# 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 2008Air Quality Impact Report Colusa Generating Station Page 2 of 47
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 .......................................................................................................................41Air Quality Impact Report Colusa Generating Station Page 3 of 47
May 2008 

### 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 .................................................................................................... 46Air Quality Impact Report Colusa Generating Station Page 4 of 47 May 2008 

### 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

μ g/m 3 

### 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

NH 3 

### Ammonia

NO 2 

### 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 compoundsAir Quality Impact Report Colusa Generating Station May 2008 Page 5 of 47 

### 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 Am bient 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 a nd 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 allAir Quality Impact Report 

### criteria pollutants, which include carbon monoxide (CO), nitrogen dioxide (NO 2 

### ), sulfur dioxide (SO 2 

### ), 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

Colusa Generating Station May 2008 Page 6 of 47Air Quality Impact Report Colusa Generating Station May 2008 Page 7 of 47 

### 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 (O 2 

### ).

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 cons ist 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 DC S; 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 engineer 1 

### for three load conditions (50, 75, and 100 percent) and three ambient te mperatures (18oF, 59oF, and 114oF). The

1 

### Bechtel Corporation is the engineer.

Colusa Generating Station May 2008 Page 8 of 47Air Quality Impact Report Colusa Generating Station May 2008 Page 9 of 47 

### 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

SO 2 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

SO 2 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

SO 2 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

NO X 20.7 19.6 19.0

SO 2 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 

### SO 2 

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

scf.Air Quality Impact Report Colusa Generating Station May 2008 Page 10 of 47 Table 5-2. Estimated Emission Rates Duri ng 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

NO X 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

SO 2 2.00 5.05 2.00 2.88 2.00 1.66 1.00 1.00

PM 10 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 Polluta nt Annual Emissions for the Turbines 3

, 4

Pollutant 1st Quarter Emissions (tons) 2nd Quarter Emissions (tons) 3rd Quarter Emissions (tons) 4th Quarter Emissions (tons) Annual Emissions (tons)

NO X 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

PM 10 35.1 35.2 35.4 35.5 141.2

SO 2 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 SO 2 

### emission rates were scaled up based on an annual average sulfur concentration of 0.3 grains/100 scf.Air Quality Impact Report Colusa Generating Station May 2008 Page 11 of 47 

### 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 SO

x 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

NO X controlled to 9 ppmvd @ 3 % O 2 0.0108 0.48 0.89 CO controlled to 50 ppmvd @ 3 % O 2 0.037 1.63 3.05

PM 10 0.0075 0.33 0.62

SO 2 0.0006 0.03 0.05 VOC controlled to 10 ppmvd @ 3 % O 2 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, SO

x 

### , and PM 10 

### from Table 5-1 adjusted to reflect one

turbine. CO and NO

x 

### 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 12 of 47 Table 5-6. Emissions for Gen erator and Firewater Pump Engine

Pollutant Generator 1340 brake horsepower (estimated) Firewater Pump 300 brake horsepower (estimated) Hourly Emissions (pounds per hour)

NO X 13.88 1.98*

CO 0.32 1.72

VOCs 0.15 0.000*

PM 10 0.09 0.10

SO 2 0.01 0.0030 Annual Emissions (tons per year)

NO X 0.347 0.050*

CO 0.008 0.043

VOCs 0.004 0.000*

PM 10 0.002 0.002

SO 2 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 Estimate d 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)

NO X 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

SO 2 4.47 4.19 4.23 4.23 17.12

(Source: December 2006 PSD application, Table 5-8)Air Quality Impact Report Colusa Generating Station May 2008 Page 13 of 47 

### 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

SO 2 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 Implemen tation of New Source Review for PM2.5” (October 23, 1997). (See http://www.epa.gov/Region7/programs/artd/air/nsr/nsrmemos/pm25.pdf )Air Quality Impact Report Colusa Generating Station May 2008 Page 14 of 47 

### 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).Air Quality Impact Report Colusa Generating Station May 2008 Page 15 of 47 

