fouling, etc., but would not be needed for an ACC. 

d) Estimated at $200/acre-foot and consumption of 4,121 acre-feet per year for wet 

cooling. 

e) Does not include additional costs required for a steam turbine that can be operated 

at high back pressure. 

f) Only includes the less than 2 miles of pipeline needed to connect to the regional 

backbone system. Dry cooling costs are underestimated since some water is needed 

even in a dry-cooled plant, which would still require a pipeline. 

The cost effectiveness of using a dry cooling process to reduce 7.1 TPY of PM, PM10, and PM2.5

is $338,000 per ton. The applicant estimated a hybrid cooling system would have direct capital 

costs of $67 million and, as a result, would be even less cost-effective than a dry cooling system. 

Based on this information, we agree that using dry or hybrid cooling systems in this case would 

not be cost-effective and would contribute to a decrease in the overall energy efficiency of the 

facility. 

Considering collateral environmental impacts, the use of wet cooling has a potential impact 

associated with additional consumption of water resources. However, the water being used for 

the cooling tower is from the Palmdale Water Reclamation Plant and therefore wet cooling is not 

expected to result in any significant adverse impact on water resources in the area. 

Step 5 – Select BACT 

The applicant proposed using a wet cooling tower with 0.0005% drift eliminators as BACT for 
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the steam turbine cooling system. A comparison of the drift elimination rates for other recently 

permitted cooling towers is provided in Table 7-22. Based on the available information, we have 

determined that BACT for the cooling towers is 0.0005% drift eliminators. Additionally, we are 

setting a mass emission limit of 1.6 lb/hr and TDS limit of 5000 ppm. 

Table 7-22: Summary of Recent BACT Determinations for Drift Eliminators 

Facility Location Limit Permit 

Issuance 

Source 

J.K. Smith 

Generating Station Kentucky 0.0005% April 2010 RBLC # KY-0100 

Chocolate Bayou 

Facility 

Texas 0.0020% June 2009 RBLC # TX-0549 

CPV St Charles Maryland 0.0005% November 

2008 RBLC # MD-0040 

John W Turk Jr 

Power Plant 

Arkansas 0.0005% November 

2008 RBLC # AR-0094 

7.5 BACT for Fugitive Road Dust 

Fugitive dust emissions will occur as a result of maintenance vehicle travel on paved and unpaved 

roadways in the solar field associated with the PHPP. Fugitive road dust is subject to BACT for 

PM, PM10, and PM2.5. A top-down BACT analysis has been performed and is summarized below. 

Step 1 – Available Control Technologies 

The control technologies for fugitive roadway dusts include: paved roads, gravel roads, chemical 

surfactants (also called “dust suppressants”), watering, and traffic speed controls. 

Step 2 – Eliminate Technically Infeasible 

All of the control technologies identified are technically feasible. 

Step 3 – Rank Remaining Control Technologies 

The available control options are ranked as follows: 

• Paved roads 

• Gravel roads 

• Chemical surfactants, watering and traffic speed controls can result in various controls 

efficiencies depending on how each technology is employed (e.g., rate of application, 

specific speed limit) 

Step 4 – Economic, Energy and Environmental Impacts 

Paved roads – The applicant proposed to pave only the main access road to the plant because 

paving other less traveled roads would only have minimal environmental benefits. The applicant 
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noted that paving increases the amount of impervious surfaces, which increases storm water 

runoff, and that the infrequent rainstorms in the desert can also erode the dirt out from under the 

paved edges. 

Gravel roads - The applicant eliminated gravel roads due to the potential for rocks to become 

airborne and damage the parabolic mirrors in the solar field. This would result in additional costs 

for repairing mirrors and a reduction in solar energy production. 

Chemical surfactants, watering, and traffic speed controls - Surface watering and/or application 

of surfactants can be supplemented with limiting vehicle speed and restricting traffic in the 

unpaved areas. According to the applicant, experience in existing solar fields (e.g., the Solar 

Energy Generating Systems (SEGS) facility near Kramer Junction and Harper Lake) shows that 

use of a combination of the above methods is very effective in controlling fugitive dust. Use of 

soil stabilizers during the first few years of operation of the solar facility, followed by application 

of water and driving slowly in the solar field, leads to a very stable surface that yields only minor 

amounts of fugitive emissions. In addition, after the solar facility is built, it is in the operator’s 

best interest to keep dust emissions to a minimum in order to reduce the amount of mirror 

washing and loss of efficiency from dirty mirrors. 

Step 5 – Select BACT 

The applicant proposed BACT for fugitive road dust as: 

• Paving the main access road into the plant site 

• Developing a dust control plan that includes inspection and maintenance procedures 

undertaken to ensure that the unpaved roads remain stabilized 

• A durable non-toxic soil stabilizer will be applied through the solar field for dust control. 

Additionally, unpaved roads within the solar field used by wash trucks that spray and clean 

the mirrors will be treated with soil stabilizers periodically. 

• Water will be applied by water trucks on regularly disturbed areas where soil stabilizers 

are not as effective due to frequent use. The water used in the mirror washing will also 

provide for some incidental dust control. 

• Vehicle speeds will be limited to no more than 10 miles per hour on unpaved roadways, 

with the exception that vehicles may travel up to 25 miles per hour on stabilized unpaved 

roads as long as such speeds do not create visible dust emissions. 

Based on the information provided, we have determined that the above measures represent BACT 

for fugitive road dust, and the fugitive dust control plan must include, at a minimum, the 

requirements listed above. This determination is consistent with other BACT determinations, as 

illustrated in Table 7-23, for onsite operations that cause vehicle traffic. 
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Table 7-23: Summary of Recent BACT Determinations for Fugitive Road Dust Emissions 

Facility Location Control Permit 

Issuance 

Source 

V & M Star Ohio Water, sweeping, chemical 

stabilization or suppressants 

Draft 

January 

2011 

RBLC # 

OH-0344 

Nucor Steel Ohio Water, resurfacing, chemical 

stabilization, and/or speed reduction 

Draft 

December 

2010 

RBLC # 

OH-0341 

Flopam Inc. Maryland 

Paved where practical, precautions 

taken to prevent dust from becoming 

airborne 

June 2010 RBLC # 

LA-0240 

Nucor Steel Louisiana 

Paved where practical, for unpaved 

roads use water or dust suppressant 

chemicals to reduce emissions and 

15 mph speed limit 

May 2010 RBLC # 

AR-0094 

John W. Turk Jr 

Power Plant 

Arkansas Water/dust suppressing chemicals 

November 

2008 

RBLC # 

AR-0094 

7.6 BACT for Circuit Breakers 

7.6.1 GHG 

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

circuit breakers is sulfur hexafluoride (SF6). With the proposed control technologies, CO2e 

emissions are estimated at 9.56 TPY. 

Step 1 – Identify all control technologies 

The inherently lower-emitting control options for GHG emissions include: 

• 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 maximum leak rate of 0.5% per year by weight and have an alarm 

warning when 10% of the SF6 has escaped. The use of an alarm identifies potential leak 

problems before the bulk of SF6 has escaped. 

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

SF6 are also currently not available.

41

 

41 Information is available at http://www.epa.gov/electricpower-sf6/documents/new_report_final.pdf. 
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Step 2 – Eliminate technically infeasible control technologies 

Both control options are assumed to be technically feasible. 

Step 3 – Rank remaining control technologies 

The expected emissions from the two control options are compared in Table 7-24. Currently, the 

only other similar facility with a GHG BACT limit is the Russell City Power Plant to be located in 

Hayward, California. The PSD permit for this facility has a voluntary GHG requirement to install 

the same leak detection system proposed for the PHPP. 

