Ambient Air Quality Impact Report 

Colusa Generating Station 

Clean Air Act 

Prevention of Significant Deterioration Permit 

Permit No. SAC 06-01 

United States Environmental Protection Agency 

Region 9 

May 2008 
Air Quality Impact Report 

Colusa Generating Station 

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May 2008

TABLE OF CONTENTS 

ABBREVIATIONS AND ACRONYMS ............................................................................. 4

1 INTRODUCTION ................................................................................................... 5

2 APPLICANT .......................................................................................................... 5

3 PROJECT LOCATION .......................................................................................... 5

4 PROJECT DESCRIPTION .................................................................................... 6

5 EMISSIONS FROM THE PROJECT ..................................................................... 8

5.1 Turbine Emissions.............................................................................................................................................8

5.2 Combustion Turbine Commissioning Emissions............................................................................................10

5.3 Auxiliary Boiler Emissions.............................................................................................................................11

5.4 Emergency Generator Engine and Firewater Pump Engine Emissions ..........................................................11

5.5 Combined Annual Emissions..........................................................................................................................12

6 DETERMINING PSD APPLICABILITY ............................................................... 13

7 BEST AVAILABLE CONTROL TECHNOLOGY................................................. 14

7.1 BACT for the Combustion Turbines and Duct Burners..................................................................................15

7.2 BACT for the Auxiliary Boiler and Diesel Engines .......................................................................................20

8 CLASS I AIR QUALITY IMPACTS...................................................................... 25

8.1 Model Selection and Setup .............................................................................................................................25

8.2 CALPUFF Modeling Analysis & Results.......................................................................................................27

9 CLASS II AIR QUALITY IMPACTS..................................................................... 30

9.1 Existing Air Quality........................................................................................................................................30

9.2 Model Selection and Inputs.............................................................................................................................31

9.3 Load Screening Analysis ................................................................................................................................34

9.4 Modeling Results............................................................................................................................................36

10 ADDITIONAL IMPACT ANALYSIS..................................................................... 40

10.1 Growth Analysis .............................................................................................................................................40

10.2 Soil & Vegetation Analysis.............................................................................................................................40

10.3 Visibility Impairment Analysis.......................................................................................................................41
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11 PROPOSED PERMIT REQUIREMENTS ............................................................ 42

11.1 Emission & Operational Limits ......................................................................................................................42

11.2 Testing & Monitoring Requirements..............................................................................................................43

11.3 Recordkeeping & Reporting Requirements....................................................................................................44

12 ENDANGERED SPECIES ACT........................................................................... 45

13 OTHER REQUIREMENTS .................................................................................. 46

14 CONCLUSION AND ACTION ............................................................................. 46

15 REFERENCES .................................................................................................... 46
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ABBREVIATIONS AND ACRONYMS 

AAQIR Ambient Air Quality Impact Analysis 

Applicant Pacific Gas and Electric Company 

AQRV Air Quality Related Values 

Army Corps Army Corps of Engineers of the U. S. Department of the Army 

BACT Best Available Control Technology 

CAA Clean Air Act 

CEC California Energy Commission 

CEM Continuous Emissions Monitoring 

CFR Code of Federal Regulations 

CGS Colusa Generating Station 

CO Carbon monoxide 

CT Combustion turbine 

DB Duct burner 

DLN Dry low-NOx combustors 

EPA United States Environmental Protection Agency 

ESA Endangered Species Act 

HAPs Hazardous air pollutants 

HRSG Heat recovery steam generator 

kV kilovolt 

lb/hr pounds per hour 

lb/day pounds per day 

μg/m3

 micrograms per cubic meter 

m meter 

mmbtu million British thermal units 

MW megawatt 

NAAQS National Ambient Air Quality Standards 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NH3 Ammonia 

NO2 Nitrogen dioxide 

NOx Nitrogen oxides 

NSPS New Source Performance Standards 

NSR New Source Review 

PG&E Pacific Gas and Electric Company 

PM Total particulate matter 

PM2.5 Particulate matter with an aerodynamic diameter less than 2.5 micrometers 

PM10 Particulate matter with an aerodynamic diameter less than 10 micrometers 

ppm parts per million 

PSD Prevention of Significant Deterioration 

RBLC RACT/BACT/LAER Clearinghouse 

scf standard cubic feet 

SCR Selective Catalytic Reduction 

Service United States Department of Interior’s Fish and Wildlife Service 

tpy tons per year 

VOCs Volatile organic compounds 
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1 INTRODUCTION 

This Air Quality Impact Report serves as the Statement of Basis, as required by 40 CFR 

124.7 and 40 CFR 52.21(q), which provides the legal and factual rationale for the 

proposed Prevention of Significant Deterioration of air quality (PSD) permit for the 

Colusa Generating Station (CGS). 

PSD is a Clean Air Act permitting program for new and modified “major” sources of air 

pollution. The objective of PSD is to prevent significant adverse environmental impact 

from air emissions by a proposed new or modified “major” source. To meet this 

objective, PSD requires new or modified “major” sources of air pollution sources to meet 

certain criteria before being constructed. 

New or modified “major” sources of air pollution must install the best available control 

technology (BACT) in order to minimize emissions. These sources must also 

demonstrate that new air pollution from the new or modified source will not cause or 

contribute to a violation of any National Ambient Air Quality Standard (NAAQS) or PSD 

Increment. In addition, PSD requires that new and modified “major” sources perform an 

additional impacts analysis which includes evaluating the effect that the proposed 

emissions might have on air quality related values such as visibility, soils, and vegetation. 

2 APPLICANT 

Pacific Gas & Electric Company 

915 Highland Point Drive, Suite 130 

Roseville, CA 95678 

3 PROJECT LOCATION 

Pacific Gas & Electric Company (PG&E) proposes to construct and operate the CGS, a 

combined-cycle electrical generating facility, in Colusa County, California. The facility 

will be located on 31-acres within a 100-acre parcel of undeveloped agricultural land that 

is within the Holthouse Ranch property 14 miles north of the farming community of 

Williams, 4 miles west of highway I-5 in Colusa County, and 72 miles north of 

Sacramento. The facility will be located in the eastern half of Section 35, Township 18 

North, Range 4 West, Mount Diablo Base and Meridian. Figure 3-1 shows the location 

for proposed project. 

The applicant, PG&E, must obtain a PSD permit for the CGS facility for all attainment or 

unclassified criteria pollutants that will be emitted from the proposed facility in major 

and significant amounts. Coulsa County is in attainment with the federal NAAQS for all 
Air Quality Impact Report 

criteria pollutants, which include carbon monoxide (CO), nitrogen dioxide (NO2), sulfur 

dioxide (SO2), ozone, regulated by its precursors, volatile organic compounds (VOC) and 

oxides of nitrogen (NOx), particulate matter (PM), particulate matter with aerodynamic 

diameter less than 10 micrometers (PM10), fine particulate matter less than 2.5 microns 

(PM2.5) and lead. The U.S. Environmental Protection Agency (EPA) is the PSD 

permitting authority for Colusa County since EPA has not delegated PSD permitting 

authority to the Colusa County Air Pollution Control District, which is the local air 

permitting authority. 

Figure 3-1. Project site 

4 PROJECT DESCRIPTION 

PG&E proposes to install two General Electric (GE) Frame 7FA combustion turbines 

(CTs) at CGS. Each CT will exhaust through a heat recovery steam generator (HRSG) 

that can be fired by duct burners (DBs). Steam generated in the HRSGs will be used 

onsite in condensing steam turbines. The CTs and DBs will be equipped with dry, low 

NOx (DLN) combustors and post-combustion controls which include selective catalytic 

reduction (SCR) and oxidation catalysts to reduce emissions of air pollutants. CGS will 

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also consist of an auxiliary boiler and associated support equipment, as well as 

continuous emissions monitoring systems (CEMS) to monitor the stack emissions of 

NOx, CO, and oxygen (O2). 

The CTs at CGS will be equipped with evaporative inlet air coolers/filters to enhance 

turbine performance in hot weather. CGS will use dry cooling tower technology, which 

would reduce water use at the facility by eliminating the use of water for steam 

condensation. Steam from the HRSGs will be directed to a multi-stage steam turbine, 

then exhausted and condensed in an air-cooled condenser (ACC). Condensate from the 

steam cycle is returned to the steam cycle. 

The CGS design will consist of one power block having a nominal capacity of 660 

megawatts (MW). The power block will consist of the two CTs, two HRSGs with DBs 

and one steam turbine (a two by 1 configuration). Each CT will generate an average of 

172 MW, and an average of 320 MW will be produced by the steam turbine. Natural gas 

will be used as the sole fuel for the CTs and DBs. Each of the CTs and the steam turbine 

will be connected to electric generators, which will generate electrical energy at 

18 kilovolts (kV). The output of each will then pass through a step-up transformer where 

it will be increased to 230 kV for transmission. The step-up transformers will be 

interconnected with a new switchyard through a series of circuit breakers which control 

the delivery of CGS’s electrical output to various PG&E transmission circuits. The 

electricity generated will be connected to the grid. 

Water for the project will be provided by the Glenn-Colusa Irrigation District via the 

Tehama-Colusa Canal, which is located to the west of the project site. Water will be 

delivered through a new 4-inch, 2,700-foot-long pipeline that will be connected to the 

Canal. E&L Westcoast plans to install a wastewater recovery system to recover all 

process wastewater for reuse. 

As shown in Figure 4-1, CGS will be located near the Delevan Compressor Station 

(DCS), an existing natural gas compressor station that is also owned and operated by 

PG&E and located west of Glenn-Colusa Bridge and Dirks Road. The facility will be 

fueled by natural gas delivered from DCS to the site via a new 8 inch, 1,500-foot natural 

gas pipeline owned and operated by PG&E. Since CGS and DCS (1) will both be owned 

by PG&E (under common control), (2) have the same 2-digit Standard Industrial 

Classification (4911 for CGS and 4922 for DCS; Major Group 49, Electric, Gas, and 

Sanitary Services), and (3) will be located on contiguous or adjacent properties and 

physically connected by a pipeline, both facilities will be considered a single source for 

Title V purposes. Designation of these two facilities as a single source does not affect 

the current PSD evaluation. If the source is subsequently modified, however, the 

source’s “baseline actual emissions” under 40 CFR 52.21(b)(48) will comprise emissions 

from both facilities (CGS and DCS). 
Air Quality Impact Report 

Figure 4-1. Project Site layout 

(Source: Image from Figure 1-4 of December 2006 PSD Application) 

5 EMISSIONS FROM THE PROJECT 

5.1 Turbine Emissions 

The applicant estimated operational emissions from the two turbines based on emission 

rates that were provided by the turbine vendor and the engineer1

 for three load conditions 

(50, 75, and 100 percent) and three ambient temperatures (18oF, 59oF, and 114oF). The 

 

1

 Bechtel Corporation is the engineer. 

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emissions expected during normal operation are shown in Table 5-1 and the emissions 

expected during startup and shutdown periods are summarized in Table 5-2. 

The applicant calculated the quarterly emissions by adding the emissions expected during 

startups to the emissions expected during normal operation, assuming 100 percent load, 

59oF for the specified number of hours per quarter and duct burner operation at 59°F for 

the specified number of hours. The estimated quarterly and annual emissions for the two 

turbines are presented in Table 5-3.