### 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 NO X 

### 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 NO X 

### 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 StationMay 2008Page 16 of 47Table 7-1. Recent NOx Determinations for Combustion Turbines/Duct Burners*FacilityLocationNOx LimitsAvg PeriodControlPermit DateSourceBlythe Energy LLC (Blythe II)California2.0 ppm3-hrSCR/DLNApr 2007PSD permitElk Hills PowerCalifornia2.5 ppm1-hrSCR/DLN orSCONOXJan 2006PSD permit modificationLa Paloma - PG&ECalifornia2.5 ppm1-hrSCRDec 2004PSD permit modificationLos Esteros - CalpineCalifornia2.0 ppm1-hrSCR & water injectionMar 2005Local construction permit(PDOC)Los Medanos - CalpineCalifornia2.5ppm1-hrSCR11/9/2004Title V permitPalomar Escondido - SempraCalifornia2.0 ppm3-hr when duct burnersfiring or transient periods;1-hr all other timesSCR/DLNDec 2002Final Determination ofCompliancePastoria Energy LLCCalifornia2.5 ppm1-hrSCR/DLN or XONONDec 2004PSD permitSan Joaquin Valley Energy CenterCalifornia2.0 ppm1-hrSCR/DLNAug 2006PSD permitMountainview Power CompanyCalifornia2.0ppm1-hrSCR2005PSD permit modificationSacramento Municipal Utility DistrictCalifornia2.0 ppm1-hrSCR--CARB BACT DatabaseThree Mountain PowerCalifornia2.5 ppm1-hrSCR10/10/2003CARB BACT DatabaseWestern Midway SunsetCalifornia2.0 ppm1-hrSCR12/12/.2003CARB BACT DatabaseMagnolia Power ProjectCalifornia2.0 ppm3-hrSCR5/27/2003CARB BACT Database6.0 ppm (applies btw May 1through Sept 30 each year)McDonough Combined-CycleGenerating UnitsGeorgia15 ppm30-day rolling avgSCR/Low NOx burners1/7/2008(Effectivedate)Title V/Part 70 OperatingPermit Amendment(non-PSD)Rocky Mountain Energy CenterColorado3.0 ppmHourlySCR/Low NOx burners5/2/2006RBLC # CO-0056PSO Southwestern Power PlantOklahoma9.0 ppm--DLN2/9/2007RBLC # OK-0117Sierra Pacific Power CompanyNevada2.0 ppm3-hrSCR8/16/2005RBLC # NV-0035Wanapa Energy CenterOregon2.0 ppm3-hrSCR/DLN8/8/2005RBLC # OR-0041Crescent City Power, LLCLouisiana3.0 ppmAnnualSCR/Low NOx burners6/6/2005RBLC # LA-0192Berrien Energy, LLCMichigan2.5 ppm24-hrSCR/DLN4/13/2005RBLC # MI-0366Turner Energy Center, LLCOregon2.0 ppm1-hrSCR1/6/2005RBLC # OR-0046Florida Power and Light – Turkey PointFlorida2.0 ppm3-run stack test;24-hr for CEMsDLN/SCR(natural gas-fired)2/8/2005PSD permit &RBLC # FL-0263BP Cherry Point CogenerationWashington2.5ppm3-hrSCR/DLN1/11/20052004 final PSD permit &RBLC # WA-0328ANP BlackstoneMassachusetts2.0 ppm, loads >50%; 3.5ppmvd, loads >100% +steam augmentation1-hrSCR4/16/1999(PSD permit)2005 final Title V permit(conditions from PSDpermit) & RBLC # MA0024(* ppm values are corrected to 15 percent O2)Air Quality Impact ReportAir Quality Impact Report Colusa Generating Station May 2008 Page 17 of 47 