Table 7-24: 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 

9.56 

Step 4 – Economic, Energy, and Environmental Impacts 

The applicant eliminated the use of dielectric oil or compressed air circuit breakers because they 

are an outdated technology and the SF6 circuit breakers are more reliable. Specifically the 

applicant provides that according to the National Institute for Standards and Technology, 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.”42 Dielectric oil or compressed air circuit breakers therefore have been eliminated based on 

the potential adverse environmental and energy impacts. Additionally, we are not aware of any 

significant or unusual environmental impacts associated with the chosen technology. 

Step 5 – Select BACT 

Based on a review of the available control technologies for GHG emissions from circuit breakers, 

we have concluded that the applicant’s proposed requirements are BACT for this source: the use 

of enclosed-pressure SF6 circuit breakers with an annual leakage rate of 0.5% by weight, a 10% 

by weight leak detection system, and 9.56 TPY of CO2e based on a 12-month rolling total. 

8. Air Quality Impacts 

Clean Air Act section 165 and EPA’s PSD regulations at 40 C.F.R. section 52.21 require 

an examination of the impacts of the proposed PHPP 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 

 

42 Ibid. 
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National Ambient Air Quality Standards (NAAQS), or (2) the applicable PSD increments 

(explained below in Section 8.4). This section includes a discussion of the relevant 

background data and air quality modeling, and our 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 would 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. 

Required model inputs characterize the various emitting units, meteorology, and the land surface, 

and define a set of receptors (spatial locations at which to estimate concentrations, typically out to 

50 km from the facility at issue). 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 a) that downwash is properly considered in the modeling for stacks less than 

GEP height, and b) that 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. The 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. 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. 
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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 PHPP is discussed in Section 9 

below. 

8.1.2 Identification of PHPP Modeling Documentation 

The PSD modeling analysis for the PHPP went through several stages, reflecting the regulatory 

requirements and guidance clarifications that came into effect over time, as well as discussions 

between the applicant and EPA about the appropriate methodologies for impact assessment. In 

general, the latest analyses submitted by the applicant are discussed in this AAQIR, with some 

references to earlier work. 

The PHPP modeling analysis comprises the eight documents listed in Table 8-1 below. The Class 

I and Class II Modeling Protocols (July 2008) describe the methods to be used for the air quality 

impact analyses, including choice of model and the preparation of model inputs such as 

meteorological data. The PSD Application (March 2009) contains the results of the modeling. 

After the application submittal, EPA policy changed so that the PM10 NAAQS could no longer be 

used as a surrogate for the PM2.5 NAAQS, and EPA promulgated the 1-hour NO2 NAAQS; 

neither PM2.5 nor 1-hour NO2 these was addressed in the original modeling. The applicant 

submitted Supplemental Information (June 2010) to update its modeling analysis by providing a 

PM2.5 analysis and a 1-hour NO2 analysis considering the Project and background concentrations; 

it also upgraded the additional impact analysis discussed in Section 9 below. The applicant's NO2 

Memo #1 (October 2010) provides a cumulative 1-hour NO2 analysis, which includes nearby 

sources in addition to the Project itself. Finally, the Updated Analyses Memo (March 2011) 

revises the PM2.5 and 1-hour NO2 analyses to account for corrected hourly emissions estimates for 

the nearby U.S. Air Force Plant 42, and to use a more conservative estimate of the NO2

background concentration. The applicant also submitted additional documentation in NO2 Memo 

#2 (December 2010), and the NO2 Background Memo (July 2011), providing additional 

justification for the approaches taken for the applicant’s 1-hour NO2 analysis. 

Table 8-1: Modeling Documentation for Palmdale Hybrid Power Project PSD Application

Short name Citation 

Class I Modeling 

Protocol 

“Class I Area Dispersion Modeling Protocol for the Proposed Palmdale Hybrid 

Power Project”, ENSR Corporation (document 10855-002-040C1MP), July 2008 

(file "PHPP Class I Modeling Protocol.pdf" 

Class II Modeling 

Protocol 

“Class II Area Dispersion Modeling Protocol for the Proposed Palmdale Hybrid 

Power Project”, ENSR Corporation (document 10855-002-040C2MP), July 2008 

(file "PHPP Class II Modeling Protocol.pdf") 

Original PSD 

Application 

“Application for Prevention of Significant Deterioration Permit for Palmdale Hybrid 

Power Project”, AECOM Environment (document 10855-002-040 PSD), March 

2009 

(file "Palmdale PSD Application.pdf") 
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Supplemental 

Information 

“Palmdale Hybrid Power Project PSD Application, Supplemental Information”, 

AECOM, June 2010 

(file "Supplemental PSD Submittal 072010.pdf") 

NO2 Memo #1 

“Response to EPA Comments on AECOM 1-hour NO2 NAAQS Analysis for 

PHPP”, Memorandum from Richard Hamel, AECOM, to Scott Bohning, EPA, 

October 7, 2010 

(file "Response to EPA Comments on NO2 Modeling.pdf") 

NO2 Memo #2 

“Response to EPA Additional Comments on AECOM 1-hour NO2 NAAQS 

Analysis for Palmdale Hybrid Power Project”, Memorandum from Richard Hamel, 

AECOM, to Scott Bohning, EPA, December 14, 2010 

(file "Response to 2nd set of EPA Comments on NO2 Modeling.pdf") 

Updated Analyses 

Memo 

“Final Update to 1-hour NO2 and 24-hour PM2.5 NAAQS Analyses for Palmdale 

Hybrid Power Project”, Memorandum from Richard Hamel, AECOM, to Scott 

Bohning, EPA, March 30, 2011 

(file "Updated NO2 and PM2.5 Modeling Analyses for PHPP 033011.pdf") 

NO2 Background 

Memo 

“Justification of the use of the 3-year average 98th percentile ambient background 

concentration for PHPP 1-hour NO2 NAAQS Modeling”, Memorandum from 

Richard Hamel, AECOM, to Scott Bohning, EPA, July 21, 2011 

(file "1-hour NO2 Ambient Background Justification for PHPP NAAQS Modeling 

072111.pdf") 

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. 

For background concentrations, PHPP chose the Lancaster Division Street monitor, which is the 

nearest available, except for SO2, for which the Burbank West Palm Avenue is nearest. The most 

recent three years of data available at the time of the application are 2005-2007. (PSD 

Application p.6-2 pdf.47; see also Class II Modeling Protocol p.2-19 pdf.24) Based on their 

siting at more urbanized locations than the Project site, these monitors provide conservative 

estimates of background concentrations. The SO2 monitor at Burbank West Palm Avenue is 34 

miles away, but is in the eastern portion of urbanized Los Angeles with its many pollution 

sources, and therefore it provides a conservative estimate of the SO2 background. The Lancaster 

Division Street monitor is just 2.5 miles from the PHPP power block; it is within the city of 

Lancaster, which has a population of some 150,000, and is near several roads; it is thus 

conservative for most pollutants. This site is discussed further below in the section on NO2-

specific issues. 

Table 8-2 below describes the maximum background concentrations of the PSD-regulated 

pollutants for which there are NAAQS that may be affected by the Project’s emissions, and the 

corresponding NAAQS. 
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Table 8-2 Maximum background concentrations and NAAQS 

NAAQS 

pollutant & 

averaging time 

Background 

Concentration, μg/m3 NAAQS, μg/m3

CO, 1-hr 3,680 40,000 (35 ppm) 

CO, 8-hr 1,840 10,000 (9 ppm) 

NO2, 1-hr 77.1 188 (100 ppb) 

NO2, annual 28.2 100 (53 ppb) 

PM10, 24-hr 86 150 

PM2.5, 24-hr 16.3 35 

PM2.5, annual 7.6 15 

 Note: The PM2.5 24-hr value is 98thpercentile rather than maximum 

8.3 Modeling Methodology for Class II areas 

The applicant modeled the impact of PHPP 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 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 modeling protocol (Class II Modeling Protocol sec. 2, p.2-1 pdf.6; also PSD 

Application p.6-1 pdf.46), 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 accords with the default recommendations in EPA's 

GAQM, section 4.2.2 on Refined Analytical Techniques. 
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8.3.2 Meteorology model inputs 

AERMOD requires representative meteorological data in order to accurately simulate air quality 

impacts. For surface air data, PHPP selected 2002-2004 data from the Palmdale Regional 

Airport. Other nearby meteorological sites were examined, but the Palmdale Airport had better 

data completeness, is the closest, and has the same surface characteristics as the Project site. It is 

at or barely below 90% completeness for every quarter; it is within 2 miles, just on the other side 

of the airport's airstrip; and it is on flat, desert scrub land, with no intervening high ground 

between the Project and the meteorological tower (Class II Modeling Protocol p.2-4 pdf.9 and 

Figure 2-2, p.2-5 pdf.10). 