 

Table 5-1. Estimated Criteria Pollutant Emission Rates During Normal Operation 

(pounds per hour per turbine)2

Load Pollutant Ambient Temperature 

18oF 59oF 114oF 

VOCs 3.4 3.1 3.0 

Ammonia Slip 14.2 13.1 12.5 

CO 14.0 13.0 12.3 

NOx 15.3 14.2 13.5 

SO2 6.0 5.5 5.5 

100% 

PM10 12.9 12.8 12.8 

VOCs 2.7 2.5 2.5 

Ammonia Slip 11.4 10.6 10.2 

CO 11.3 10.5 10.0 

NOx 12.3 11.5 11.0 

SO2 5.0 4.5 4.5 

75% 

PM10 12.7 12.7 12.6 

VOCs 2.2 2.1 2.1 

Ammonia Slip 9.0 8.4 7.9 

CO 8.9 8.3 7.8 

NOx 9.7 9.1 8.6 

SO2 4.0 3.5 3.5 

50% 

PM10 12.6 12.5 12.5 

VOCs 7.2 6.8 6.6 

Ammonia Slip 19.2 18.2 17.6 

CO 18.9 17.9 17.4 

NOX 20.7 19.6 19.0 

SO2 8.0 7.5 7.5 

100% 

with Duct 

Burners 

PM10 20.0 19.9 20.1 

(Source: Based on data from Table 5-1 of the December 2006 PSD application) 

 

2

 SO2 emission rates are based on a maximum (hourly) sulfur concentration of 1 grain per 100 

scf. 
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Table 5-2. Estimated Emission Rates During Startup and Shutdown (for each turbine) 

Pollutant Cold Startup 

(270 Minutes) 

Warm Startup 

(180 Minutes) 

Hot Startup 

(90 Minutes) 

Shutdown 

(30 Minutes) 

Max 

lb/hour 

Total 

lb/270 min 

Max 

lb/hour 

Total 

lb/180 min

Max 

lb/hour 

Total 

lb/90 min 

Max 

lb/hour 

Total 

lb/30 min 

NOX 333.3 779.10 152.00 456.20 249.90 259.90 115.00 115.00 

CO 373.60 1355.60 370.30 790.50 429.60 679.60 483.50 483.50 

VOCs 27.7 106.70 27.7 47.40 27.7 38.00 23.9 23.90 

SO2 2.00 5.05 2.00 2.88 2.00 1.66 1.00 1.00 

PM10 12.00 48.80 12.00 30.80 12.00 12.80 6.00 6.00 

(Source: December 2006 PSD application, Table 5-2) 

Table 5-3. Estimated Criteria Pollutant Annual Emissions for the Turbines3,

4

Pollutant 1st Quarter 

Emissions (tons) 

2nd Quarter 

Emissions (tons) 

3rd Quarter 

Emissions (tons) 

4th Quarter 

Emissions (tons) 

Annual 

Emissions (tons) 

NOX 45.1 43.1 50.9 43.8 182.9 

CO 53.4 51.6 106.3 53.1 264.4 

VOCs 12.3 11.6 11.8 11.7 47.4 

PM10 35.1 35.2 35.4 35.5 141.2 

SO2 4.5 4.2 4.2 4.2 17.1 

(Source: December 2006 PSD application, Table 5-3) 

5.2 Combustion Turbine Commissioning Emissions 

The applicant proposed a commissioning period of approximately 6 months during which 

all installed equipment will be run and tested. The period will be divided into four 

phases: 

1. Gas Turbine 1 (GT-1) Commissioning 

2. Gas Turbine 2 (GT-2) Commissioning 

3. Commissioning of both HRSGs and the steam turbine 

4. Performance and Reliability Testing of the entire plant together 

The applicant will make every effort to minimize CO, VOC, and NOx emissions during 

the commissioning period but expects that not all of the equipment to abate these 

emissions will be fully operational at the start of the commissioning period. The 

applicant requested a maximum of 500 hours of partially abated emissions for each gas 

turbine train. 

 

3

 These estimates include emissions from the two turbines. 

4

 Annual SO2 emission rates were scaled up based on an annual average sulfur concentration of 

0.3 grains/100 scf. 
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Colusa Generating Station May 2008

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The applicant estimated the worst case commissioning emissions by assuming that the 

control efficiency of the applicable abatement systems is essentially zero during 

significant portions of the commissioning phase. The expected emissions during the 

commissioning period are shown in Table 5-4. 

Table 5-4. Estimated Emissions from Gas Turbine Commissioning 

Operational Mode VOC CO NOx SOx PM10

Worst-Case Commissioning Emissions 

(lb/hour/combustion turbine)5

7.2 <950 <500 8.0 20.1 

Total Commissioning Period Emissions 

(tons/combustion turbine)6

6.75 152 48.5 3.0 7 

(Source: December 2006 PSD application, Table 5-5) 

5.3 Auxiliary Boiler Emissions 

The facility will operate a 44 mmbtu per hour (MMBtu/hr) auxiliary boiler. The 

emissions expected for the auxiliary boiler are shown in Table 5-5. Emissions are based 

on 3,744 hours of operation, the proposed BACT concentrations for NOx, CO and VOC 

and AP-42 for the PM10 emission factor. 

Table 5-5. Auxiliary Boiler Emissions 

Pollutant Emission Factor Emissions 

(lb/mmbtu) lb/hour ton/year 

NOX controlled to 9 ppmvd @ 3 % O2 0.0108 0.48 0.89 

CO controlled to 50 ppmvd @ 3 % O2 0.037 1.63 3.05 

PM10 0.0075 0.33 0.62 

SO2 0.0006 0.03 0.05 

VOC controlled to 10 ppmvd @ 3 % O2 0.0042 0.18 0.34 

(Source: December 2006 PSD application, Table 5-6) 

5.4 Emergency Generator Engine and Firewater Pump Engine Emissions 

The facility will operate a 1,340 brake hp diesel engine to power an electrical generator 

and a 300 brake hp diesel engine to power a firewater pump. The applicant estimated 

emissions based of manufacturer’s emissions data, 15 ppm sulfur diesel fuel, and annual 

emissions based on a maximum of 50 non-emergency hours per year of operation for 

each engine. Emissions estimates for these two diesel engines are shown in Table 5-6. 

 

5 Worst-case hourly emissions for VOCs, SOx, and PM10 from Table 5-1 adjusted to reflect one 

turbine. CO and NOx emission rates stated equal worst-case hourly emissions that will not be 

exceeded during commissioning. 

6

 Worst-case commissioning period emissions estimated by design engineer. 
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Table 5-6. Emissions for Generator and Firewater Pump Engine 

Pollutant 

Generator 

1340 brake horsepower 

(estimated) 

Firewater Pump 

300 brake horsepower 

(estimated) 

Hourly Emissions (pounds per hour) 

NOX 13.88 1.98* 

CO 0.32 1.72 

VOCs 0.15 0.000* 

PM10 0.09 0.10 

SO2 0.01 0.0030 

Annual Emissions (tons per year) 

NOX 0.347 0.050* 

CO 0.008 0.043 

VOCs 0.004 0.000* 

PM10 0.002 0.002 

SO2 0.000 0.0001 

* NOx and VOCs are combined and reported as NOx. (Source: December 2006 PSD application, Table 5-7) 

5.5 Combined Annual Emissions 

The total combined annual emissions that are expected to be emitted from CGS are 

shown in Table 5-7. The emission estimates include emissions from the turbines, duct 

burners, auxiliary boiler, emergency generator engine, and emergency firewater pump 

engine. 

Table 5-7. Quarterly and Annual Estimated Emissions from the Proposed Project 

Pollutant 

1st Quarter 

Emissions 

(tons) 

2nd Quarter 

Emissions 

(tons) 

3rd Quarter 

Emissions 

(tons) 

4th Quarter 

Emissions 

(tons) 

Annual 

Emissions 

(tons) 

NOX 45.77 43.77 51.57 44.47 185.58 

CO 55.35 53.55 108.25 55.05 272.20 

VOCs 12.51 11.81 12.01 11.91 48.24 

PM10 35.36 35.46 35.66 35.76 142.24 

SO2 4.47 4.19 4.23 4.23 17.12 

(Source: December 2006 PSD application, Table 5-8) 
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6 DETERMINING PSD APPLICABILITY 

PSD review, which includes the requirements of 40 CFR 52.21(j) through (r), applies to 

the construction of any new major stationary source or any project at an existing major 

stationary source in an area designated as attainment or unclassifiable under sections 

107(d)(1)(A)(ii) or (iii) of the Clean Air Act (CAA or “the Act”). The PSD regulations 

(40 CFR 52.21) define a “major source” as any source type belonging to a list of 28 

source categories which emits or has the potential to emit 100 tons per year (tpy) or more 

of any attainment pollutant regulated under the Act, or any other source type which emits 

or has the potential to emit such pollutants in amounts equal to or greater than 250 tpy. 

Since the proposed CGS facility will be a fossil fuel-fired electric plant (with heat inputs 

of more than 250 million British thermal units per hour) and this is one of the 28 source 

categories specified in the PSD regulations, the 100 tpy threshold applies. As shown in 

the Table 5-7, the proposed CGS facility is major for NOx, CO and PM/PM10 since the 

emissions for these pollutants exceed 100 tpy. 

For new major sources, PSD review also applies to any other pollutants that are emitted 

in quantities equal to or equal to the PSD significance thresholds. As shown Table 6-1, 

in addition to NOx, CO, PM/PM10, PSD review also applies to VOC since emissions for 

this pollutant exceed the significance level of 40 tpy. 

Consistent with existing EPA policy, PSD review of PM10 emissions will serve as a 

surrogate for review of PM2.5 emissions while EPA continues to work through the 

significant technical difficulties associated with integrating the new PM2.5 standard into 

the PSD program.7 

Table 6-1. Pollutants Undergoing PSD Review 

Pollutant PTE 

(tpy) 

Significant Emission Level 

(tpy) PSD Review Applies? 

NOx 185.58 40 Yes 

CO 272.20 100 Yes 

VOC 48.24 40 Yes 

SO2 11.32 40 No 

PM/PM10 142.24 25/15 Yes 

 

7

 See memorandum from John S. Seitz, Director Office of Air Quality Planning and Standards, 

to Regional Air Directors, “Interim Implementation of New Source Review for PM2.5” (October 

23, 1997). (See http://www.epa.gov/Region7/programs/artd/air/nsr/nsrmemos/pm25.pdf) 
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7 BEST AVAILABLE CONTROL TECHNOLOGY 

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. BACT is defined as “an emission limitation (including a visible 

emission standard) based on the maximum degree of reduction of each pollutant subject 

to regulation under the Act ... which the Administrator, on a case-by-case basis, taking 

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

achievable for such source.” BACT must be at least as stringent as any applicable New 

Source Performance Standards (NSPS) under 40 CFR Part 60 or National Emission 

Standard for Hazardous Air Pollutants (NESHAP) under 40 CFR Part 61. EPA outlines 

the process it will use to do this case-by-case analysis (referred to as “top-down” BACT 

analysis) in a June 13, 1989 memorandum. The top-down BACT analysis is a well 

established procedure that the Environmental Appeals Board (EAB) has consistently 

followed in adjudicating PSD permit appeals.8 The analysis consists of the following 

five steps. 

Step 1 - Identify all potentially available control technologies for each pollutant: The list 

of potentially available control technologies for BACT is based on defining the proposed 

source broadly. Technologies that have been required as Lowest Achievable Emission 

Rate (“LAER”) options, as well as technologies or processes used outside the United 

States, must be included as available. 

Step 2 - Eliminate technically infeasible options: Because the source category for 

identifying potentially available control technologies in Step 1 is broad, certain 

technologies may be determined infeasible under Step 2 when the particular physical, 

engineering and chemical processes of the proposed source are considered in more detail. 

The analysis in Step 2 may review whether a technology has been “demonstrated”, which 

is generally established if the technology has been installed and operated successfully 

elsewhere. If the technology has not been demonstrated, it may still be technically 

feasible if the technology is both “available” and “applicable.” 

Step 3 - Rank remaining control technologies by control effectiveness, with the most 

effective listed at the top. 

Step 4 - Evaluate most effective controls by including in the analysis: (a) economic 

impacts of each option based on total cost effectiveness and, where appropriate, 

incremental cost effectiveness; (b) energy impacts of each option; and (c) other 

environmental impacts of each option. 

Step 5 - Select BACT by choosing the most effective control technology that is not 

8

 See, e.g., In re Knauf, 8 E.A.D. 121, 129-31 (EAB 1999) and In re Maui Electric, 8 E.A.D. 1, 

5-6 (EAB 1998). 
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Colusa Generating Station May 2008

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eliminated under Step 4. 

The applicant conducted a BACT analysis for NOx, CO, PM10 and VOC and proposed 

BACT emission limitations based on each analysis. EPA independently evaluated the 

information the applicant submitted. The analyses and our evaluation for each pollutant 

are presented below. 

7.1 BACT for the Combustion Turbines and Duct Burners 

7.1.1 BACT for NOx – Combustion Turbines and Duct Burners 

The applicant evaluated DLN with XONON, SCONOx and SCR control technologies for 

use at CGS. The XONON combustion system combusts the fuel without a flame, thus 

eliminating the peak flame temperatures that lead to NOx. The XONON combustion 

system uses a catalytic module that is integral to the gas turbine combustor. 