### 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 cons ists 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, excludi ng 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 StationMay 2008Page 18 of 47Table 7-2. Recent CO & VOC Determinations for Combustion Turbines/Duct Burners *FacilityLocationCO LimitsAvg PeriodVOC LimitsAvgPeriodEmission ControlPermit DateSource of InformationBlythe Energy LLC (Blythe II)California4.0 ppm3-hr------Apr 2007PSD permitElk Hills PowerCalifornia4.0 ppm3-hr----SCR/DLN or SCONOXJan 2006PSD permit modificationLa Paloma - PG&ECalifornia6.0 ppm (10 ppm forloads below 221 MW)3-hr----Oxidation catalystDec 2004PSD permitLos Esteros Energy CenterCalifornia9.0 ppm3-hr2.0 ppm3-hrOxidation catalystMar 2005Local construction permit(PDOC)Los Medanos Energy CenterCalifornia6.0 ppm3-hr0.0017 lb/mmbtu--Oxidation catalyst11/9/2004Title V permitPalomar Escondido - SempraCalifornia4.0 ppm3-hr2.0 ppm3-hrOxidation catalystDec 2002Local construction permit(FDOC)Pastoria Energy LLCCalifornia9.0 ppm3-hr----SCR/DLN or XONONDec 2004PSD permitSan Joaquin Valley Energy CenterCalifornia4.0ppm1-hr----Oxidation catalystAug 2006PSD permitMountainview Power CompanyCalifornia----------2005PSD permit modificationSacramento Municipal Utility DistrictCalifornia4.0 ppm3-hr1.4 ppm3-hr----CARB BACT DatabaseThree Mountain PowerCalifornia4.0 ppm3-hr2.0 ppm1-hrOxidation catalyst10/10/2003CARB BACT DatabaseWestern Midway SunsetCalifornia4.0 ppm3-hr1.4 ppm3-hrOxidationcatalyst12/12/2003CARB BACT DatabaseMagnolia Power ProjectCalifornia2.0 ppm1-hr2.0 ppm1-hrOxidationcatalyst5/27/2003CARB BACT Database1.8 w/ DBMcDonough Combined-CycleGenerating UnitsGeorgia1.8ppm3-hr1.0 w/o DB3-hrOxidation catalyst1/7/2008(Effective date)Title V/Part 70 OperatingPermit AmendmentRocky Mountain Energy CenterColorado3.0 ppm--0.0029 lb/MMBtu--Oxidation catalyst &good combustion5/2/2006RBLC # CO-0056PSO Southwestern Power PlantOklahoma25.0 ppm------Combustion control2/9/2007RBLC # OK-0117Sierra Pacific Power CompanyNevada3.5 ppm3-hr4.0 ppm3-hrOxidation catalyst8/16/2005RBLC # NV-0035Wanapa Energy CenterOregon2.0 ppm3-hr----Oxidation catalyst8/8/2005RBLC # OR-0041Crescent City Power, LLCLouisiana4.0 ppmAnnual1.1 ppmAnnualOxidation catalyst& good combustion6/6/2005RBLC # LA-0192Berrien Energy, LLCMichigan2.0 ppm3-hr3.2 lb/hr--Oxidation catalyst4/13/2005RBLC # MI-0366Turner Energy Center, LLCOregon2.0 ppm at >70% load;3.0 ppm at <70% load3-hr1.0 ppm3-hrOxidation catalyst1/6/2005RBLC # OR-00464.1 ppm CT normal7.6 ppm CT + DBStack test3-run avgFlorida Power and Light – TurkeyPointFlorida8.0 ppm24-hr block avg1.3 ppm CT, normal1.9 ppm CT + DB--Good combustion2/8/2005PSD permit &RBLC # FL-0263BP Cherry Point CogenerationWashington2.0 ppm3-hr3.0 lb/hr24-hrOxidation catalyst1/11/2005PSD permit & RBLC # WA-0328ANP BlackstoneMassachusetts3.0 ppm1-hr1.4 ppm1-hrOxidation catalyst4/16/1999(PSD permit)2005 final Title V permit (PSDConditions) &RBLC # MA-0024(* ppm values are corrected to 15 percent O2)Air Quality Impact ReportAir Quality Impact Report Colusa Generating Station May 2008 Page 19 of 47 