The applicant made additional comparisons of land surface characteristics of the Project and 

meteorological sites, in terms of surface roughness in each radial direction, concluding that 

because of the sites' proximity and essentially identical characteristics, the Palmdale Airport data 

should be considered “site specific” (or “on-site”) data (NO2 Memo #2 p.9ff pdf.9). Normally 

GAQM would require 5 years of airport data for modeling, but if on-site data is used, then a 

single year or those years available, may be used (GAMQ 8.3.3.2). In this case, additional data 

were available for 2005-2006, but the corresponding upper air data had a substantial amount of 

missing data (NO2 Memo #2 p.10 pdf.10). In any case, the wind roses for the various years are 

virtually indistinguishable, evidence that the 2002-2004 data are adequately representative of the 

meteorological conditions at the site. EPA believes that the chosen 2002-2004 Palmdale Regional 

Airport data is amply representative for the PHPP analysis. 

For upper air data, the applicant selected Mercury Desert Rock Airport in Mercury, Nevada, as 

being the most representative site available that had data complete enough to use (Class II 

Modeling Protocol p.2-4 pdf.9). PHPP later elaborated on the representativeness of the Mercury 

Desert Rock Airport Data, noting that Vandenberg AFB in Lompoc, CA and the Marine Corps 

Air Station in Miramar, CA, near San Diego are near the ocean and have a very different climate 

than the high-altitude, desert Palmdale location (NO2 Memo #1 p.2ff pdf.2). EPA agrees that it is 

appropriate to use the Mercury Desert Rock Airport upper air data for the PHPP analysis. 

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, Bowen ratio, and albedo. 

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

Elevation Model (DEM) data for receptor heights for AERMOD, which uses them to assess 

plume distance from the ground for each receptor. The elevations were also used within the 

AERMAP preprocessor to determine hill height scales for each receptor, used by AERMOD to 
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determine whether the plume goes over or around the hill. 

For rural versus urban algorithm within AERMOD, the applicant classified land use within 3 km 

of the project using the 12-category Auer procedure, one of the methods recommended by EPA 

(GAQM 7.2.3(c)). Since desert scrub land is more than 50% of the area, it is classified as “rural” 

for choosing dispersion algorithms within AERMOD (Class II Modeling Protocol p.2-2 pdf.7, and 

Figure 2-1, p.2-3 pdf.8). 

The applicant followed EPA's “AERMOD Implementation Guide” (2008 version) in using EPA's 

AERSURFACE processor with the National Land Cover Data 1992 archive to determine surface 

characteristics for AERMET (Class II Modeling Protocol p.2-9 to 2-14 pdf.14 to 19). A 2005 

satellite image shows no significant change in land use since the 1992 data was compiled, so it 

remains appropriate. Land use cover categories were translated by AERSURFACE into monthly 

parameter values used in AERMET's stage 3 input files. The AERSURFACE determination of 

surface roughness length used land cover in 2 radial sectors, desert scrub and the airport's airstrip, 

which appears reasonable. The Bowen ratio (ratio of sensible to latent heating, i.e., direct 

temperature change versus air heating via evaporation), and albedo (reflection coefficient) affect 

heat-driven turbulence and dispersion under daytime convective conditions. Seasonal Bowen 

ratio for the surrounding 10x10 km area was estimated by AERSURFACE using three surface 

moisture categories and the amount of precipitation relative to the 30-year climatological record. 

Seasonal albedo was also supplied by AERSURFACE for the 10x10 km area based on land cover. 

 

All of these are the standard EPA-recommended procedures for AERMOD inputs. 

8.3.4 Model receptors 

Model receptors are chosen geographic locations at which the model estimates concentrations. 

The receptors should have good area coverage and be closely spaced enough so that the 

maximum model concentrations are 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 not inside the project fence line. In addition, to avoid overly conservative estimates 

when multiple sources are being modeled, separate modeling runs may be needed for different 

subsets of receptors, so that a given source's emissions are not counted toward concentrations 

within its own fence line. 

The applicant used receptors every 50 m along the project fence line, together with a Cartesian 

grid (rectangular array) of receptors, starting with 100 m spacing out to 3 km distant, and with 

progressively larger spacing, with 1000 m spacing between 10 and 20 km distant (PSD 

Application p.6-3 pdf.48). The applicant supplied a rationale for limiting the grid extent to 20 

km, as opposed to 50 km. It found that short-term impacts were caused mainly by the ancillary 
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equipment, such as the emergency generator, rather than the main combustion turbines, and that 

maximum impacts were on the fence line or within 100 m, and likely driven by downwash effects. 

 The applicant conducted additional modeling to compare distance impacts to those within the 20 

km grid, and found that the maximum impacts within 20 km are 2 to 50 times higher than those 

outside, depending on averaging time (Supplemental Information p.6-1 pdf.41). EPA agrees that 

the receptor spacing and 20 km spatial extent are adequate for analysis of PHPP impacts. 

8.3.5 Load screening and stack parameter model inputs 

The applicant performed initial “load screening” modeling, in which a variety of source operating 

loads and ambient temperatures were modeled, to determine the worst case stack parameter 

scenario for use in the rest of the modeling. It modeled 100% load, 100% with duct burners 

operating, 75% load, and 50% load. For annual averages, it used 100% load with a 

conservatively low temperature of 64°F (lower than actual annual average). (PSD Application 

Table 6-3, p.6-4 pdf.49) The choice of “worst case” is different for each pollutant, since different 

pollutants’ emissions respond differently to temperature and flow rate. Worst case for CO and 

NO2 was 100% with duct burners operating; for PM10 and PM2.5 it was 50% load (PSD 

Application p.6-6 pdf.51). The corresponding stack parameters were used in the remainder of 

the modeling to provide conservative estimates of PHPP impacts. 
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Table 8-3: Load screening and stack parameters 

Source: PSD Application Table 6-3, p.6-4 pdf.49 

8.3.6 Good Engineering Practice (GEP) Analysis 

The applicant performed a Good Engineering Practice (GEP) stack height analysis, to ensure a) 

that downwash is properly considered in the modeling for stacks less than GEP height, and b) that 

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. The analysis found that GEP stack height for the main combustion 

turbines was 83.8 m, greater than the planned actual height of 44.2 m. GEP stack height for the 

other equipment was similarly greater than the planned heights. So, for all emitting units, the 

AERMOD modeling used the planned actual stack heights, and included wind direction-specific 

Equivalent Building Dimensions to properly account for downwash. (PSD Application p.6-5 

pdf.50) 
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8.4 National Ambient Air Quality Standards and PSD Class II Increment 

Consumption Analysis 

8.4.1 Pollutants with significant emissions 

An air quality impact analysis is required for each PSD-regulated pollutant (for which there is a 

NAAQS) that is emitted in a significant amount, i.e., an amount greater than the Significant 

Emission Rate for the pollutant. Applicable PHPP emissions and the Significant Emission Rates 

are shown in Table 8-4 (derived from PSD Application Table 1-1, p.8 pdf.8). PHPP emissions of 

SO2 are not significant. However, PHPP emits significant amounts of CO, NOX, PM10, and PM2.5, 

so air impact analyses are required for CO, NO2, PM10, and PM2.5. 