SCONOx is a NOX reduction system produced by Goal Line Environmental 

Technologies (now distributed by EmeraChem) for gas turbine applications. This system 

uses a coated catalyst to oxidize both NOx and CO, thereby reducing plant emissions of 

these pollutants. The SCONOx technology employs a reactive catalyst that must be 

regenerated on a regular basis. The system does not use ammonia as a reagent; rather, it 

uses natural gas as the basis for a proprietary catalyst regeneration process. 

The SCR system uses ammonia injection to reduce NOX emissions. SCR systems have 

been widely used in combined cycle gas turbine applications, and is, generally, widely 

available compared to SCONOx which is available from a single vendor. The SCR 

process involves the injection of ammonia into the flue gas stream via an ammonia 

injection grid upstream of a catalyst. The ammonia reacts with the NOx gases in the 

presence of the catalyst. The catalyst is not regenerated and requires periodic 

replacement. SCR vendors typically offer a 3-year guarantee on catalyst life. 

According to several sources, including the RACT/BACT/LAER Clearinghouse (RBLC), 

the California Air Resources Board BACT Clearinghouse database, and other permits, 

similar facilities achieve an emission level of 2.0 ppm and higher using DLN combustors 

and SCR control technology. Two facilities were given the option of installing SCR or, 

either SCONOX or XONON. Table 7-1 shows some recent determinations for NOx 

emission limitations at similar facilities. For the CTs and DBs, the applicant proposed 

DLN combustors with SCR control technology that will achieve a NOx exhaust 

concentration of 2.0 ppm or less corrected to 15 percent oxygen and averaged over a 1-

hour averaging period, excluding startups and shutdowns, as BACT. EPA concurs that 

this proposed emission level represents BACT for the CTs and DBs at CGS. 
Colusa Generating Station 

Table 7-1. Recent NOx Determinations for Combustion Turbines/Duct Burners* 

Facility Location NOx Limits Avg Period Control Permi

Blythe Energy LLC (Blythe II) California 2.0 ppm 3-hr SCR/DLN Apr 2

Elk Hills Power California 2.5 ppm 1-hr SCR/DLN or SCONOX Jan 2

La Paloma - PG&E California 2.5 ppm 1-hr SCR Dec 2

Los Esteros - Calpine California 2.0 ppm 1-hr SCR & water injection Mar 2

Los Medanos - Calpine California 2.5 ppm 1-hr SCR 11/9/

Palomar Escondido - Sempra California 2.0 ppm 

3-hr when duct burners 

firing or transient periods; 

1-hr all other times 

SCR/DLN Dec 2

Pastoria Energy LLC California 2.5 ppm 1-hr SCR/DLN or XONON Dec 2

San Joaquin Valley Energy Center California 2.0 ppm 1-hr SCR/DLN Aug 2

Mountainview Power Company California 2.0 ppm 1-hr SCR 20

Sacramento Municipal Utility District California 2.0 ppm 1-hr SCR -

Three Mountain Power California 2.5 ppm 1-hr SCR 10/10/

Western Midway Sunset California 2.0 ppm 1-hr SCR 12/12/

Magnolia Power Project California 2.0 ppm 3-hr SCR 5/27/

6.0 ppm (applies btw May 1 

through Sept 30 each year) McDonough Combined-Cycle Generating Units Georgia 15 ppm 30-day rolling avg SCR/Low NOx burners 1/7/2

(Effe

dat

Rocky Mountain Energy Center Colorado 3.0 ppm Hourly SCR/Low NOx burners 5/2/2

PSO Southwestern Power Plant Oklahoma 9.0 ppm -- DLN 2/9/2

Sierra Pacific Power Company Nevada 2.0 ppm 3-hr SCR 8/16/

Wanapa Energy Center Oregon 2.0 ppm 3-hr SCR/DLN 8/8/2

Crescent City Power, LLC Louisiana 3.0 ppm Annual SCR/Low NOx burners 6/6/2

Berrien Energy, LLC Michigan 2.5 ppm 24-hr SCR/DLN 4/13/

Turner Energy Center, LLC Oregon 2.0 ppm 1-hr SCR 1/6/2

Florida Power and Light – Turkey Point Florida 2.0 ppm 3-run stack test; 24-hr for CEMs DLN/SCR (natural gas-fired) 2/8/2

BP Cherry Point Cogeneration Washington 2.5 ppm 3-hr SCR/DLN 1/11/

ANP Blackstone Massachusetts 

2.0 ppm, loads >50%; 3.5 

ppmvd, loads >100% + 

steam augmentation 

1-hr SCR 4/16/

(PSD p

(* ppm values are corrected to 15 percent O2) 

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7.1.2 BACT for CO and VOCs - Combustion Turbines and Duct Burners 

For control of CO and VOC emissions, the applicant evaluated catalytic oxidation 

beyond the base case of good combustion. Catalytic oxidation is the control technology 

most often used with gas turbines and consists of a catalyst bed located in the HRSG 

downstream of the duct burner. The oxidation catalyst causes a small pressure drop 

which causes a slight loss in power output from the turbine. No additional reactants are 

required since there is sufficient oxygen in the gas stream for the oxidation reactions to 

proceed in the presence of the catalyst. 

The applicant proposed the use of an oxidation catalyst that will achieve a CO exhaust 

concentration of 3.0 ppm or less, at 15 percent oxygen and averaged over a 3-hour 

averaging period, except during startups and shutdowns, as BACT. For VOC, The 

applicant proposed a maximum VOC exhaust level of 2.0 ppm or less, at 15 percent 

oxygen and averaged over a 1-hour period, excluding startups and shutdowns, as BACT. 

Table 7-2 shows several recent BACT determinations that have the lowest limits 

achieved at similar facilities. Similar facilities using oxidation catalysts have been 

permitted at between 2.0 to 4.0 ppm for CO and between 1.0 and 2.0 ppm for VOC. 

Based on this information, EPA concurs that these proposed emission levels for periods 

other than startup and shutdown, can be achieved with catalytic oxidation control 

technology, and that such emission limits represent BACT for the CTs and DBs. 
Colusa Generating Station 

Table 7-2. Recent CO & VOC Determinations for Combustion Turbines/Duct Burners *

Facility Location CO Limits Avg Period VOC Limits Avg Period Emission Control Per

Blythe Energy LLC (Blythe II) California 4.0 ppm 3-hr -- -- -- A

Elk Hills Power California 4.0 ppm 3-hr -- -- SCR/DLN or SCONOX J

La Paloma - PG&E California 6.0 ppm (10 ppm for loads below 221 MW) 3-hr -- -- Oxidation catalyst D

Los Esteros Energy Center California 9.0 ppm 3-hr 2.0 ppm 3-hr Oxidation catalyst M

Los Medanos Energy Center California 6.0 ppm 3-hr 0.0017 lb/mmbtu -- Oxidation catalyst 11

Palomar Escondido - Sempra California 4.0 ppm 3-hr 2.0 ppm 3-hr Oxidation catalyst D

Pastoria Energy LLC California 9.0 ppm 3-hr -- -- SCR/DLN or XONON D

San Joaquin Valley Energy Center California 4.0 ppm 1-hr -- -- Oxidation catalyst A

Mountainview Power Company California -- -- -- -- -- 

Sacramento Municipal Utility District California 4.0 ppm 3-hr 1.4 ppm 3-hr -- 

Three Mountain Power California 4.0 ppm 3-hr 2.0 ppm 1-hr Oxidation catalyst 10

Western Midway Sunset California 4.0 ppm 3-hr 1.4 ppm 3-hr Oxidation catalyst 12

Magnolia Power Project California 2.0 ppm 1-hr 2.0 ppm 1-hr Oxidation catalyst 5/

McDonough Combined-Cycle 1.8 w/ DB 

Generating Units Georgia 1.8 ppm 3-hr 1.0 w/o DB 3-hr Oxidation catalyst 1

(Effe

Rocky Mountain Energy Center Colorado 3.0 ppm -- 0.0029 lb/MMBtu -- Oxidation catalyst & good combustion 5

PSO Southwestern Power Plant Oklahoma 25.0 ppm -- -- -- Combustion control 2

Sierra Pacific Power Company Nevada 3.5 ppm 3-hr 4.0 ppm 3-hr Oxidation catalyst 8/

Wanapa Energy Center Oregon 2.0 ppm 3-hr -- -- Oxidation catalyst 8

Crescent City Power, LLC Louisiana 4.0 ppm Annual 1.1 ppm Annual Oxidation catalyst & good combustion 6

Berrien Energy, LLC Michigan 2.0 ppm 3-hr 3.2 lb/hr -- Oxidation catalyst 4/

Turner Energy Center, LLC Oregon 2.0 ppm at >70% load; 3.0 ppm at <70% load 3-hr 1.0 ppm 3-hr Oxidation catalyst 1

4.1 ppm CT normal 

7.6 ppm CT + DB 

Stack test 

Florida Power and Light – Turkey 3-run avg 

Point Florida 

8.0 ppm 24-hr block avg 

1.3 ppm CT, normal 

1.9 ppm CT + DB -- Good combustion 2

BP Cherry Point Cogeneration Washington 2.0 ppm 3-hr 3.0 lb/hr 24-hr Oxidation catalyst 1/

ANP Blackstone Massachusetts 3.0 ppm 1-hr 1.4 ppm 1-hr Oxidation catalyst 4/

(PS

(* ppm values are corrected to 15 percent O2)

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Colusa Generating Station May 2008

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7.1.3 BACT for PM - Combustion Turbines and Duct Burners 

PM emissions from turbines primarily result from carryover of noncombustible trace 

constituents in the fuel. The applicant proposed that PM/PM10 emissions, as well as SO2

emissions, be controlled through the use of clean burning pipeline quality natural gas for 

the CTs and DBs. Based on other similar recently permitted gas turbine operations, EPA 

concurs that the exclusive use of pipeline-quality natural gas represents BACT for the 

CTs and DBs. 

7.1.4 BACT for Startup and Shutdown Periods – Combustion Turbines 

Startup and shutdown periods are a normal part of the operation of combined-cycle 

natural gas-fired power plants, such as CGS. BACT applies during all modes of 

operation, including startup and shutdown periods. The BACT limits established in the 

previous sections for the CTs are for steady-state operation, which are not technically 

feasible during startup and shutdown of the CTs. Therefore, alternate BACT limits must 

be specified for these modes of operation. 

Startup and shutdown periods, when compared to emissions generated at steady-state 

operation, generate elevated emissions for various reasons. For instance, decreased 

turbine loads (less than 70%) occur during these periods which can cause incomplete 

combustion and lead to excess CO or VOC emissions. Also, decreased temperatures 

during these periods which fall outside of the optimal temperature range for the SCR 

control can cause too little or too much ammonia injection in the SCR system which may 

result in excess NOx emissions or ammonia slip. Furthermore, the decreased 

temperatures which fall outside of the optimal temperature range for the control 

equipment (SCR and oxidation catalyst) may lead to non-operation of the control 

equipment for all or part of the duration of startup and shutdown periods. 

Since startup and shutdown emissions from the gas turbines are much higher in both 

concentration (ppm) and mass rates (lb/hr), it is important to quantify and minimize 

emissions during these periods. The applicant described three types of startups based 

primarily on how long the gas turbines had been shutdown prior to the startup: cold 

startup; warm startup; and hot startup. Table 7-4 shows the applicant’s emission limits 

and durations for each startup period and during shutdown. The estimates are based on 

data provided by the gas turbine vendor, and are specific to the configuration and 

operational characteristics for the proposed CGS facility.9

 

9

 See the Preliminary Technical Support Document for the Wanapa Energy Center PSD permit 

issued in August 2005 and the Air Quality Impact Report for the Mountainview Power Company 

PSD permit issued in May 2005. 
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Colusa Generating Station May 2008

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Table 7-3. Proposed Startup and Shutdown Emission Rates for Each Turbine 

NOx CO VOC PM10 

Event 

(Duration)

Hourly 

Maximum 

(lb/hr) 

Total 

(lb/event) 

Hourly 

Maximum 

(lb/hr) 

Total 

(lb/event) 

Hourly 

Maximum 

(lb/hr) 

Total 

(lb/event) 

Hourly 

Maximum 

(lb/hr) 

Total 

(lb/event) 

Cold Startup 

(4.5 hours) 333.3 779.1 373.6 1355.6 27.7 106.7 12.0 48.8 

Warm 

Startup 

(3 hours) 

152.0 456.2 370.3 790.5 27.7 47.4 12.0 30.8 

Hot Startup 

(1.5 hours) 249.9 259.9 429.6 679.6 27.7 38.0 12.0 12.8 

Shutdown 

(30 minutes) 115.0 115.0 483.5 483.5 23.9 23.9 6.0 6.0 

(Based on data from Table 5-2 of the December 2006 PSD application) 

Based on the above information, EPA concurs that these proposed emission levels for 

startup and shutdown periods represent BACT for the CTs. The proposed BACT 

emission limits were estimated based on data provided by the equipment manufacturer. 