### 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 SO 2 

### 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 stea dy-state operation, which are not technically feasible during startup and shutdown of the CT s. 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. Ta ble 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 20 of 47 Table 7-3. Proposed Startup and Shutdo wn 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 NO

x 

### 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 ReportColusa Generating StationMay 2008Page 21 of 47Table 7-4. Recent NOx Determinations for Natural Gas-FiredAuxiliary Boilers*FacilityLocationSize(MMBtu/hr)NOx LimitsControl MethodPermit DateSource ofInformationLos MedanosCalifornia3209 ppmSCR/oxidation catalyst11/9/2004Title V permitSan Joaquin Valley EnergyCenterCalifornia1609 ppm--Aug 2006PSD permitLA County Internal ServicesDept.California399ppmUltra-Low NOx burner withFlue Gas Recirculation (FGR)10/8/2002CARB BACTClearinghouseGenentech, IncCalifornia979 ppmUltra-Low NOx burners9/27/2005CARB BACTClearinghouseMcDonough Combined-CycleGenerating UnitsGeorgia20(3 aux boilers; each auxboiler limited to 175,200MMBtu/yr)30 ppmLow NOx burners & FGR1/7/2008(Effective date)Title V/Part 70Operating PermitAmendmentLa Paz Generating FacilityArizona41 (aux boiler for GEturbine)0.027 lb/MMBtuLow NOx burners9/4/2003RBLC # AZ-0049Genova Arkansas I, LLCArkansas330.04 lb/MMBtuLow NOx burners &/or FGR8/23/2002RBLC # AR-0070Barton Shoals Energy LLCAlabama40 (2 boilers)0.05 lb/MMBtuLow NOx burners7/12/2002RBLC # AL-0185Clovis Energy FacilityNew Mexico33 (2 boilers, limits applyseparately)0.036 lb/MMBtuGood combustion6/27/2002RBLC # NM-0044Genova Oklahoma LLCOklahoma330.035 lb/MMBtuLow NOx burners6/13/2002RBLC # OK-0070Thunderbird Generation LLCOklahoma200.049 lb/MMBtuLow NOx burners5/17/2001RBLC # OK-0046Cabot Power CorporationMassachusetts26.60.04 lb/MMBtuSCR, Dry Low NOx combustor5/7/2000RBLC # MA-0027McClain Energy FacilityOklahoma220.035 lb/MMBtuCombustion control1/19/2000RBLC # OK-0041Beatrice Power StationNebraska73.3 (natural gas)0.050 lb/MMBtuOperationlimited to 500 hrs/yr.6/22/2004RBLC # NE-0023Copper Mountain PowerNevada600.035lb/MMBtuUltra-Low NOx burner witheither internal or external FGR5/14/2004RBLC # NV-0037Rincon Power Plant CGeorgia830.055 lb/MMBtuOperation limited to 1000hrs/yr.3/24/2003RBLC # GA-0098Emery Generating StationIowa680.049 lb/MMBtuDLN12/20/2002RBLC # IA-0062Competitive Power Venture,CPV Cunningham PlantVirginia800.050lb/MMBtuLow NOx burners, goodcombustion9/6/2002RBLC # VA-0261Greater Des Moines EnergyCenterIowa680.050 lb/MMBtu--4/10/2002RBLC # IA-0058Fremont Energy Center LLCOhio800.034 lb/MMBtu(calculated)Low NOx burners8/9/2001RBLC # OH-0263(* ppm values are corrected to 3 percent O2)Air QualityAir Quality Impact Report Colusa Generating Station May 2008 Page 22 of 47 