Table 8-4: PSD Applicability to PHPP: Pollutants Emitted in Significant Amounts 

Criteria Pollutant 

PHPP Emissions, 

tons/year 

Significant Emission 

Rate, tons/year PSD applicable? 

CO 254.6 100 Yes 

NOX 114.9 40 Yes 

PM10 131.8 15 Yes 

PM2.5 125.3 10 Yes 

SO2 8.9 40 No 

Source: PSD Application Table 1-1, p.8 pdf.8 

8.4.2 Preliminary analysis: Project-only impacts 

EPA has established Significant Impact Levels (SILs) to characterize air quality impacts. A SIL is 

the ambient concentration resulting from the facility’s emissions, for a given pollutant and 

averaging period, below which the source is assumed to have an insignificant impact. For 

maximum modeled concentrations below the SIL, no further air quality analysis is required for the 

pollutant. For maximum concentrations that exceed the SIL, a cumulative modeling analysis, 

which incorporates the combined impact of nearby sources of air pollution, is required to 

determine compliance with the NAAQS and PSD increments. 

The results of the preliminary or Project-only analysis are shown in Table 8-5. PHPP impacts are 

significant for 1-hour NO2, 24-hour PM10, 24-hour PM2.5, and annual PM2.5, so cumulative impact 

analyses are required for these pollutants. 

Table 8-5: PHPP Significant Impacts, Normal Operations 

NAAQS pollutant & 

averaging time 

Project-only 

Modeled Impact 

Significant Impact 

Level (SIL), μg/m3

Project impact 

significant? 

CO, 1-hr 369.6 2000 No 

CO, 8-hr 20.4 500 No 

NO2, 1-hr 106.9 7.5 (4 ppb) Yes 
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NO2, annual 0.98 1 No 

PM10, 24-hr 12.7 5 Yes 

PM2.5, 24-hr 12.57 1.2 Yes 

PM2.5, annual 1.2 0.3 Yes 

Sources:

Impacts (except for 1-hr NO2 and PM2.5): PSD Application p.6-7 pdf.52 

NO2 1-hr: Supplemental Information p3-2. pdf.22 

PM10: PSD Application Table 6-7, p.6-8 pdf.53 

PM2.5: Updated Analyses Memo Table 9, p.15 pdf.15

8.4.3 Cumulative impact analysis 

A cumulative impact analysis includes nearby sources in addition to the Project itself. For 

demonstrating compliance with the PSD increment, only increment-consuming sources need be 

included, since the increment concerns only changes occurring since the applicable baseline date. 

However, a conservative and sometimes easier approach is simply to model all nearby sources; 

this was the approach taken by PHPP. 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 contribution to current air quality. 

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 judgement 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) 

The applicant identified two sources nearby for inclusion in the emission inventory for the 

cumulative analysis, based on discussions with the Antelope Valley Air Quality Management 

District (District) (PSD Application p.6-7 pdf.52). These are Lockheed Martin Aeronautics and 

Northrop Grumman, both within or adjacent to U.S. Air Force Plant 42 near the Palmdale airport. 

These sources had a large number of individual emitting sources (284), most of which had very 

low emissions. For practicality of modeling some of these were combined in a conservative way: 

emitters with less than 5% of total had their emissions added to the largest emitters. 

In support of limiting the inventory to these sources, the applicant quoted a statement from Mr. 

Chris Anderson, Air Quality Engineer, and Mr. Alan De Salvio, Supervisor of Air Quality 

Engineering, of the District: “Minor facilities located within the 6 mile radius are expected to be 

included in the background monitored at the AVAQMD [District] air monitoring station which is 

located in close proximity (approximately within 2 miles) of the PHPP site.” (NO2 Memo #2 p.11 

pdf.11) 

The applicant also documented discussions with the District, Mojave Desert Air Quality 
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Management District (AQMD), Kern County Air Pollution Control District, and South Coast 

AQMD showing that there are few substantial PM2.5 sources nearby; however, Granite Rock 

Construction and Robertson’s Ready Mix were included in the modeling, both about 15 km (9 

miles) from PHPP (Supplemental Information p.2-1 to 2-2 pdf.9 to 10, and Figure 2-1 p.2-3 

pdf.11). 

Also, recent EPA NO2 guidance clarification states that the nearby source inventory “should focus 

on the area within about 10 kilometers of the project location”, which suggests that the PHPP 

inventory is adequate for NO2 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, the applicant also performed a “Q/D” analysis, which provides another factor for 

consideration in determining whether sources with small emissions (Q) and/or at large distances 

(D) would be reasonable to exclude from the analysis. The applicant proposed that sources with a 

km distance greater than the NOX emissions in tons per year divided by 20 would be eligible for 

exclusion. (Updated Analyses Memo p.6 pdf.6, citing “Screening Method for PSD” developed by 

the North Carolina Air Quality Section of the North Carolina Department of Natural Resources, 

in file “NC 20D Letter to EPA.pdf”). The only sources to pass this initial screen were those 

within US Air Force Plant 42, already included in the cumulative modeling, and Bolthouse Farm 

emissions. In addition to being mostly downwind (east) of the project, the emissions of Bolthouse 

Farm are widely distributed throughout the area, and therefore are dispersed enough that they 

would have a negligible contribution to maximum concentrations (Updated Analyses Memo p.8 

pdf.8). The Q/D analysis provides additional evidence that the source inventory is adequate for 

the cumulative impact analysis. 

EPA believes that the combination of a conservative background monitored concentration 

expected to include the effect of most nearby sources, EPA guidance clarification focusing on 

sources within 10 km, and the Q/D analysis are sufficient justification for the inventory used in the 

cumulative analysis. 

8.4.3.2 PM2.5-specific issues 

The applicant originally relied on the PM10 NAAQS as a surrogate for the PM2.5 NAAQS, which 

was allowed under previous EPA policy. However, EPA repealed this policy (proposed February 

11, 2010; final May 18, 2011), so that PM2.5 itself must be modeled. EPA also issued guidance 

clarification on how to combine modeled results with monitored background concentrations 

(“Modeling Procedures for Demonstrating Compliance with PM2.5 NAAQS”, memorandum from 

Stephen D. Page, Director, EPA OAQPS, March 23, 2010). 

Accordingly, the applicant replaced the original analysis with a new cumulative PM2.5 analysis. 

The applicant still conservatively used PM10 emissions as input to the modeling, so actual PM2.5

impacts may be lower than those indicated in the model results. Maximum model results were 
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correctly added to the ninety-eighth percentile of the monitored background concentration, as 

called for in the EPA guidance clarification. (Updated Analyses Memo p.12ff pdf.12) 

The PHPP application has little discussion of secondarily formed PM2.5 (as distinguished from 

directly emitted primary PM2.5). However, the applicant does cite an earlier AECOM analysis 

showing that that near the source, primary PM2.5 emissions dominate the modeled impacts 

(Supplemental Information, p.2-10 pdf. 18). EPA notes that, due to the time needed for chemical 

formation, secondary PM2.5 impacts are likely to occur much farther downwind than the 

significant primary impacts, which occur within 400 m of the project (Updated Analyses Memo 

p.12 pdf.12), and so are likely to be small and not overlapping with the impacts estimated in the 

application. 

8.4.3.3 NO2-specific issues 

The applicant used the Ozone Limiting Method (OLM) option in AERMOD, in which ambient 

ozone concentrations limit the amount of emitted NO that is converted to NO2 (after an initial 

10% conversion). In addition to requiring monitored ozone, the method requires specification of 

an in-stack NO2/NOX ratio. EPA believes the OLM method is justified in this area because while 

it has substantial ozone, most of that is due to transport from outside the area, rather than to 

photochemistry operating on VOC and NOX emiossions from sources within the area. Therefore, 

the alternative mechanisms for conversion of NO to NO2 by the hydroxyl and peroxy radicals are 

likely to be less important than the ozone conversion mechanism, and so the conversion is ozonelimited. 