If source testing determines that these emission rates are not achievable, then these 

BACT limits, as well as the air quality impact modeling based on the proposed emission 

limits, must be re-evaluated. 

7.2 BACT for the Auxiliary Boiler and Diesel Engines 

7.2.1 BACT for NOx - Auxiliary Boiler and Diesel Engines 

The facility will consist of one auxiliary boiler and two emergency diesel engines. The 

applicant proposed to equip the auxiliary boiler with an ultra-low NOx burner that will 

achieve a NOx exhaust concentration of 9 ppm (0.0108 lb/MMBtu). Table 7-4 shows 

recent NOx determinations for auxiliary boilers. The auxiliary boiler will have a heat 

input of 44 mmbtu per hour and will operate a maximum of 3,744 hours per year. For the 

two emergency diesel engines, the applicant proposed that each engine will operate no 

more than 50 hours per year and no more than 1 hour per day. 

Based on similar permitting decisions at similar facilities, EPA concurs with the 

proposed operational limits for the auxiliary boiler and emergency diesel engines. The 

proposed BACT emission limits were estimated based on data provided by the equipment 

manufacturer. If source testing determines that these emission rates are not achievable, 

then these BACT limits will be revisited, as well as the impact modeling based on the 

proposed emission limits. 
 Impact Report 

Colusa Generating Station 

Table 7-4. Recent NOx Determinations for Natural Gas-Fired Auxiliary Boilers*

Facility Location Size (MMBtu/hr) NOx Limits Control Method Permit D

Los Medanos California 320 9 ppm SCR/oxidation catalyst 11/9/20

San Joaquin Valley Energy 

Center California 160 9 ppm -- Aug 20

LA County Internal Services 

Dept. California 39 9 ppm Ultra-Low NOx burner with Flue Gas Recirculation (FGR) 10/8/20

Genentech, Inc California 97 9 ppm Ultra-Low NOx burners 9/27/20

McDonough Combined-Cycle 

Generating Units Georgia 

20 

(3 aux boilers; each aux 

boiler limited to 175,200 

MMBtu/yr) 

30 ppm Low NOx burners & FGR 1/7/20

(Effective 

La Paz Generating Facility Arizona 41 (aux boiler for GE turbine) 0.027 lb/MMBtu Low NOx burners 9/4/20

Genova Arkansas I, LLC Arkansas 33 0.04 lb/MMBtu Low NOx burners &/or FGR 8/23/20

Barton Shoals Energy LLC Alabama 40 (2 boilers) 0.05 lb/MMBtu Low NOx burners 7/12/20

Clovis Energy Facility New Mexico 33 (2 boilers, limits apply separately) 0.036 lb/MMBtu Good combustion 6/27/20

Genova Oklahoma LLC Oklahoma 33 0.035 lb/MMBtu Low NOx burners 6/13/20

Thunderbird Generation LLC Oklahoma 20 0.049 lb/MMBtu Low NOx burners 5/17/20

Cabot Power Corporation Massachusetts 26.6 0.04 lb/MMBtu SCR, Dry Low NOx combustor 5/7/20

McClain Energy Facility Oklahoma 22 0.035 lb/MMBtu Combustion control 1/19/20

Beatrice Power Station Nebraska 73.3 (natural gas) 0.050 lb/MMBtu Operation limited to 500 hrs/yr. 6/22/20

Copper Mountain Power Nevada 60 0.035 lb/MMBtu Ultra-Low NOx burner with either internal or external FGR 5/14/20

Rincon Power Plant C Georgia 83 0.055 lb/MMBtu Operation limited to 1000 hrs/yr. 3/24/20

Emery Generating Station Iowa 68 0.049 lb/MMBtu DLN 12/20/2

Competitive Power Venture, 

CPV Cunningham Plant Virginia 80 0.050 lb/MMBtu Low NOx burners, good combustion 9/6/20

Greater Des Moines Energy 

Center Iowa 68 0.050 lb/MMBtu -- 4/10/20

Fremont Energy Center LLC Ohio 80 0.034 lb/MMBtu (calculated) Low NOx burners 8/9/20

(* ppm values are corrected to 3 percent O2)

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Colusa Generating Station May 2008

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7.2.2 BACT for CO and VOC - Auxiliary Boiler and Diesel Engines 

For the auxiliary boiler, the applicant proposed a CO emission rate of less than 50 ppmvd 

(0.037 lb/mmbtu), corrected to 3 percent oxygen and a VOC emission rate of less than 10 

ppmvd (0.004 lb/mmbtu), corrected to 3 percent oxygen. The auxiliary boiler will have a 

heat input of 44 mmbtu per hour and will operate a maximum of 3,744 hours per year. 

The applicant also proposed that the two emergency diesel engines will each operate no 

more than 50 hours per year and no more than 1 hour per day. 

Based on other similar recently permitted gas turbine operations, EPA concurs that these 

proposed emission levels for periods other than startup and shutdown, can be achieved 

with this technology, and that such emission limits represent BACT for the gas turbines, 

auxiliary boiler. The proposed BACT emission limits were estimated based on data 

provided by the equipment manufacturer. If source testing determines that these 

emission rates are not achievable, then these BACT limits will be revisited, as well as the 

impact modeling based on the proposed emission limits. 
 Impact Report 

Colusa Generating Station 

Table 7-5. Recent CO & VOC Determinations for Natural Gas-Fired Auxiliary Boilers* 

Facility Location Size (MMBtu/hr) CO Limits VOC Limits Control Method Perm

Los Medanos California 320 50 ppm 1.7 lb/hr Oxidation catalyst 

San Joaquin Valley Energy Center California 160 50 ppm -- -- Au

LA County Internal Services Dept. California 39 100 ppm -- -- 10/

Genentech, Inc California 97 50 ppm -- -- 9/2

McDonough Combined-Cycle 

Generating Units Georgia 

20 

(3 aux boilers; each aux 

boiler limited to 175,200 

MMBtu/yr) 

0.037 lb/MMBtu 0.0051 lb/MMBtu 1/

(Effec

Turner Energy Center, LLC Oregon 4,179,040 mmbtu/yr, 3000 hr/yr 0.038 lb/MMBtu 0.0044 lb/MMBtu Oxidation catalyst 1/

Dome Valley Energy Partners Arizona 38 0.080 lb/MMBtu 0.003 lb/MMBtu -- 12/

South Point Biomass Generation Ohio 247 (nat gas) 0.110 lb/MMBtu 0.004 lb/MMBtu -- 4/4

La Paz Generating Facility Arizona 41 (aux boiler for GE turbine) 0.09 lb/MMBtu 0.01 lb/MMBtu -- 9/4

Genova Arkansas I, LLC Arkansas 33 0.04 lb/MMBtu -- Good combustion 8/2

Barton Shoals Energy LLC Alabama 40 (2 boilers) 0.082 lb/MMBtu 0.0054 lb/MMBtu Good combustion 7/1

Clovis Energy Facility New Mexico 

33 

(2 boilers, limits apply 

separately) 

0.07 lb/MMBtu 0.5 lb/hr Clean fuel/ good combustion 6/2

Genova Oklahoma LLC Oklahoma 33 0.037 lb/MMBtu 0.016 lb/MMBtu Good combustion 6/1

Copper Mountain Power Nevada 60 0.08 lb/MMBtu 0.4 lb/hr 

Effective 

combustion 

design 

5/1

Rincon Power Plant Georgia 83 0.093 lb/MMBtu 0.004 lb/MMBtu -- 3/2

Emery Generating Station Iowa 68 0.0164 lb/MMBtu 0.0054 lb/MMBtu Catalytic oxidation 12/2

Greater Des Moines Energy 

Center Iowa 68 0.084 lb/MMBtu -- -- 4/1

(* ppm values are corrected to 3 percent O2)

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Colusa Generating Station May 2008

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7.2.3 BACT for PM - Auxiliary Boiler and Diesel Engines 

PM emissions primarily result from carryover of noncombustible trace constituents in the 

fuel. The applicant proposed that PM/PM10 emissions, as well as SO2 emissions, be 

controlled through the use of clean burning pipeline quality natural gas for the auxiliary 

boiler. 

For the two emergency diesel engines, the operational and emission limits vary for units 

at similar facilities. According to the RBLC, CARB BACT Clearinghouse, and permits 

for similar facilities, BACT has been emission limits depending on the size of the unit, 

limits on the hours of operation, and sulfur content restriction for diesel fuel. 

As mentioned in previous sections, the auxiliary boiler will have a maximum heat input 

of 44 mmbtu per hour and will operate a maximum of 3,744 hours per year. The two 

emergency diesel engines will each operate no more than 50 hours per year and no more 

than 1 hour per day. Also, based on the applicant’s emission calculations, the applicant 

will be restricted to using ultra-low sulfur diesel fuel containing 15 ppm sulfur. 

Based on other similar recently permitted gas turbine operations, EPA concurs that these 

proposed emission levels for periods other than startup and shutdown represent BACT 

for the auxiliary boiler and two emergency diesel engines. The proposed BACT emission 

limits were estimated based on data provided by the equipment manufacturer. If source 

testing determines that these emission rates are not achievable, then these BACT limits 

will be revisited, as well as the impact modeling based on the proposed emission limits. 
Air Quality Impact Report 

Colusa Generating Station May 2008

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8 CLASS I AIR QUALITY IMPACTS 

The PSD regulations require that the applicant perform an analysis of the impact that its 

emission increases would have on nearby Class I areas. The analysis is required for 

regulated pollutants that would have significant increases. The applicant performed 

analyses for PM and NOx, and for SO2 even though the proposed facility’s emission 

increases for SO2 are less than significant (i.e., less than 40 tpy). 

Class I areas are areas of special national or regional natural, scenic, recreational, or 

historic value for which the PSD regulations provide special protection. The Class I 

analysis is used to determine whether the emission increases will cause or contribute to a 

violation of the Class I increments and whether it will have an adverse impact on the air 

quality related values (AQRV) of a particular Class I area. The AQRVs are special 

attributes of a Class I area that may be adversely affected by deterioration of air quality. 

The Class I analysis is typically done for areas located within 100 km from the proposed 

facility. In accordance with comments from the USDA Forest Service (USFS) and EPA 

Region 9 regarding the Class I air quality modeling analysis for CGS, the applicant 

considered impacts on five Class I areas within 200 km from the proposed facility, which 

include Yolla Bolly-Middle Eel Wilderness, Lassen Volcanic National Park, Thousand 

lakes Wilderness, Caribou Wilderness, and Desolation Wilderness Class I area. The 

AQRVs analyzed by the applicant include visibility, increment, nitrogen and sulfur 

deposition. 

8.1 Model Selection and Setup 

The applicant used CALPUFF and CALMET to model for impacts on AQRVs due to 

PM10 and NOx emission increases. CALPUFF is a puff-type model that can incorporate 

three-dimensionally varying wind fields, wet and dry deposition, and atmospheric gas 

and particle phase chemistry. The CALMET model is used to prepare the necessary 

gridded wind fields for use in the CALPUFF model. The parameters used in the model 

are listed below. 

8.1.1 Receptor Network 

The applicant used receptors that were obtained from the National Park Service’s (NPS) 

Class I Areas receptor database for modeling of each Class I area. Latitude/Longitude of 

the Class I receptor coordinates were converted to Lambert Conformal Conic (LCC) 

coordinate system. Table 8-1 lists the distances from the project site to the closest and 

farthest points of each Class I area. 
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Colusa Generating Station May 2008

Page 26 of 47

Table 8-1. Class I Areas within 200 km Radius of the Project Site 

Class I Areas Distance (km) 

Closest 88 Yolla Bolly-Middle Eel Wilderness Area Farthest 121 

Closest 132 Lassen Volcanic National Park Farthest 160 

Closest 155 Thousand Lakes Wilderness Area Farthest 165 

Closest 146 Caribou Wilderness Area Farthest 160 

Closest 176 Desolation Wilderness Area Farthest 199 

(Source: CALMET/CALPUFF Air Quality Modeling Impact Analysis, August 2007, Table 1) 

8.1.2 Source Data 

The maximum emission rate for each averaging time period is shown in Table 8-2 and the stack 

parameters used in the modeling are shown in Table 8-3. 