### 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 ReportColusa Generating StationMay 2008Page 23 of 47Table 7-5. Recent CO & VOC Determinations for Natural Gas-FiredAuxiliary Boilers*FacilityLocationSize(MMBtu/hr)CO LimitsVOC LimitsControlMethodPermit DateSource ofInformationLos MedanosCalifornia32050 ppm1.7 lb/hrOxidation catalyst2004Title V permitSan Joaquin Valley Energy CenterCalifornia16050 ppm----Aug 2006PSD permitLA County Internal Services Dept.California39100 ppm----10/8/2002CARB BACTClearinghouseGenentech, IncCalifornia9750 ppm----9/27/2005CARB BACTClearinghouseMcDonough Combined-CycleGenerating UnitsGeorgia20(3 aux boilers; each auxboiler limited to 175,200MMBtu/yr)0.037 lb/MMBtu0.0051 lb/MMBtu1/7/2008(Effective date)Title V/Part 70Operating PermitAmendmentTurner Energy Center, LLCOregon4,179,040 mmbtu/yr, 3000hr/yr0.038 lb/MMBtu0.0044 lb/MMBtuOxidation catalyst1/6/2005RBLC # OR-0046Dome Valley Energy PartnersArizona380.080lb/MMBtu0.003 lb/MMBtu--12/1/2005RBLC # AZ-0047South Point Biomass GenerationOhio247(nat gas)0.110 lb/MMBtu0.004 lb/MMBtu--4/4/2006RBLC # OH-0307La Paz Generating FacilityArizona41(aux boiler for GE turbine)0.09 lb/MMBtu0.01 lb/MMBtu--9/4/2003RBLC # AZ-0049Genova Arkansas I, LLCArkansas330.04 lb/MMBtu--Good combustion8/23/2002RBLC # AR-0070Barton Shoals Energy LLCAlabama40(2 boilers)0.082 lb/MMBtu0.0054 lb/MMBtuGood combustion7/12/2002RBLC # AL-0185Clovis Energy FacilityNew Mexico33(2 boilers, limits applyseparately)0.07 lb/MMBtu0.5 lb/hrClean fuel/ goodcombustion6/27/2002RBLC # NM-0044Genova Oklahoma LLCOklahoma330.037 lb/MMBtu0.016 lb/MMBtuGood combustion6/13/2002RBLC # OK-0070Copper Mountain PowerNevada600.08 lb/MMBtu0.4 lb/hrEffectivecombustiondesign5/14/2004RBLC # NV-0037Rincon Power PlantGeorgia830.093 lb/MMBtu0.004 lb/MMBtu--3/24/2003RBLC # GA-0098Emery Generating StationIowa680.0164 lb/MMBtu0.0054 lb/MMBtuCatalyticoxidation12/20/2002RBLC # IA-0062Greater Des Moines EnergyCenterIowa680.084 lb/MMBtu----4/10/2002RBLC # IA-0058(* ppm values are corrected to 3 percent O2)Air QualityAir Quality Impact Report Colusa Generating Station May 2008 Page 24 of 47 

### 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 SO 2 

### 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 Page 25 of 47 

### 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 SO 2 

### even though the proposed facility’s emission

increases for SO 2 

### 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 advers ely 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.Air Quality Impact Report 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 Rate s 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 conjunctionAir 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 theMM5 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, SO 2 

### 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/m 3 ) 2.5 0.00053 0.00045 0.00076 0.00058 0.00173

3-hr SO 2 (μg/m 3 ) 25 0.01886 0.02824 0.02670 0.01752 0.05732

24-hr SO 2 (μg/m 3 ) 5 0.00433 0.00870 0.00540 0.00428 0.01254

Annual SO 2

(μg/m 3 ) 2 0.00022 0.00016 0.00029 0.00023 0.00038

24-hr PM (μg/m 3 ) 8 0.02485 0.04298 0.02894 0.02450 0.05813 Class I

Increments

Annual PM (μg/m 3 ) 4 0.00139 0.0112 0.00172 0.00140 0.00183

Total Nitrogen (g/m 2 /s) 1.59E-11 1.1963E-12 5.7242E-13 1.5486E-12 1.2028E-12 1.6869E-12 Deposition Total Sulfur (g/m 2 /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 em ail 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 Page 29 of 47 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/m 3 ) 2.5 0.00053 0.00033 0.00096 0.00065 0.00148