A. In-stack NO2/NOX ratio 

The applicant notes that since the Project would be located in an ozone nonattainment area, ozone 

concentrations are generally high, so that the initial in-stack NO2/NOX ratio is of less importance 

than would otherwise be the case, since plentiful ozone is available to convert NO to NO2 (NO2 

Memo #2 p.3 pdf.3). 

GE Power and Water, the vendor of the GE7FA turbines planned for PHPP, provided an in-stack 

NO2/NOX ratio of 0.10 to 0.15 based on its review of available NO2 emission data; the Selective 

Catalytic Reduction (SCR) planned for PHPP would make this ratio even lower (NO2 Memo #1 

p.8 pdf.8; NO2 Memo #2 p.3 pdf.3). Since little data is available for the ratio during startup and 

shutdown conditions, the applicant relied on a 0.4 ratio as recommended by the San Diego 

County Air Pollution Control District for a project with similar turbines, despite some evidence 

that the actual ratio could be lower for both startup and shutdown events. The short duration of 

these events implies that that actual ratio would be closer to the 0.10 used for normal operations 

(NO2 Memo #1 p.9 pdf.9). 
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B. NO2 monitor representativeness/conservativeness 

As mentioned above, the applicant chose the Lancaster Division Street monitor for background 

NO2 concentrations. This monitor is just 2.5 miles from the PHPP power block, and is near the 

Sierra Highway (110 m), the Antelope Valley Freeway (SR-14) (4 km), commute traffic on 

Division Street (50 m), and the Southern Pacific Railway (80 m). EPA agrees with PHPP that 

this location is quite conservative for providing NO2 background concentrations. 

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 Lancaster Division Street monitor is just 2.5 miles away from the PHPP power 

block, and EPA agrees that it is adequately representative. 

D. Missing O3 data procedure 

The applicant filled in missing ozone data using a procedure to ensure that NO to NO2 conversion 

is not underestimated. When 1 or 2 hours are missing, the higher of the two endpoints are used 

for the missing hours. When 3 or more hours are missing, the higher of the two end points and of 

the corresponding hours from the two neighboring days are used for the missing hours. (NO2 

Memo #2 p.8 pdf.8) Under this procedure, professional judgement is applied to ensure that the 

data from the neighboring days are not anomalously low. 

The applicant provided an example of the application of this procedure (Updated Analyses Memo 

p.3 to 4 pdf.3 to 4), as well as details of the full calculations (file “PHPP Ozone Filling 

Analysis.xlsx” from July 2011). 

EPA believes that the applicant followed a reasonable and conservative procedure for filling in 

missing ozone values. 

E. Combining modeled and monitored values 

Originally, the applicant combined 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’s43 “first tier” approach: it used the 98th 

percentile of all monitored values, though only for model receptors outside the USAF Plant 42 

boundary; the hour-by-hour approach still applied to other receptors. (The EPA March 2011 

memo’s “first-tier” approach uses the 98th percentile from among only the daily maxima, whereas 

 

43 “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 
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the applicant’s variant uses the 98th percentile from among all hourly values.) While the 

applicant’s approach is less conservative than EPA’s first-tier approach, we believe that it remains 

conservative given the very conservative background monitor that is being used (NO2 

Background Memo). The maximum values coincide with morning and evening commute traffic, 

due to the several roads near the monitor. 

A key concern expressed in EPA’s March 2011 memo about the hour-by-hour approach is that it 

implicitly assumes concentrations are spatially uniform, i.e., that the background monitor is 

representative of all locations

44

. Since this is not generally true, some degree of temporal 

conservativeness is warranted, as in the memo-recommended 98th-percentile of the available 

background concentrations by season and hour-of-day. However, for PHPP, the background 

monitor appears to be very conservative, so that the implicit spatial uniformity assumption of the 

hour-by-hour approach is actually a conservative assumption in this case. If the memorecommended procedure were to be used in this case, then a single unusually high morning 

commute hourly concentration would be assumed to apply to every day of the season; a single 

NO2 exceedance would then become 90 exceedances, thus possibly causing an erroneous 

prediction of a 1-hour NO2 violation, an overly conservative approach. 

In addition, the applicant’s modeling included some intermittent sources (PHPP's emergency 

generators) that may not need to be included, per EPA’s March 2011 memo45 on hourly NO2

modeling, further adding to the conservativeness of the analysis. 

EPA believes that the applicant’s overall approach to the 1-hour NO2 analysis for the PHPP, 

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 Results of the cumulative impacts analysis 

The results of the PSD cumulative impacts analysis for PHPP’s normal operations is shown in 

Table 8-6. The analysis demonstrates that emissions from PHPP during normal operations will 

not cause or contribute to exceedances of the NAAQS for 1-hour NO2, 24-hour PM10, 24-hour 

PM2.5, or annual PM2.5 or applicable PSD increments. As discussed above, PHPP’s maximum 

modeled concentrations are below the SILs for annual NO2, 1-hour CO, and 8-hour CO; 

therefore, a cumulative impacts analysis was not required to demonstrate compliance for these 

pollutants/averaging times. 

 

44 Ibid., p.21. 

45 Ibid., p.10. 
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Table 8-6: PHPP Compliance with PSD Increments and NAAQS, Normal Operations 

NAAQS 

pollutant & 

averaging 

time 

All Sources 

Modeled 

Impact 

PSD 

Increment 

Background 

Concentration

Cumulative 

impact w/ 

background NAAQS 

NO2, 1-hr; 

USAF 106.9 NA (hourly) 175.3 188 (100 ppb) 

NO2, 1-hr; 

other 

108.2 NA 77.1 185.3 188 (100 ppb) 

PM10, 24-hr 12.9 30 86 98.9 150 

PM2.5, 24-hr 12.58 NA 16.3 28.9 35 

PM2.5, annual 1.3 NA 7.6 8.9 15 

Notes:

- “USAF” values are for receptors within USAF Plant 42; “other” is for receptors elsewhere; USAF Plant 42 receptors 

are not ambient air with respect to its own emissions. 

- Background concentrations for USAF receptors were added hour-by-hour to modeled concentrations before computing 

98th percentile total impact, rather than a single background value being added to the modeled impact as for 

the other cases. 

Sources:

NO2 USAF: Supplemental Information p3-2. pdf.22 

NO2 other: Updated Analyses Memo Table 7, p.11 pdf.11, “Normal Operations - No PHPP Fire Water Pump” 

PM10: PSD Application Table 6-7, p.6-8 pdf.53 

PM2.5: Updated Analyses Memo Table 9, p.15 pdf.15

8.4.3.5 Startup and shutdown analyses 

Combustion turbine CO and NOX emissions during startup and shutdown (SU/SD) are estimated 

to be substantially higher than during normal operations, and thus the applicant also modeled for 

shutdown, the condition having the highest emissions. Modeled stack parameters such as exit 

temperature and exhaust velocity were consistent with a 20% operating load; the ambient 

temperature used represented worst-case meteorological conditions, emission into a cool morning 

stable layer. Since shutdown duration may not exceed half an hour, worst case hourly emissions 

consist of a half-hour of normal operations followed by a shutdown event. For CO, this is 1/2 of 

15.16 lb/hr, plus 337 lb, for a combined rate of 344.6 lb/hr per turbine (PSD Application p.6-9 

pdf.54). For NOX, this is 1/2 of 16.6 lb/hr, plus 57 lb, for a combined rate of 65.3 lb/hr per 

turbine (Updated Analyses Memo Table 7, p.11 pdf.11). Emergency generator testing was not 

included in the NOX modeling, since it would not be undergoing testing during source shutdown. 