Table 8-2. Maximum Emission Rates of Each Averaging Time Period 

Emission Unit 

PM10 

24-hr 

(g/s) 

NOx 

Annual 

(g/s) 

PM10 

Annual 

(g/s) 

Turbine 1 2.53 2.63 2.04 

Turbine 2 2.53 2.63 2.04 

Auxiliary Boiler 0.04162 4.27E-02 1.78E-02 

Fire Water Pump 0.00052 1.43E-03 7.13E-05 

Emergency Diesel 0.00045 9.99E-03 6.16E-05 

Total 5.108 5.323 4.091 

(Source: CALMET/CALPUFF Air Quality Modeling Impact Analysis, August 2007, Table 2) 

Table 8-3. Stack Parameters

Source 

Description 

UTM 

NAD27 

Easting 

(m) 

UTM 

NAD27 

Northing 

(m) 

LCC X 

(km) 

LCC Y 

(km) 

Base 

Elevatio

n 

(m) 

Stack 

Height 

(m) 

Stack 

Temperature 

(K) 

Stack 

Velocity 

(m/s) 

Stack 

Diameter 

(m) 

Turbine 1 562980 4357423 -57.6413 -45.7594 57 53.34 344.82 19.416 5.7912 

Turbine 2 563025.8 4357423 -57.5955 -45.7601 57 53.34 344.82 19.416 5.7912 

Auxiliary 

Boiler 562978.5 4357409 -57.643 -45.7731 57 11.2776 438.15 33.01 0.6096 

Fire Water 

Pump 562882.5 4357389 -57.7393 -45.7913 56.1 5.4864 683.15 45.04 0.1524 

Emergency 

Diesel 562944.3 4357406 -57.6773 -45.7755 56.2 7.62 718.71 119.437 0.2032 

(Source: CALMET/CALPUFF Air Quality Modeling Impact Analysis, August 2007, Table 3) 

8.1.3 Meteorological Data 

The applicant used a Mesoscale Meteorological Model (MM5) data set in conjunction 
Air Quality Impact Report 

Colusa Generating Station May 2008

Page 27 of 47

 

with the actual surface and precipitation meteorological data observations. The Federal 

Land Managers (FLMs) typically recommend that the meteorological input data set for 

CALPUFF include a 50 km buffer around of all Class I areas within the modeling 

domain, in order to prevent the loss of mass outside the domain boundary. While the 

MM5 data set obtained from WRAP only goes to 42 km west beyond the Yolla BollyMiddle Eel Wilderness Area, the FLMs deem it acceptable in this case. The applicant 

obtained three years (2001-2003) of MM5 data from the Western Regional Air 

Partnership (WRAP). The MM5 data had a 36 km resolution and initial guess wind 

fields that were based on hourly 36 km MM5 meteorological fields for 2001, 2002 and 

2003 was used. The data were pre-processed in CALMET for the CALPUFF air 

dispersion model, and were used for computing visibility, concentration, and dry 

deposition impacts. 

8.2 CALPUFF Modeling Analysis & Results 

The applicant’s modeling results are provided in Tables 8-4, 8-5 and 8-6 for the years 

2001, 2002, and 2003, respectively. The tables also include the Class I significant impact 

levels (SIL) for PM10, SO2 and NOx, and the thresholds for visibility and deposition. 

None of the modeled results exceed the SILs or threshold values shown in the tables 

below. Based on this information, EPA believes the proposed facility will not cause or 

contribute to any NAAQS or Class I PSD increment violation, and will not have an 

adverse impact on any Air Quality Related Value at any Class I area. EPA has notified 

the applicable FLMs and the agency has not received a formal finding of a potential 

adverse impact from the FLMs. Therefore, no further analyses, including additional 

AQRV impacts, are required. 

The applicant conducted an analysis of the potential impairment to visibility in Class I 

areas using the CALPUFF model, following the procedures recommended in “Federal 

Land Managers’ Air Quality Related Values Workgroup (FLAG) Phase I Report” (USFS, 

NPS, USFWS, December 2000). The calculated extinction changes due to the project 

exceeded the 5% FLAG level of concern for visibility at the Yolla Bolly-Middle Eel 

Wilderness Area. The modeled values for all other Class I areas were below the level of 

concern. To address the visibility AQRV exceedances, the applicant has agreed to do 

two things.10

First, PG&E agreed to analyze the effects of reducing its PM emissions to eliminate the 

modeled exceedances. If PG&E can reduce the PM emission limits from the combined 

cycle turbine units sufficient to eliminate the modeled exceedances, while still 

maintaining a sufficient compliance margin, PG&E will submit applications to the 

Colusa County APCD, California Energy Commission, and EPA (with copies to the 

10 See letter dated April 17, 2008, from Jon Maring of PG&E to Randy Moore of U.S. Forest 

Service. 
Air Quality Impact Report 

Colusa Generating Station May 2008

Page 28 of 47

USFS) proposing the lower PM emission limits and demonstrating the elimination of the 

modeled exceedances. 

Second, if PG&E can not reduce the PM emission limits from the combined cycle units 

sufficient to eliminate the modeled exceedances of the 5% visibility concern level, PG&E 

will begin negotiations with the USFS on a mitigation package that involves funding 

additional monitoring at the Yolla Bolly-Middle Eel Wilderness Area. The details of this 

monitoring program (i.e., specific projects, funding requirements) will be negotiated 

between PG&E and the USFS in a cooperative manner. 

Based on the agreement from the applicant to address the modeled exceedances, the 

USFS has no objection to the issuance of a PSD permit for the project.11.

Table 8-4. 2001 CALPUFF Modeling Results 

Class I 

Increment 

or AQRV 

Parameter 

Class I 

SIL or 

AQRV 

Threshold 

Caribou Desolation Lassen 

Volcanic 

Thousand 

Lakes 

Yolla Bolly 

Middle Eel 

Annual NOx 

(μg/m3

) 2.5 0.00053 0.00045 0.00076 0.00058 0.00173 

3-hr SO2 (μg/m3) 25 0.01886 0.02824 0.02670 0.01752 0.05732 

24-hr SO2 (μg/m3) 5 0.00433 0.00870 0.00540 0.00428 0.01254 

Annual SO2

(μg/m3

) 2 0.00022 0.00016 0.00029 0.00023 0.00038 

24-hr PM (μg/m3) 8 0.02485 0.04298 0.02894 0.02450 0.05813 

Class I 

Increments 

Annual PM 

(μg/m3

) 4 0.00139 0.0112 0.00172 0.00140 0.00183 

Total Nitrogen 

(g/m2

/s) 1.59E-11 1.1963E-12 5.7242E-13 1.5486E-12 1.2028E-12 1.6869E-12 

Deposition Total Sulfur 

(g/m2

/s) 1.59E-11 8.3892E-13 3.4511E-13 1.0286E-12 8.1071E-13 7.2425E-13 

No. of Days > 5% 0 0 0 0 0 2 

Max Extinction 

Change 5 2.04 1.83 2.24 1.8 5.51 

Visibility Day of Maximum 

Extinction 

Change 

-- 348 273 306 306 364 

(Source: CALMET/CALPUFF air quality modeling results submitted to EPA in a March 17, 2008 email from URS Corporation) 

 

11 See letter dated April 25, 2008, from Randy Moore of U.S. Forest Service to Deborah Jordan 

of EPA, Region 9. 
Air Quality Impact Report 

Colusa Generating Station May 2008

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Table 8-5. 2002 CALPUFF Modeling Results 

Class I 

Increment 

or AQRV 

Parameter 

Class I 

SIL or 

AQRV 

Threshold 

Caribou Desolation Lassen 

Volcanic 

Thousand 

Lakes 

Yolla Bolly 

Middle Eel 

Annual NOx 

(μg/m3

) 2.5 0.00053 0.00033 0.00096 0.00065 0.00148 

3-hr SO2 (μg/m3) 25 0.01632 0.01001 0.02972 0.01652 0.06444 

24-hr SO2 (μg/m3) 5 0.00386 0.00234 0.00541 0.00387 0.01663 

Annual SO2

(μg/m3

) 2 0.00023 0.00013 0.00035 0.00025 0.00033 

24-hr PM (μg/m3) 8 0.02152 0.01841 0.02792 0.02044 0.08766 

Class I 

Increments 

Annual PM 

(μg/m3

) 4 0.00144 0.00098 0.00198 0.00146 0.00171 

Total Nitrogen 

Deposition 

(g/m2

/s) 

1.59E-11 1.3388E-12 5.5670E-13 2.1672E-12 1.5717E-12 1.1880E-12 

Deposition Total Sulfur 

Deposition 

(g/m2

/s) 

1.59E-11 1.60E-13 3.8847E-13 1.4928E-12 1.1306E-12 4.5597E-13 

No. of Days > 5% 0 0 0 0 0 6 

Max Extinction 

Change 5 2.05 1.06 2.25 1.78 10.25 

Visibility Day of Maximum 

Extinction 

Change 

-- 124 292 124 71 341 

(Source: CALMET/CALPUFF air quality modeling results submitted to EPA in a March 17, 2008 email from URS Corporation) 

Table 8-6. 2003 CALPUFF Modeling Results 

Class I 

Increment 

or AQRV 

Parameter 

Class I 

SIL or 

AQRV 

Threshold 

Caribou Desolation Lassen 

Volcanic 

Thousand 

Lakes 

Yolla Bolly 

Middle Eel 

Annual NOx 

(μg/m3

) 2.5 0.00077 0.00033 0.00108 0.00079 0.00220 

3-hr SO2 (μg/m3) 25 0.02868 0.01022 0.02896 0.01662 0.07118 

24-hr SO2 (μg/m3) 5 0.00495 0.00331 0.00705 0.00390 0.01468 

Annual SO2

(μg/m3

) 2 0.00028 0.00013 0.00039 0.00030 0.00048 

24-hr PM (μg/m3) 8 0.02584 0.02304 0.03320 0.02003 0.06869 

Class I 

Increments 

Annual PM 

(μg/m3

) 4 0.00166 0.00097 0.00222 0.00174 0.00243 

Total Nitrogen 

Deposition 

(g/m2

/s) 

1.59E-11 1.5007E-12 5.4074E-13 2.0987E-12 1.5950E-12 2.1042E-12 

Deposition Total Sulfur 

Deposition 

(g/m2

/s) 

1.59E-11 9.2764E-13 3.5270E-13 1.3478E-12 1.0213E-12 8.7814E-13 

No. of Days > 5% 0 0 0 0 0 4 

Max Extinction 

Change 5 2.16 1.68 2.97 3.61 8.05 

Visibility Day of Maximum 

Extinction 

Change 

-- 329 71 33 33 339 

(Source: CALMET/CALPUFF air quality modeling results submitted to EPA in a March 17, 2008 email from URS Corporation) 
Air Quality Impact Report 

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9 CLASS II AIR QUALITY IMPACTS 

The PSD regulations require the applicant to perform an air quality impact analysis to 

determine the impacts that a proposed project would have on ambient air quality. For all 

regulated pollutants emitted in significant quantities, the analysis must consider whether 

the proposed facility will cause a violation of the applicable National Ambient Air 

Quality Standards (NAAQS) or ambient air quality PSD increments. 

The proposed project is significant for NOx (as NO2), PM10 (which is used as a 

surrogate for PM2.5), CO and ozone. Although the proposed project is significant for 

ozone, there is no recommended ozone model for analyzing the impact of individual 

point sources. In absence of a recommended model, EPA used emissions from the 

proposed project in conjunction with the “VOC/NOx Point Source Screening Tables”, 

Richard D. Scheffe, EPA, September 1988. EPA applied these tables to derive a very 

conservative estimate of the 1-hour average ozone impact of 11 ppb, well below the 

ozone NAAQS. 

In general, the air quality impact analysis involves an assessment of (1) the existing air 

quality including ambient monitoring data, and (2) predictions, using dispersion 

modeling, of ambient concentrations that will result from the applicant’s project and 

future growth associated with the project. A discussion on the general approach, air 

quality model selection, significant impact analysis, compliance with ambient standards, 

and increment consumption are presented below. 