3-hr SO 2 (μg/m 3 ) 25 0.01632 0.01001 0.02972 0.01652 0.06444

24-hr SO 2 (μg/m 3 ) 5 0.00386 0.00234 0.00541 0.00387 0.01663

Annual SO 2

(μg/m 3 ) 2 0.00023 0.00013 0.00035 0.00025 0.00033

24-hr PM (μg/m 3 ) 8 0.02152 0.01841 0.02792 0.02044 0.08766 Class I

Increments

Annual PM (μg/m 3 ) 4 0.00144 0.00098 0.00198 0.00146 0.00171

Total Nitrogen

Deposition

(g/m 2 /s) 1.59E-11 1.3388E-12 5.5670E-13 2.1672E-12 1.5717E-12 1.1880E-12
Deposition Total Sulfur Deposition

(g/m 2 /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 em ail 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/m 3 ) 2.5 0.00077 0.00033 0.00108 0.00079 0.00220

3-hr SO 2 (μg/m 3 ) 25 0.02868 0.01022 0.02896 0.01662 0.07118

24-hr SO 2 (μg/m 3 ) 5 0.00495 0.00331 0.00705 0.00390 0.01468

Annual SO 2

(μg/m 3 ) 2 0.00028 0.00013 0.00039 0.00030 0.00048

24-hr PM (μg/m 3 ) 8 0.02584 0.02304 0.03320 0.02003 0.06869 Class I

Increments

Annual PM (μg/m 3 ) 4 0.00166 0.00097 0.00222 0.00174 0.00243

Total Nitrogen

Deposition

(g/m 2 /s) 1.59E-11 1.5007E-12 5.4074E-13 2.0987E-12 1.5950E-12 2.1042E-12
Deposition Total Sulfur Deposition

(g/m 2 /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 em ail from URS Corporation)Air Quality Impact Report Colusa Generating Station May 2008 Page 30 of 47 

### 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 NO 2 

### ), PM10 (which is used as a surrogate for PM2.5), CO and ozone. Alt hough 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 31 of 47 

### 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, NO 2 

### , SO 2 

### , 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 NO 2 

### , 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: AERM OD (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 ofAir Quality Impact Report Colusa Generating Station May 2008 Page 32 of 47 

### 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 appli cant used structures from the layout for the proposed project in the analysis and included the results of this analysis in the AERMODinput 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 33 of 47 

### • 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 th eir Maxwell meteorological station. The meteorological station is outside the to wn 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 gridAir Quality Impact Report Colusa Generating Station May 2008 Page 34 of 47 

### • 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,Air Quality Impact Report Colusa Generating Station May 2008 Page 35 of 47 

### 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 μ g/m 3

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 th e 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 NO 2 

### 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 36 of 47 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 NO 2 

### from the turbine/HRSG equal the annual emission estimates (see Table 5-3). Includes 50 hours of each fire pump and emergency generator a nd 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 ( μ g/m 3 ) PSD Significant Impact Level ( μ g/m 3 ) Background ( μ g/m 3 ) Total Predicted

Concentration ( μ g/m 3 )

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

NO 2 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)Air Quality Impact Report Colusa Generating Station May 2008 Page 37 of 47 

### 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 SO 2 

### (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 SO 2 

### , and February 8, 1988 for NO 2 

### 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 NO 2 

### , for Colusa County, California. Thus, after this date, all minor

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

and NO 2



### .

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.Air Quality Impact Report Colusa Generating Station May 2008 Page 38 of 47 

### 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 NO 2 

### 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 μ g/m 3 

### , which is above the significant modeling concentration of 5 μ g/m 3 

### . 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/m 3



### .

Table 9-6. Class II Increment Analysis

Pollutant Averaging

Period Maximum Modeled

Concentration from the Proposed Project ( μ g/m 3 ) Significant Modeling

Concentration ( μ g/m 3 ) 14 PSD Class II

Increment

( μ g/m 3 )