This 1-hour NO2 analysis continues to use the conservative assumptions discussed above for the 

analysis of normal operations. The model results are shown in Table 8-7 for the preliminary or 

Project-only analysis, and in Table 8-8 for the cumulative impacts analysis. The results 

demonstrate that emissions from PHPP will comply with the 1-hour NO2 NAAQS and both the 1-

hour and 8-hour CO NAAQS under shutdown conditions (and therefore for startup conditions, 

for which emissions are lower). We note that the applicant was not required to, and did not, 

perform a cumulative impact analysis for CO, as its emissions are below the SILs; however, for 

informational purposes, Project impacts were added to background concentrations of CO for a 

rough comparison to the NAAQS. 
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Table 8-7: PHPP Significant Impacts, Startup/Shutdown 

NAAQS pollutant 

& averaging time 

Project-only Modeled 

Impact 

Significant Impact 

Level (SIL), μg/m3

Project significant 

impact? 

CO, 1-hr 674.6 2000 No 

CO, 8-hr 489.1 500 No 

NO2, 1-hr 136.4 7.5 (4 ppb) Yes 

Sources:

CO: PSD Application Table 6-9, p.6-9 pdf.54 

NO2 1-hr: Supplemental Information p3-3. pdf.23 

Table 8-8: PHPP Compliance with NAAQS, Startup/Shutdown 

NAAQS 

pollutant & 

averaging 

time 

Projectonly 

Modeled 

impact 

All 

Sources 

Modeled 

Impact 

Background 

Concentration

Cumulative 

impact w/ 

background NAAQS 

CO, 1-hr 674.6 NA 3,680 4,354.6 40,000 (35 ppm) 

CO, 8-hr 489.1 NA 1,840 2,329.1 10,000 (9 ppm) 

NO2, 1-hr; 

USAF 

(not 

modeled) 136.4 (hourly) 180.3 188 (100 ppb) 

NO2, 1-hr; 

other 

(not 

modeled) 109.7 77.1 186.9 188 (100 ppb) 

Notes:

- There are no PSD increments defined for CO or for 1-hour NO2. 

- PHPP emissions are not significant for CO, so no cumulative analysis is required; “cumulative impact” here is PHPPonly plus background. 

- “USAF” values are for receptors within USAF Plant 42; “other” is for receptors elsewhere; USAF Plant 42 receptors 

are not ambient air with respect to its own emissions. Project-only impacts were not modeled for 1-hour NO2 

startup/shutdown, rather only the full cumulative impact was modeled. 

- Background concentrations for USAF receptors were added hour-by-hour to modeled concentrations before computing 

98th percentile total impact, rather than a single background value being added to the modeled impact as for the 

other cases.”Project-only” and “all sources” are the same except for 1-hr NO2 “other” receptors. 

Sources:

CO: PSD Application Table 6-9, p.6-9 pdf.54; Project-only plus background 

NO2 USAF: Supplemental Information p3-3. pdf.23 

NO2 other: Updated Analyses Memo Table 7, p.11 pdf.11, “Startup/Shutdown - No PHPP Emergency generator”

8.5 Class I Area Analysis 

The Class I area analysis was performed using CALPUFF Version 5.8 for long range transport, 

which required additional detailed meteorological data as explained in the applicant’s Class I 

Modeling Protocol. Additionally, the applicant used CALPUFF to assess PSD Class I increment 

consumption, regional haze, and acid deposition. The Class I modeling protocol was provided to 

the Federal Land Managers (FLMs) for the two relevant Class I areas, the Cucamonga and the 

San Gabriel Wilderness Areas. The FLMs raised no objections to the protocol or the modeling 
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itself. 

8.5.1 Class I Increment Consumption Analysis 

The results of the PHPP Class I increment analysis are shown in Table 8-9; for the PSD pollutants 

for which there are applicable increments, PHPP impacts are less than the Class I Significant 

Impact Levels (SILs), and therefore the applicant has demonstrated that the Project will not cause 

or contribute to any Class I PSD increment violation. 

Table 8-9: PHPP Class I Increment Impacts

Class I Area 

Pollutant and 

averaging time 

Project Impact, 

μg/m3

Significant 

Impact Level, 

μg/m3

Class I PSD 

Increment, 

μg/m3

Cucamonga 

Wilderness Area 

NO2, annual 0.0010 0.1 2.5 

PM10, 24-hr 0.059 0.3 8 

PM10, annual 0.003 0.2 4 

San Gabriel 

Wilderness Area 

NO2, annual 0.0017 0.1 2.5 

PM10, 24-hr 0.122 0.3 8 

PM10, annual 0.004 0.2 4 

Source: PSD Application, Table 6-10, p.6-11 pdf.56 

8.5.2 Visibility and Deposition in Class I areas 

The PSD regulations at 40 C.F.R. section 52.21 require that PSD permit applicants address 

potential impairment to visibility (e.g., regional haze, plume blight) for Class I areas. The 

deposition of nitrogen is another potential concern due to potential effects on soils, vegetation, 

and other biological resources. 

For Cucamonga Wilderness Area (WA), which is located greater than 50 km from the Project, a 

Class I regional haze analysis was conducted. The modeling considered the two CTGs’ emissions 

of H2SO4, NOX, PM10, PM2.5, and SO2. The applicant used CALPUFF to predict visibility 

impacts at Class I areas. Visibility impacts are assessed using the extinction coefficient (bext), 

which represents the scattering of light by air pollutants, which appears as haze that reduces 

visibility. The results of the CALPUFF modeling for the three meteorology years (2001-2003) 

are shown in Table 8-10 and indicate that changes in light extinction (bext), averaged over a 24-

hour period, at Cucamonga WA is predicted to be below the 5% change threshold46. 

 

46 “Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) Phase I Report” (December 2000), U.S. 

Forest Service, National Park Service, U.S. Fish And Wildlife Service. http://www2.nature.nps.gov/air/Permits/flag/
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Table 8.10: Class I Area Regional Haze CALPUFF Modeling Results 

Class I Area

Maximum Predicted 

% Change in bext

Significance 

Threshold 

2001 2002 2003 (%)

Cucamonga WA 1.77 2.14 1.92 5 

Applicants are not required to perform a cumulative effects analysis of new source growth if the 

visibility impact of their proposed source is less than 5%. Based on the Class I regional haze 

results, emissions from the facility are not expected to have an adverse impact on visibility in the 

Cucamonga WA. 

For San Gabriel WA, which is within 50 km of the Project, the impact of the Project on visibility 

impairment, also known as plume blight, was assessed. The EPA VISCREEN screening model 

was used to estimate visibility impairment to the San Gabriel WA from the CTG emissions. 

Effects of plume blight are assessed as changes in plume perceptibility (ΔE) and plume contrast 

(Cp) for sky and terrain backgrounds. A Level 1 analysis, using default meteorological data and 

no site-specific conditions, was conducted. Because the Level 1 results of ΔE and Cp were above 

the screening thresholds, a Level 2 analysis was conducted. A detailed discussion of the 

VISCREEN plume blight impact analysis is presented in Section 6.2.4 of the applicant’s PSD 

permit application. 

The results of the VISCREEN modeling runs are presented in Tables 8-11 and 8-12. The 

VISCREEN results are presented for the two default worst-case theta angles – theta equal to 10 

degrees representing the sun being in front of an observer, and theta equal to 140 degrees 

representing the sun being behind the observer. A negative plume contrast means the plume has a 

darker contrast than the background sky. 