9.1 Existing Air Quality 

To evaluate whether the emissions from the proposed project would cause a violation of 

the NAAQS, information on the existing ambient air quality in the vicinity of the project 

site is needed. The air quality data provisions generally require PSD applicants to obtain 

continuous air quality monitoring data representing the 12-month period preceding 

submittal of the applicant’s PSD application to EPA.12 Typically, this data requirement 

has been satisfied through the use of monitoring data collected from existing State or 

local agency air quality networks. The ambient air quality monitoring data is needed for 

the purpose of establishing background pollutant concentration in the area. 

The applicant obtained information on the existing ambient air quality in the region based 

on existing air quality networks in California. The air quality monitoring data was based 

on information from the following three ambient air quality monitoring stations that are 

operated by the California Air Resources Board (CARB): Colusa-Sunrise Boulevard 

12 See 40 CFR 52.21(m)(1)(vii). A shorter time frame (not less than 4 months) is allowed if 

enough data is provided to perform adequate analysis. 
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Station, Yuba City–Almond Street Station and Sacramento–Del Paso Manor Station. The 

Colusa-Sunrise Boulevard Station is within 20 miles from the project site and monitors 

for ozone, PM10 and PM2.5. The Yuba City–Almond Street Station is in Sutter County 

and located 38 miles from the proposed project site and the Sacramento–Del Paso Manor 

Station is in Sacramento County and located 60 to 70 miles from the project site. The 

pollutants monitored at the Yuba City–Almond Street Station and Sacramento–Del Paso 

Manor Station include ozone, CO, NO2, SO2, PM10, and PM2.5. For the air quality 

impact analysis, the applicant used the maximum background concentration from the past 

3 years from all monitoring stations. 

9.2 Model Selection and Inputs 

The applicant must use an air quality dispersion model to estimate the ambient 

concentrations that will result from a proposed project. If the applicant’s estimated 

ambient concentrations are above the PSD modeling or monitoring significance levels 

that apply to CO, PM10 or NO2, the applicant must perform additional air quality 

analyses that include emissions increases from the proposed project and emissions from 

other nearby existing sources. The results of the model are the estimated total ambient 

concentrations, which are used to demonstrate compliance with any applicable NAAQS 

or PSD increments. 

The applicant used the AERMOD air dispersion model to estimate the ambient 

concentrations that will result from a proposed project. The AERMOD modeling system 

has three separate components: AERMOD (AERMIC Dispersion Model), AERMAP 

(AERMOD Terrain Preprocessor), and AERMET (AERMOD Meteorological 

Preprocessor). The applicant ran the AERMOD model with the following default 

regulatory options: 

• Final plume rise at all receptors 

• Stack-tip downwash 

• Buoyancy-induced dispersion 

• Calms processing 

• Default wind profile exponents 

• Default vertical potential temperature gradients 

• Rural dispersion coefficients 

The inputs to the model are as follows. 

9.2.1 Stack Height Analysis 

Section 123 of the Clean Air Act defines the good engineering (GEP) stack height as the 

height necessary to insure that emissions from the stack do not result in excessive 

concentrations of any pollutant in the immediate vicinity of the source as a result of 
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Colusa Generating Station May 2008

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atmospheric downwash, eddies or wakes. Atmospheric downwash, eddies or wakes may 

be created by the source itself, nearby structures or nearby terrain obstacles. The stack 

must not exceed what is considered to be the GEP stack height for the source. The 

portion of a stack height that is in excess of the GEP height is generally not creditable 

when modeling to develop source limitations or to determine source impacts in the air 

quality analysis. For a stack height less than GEP height, the applicant performs 

screening procedures to assess the potential air quality impacts associated with building 

downwash. 

The applicant evaluated the effect of atmospheric downwash for routine operation of the 

turbines. The applicant used U.S. EPA’s Building Profile Input Program per the 

modeling protocol to generate direction-specific building data for stacks below good 

engineering practice stack height. The applicant used structures from the layout for the 

proposed project in the analysis and included the results of this analysis in the AERMOD 

input files to assess downwash effects. The AERMOD model considers directionspecific downwash using both the Huber-Snyder and Schulman-Scire algorithms as 

evaluated in the Building Profile Input Program (BPIP). 

Based on the applicant’s output from BPIP, which is shown is Table 9-1, the stack 

heights for the emission units do not exceed the calculated maximum allowable GEP 

stack height. Therefore, the project complies with the maximum stack height 

requirements. 

Table 9-1. BPIP Output of GEP Stack Heights 

Emission Unit Stack Height 

(m) 

GEP Stack Height 

(m) 

Turbine #1 53.34 108.83 

Turbine #2 53.34 108.83 

Auxiliary Boiler 11.28 108.83 

Diesel fire pump engine 5.49 109.73 

Emergency diesel engine 7.62 109.73 

(Source: December 2007 PSD application BPIP modeling output) 

9.2.2 Land Use 

The applicant obtained the land use classifications for the proposed project site from the 

U.S. Geological Survey National Land Cover Data. These classifications encompass 

rural agricultural or grazing lands and include the following: 

• Grasslands/Herbaceous – Areas dominated by upland grasses and forbs. In rare 

cases, herbaceous cover is less than 25 percent, but exceeds the combined cover 

of the woody species present. These areas are not subject to intensive 

management, but they are often utilized for grazing. 

• Pasture/Hay – Areas of grasses, legumes, or grass-legume mixtures planted for 

livestock grazing or the production of seed or hay crops. 
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• Row Crops – Areas used for the production of crops, such as corn, soybeans, 

vegetables, tobacco, and cotton. 

• Small Grains – Areas used for the production of graminoid crops such as wheat, 

barley, oats, and rice. 

The applicant used the following data sources to determine the appropriate surface 

characteristics (albedo, Bowen ratio and surface roughness) for use in the AERMET 

meteorological processing: 

• Boundary Layer Climates by T. R. Oke (1987), and 

• Tables 4-1, 4-2a, 4-2b, 4-2c, and 4-3 in the AERMET manual. 

9.2.3 Meteorological Data 

The applicant obtained meteorological data for input into AERMOD from Western 

Weather Group of Chico, California, from their Maxwell meteorological station. The 

meteorological station is outside the town of Maxwell (population about 1,300) and 

located approximately 8 miles south of the CGS project site. The 5 years of 

meteorological data to be used in this modeling analysis include data from 2001 through 

2005. 

According to the applicant’s PSD application, the National Weather Service stations 

closest to the proposed project site are at Red Bluff (60 miles), Sacramento (70 miles) 

and Redding (90 miles). Since none of these stations have land use or terrain as similar 

to the conditions at the proposed project site as the Maxwell Station, the applicant 

concluded that these sites are not as representative of the meteorological conditions of the 

project site and did not use them as the primary source of meteorological data in the 

permit modeling for the proposed project. However, the applicant proposed that the 

cloud cover data collected at Red Bluff be used to supplement the Maxwell data because 

cloud cover data are not recorded at Maxwell. The applicant also used upper air data 

from Oakland Airport in AERMOD. EPA agrees that the Maxwell surface data and the 

Oakland upper air data are representative and appropriate for use in air quality modeling 

for this facility. 

9.2.4 Receptor Network 

The applicant used some 2300 receptor locations in its AERMOD modeling analysis, 

according to the following receptor spacing scheme. 

• 25-m spacing along the property line and extending from the property line out to 

100 m 

• 100-m spacing within 1 km of project sources for any locations not covered by 

the 25-m grid 
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• 500-m spacing within 1 to 5 km of project sources 

• 1,000-m spacing within 5 to 10 km of project sources 

• If maximum concentrations are predicted where the grid spacing is less dense 

than 25 m, a 25-m spaced nested grid of receptors was placed surrounding the 

receptor where the maximum concentration was predicted. This nested grid 

extended out 500 m in all directions or until the next regular grid receptor was 

encountered. 

The receptor locations were designated using Universal Transverse Mercator (UTM) 

coordinates. The applicant obtained the receptor elevations from U.S. Geological Survey 

7.5-minute electronic data. 

9.3 Load Screening Analysis 

The applicant performed screening modeling to determine which turbine operating modes 

(i.e., load level, duct burner firing, and ambient temperature) produced worst-case 

impacts for each pollutant and averaging time. The applicant used AERMOD for the 

screening analysis, with the 2001-2005 meteorological data, building wake information, 

and receptor grid previously described. 

The model simulated natural gas combustion emissions from two 19-foot-diameter 

(5.8-meters), 175-foot-tall (53.34-meters) stacks. The stacks were modeled as point 

sources at their proposed locations. The applicant’s stack parameters for each operating 

mode are shown in Table 9-3. 

Table 9-2. Stack Parameters at Each Operating Mode 

Season CTG Load Duct Burner Status Stack Velocity 

(ft/sec) 

Stack Temperature 

(oF) 

100% On 68.6 162 

100% Off 71 193 

75% Off 55.1 181 

Winter 

Minimum (18oF) 

50% Off 44.3 175 

100% On 63.7 161 

100% Off 66 193 

75% Off 52.3 181 

Yearly Average 

(59oF) 

50% Off 42.8 175 

100% On 63.1 186 

100% Off 63.7 202 

75% Off 51.5 188 

Summer 

Maximum 

(114oF) 50% Off 42 167 

(Source: December 2006 PSD application, Table 6-1) 

The results from AERMOD screening runs using the above stack parameters for the 

various operating scenarios were then combined with specific pollutant emission rates for 

different averaging times. The result was the worst case impacts occur for 100% load, 
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Colusa Generating Station May 2008

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with duct burners, at 59 degrees F. This applies to all pollutants and averaging times, 

except the 24-hour PM10 used 50% load, no duct burners, 114 degrees F. The 

AERMOD results are in Table 9-4. 

Table 9-3. AERMOD Results in μg/m3

Season CTG 

Load NOx 

(Annual) 

CO 

(1-hour) 

CO 

(8-hour) 

PM10 

(24-hour) 

PM10 

(Annual) 

100% 0.585 34.645 11.210 3.904 0.565 

100% 0.329 22.002 7.881 2.323 0.277 

75% 0.384 21.787 7.496 2.820 0.396 

Winter Minimum 

(18oF) 

50% 0.405 25.107 8.563 3.865 0.526 

100% 0.607 34.713 11.941 4.249 0.617 

100% 0.334 20.808 7.502 2.362 0.301 

75% 0.379 22.007 7.547 2.949 0.419 

Yearly Average 

(59oF) 

50% 0.395 24.323 8.353 4.010 0.543 

100% 0.493 29.864 10.241 3.840 0.522 

100% 0.312 19.622 7.065 2.352 0.296 

75% 0.352 19.988 6.864 2.874 0.403 

Summer Maximum 

(114oF) 

50% 0.407 24.795 8.655 4.417 0.591 

(Source: Data from supplemental information provided by the URS Corporation to EPA in a September 24, 2007 email) 

Based on the screening results, the applicant used the following stack parameters to 

estimate the proposed project’s ambient air impacts: 

● 50 percent load, with no duct firing, at 114°F ambient temperature for 1-hour CO 

impacts. 

● 100 percent load, with duct firing, at 114°F ambient temperature operating mode 

for estimated for 24-hour PM10 impacts 

● 100 percent load, with duct firing, at 59°F ambient temperature operating mode 

for annual NO2 and PM10 impacts and 8-hour CO impacts. 

The applicant also used the following modeling assumptions in Table 9-5 to determine 

the worst-case emissions for each applicable averaging period to demonstrate compliance 

with NAAQS and PSD increments. 
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Table 9-4. Modeling Assumptions 

Averaging Period Worst Case Assumption 

1-hour 

Worst-case 1-hour emissions for CO are equal to 

shutdown emission rate (483 lb/hr per CT). Includes 1 

hour of each auxiliary boiler, fire pump and 

emergency generator. 

8-hour 

Worst-case 8-hour emissions for CO include six hours 

at startup and shutdown rate and remainder of 8 hours 

is at 18°F, 100 percent load, duct firing emission rates 

(236.98 lb/hr per CT). Includes 1 hour of each fire 

pump and emergency generator and 8 hours of 

auxiliary boiler. 

24-hour Worst-case 24-hour emissions of PM10 based on 

normal operation of turbines (482.4 lb/hr per CT). 

Annual 

Worst-case annual emissions for PM10 and NO2 from 

the turbine/HRSG equal the annual emission estimates 

(see Table 5-3). Includes 50 hours of each fire pump 

and emergency generator and 3,744 hours of auxiliary 

boiler. 