NO 2 Annual 0.64 1 25

PM10 15 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 μ g/m 3 

### on a 24-hour basis is significant.

15 

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

PM2.5.Air Quality Impact Report Colusa Generating Station May 2008 Page 39 of 47 

### in Glenn County and about 20 km N of CG S) 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, NO 2 

### and PM10 from proposed project, when combined with the background ambient air quality, are below the NAAQS for these pollutants. Therefore, the proposed project w ill not cause or contribute to a violation of the NAAQS.

Table 9-7. NAAQS Impacts Analysis

Pollutant Averaging

Period Maximum

Modeled

Concentration ( μ g/m 3 ) Maximum Background

Concentration ( μ g/m 3 ) Total

Concentration ( μ g/m 3 ) NAAQS ( μ g/m 3 ) Monitoring

De Minimus

Concentrations ( μ g/m 3 )

NO 2 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..Air Quality Impact Report Colusa Generating Station May 2008 Page 40 of 47 

### 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/m 3 ) Modeled maximum (μg/m 3 ) Model averaging

time used

1-hr 917 4.4 1 hour

3-hr 786 1.85 3 hour SO 2 Annual 18 0.04 annual

4-hr 3,760 336.5 1 hour

1-month 564 336.5 1 hour NO 2 Annual 94 0.64 annual

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



### The applicant analyzed the potential effects of NO 2 

### and, although not required, SO 2 

### . The applicant modeled the maximum annual NO 2 

### impacts from normal plant operations using CALPUFF, as well as estimates of total nitrogen deposition estimated byAir Quality Impact Report Colusa Generating Station May 2008 Page 41 of 47 

### CALPUFF. Although, the emissions increases of SO 2 

### would be below the significance threshold, the applicant considered SO 2 

### 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

SO 2 Annual 8 ppbv 0.0004 ppbv (0.001 μ g/m 3 )

SO 2 Hourly 40 ppbv 0.012 ppbv (0.031 μ g/m 3 )

NO 2 Annual 15 ppbv 0.0043 ppbv (0.008 μ g/m 3 )

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 μ g/m 3 

### annual average for NO 2 

### and 4.35 μ g/m 3


### 24-hour average and 0.5 μ g/m 3 

### annual average for PM10 concentrations from this project are below the secondary NAAQS for NO 2 

### (100 μ g/m 3 

### annual average) and PM10 (5

μ g/m 3 

### 24-hour average and 1 μ g/m 3 

### annual average). Therefore, no harmful effects of

NO 2 

### 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’sAir Quality Impact Report Colusa Generating Station May 2008 Page 42 of 47 

### “Workbook for Plume Visual Impact Screeni ng 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 Burners 16

Pollutant BACT Requirements PSD Increments and NAAQS Requirements

NOx • 2.0 ppmvd, 1-hr average, corrected to 15 % O 2 , 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 % O 2 , 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 % O 2 , 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 appl y 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 43 of 47 Table 11-2. Auxiliary Boiler

Pollutant BACT Requirements PSD Increments and NAAQS Requirements

NOx • 9 ppmvd, 3-hr average, corrected to 3% O 2

• 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% O 2 ;

• 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 44 of 47 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 NO 2 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 45 of 47 

### 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 ArmyCorps 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, a nd 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.Air Quality Impact Report Colusa Generating Station May 2008 Page 46 of 47 

### 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 St rehlow, 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 - Tec hnology Transfer Network, Clean Air Technology Center, http://cfpub.epa.gov/rblc/htm/bl02.cfmAir Quality Impact Report Colusa Generating Station May 2008 Page 47 of 47 

### 6. CARB Statewide Best Available Cont rol 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. Cr oss, 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 Colu sa Generating Station Project (Corps File Number 200600897), Colusa County, California, for Inclusion with theVernal 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, Dir ector 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