Table 8-11a: Class I VISCREEN Modeling Results of 

Changes in Plume Perceptibility (ΔE) 

Background Distance

Plume Perceptibility (ΔE) 

Theta 10 Theta 140 Criteria 

Sky 47.4 0.135 0.261 2.00 

Terrain 34.6 0.806 0.072 2.00 
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Table 8-11b: Class I VISCREEN Modeling Results of 

Changes in Plume Contrast (Cp) 

Background Distance

Plume Contrast (Cp) 

Theta 10 Theta 140 Criteria 

Sky 47.4 0.001 -0.009 0.05 

Terrain 34.6 0.005 0.001 0.05 

The results from the VISCREEN model show that changes in plume perceptibility and plume 

contrast for sky and terrain backgrounds are below the criteria thresholds. Therefore, the plume 

would not be perceptible against a sky or terrain background. 

For Cucamonga WA and San Gabriel WA, a deposition analysis was conducted for nitrogen 

compounds which considered Project emissions of NOX and conversion of NOX to nitrate and 

nitric acid. The results from the deposition analysis are presented in Table 8-12. 

Table 8-12: Class I Nitrogen Deposition CALPUFF Modeling Results 

Class I Area

Maximum Predicted Nitrogen 

Deposition – Annual average (g/ha/yr)

Deposition 

Analysis 

Threshold 

(g/ha/yr)

2001 2002 2003 

Cucamonga WA 0.496 0.521 0.458 5 

San Gabriel WA 0.718 0.396 0.607 5 

The Deposition Analysis Threshold was established by the Federal Land Managers, and represents 

a level below which deposition is deemed to have no adverse effect, and does not require further 

analysis.47 The maximum deposition rates modeled for PHPP are below the Class I Area Nitrogen 

Deposition Analysis Threshold of 0.005 kilograms per hectares per year, or below 5 grams per 

hectare per year (g/ha/yr), and therefore no further deposition analysis is necessary. 

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 C.F.R. § 52.21(o). The depth 

of the analysis generally depends on existing air quality, the quantity of emissions, and the 

 

47 “Guidance on Nitrogen and Sulfur Deposition Analysis Thresholds”, Attachment to Letter from Christine L. Shaver, 

National Park Service and Sandra V. Silva, U.S. Fish and Wildlife Service to S. William Becker, STAPPA/ALAPCO, 

January 3, 2002 (files DatNotifyLetter.pdf, nsDATGuidance.pdf) http://www.nature.nps.gov/air/Permits/flag/
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sensitivity of local soils, vegetation, and visibility in the source's impact area. 

9.1 Soils and Vegetation 

For the soils and vegetation analysis, the applicant considered as part of the impact area the 400 

meter significant impact area considered in the initial PSD application for the Project. In the 

applicant’s July 2010 supplement (Section 5.0), the applicant provided additional information on 

the vegetation and soils inventory in the project area, a discussion of the potential impacts to 

those soils and vegetation types with respect to the five Class II areas (within 50 km of the 

project) discussed in Section 9.2, Visibility Impairment, and a discussion of nitrogen deposition. 

Also, the applicant noted there are no federal habitat areas of concern within 20 miles of the 

PHPP. 

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 vegetation, crops, and animals. No harmful effects are expected 

from this project because the total estimated maximum ambient concentrations presented in Table 

9-1 are below the primary NAAQS (listed in Table 8-1 of Section 8) and secondary NAAQS for 

NO2 (100 μg/m3) and PM2.5 (35 μg/m3 for 24-hour periods; and 15.0 μg/m3over an annual 

period). There are no secondary NAAQS for CO. 

The initial application (dated March 2009) used EPA’s "Screening Procedure for the Impacts of 

Air Pollution Sources on Plants, Soils and Animals" (1980)48 to determine if maximum modeled 

ground-level concentrations of NO2 and CO could have an impact on plants, soils, and animals. 

The modeled impacts of NO2 and CO emissions from the facility, individually, and in addition to 

the background concentrations of NO2 and CO, are below the minimum impact level for sensitive 

plants. The following table summarizes information in this regard from the PSD application (Table 

6-17, Soils and Vegetation Analysis). 

Table 9. 1 

Project Maximum Concentrations and EPA Guidance Levels

Criteria Pollutant 

and Guidance 

Averaging Time 

EPA Screening 

Concentration 

(μg/m3) 

Modeled Maximum 

Concentrations

(μg/m3) 

Modeling 

Averaging 

time 

NO2 4-Hours 3,760 419.7 1 hour 

NO2 8-Hours 3,760 419.7 1 hour 

NO2 1-Month 564 419.7 1 hour 

NO2 Annual 94 29.2 Annual 

CO Weekly 1,800,000 1,806.4 8 hour 

 

48 Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals,” EPA 450/2-81-078, 

December 1980. 
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As part of the July 2010 supplement regarding additional impacts to vegetation, the applicant also 

reviewed a document developed by the U.S. Department of Agriculture entitled “A Screening 

Procedure to Evaluate Air Pollution Effects in Region 1 Wilderness Areas” (1991). As a 

complement to the EPA 1980 screening procedure document, the applicant determined that for 

the NOX “sensitive” species of alfalfa, which is found nearby the project, the modeled air 

concentrations (Table 9-1) demonstrate that the impacts are below the significance criteria. 

The applicant also considered soil acidification and eutrophication as part of the July 2010 

supplement regarding additional impacts on soil. Nitrogen deposition in soil can have beneficial 

effects to vegetation if they are lacking these elements; however, gaseous emissions impacts on 

soils at levels greater than vegetation requirements can cause acidic conditions to develop. Soil 

acidification and eutrophication can occur as a result of atmospheric deposition of nitrogen. 

The applicant determined that project-specific modeling for nitrogen deposition was not 

warranted because the estimated nitrogen deposition rates were negligible as a plant growth 

influence and because the effects of deposition on eutrophication were insignificant, as described 

below. 

When considering soil acidification, the applicant referred to the CALPUFF modeling conducted 

for the PHPP’s Class I analysis. The applicant also referred to the nitrogen deposition modeling 

analysis (using CALPUFF) performed for a similar project, the Victorville 2 (VV2) Hybrid Power 

Project.49 CALPUFF incorporates the atmospheric chemistry and chemical transformations to 

determine nitrogen deposition and provides results in units of kilograms per hectare per year, 

which can be converted to pounds per unit area. For the VV2 project, the modeled maximum 

annual deposition rate was considered to be very low. 

The PHPP is nearly identical to the VV2 hybrid solar-gas plant, with the exception of a larger 

natural gas-fired auxiliary boiler; the PHPP boiler is 110 MMBtu/hr, while the VV2 boiler is 40 

MMBtu/hr. Additionally, the predominant wind direction for PHPP is the northeast of the power 

block, which is similar to the predominant wind direction for VV2. (There have not been 

pertinent upgrades to the CALPUFF model since the VV2 2008 analysis.). Because of the 

similarities between the PHPP and VV2, and VV2’s fence line deposition of 1.2 ounces of 

nitrogen per acre, the applicant determined that the nitrogen deposition rates for PHPP also 

would be considered negligible as a plant growth influence, and therefore no additional nitrogen 

deposition analysis was performed. 

In sum, based on our consideration of the information and analysis provided by the applicant, we 

do not believe that emissions associated with the Project will result in adverse impacts on soils or 

vegetation. 

 

49 EPA Region 9 issued the initial PSD permit to the Victorville 2 Hybrid Power Project in 2010. EPA proposed the 

PSD permit in 2008, with Docket I.D. number EPA-R09-OAR-2008-0406. 

(http://www.regulations.gov/#!docketDetail;D=EPA-R09-OAR-2008-0406). The initial PSD permit was issued in 2010 

with Docket I.D. number EPA-R09-OAR-2008-0765 (http://www.regulations.gov/#!docketDetail;D=EPA-R09-OAR2008-0765 ) 
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9.2 Visibility Impairment 

Using procedures in EPA’s Workbook for Plume Visual Impact Screening and Analysis50, the 

applicant evaluated visibility impairment for one Class I area and five Class II areas. The five 

Class II areas included three state parks, one woodland, and one wilderness area. 