(Source: Appendix B of the December 2006 PSD application and 

the applicant’s Responses to CEC Data Requests of January 11, 2007, Table 19-1) 

9.4 Modeling Results 

The applicant performed air dispersion modeling to evaluate the increases in pollutant 

concentrations from the project by itself. Potential emissions from the turbine/HRSG, the 

generator and fire pump engines and auxiliary boiler were included in the modeling 

analysis. The UTM coordinates of the maximum impact locations and the results of the 

air dispersion modeling are shown in Table 9-5. The UTM coordinates are all within 10 

km of the proposed facility. 

Table 9-5. AERMOD Modeling Results 

Pollutant Averaging 

Period 

UTM 

East 

(m) 

UTM 

North 

(m) 

Maximum 

Modeled Impact

(μg/m3) 

PSD Significant 

Impact Level

(μg/m3) 

Background 

(μg/m3) 

Total Predicted 

Concentration 

(μg/m3) 

1-hr 558,375 4,359,450 1.396 2,000 6,444 7,840 CO 

8-hour 558,325 4,359,325 293 500 3768 4061 

NO2 Annual 562,750.2 4,357,572 0.64 1 26.3 27.0 

24-hour 562,600 4,357,800 6.11 5 92 98.1 PM10 

Annual 562,425 4,358,075 0.51 1 25.5 26.0 

(Source: December 2006 PSD application, Table 6-2) 
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9.4.1 PSD Increment Analysis 

The PSD increment analysis is the portion of the air quality analysis that is used to 

determine whether the amount of new pollution from a new or modified source will cause 

significant deterioration. 

Increment is the maximum increase in concentration of a pollutant that is allowed above 

a baseline concentration in an area. Increment standards exist for 3 pollutants: PM10 

(24-hour and annual averages), NOx (annual average only), and SO2 (3-hour, 24-hour 

and annual averages). A PSD increment analysis is required for every pollutant emitted 

in significant amounts, which for Colusa Generating Station are NOx and PM10. 

A key component to completing the increment analysis is establishing the baseline 

concentration for a pollutant in an area, which involves determining the baseline dates for 

the area. The baseline concentration is the ambient concentration existing at the time that 

the first complete PSD permit application affecting the area is submitted. The baseline 

concentration is essentially the reference point for determining air quality deterioration in 

an area. Significant deterioration is said to occur when the amount of new pollution 

would exceed an applicable PSD increment. 

The requirement to evaluate increment begins when the ‘baseline date’ is triggered. 

There are two types of baseline dates: (1) the major source baseline date, and (2) the 

minor source baseline date. The major source baseline dates are fixed dates that were 

established by the PSD regulations and reflect the date that the permitting authority is 

responsible for tracking increment consumption due to changes at major sources only. 

The major source baseline date is January 6, 1975 for particulate matter and SO2, and 

February 8, 1988 for NO2 for all areas.13

The minor source baseline date is triggered when a PSD application (for a new source or 

major modification at an existing source) is submitted and determined to be complete. 

When the first PSD application is determined to be complete, the baseline date is set for 

each pollutant that is subject to PSD regulations and for which there is an increment 

standard established. When the minor source baseline date is triggered, the increment 

analysis must evaluate changes that occur at all sources (including minor, area and 

mobile sources) after that date. The minor source baseline is September 19, 2001 for 

PM10, as well as NO2, for Colusa County, California. Thus, after this date, all minor 

source emission increases and decreases affect the available PSD increments for PM10 

and NO2. 

 

13 See 40 CFR 52.21(b)(14). The major source baseline date applies to PM. No major source 

baseline date specifically applies to PM10. 
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Generally, increment is consumed by emission increases from new or modified sources in 

an area and expanded through emission reductions in an area. If a new or modified 

source’s impacts are less than the significant values then the source is said to have no 

impact on the increment. 

There are two types of areas for which increments apply: Class I and Class II. Class I 

areas (e.g. wilderness areas and national parks) have more stringent increment limits than 

the Class II (non-Class I) areas. The Class I analysis is discussed in Section 8 of this 

document. 

The modeling results in Table 9-6 show the predicted annual impacts for both NO2 and 

PM10 are below the Class II increments, as well as the significant modeling 

concentrations. However, the predicted impact for 24-hour PM10 is 6.11 μg/m3

, which is 

above the significant modeling concentration of 5 μg/m3

. Therefore, the applicant is 

required to perform a cumulative impacts analysis (also called a full impacts increment 

analysis) to determine if the PM10 impacts due to CGS and changes at major and minor 

sources in the area reach or exceed the 24-hour PM10 increment standard of 30 ug/m3

. 

Table 9-6. Class II Increment Analysis 

Pollutant Averaging 

Period 

Maximum Modeled 

Concentration from the 

Proposed Project 

(μg/m3) 

Significant 

Modeling 

Concentration 

(μg/m3)

14

PSD Class II 

Increment 

(μg/m3) 

NO2 Annual 0.64 1 25 

PM1015 24-hour 6.11 5 30 

Annual 0.50 1 17 

(Source: December 2006 PSD application, Table 6-2) 

The applicant submitted a cumulative impact analysis for 24-hour PM10, including 

modeling results, to EPA on January 30, 2008 and February 7, 2008. The first step in the 

analysis is the establishment of the PM10 24-hour impact area. The impact area includes 

the area where the emissions from the new source will cause a significant ambient impact 

plus 50 kilometers (km). For the proposed CGS facility, the impact area included 

changes at all major and minor sources within a 55.4 km-radius from the proposed 

facility. The impact area overlaps essentially all of Colusa County, as well as portions of 

other adjacent California counties including Glenn, Yolo, Butte, Sutter, Lake and 

Tehema. The applicant identified only one major source (Johns-Manville fiberglass plant 

 

14 Significant modeling values apply to Class II areas only. If a proposed project is located 

within 100 km of a Class I area, an impact of 1 μg/m3

 on a 24-hour basis is significant. 

15 No PSD ambient air increments or significant modeling concentrations currently exist for 

PM2.5. 
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Colusa Generating Station May 2008

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in Glenn County and about 20 km N of CGS) and no minor sources. Other modeling 

parameters were the same as those shown in Section 9.2. 

The applicant considered anthropogenic activities that may increase ambient PM10 

levels, including population growth, highway improvements, and increased agricultural 

usage by showing a side-by-side temporal comparison of the area within about a 10-km 

distance from the proposed CGS site between the time prior to the minor source baseline 

date (1998-1999) and the most recently available data that corresponds to the CGS PSD 

application date (2006). No increase in housing, no road improvements, and no increase 

in agricultural land usage is evident during this period. Thus, these activities would 

likely have a negligible impact on increment consumption. 

The results of the 24-hour PM10 cumulative impacts analysis showed the proposed CGS 

facility would not cause or contribute to violations of the 24-hour PM10 increment 

standard. Therefore, no further air quality analyses are required. 

9.4.2 NAAQS Analysis 

The NAAQS are maximum concentration “ceilings” measured in terms of the total 

concentration of a pollutant in the atmosphere. 

Table 9-7 shows the results of ambient air quality impact from the facility. The results 

show that the maximum impacts for CO, NO2 and PM10 from proposed project, when 

combined with the background ambient air quality, are below the NAAQS for these 

pollutants. Therefore, the proposed project will not cause or contribute to a violation of 

the NAAQS. 

Table 9-7. NAAQS Impacts Analysis 

Pollutant Averaging 

Period 

Maximum 

Modeled 

Concentration 

(μg/m3) 

Maximum 

Background 

Concentration 

(μg/m3) 

Total 

Concentration 

(μg/m3) 

NAAQS 

(μg/m3) 

Monitoring 

De Minimus 

Concentrations 

(μg/m3) 

NO2 Annual 0.64 26.3 26.94 100 14 

24-hour 6.11 92 98.1 150 10 PM10 Annual 0.5 25.5 26.00 50 -- 

1-hour 1,396 6,444 7,840 40,000 -- CO 8-hour 293 3,768 4061 10,000 575

(Source: December 2006 PSD application, Table 6-2) 

Also, since the maximum modeled impact is below the monitoring de minimus 

concentrations for all pollutants, EPA is not requiring any preconstruction ambient air 

quality monitoring.. 
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10 ADDITIONAL IMPACT ANALYSIS 

The PSD regulations require PSD applicants to provide an analysis of the impairment to 

visibility, soils and vegetation that would occur as a result of the source or modification 

and general commercial, residential, industrial and other growth associated with an 

applicant’s proposed project. The analysis generally includes the projected air quality 

and visibility impacts for the area as a result of general commercial, residential, industrial 

and other growth associated with the proposed project. The PSD applicant’s analysis 

follows. 

10.1 Growth Analysis 

EPA expects little to no associated commercial growth as a result of the project. The 

proposed project is an electrical generating station. The proposed plant will operate in 

conjunction with an existing PG&E facility, natural gas pipelines and transmission lines 

that are located immediately adjacent to the proposed site. Also, the area where the 

proposed project will be located is used primarily for agricultural purposes. Therefore, 

little or no associated industrial, commercial, and residential source growth is expected to 

occur in the area due to the project. 

10.2 Soil & Vegetation Analysis 

Table 10-1 compares the proposed CGS modeled impacts against ambient screening 

concentrations established in EPA’s “A Screening Procedure for the Impacts of Air 

Pollution Sources on Plants, Soils, and Animals”, EPA-450/2-81-078, December 1980. 

Table 3.1 of this EPA guidance document lists for various pollutants screening 

concentrations, representing minimum concentrations at which adverse growth effects or 

tissue injury were reported in the scientific literature. While dated, this document is the 

only guidance currently available for conducting additional impacts assessments. 

Table 10-1. Screening Concentrations for Soils and Vegetation 

Pollutant Averaging Period Screening Concentration 

(μg/m3) 

Modeled maximum 

(μg/m3) 

Model averaging 

time used 

1-hr 917 4.4 1 hour 

SO2 3-hr 786 1.85 3 hour 

Annual 18 0.04 annual 

4-hr 3,760 336.5 1 hour 

NO2 1-month 564 336.5 1 hour 

Annual 94 0.64 annual 

CO Weekly 1,800,000 1,396 8 hour 

The applicant analyzed the potential effects of NO2 and, although not required, SO2. The 

applicant modeled the maximum annual NO2 impacts from normal plant operations using 

CALPUFF, as well as estimates of total nitrogen deposition estimated by 
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CALPUFF. Although, the emissions increases of SO2 would be below the significance 

threshold, the applicant considered SO2 impacts and total sulfur deposition. The applicant 

compared these estimates against the Deposition Analysis Threshold for individual sources 

established by the National Park Service for vegetation and ecosystems for Class I 

Wilderness Areas. Table 10-1 summarizes the maximum modeled impacts versus the 

National Park Service and the USFS significance criteria. All impacts are below the 

significance criteria. 

Table 10-2. Maximum Modeled Soil and Vegetation Impacts of the Proposed Project 

Pollutant USFS Significance Level Maximum Project Impact 

SO2 Annual 8 ppbv 0.0004 ppbv (0.001 μg/m3

) 

SO2 Hourly 40 ppbv 0.012 ppbv (0.031 μg/m3

) 

NO2 Annual 15 ppbv 0.0043 ppbv (0.008 μg/m3

) 

Total Sulfur Deposition 0.005 kg/ha-year* 0.00025 kg/ha-year 

Total Nitrogen Deposition 0.005 kg/ha-year* 0.0017 kg/ha-year 

(Source: December 2006 PSD application, Table 7-1) 

Generally, for most types of soils and vegetations, ambient concentrations of criteria 

pollutants below the secondary NAAQS will not result in harmful effects. The estimated 

maximum ambient concentrations of 0.64 μg/m3 annual average for NO2 and 4.35 μg/m3

24-hour average and 0.5 μg/m3 annual average for PM10 concentrations from this project 

are below the secondary NAAQS for NO2 (100 μg/m3

 annual average) and PM10 (5 

μg/m3 24-hour average and 1 μg/m3 annual average). Therefore, no harmful effects of 

NO2 and PM10 are expected. 

EPA expects the impact from the proposed project will be minimal on surrounding 

vegetation. 

10.3 Visibility Impairment Analysis 

The applicant conducted an analysis of the potential impairment to visibility in Class I 

areas using the screening version of the CALPUFF model and the same meteorological 

input data used for the air quality modeling analysis, which is also discussed in Section 8. 