In the initial PSD application, the applicant presented visibility impairment (e.g., plume blight) for 

the Class I area of San Gabriel Wilderness Area (see Section 8.5.2 of the application), which is 

located within 50 km of the proposed PHPP. The applicant provided supplemental application 

information for visibility impairment in July 2010 for five Class II areas identified as potentially 

sensitive state or federal parks, forests, monuments, or recreation areas within 50 km of the 

project. These five areas with their approximate closest distances to PHPP were: 

• Antelope Valley Indian Museum State Park (23 km) 

• Saddleback Butte State Park (26 km) 

• Antelope Valley California Poppy State Reserve (26 km), 

• Arthur B. Ripley Desert Woodland (37 km), and 

• Sheep Mountain WA (43 km) 

The applicant performed a Level 1 and Level 2 VISCREEN analysis for all five areas. The results 

of this analysis were below the significance criteria for three of the five areas. A further refinement 

in VISCREEN of plume perceptibility for the two exceptions – Saddleback Butte State Park and 

Antelope Valley Indian Museum State Park – was performed for the worst-case daytime 

meteorological conditions; the result is that the plume would not be perceptible at either site 

during daylight hours, based on low plume perceptibility and contrast predicted by VISCREEN. 

Based on the VISCREEN results, w believe that the Project would not contribute to visibility 

impairment. 

9.3 Growth 

The growth component of the additional impact analysis considers an analysis of general 

commercial, residential, industrial and other growth associated with the PHPP. 40 C.F.R. § 

52.21(o). The PHPP is expected to employ 36 employees, with an ample work force in the 

Southern California area to accommodate the PHPP estimated peak of 767 construction workers; 

impacts to the local population and housing needs are therefore expected to be minimal. 

Therefore, we do not expect this project to result in any significant growth. 

The applicant provided growth-related information in its initial PSD application and in 

supplemental application materials submitted to EPA in July 2010 and July 2011. The July 2011 

supplement includes Attachment A, which is an updated version of the socioeconomics analysis 

PHPP prepared for its July 2008 California Energy Commission (CEC) Application for 

 

50 “Workbook for Plume Visual Impact Screening and Analysis (Revised)”, EPA, EPA–454/R–92–023, 1992. 
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Certification (AFC). The applicant’s original July 2008 CEC AFC socioeconomics analysis was 

based on 2000 Census data; Attachment A of the July 2011 supplement includes updated 

information based on the available 2010 Census data regarding population and population growth 

projections. 

The applicant’s initial PSD application growth analysis (Section 6.3.2) stated that “... no longterm growth is expected during project operations.” A Project labor force of 36 employees was 

estimated. The July 2010 supplement further discussed the Project’s potential growth-inducing 

activities. Additional details in this supplement included a summary of growth-inducing impacts 

associated with employment. The information submitted indicates that for the construction and 

operating phases of the Project, impacts to the population and housing needs are expected to be 

minimal, and are expected not to induce substantial population growth. 

With regards to the question of whether the Project’s power generation would induce growth, the 

applicant anticipates that the Project would likely displace the older once-through cooling 

facilities in the Southern California region that are expected to be retired in the future. Therefore, 

rather than induce growth, PHPP would supply energy to accommodate the existing demand and 

projected growth in the Southern California region. 

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 Endangered Species Act (ESA), 16 U.S.C. 1536, and its 

implementing regulations at 50 C.F.R. 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 two federally-listed species,the desert tortoise Gopherus 

agassizii) and the arroyo toad (Bufo californica), that might be affected by the proposed 

PSD permitting action for the Project. In March 2009, a Draft Biological Assessment 

(BA) was submitted by the applicant to EPA and the U.S. Fish and Wildlife Service 

(FWS). Based on discussions between the applicant and FWS, in August 2009, the 

applicant submitted to EPA and FWS an Addendum to the BA. The BA Addendum 

further detailed that the PHPP “... may affect but is not likely to adversely affect the 

desert tortoise and will have no effect on the arroyo toad.” In July 2011, the applicant 

submitted a second Addendum to the BA to EPA and FWS, outlining updates to the 

Project scope and a further analysis supporting the conclusion that the PHPP may affect, 

but is not likely to adversely affect, the federally-listed desert tortoise and will have no 

effect on the federally-listed arroyo toad. 
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In a letter dated August 5, 2011, EPA requested FWS’s written concurrence with EPA’s 

determination under ESA section 7 that the proposed PSD permit for the PHPP is not 

likely to adversely affect the desert tortoise or arroyo toad. 

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 making this 

determination, EPA will consider actions taken, or to be taken, by the applicant to ensure 

ESA compliance. 

11. Environmental Justice 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 PHPP 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. 

The applicant will apply for these permits after the facility is constructed, as these permits 

are not required prior to construction. The District has jurisdiction to issue the Acid Rain 

Permit and the Operating Permit for the facility. 

13. Comment Period, Hearing, Public Information Meeting, 

Procedures for Final Decision, and EPA Contact 
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The comment period for EPA’s proposed PSD permit for the Project begins on August 

11, 2011. 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 September 14, 2011, or postmarked by September 14, 2011. 

Comments must be sent or delivered in writing to Lisa Beckham at one of the following 

addresses: 

E-mail: R9airpermits@epa.gov

U.S. Mail: Lisa Beckham (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 September 14, 2011, pursuant to 40 C.F.R. § 

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. 

Prior to the Public Hearing, EPA will also hold a Public Information Meeting for the 

purpose of providing interested parties with additional information and an opportunity for 

informal discussion of the proposed Project. 

The date, time and location of the Public Information Meeting and the Public Hearing are 

as follows: 

Date: September 14, 2011 

Time: 4:00 p.m. - 6:00 p.m. (Public Information Meeting) 

 7:00 p.m. – 10:00 p.m. (Public Hearing) 

Location: Larry Chimbole Cultural Center 

 Manzanita Ballroom, 2nd Floor 

38350 Sierra Highway 

Palmdale, California 93550-4611 
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English-Spanish translation services will be provided at both the Public Information 

Meeting and the Public Hearing. 

If you require a reasonable accommodation, by August 31, 2011 please contact Terisa 

Williams, EPA Region 9 Reasonable Accommodations Coordinator, at (415) 972-3829, or 

Williams.Terisa@epa.gov. 

All information submitted by the applicant is available as part of the administrative record. 

 The proposed air permit, fact sheet/ambient air quality impact report, 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 Lisa Beckham at (415) 972-3811 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/ . 

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, from: 

E-mail: R9airpermits@epa.gov

U.S. Mail: Lisa Beckham (AIR-3) 

 U.S. EPA Region 9 

 75 Hawthorne Street 

 San Francisco, CA 94105-3901 

 Phone: (415) 972-3811 

EPA’s proposed PSD permit for the Project and the accompanying fact sheet/ambient air 

quality impact report are also available for review at the following locations: Antelope 

Valley Air Quality Management District, 43301 Division Street, Suite 206, Lancaster, CA 

93535, (661) 723-8070; Palmdale City Library, 700 East Palmdale Boulevard, Palmdale, 

CA 93550-4742, (661) 267-5600; Lancaster Regional Library, 601 W. Lancaster 

Boulevard, Lancaster, CA 93534-3398, (661) 948-5029; Lake Los Angeles Library, 

16921 East Avenue O, Palmdale, CA 93591-3045, (661) 264-0593; and Quartz Hill 

Library, 42018 N. 50th Street West, Quartz Hill, CA 93536-3590, (661) 943-2454. 

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 
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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 and oral comments submitted during the public comment 

period 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 

EPA is proposing to issue a PSD permit for the PHPP. 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/AAQIR available to the public for 

review, and make a final decision after considering any public comments on our proposal.