The CALPUFF model was used in screening mode to evaluate potential visibility impacts 

on nearby Class I areas. The results of the analysis showed modeled exceedances of the 

5% FLAG level of concern for visibility in the FLAG document. Based on the 

agreement from the applicant to address the modeled exceedances, the USFS has no 

objection to the issuance of a PSD permit for the project. (See section 8.2 for more 

information about the agreement.) 

The applicant used EPA’s VISCREEN model to assess the potential impact of individual 

plumes on visibility. The Level I visibility screening analysis found that worst case 

impacts for color contrast and overall contrast were below the suggested criteria in EPA’s 
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Colusa Generating Station May 2008

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“Workbook for Plume Visual Impact Screening and Analysis” (Revised), EPA-454/R-92-

023, October, 1992. As there are no regulatory criteria for acceptability of plume 

contrast, this result can be considered informational.

11 PROPOSED PERMIT REQUIREMENTS 

11.1 Emission & Operational Limits 

The emission and operational limits for the CT units, auxiliary boiler and diesel engines 

are presented in Tables 11-2, 11-2, and 11-3. The emission limits are based upon the 

results of a BACT analysis and ambient air quality analyses. The emission limits based 

upon the ambient air quality analyses reflect emission rates that assure compliance with 

the NAAQS and PSD increments. Each pollutant emission rate is assigned an averaging 

period to coincide with the averaging time to ensure ongoing compliance with the 

emission limits. 

Table 11-1. Combustion Turbines/Duct Burners16

Pollutant BACT Requirements PSD Increments and NAAQS Requirements 

NOx 

• 2.0 ppmvd, 1-hr average, corrected to 15 % O2, 

except during CT startup and shutdown 

• Employ SCR system 

• Combust pipeline quality natural gas 

• 19.6 lb/hr 

• 1497.3 lb/day 

• 185.6 tpy, 12-month rolling average 

CO 

• 3.0 ppmvd, 3-hr average, corrected to 15 % O2, 

except during CT startup and shutdown 

• Employ oxidation catalyst system 

• Combust pipeline quality natural gas 

• 17.9 lb/hr 

• 3829.5 lb/day 

• 272.2 tpy, 12-month rolling average 

VOC 

• 2.0 ppmvd, 3-hr average, corrected to 15 % O2, 

except during CT startup and shutdown 

• Employ oxidation catalyst system 

• Combust pipeline quality natural gas 

• 11 lb/hr 

• 315.3 lb/day 

• 48.2 tpy, 12-month rolling average 

PM/PM10 Combust pipeline quality natural gas 

• 20 lb/hr 

• 482.4 lb/day 

• 142.2 tpy, 12-month rolling average 

(Note: For the proposed BACT requirements that apply during startup and shutdown periods, see Table 7.3.) 

 

16 The emission limits in lb/hr includes emissions during normal operation only. The emission 

limits in lb/day and tpy includes emissions during normal operation, as well as emissions during 

startup and shutdown periods. 
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Table 11-2. Auxiliary Boiler 

Pollutant BACT Requirements PSD Increments and NAAQS Requirements 

NOx 

• 9 ppmvd, 3-hr average, corrected to 3% O2

• Employ ultra-low NOx burners 

• Operate no more than 3,744 hours per yea 

• Combust pipeline quality natural gas r 

• 0.48 lb/hr 

• Operate no more than 3,744 hours per year 

CO 

• 50 ppmvd, 3-hr average, corrected to 3% O2; 

• Operate no more than 3,744 hours per year 

• Combust pipeline quality natural gas 

• 1.63 lb/hr 

• Operate no more than 3,744 hours per year 

VOC 

• 10 ppmvd, 3-hr average, corrected to 3% O2; 

• Operate no more than 3,744 hours per year 

• Combust pipeline quality natural gas 

• 0.18 lb/hr 

• Operate no more than 3,744 hours per year 

PM/PM10 • Combust pipeline quality natural gas 

• Operate no more than 3,744 hours per year 

• 0.33 lb/hr 

• Operate no more than 3,744 hours per year 

Table 11-3. Diesel engines (emergency and firewater pump) 

Pollutant BACT, PSD Increments and NAAQS 

NOx 

• 13.88 lb/hr for emergency engine 

• 1.98 lb/hr for firewater pump engine 

• Operate no more than 50 hours per year and no more than 1 hour per day 

CO, VOC, PM/PM10 Operate no more than 50 hours per year and no more than 1 hour per day 

11.2 Testing & Monitoring Requirements 

The emission limits established as BACT and for protecting ambient air quality standards 

must be associated with a specific emission test method for determining compliance with 

the emission limit. The specific emission test methods, continuous emission monitoring 

(CEM) requirements and the required testing frequency for the CTs and auxiliary boiler 

are detailed in Table 11-4. 

PG&E may request EPA approval of alternative test methods or testing frequencies. 

Until EPA provides written approval of such alternative test methods, however, PG&E is 

subject to the testing requirements in the permit. 
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Table 11-4. Combustion Turbines/Duct Burners & Auxiliary Boiler 

Pollutant Performance test method Monitoring Technique 

& Frequency 

CEMS Performance 

Testing Frequency 

(for CTs only) 

NOx 

• EPA Methods 1-4, and 7E if NOx 

emissions are measured in ppmv; 

• EPA Methods 1-4, 7E and 19 if NOx 

emissions are measured on a heat 

input basis 

• Additional testing requirements for 

‘high NO2 sites’ 

• CEMs for CTs 

• Annual testing for CTs 

and auxiliary boilers 

Initial and annual CEMs 

RATA in accordance with 

40 CFR Part 60 or 75 

CO EPA Methods 1-4 and 10 for CO 

emissions 

• CEMs for CTs 

• Annual testing for CTs 

and auxiliary boilers 

Initial and annual CEMs 

RATA in accordance with 

40 CFR Part 60 

VOC EPA Methods 25A or 25B for VOC 

emissions 

Annual performance 

testing -- 

PM/PM10 

Performance tests for the emissions of 

PM/PM10 shall be conducted using 

EPA Methods 1-5 and 202 

Annual performance 

testing -- 

11.3 Recordkeeping & Reporting Requirements 

PG&E is required to keep all records for a period of five (5) years. These records include 

hours of operation for the auxiliary boiler and diesel engines, fuel used in the all 

equipment, sulfur content of diesel fuel used in the diesel engines, CEM measurements 

and operation, and excess emissions reports. PG&E is required to report excess 

emissions to EPA on a quarterly basis. 
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12 ENDANGERED SPECIES ACT 

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, and its 

implementing regulations at 50 CFR Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued 

existence of any endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. For this proposed project, the 

applicant applied for federal permits from EPA and the Army Corps of Engineers of the 

U. S. Department of the Army (Army Corps). When a federal action involves more than 

one Federal agency, consultation responsibilities under Section 7 of the ESA may be 

fulfilled through a lead agency pursuant to 50 CFR § 402.07. For this proposed project, 

the Army Corps is the lead agency. 

The applicant submitted a biological assessment for the project in December 2006 to 

EPA, the Army Corps, and the U. S. Fish and Wildlife Service (Service). The biological 

assessment detailed the impact that the proposed project may have on several listed and 

proposed plant and animal species, as well as designated and proposed critical habitats, to 

determine whether any such species or habitat are likely to be adversely affected by the 

proposed project. 

In a June 13, 2007 letter to the Service, the Army Corps initiated informal consultation 

under Section 7 of the ESA and 50 CFR § 402.13. According to the letter, the Army 

Corps determined that the proposed project may affect the federally-listed California redlegged frog (Rana aurora draytonii), giant garter snake (Thamnophis gigas), vernal pool 

fairy shrimp (Branchinecta lynchi), conservancy fairy shrimp (Branchinecta conservatio), 

vernal pool tadpole shrimp (Lepidurus packardi), California tiger salamander 

(Ambystoma californiense), or their designated critical habitat. 

The applicant submitted a revised biological assessment for the project in October 2007, 

to EPA, the Army Corps, and the Service. Since the Service found that project was likely 

to adversely affect one or more of the federally-listed species, the Service initiated formal 

consultation as required under Section 7(a)(2) of the ESA and 50 C.F.R. Part 402.14. 

On March 14, 2008, the Service issued its biological opinion. According to the 

biological opinion, the Service determined that the proposed project was likely to directly 

affect the federally-listed vernal pool tadpole shrimp (Lepidurus packardi) and vernal 

pool fairy shrimp (Branchinecta lynchi), and permanently affect the giant garter snake 

(Thamnophis gigas). In the biological opinion, the Service discusses various 

conservation measures proposed by PG&E, and the biological opinion also specifies 

PG&E’s conservation responsibilities, including purchase of vernal pool preservation and 

creation credits at a Service-approved conservation bank and purchase of giant garter 

snake habitat credits from a mitigation bank approved by the Service and the California 

Department of Fish and Game. 
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The measures and conditions in the biological opinion that are necessary to minimize any 

likely adverse impacts may be contained in the federal permit that will be issued by the 

Army Corps, but the Army Corps has not yet issued its permit. EPA will proceed with 

the final permit issuance upon conclusion of our review of the Service’s biological 

opinion, actions taken or to be taken by the Army Corps, and our determination that 

issuance of the permit will be consistent with the ESA requirements. 

13 OTHER REQUIREMENTS 

The applicant must apply for and obtain an acid rain permit. The applicant will obtain 

this permit from the Colusa County Air Pollution Control District. 

14 CONCLUSION AND ACTION 

Based on the information supplied by the Applicant, and the evaluation provided above 

to determine if the project complies with PSD permitting requirements, EPA is proposing 

to issue the attached draft permit (PSD Permit number SAC 06-01). 

For questions or additional information regarding this project, contact Shaheerah Kelly at 

(415) 947-4156 or kelly.shaheerah@epa.gov. 

 

15 REFERENCES 

1. PSD Permit Application for the Colusa Generating Station, Prepared by URS 

Corporation, December 2006 

2 . “CALMET/CALPUFF Air Quality Modeling Impact Analysis for Far-Field Class 

I Areas for the Colusa Generating Project, Colusa, CA”, Prepared by URS 

Corporation, August 2007 

3. Supplemental information supporting the PSD permit application provided on 

behalf of the applicant for Colusa Generating Station Facility to EPA Region 9 

via email from URS Corporation (Mark Strehlow, et. al.) and Sierra Research 

(Gary Rubenstein, et al.) between December 2006 and April 2008 

4. “EPA Air Pollution Control Cost Manual - Sixth Edition”, EPA 452/B-02-001, 

January 2002 

5. RACT/BACT/LAER Clearinghouse - Technology Transfer Network, Clean Air 

Technology Center, http://cfpub.epa.gov/rblc/htm/bl02.cfm 
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Colusa Generating Station May 2008

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6. CARB Statewide Best Available Control Technology (BACT) Clearinghouse, 

http://www.arb.ca.gov/bact/bact.htm

7. EPA Memorandum from John Calcagni, Director, Air Quality Management 

Division, to Air Division Directors, Regions I-X, “Transmittal of Background 

Statement on ‘Top-Down’ Best Available Control Technology (BACT),” 

June 13, 1989 

8. Responses to Data Requests to the California Energy Commission, Application 

for Certification (06-AFC-9), Colusa Generating Station, Colusa County, 

California, Prepared for E&L Westcoast, LLC & URS, February 12, 2007 

9 . “Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) Phase 

I Report”, U.S. Forest Service, National Park Service, and U.S. Fish And Wildlife 

Service, December 2000 

10. “A Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, 

and Animals”, EPA-450/2-81-078, December 1980 

11. Letter (Biological Opinion) from Peter A. Cross, U. S. Department of the Interior 

(Fish and Wildlife Service), to Mr. Thomas J. Cavanaugh, U. S. Army Corps of 

Engineers, “Review of the Proposed Colusa Generating Station Project (Corps 

File Number 200600897), Colusa County, California, for Inclusion with the 

Vernal Pool Crustaceans Programmatic Consultation (Service file no. 1-1-96-F001), the Programmatic Consultation for the U. S. Army Corps of Engineers 404 

Permitted projects with Relatively Small Effects on the Giant Garter Snake 

(Service file no. 1-1-F-97-149)”, March 14, 2008 

12. EPA memorandum from John S. Seitz, Director Office of Air Quality Planning 

and Standards, to Regional Air Directors, “Interim Implementation of New 

Source Review for PM2.5,” October 23, 1997 

13. USFS letter from Randy Moore of U.S. Forest Service to Deborah Jordan of EPA, 

Region 9, dated April 25, 2008