Prepared for: Prepared by: 

City of Palmdale & AECOM 

Inland Energy Camarillo, CA 

 60138827 

June 2010

Environment 

Palmdale Hybrid Power Project

PSD Application, Supplemental Information 
Prepared for: Prepared by: 

City of Palmdale & AECOM 

Inland Energy Camarillo, CA 

 60138827 

June 2010

Environment 

Palmdale Hybrid Power Project

PSD Application, Supplemental Information 

Prepared By Russell Kingsley 

Reviewed By Sara J. Head 
AECOM Environment i 

Contents 

1.0 Introduction ...................................................................................................................... 1-1

1.1 Project Overview .................................................................................................................. 1-2

1.2 Project Application History ................................................................................................... 1-2

1.3 Application Contacts ............................................................................................................ 1-3

1.4 Responsible Official Certification ......................................................................................... 1-3

2.0 PM2.5 Modeling Analyses .............................................................................................. 2-1

2.1 PM2.5 Cumulative Modeling Analysis ................................................................................. 2-1

2.1.1 History and Choice of Facilities to be Included in PM2.5 Cumulative Analysis .. 2-1

2.1.2 Characterization of Modeled Non-PHPP Sources ............................................... 2-2

2.1.3 Modeling Methodology ......................................................................................... 2-8

2.1.4 Results and Discussion ........................................................................................ 2-9

2.2 PM2.5 Increment Analysis ................................................................................................. 2-11

2.3 References for Section 2 ................................................................................................... 2-11

3.0 1-Hour NO2 NAAQS Modeling ........................................................................................ 3-1

3.1 Regulatory Background ....................................................................................................... 3-1

3.2 Modeling Methodology ........................................................................................................ 3-1

3.2.1 Normal Operations ................................................................................................ 3-2

3.2.2 Startup and Shutdown Analysis ........................................................................... 3-2

3.3 Summary of Results ............................................................................................................ 3-3

4.0 Visibility Analysis ............................................................................................................ 4-1

5.0 Soils and Vegetation Analysis ....................................................................................... 5-1

5.1 Regulatory Overview and Background ............................................................................... 5-1

5.2 Extent of the Analysis .......................................................................................................... 5-2

5.3 Vegetation Types ................................................................................................................. 5-2

5.4 Soils ...................................................................................................................................... 5-4

5.4.1 Soil Types .............................................................................................................. 5-4

5.4.2 Nitrogen Deposition .............................................................................................. 5-4

5.5 References for Section 5 ..................................................................................................... 5-6

6.0 Receptor Grid Evaluation ............................................................................................... 6-1
AECOM Environment ii 

7.0 Growth Analysis .............................................................................................................. 7-1

7.1 Summary of Growth Inducing Impacts Associated with Employment ............................... 7-1

7.1.1 Construction Phase Population and Housing Impacts ........................................ 7-1

7.1.2 Operation Phase Population and Housing Impacts ............................................. 7-1

7.2 Growth Inducing Impacts Associated with the Provision of Electric Power Generation ... 7-2

7.3 References for Section 7 ..................................................................................................... 7-4

8.0 Supplemental BACT Analysis ....................................................................................... 8-1

8.1 Methodology ......................................................................................................................... 8-1

8.2 Supplemental BACT for Combustion Turbines ................................................................... 8-2

8.2.1 Evaluation of Add-on Particulate Controls for the Combustion Turbines and 

HRSG .................................................................................................................... 8-2

8.2.2 BACT for CO Emissions from the Combustion Turbines and HRSGs ............. 8-10

8.3 BACT Determination for Boilers and HTF Heaters ........................................................... 8-11

8.3.1 NOx ..................................................................................................................... 8-12

8.3.2 CO and VOC ....................................................................................................... 8-13

8.3.3 PM, PM10 and PM2.5 ........................................................................................ 8-14

8.3.4 Summary of Proposed BACT for Boiler and HTF Heater ................................. 8-16

8.4 Add-on NOx Controls for Emergency Diesel Generator and Fire Water Pump Engine . 8-17

8.5 References for Section 8 ................................................................................................... 8-20

List of Appendices 

Appendix A Electronic Archive of Modeling Files

Appendix B Summary of BACT Evaluations

Appendix C Preliminary Cost Effectiveness Calculation
AECOM Environment iii 

List of Tables 

Table 2-1 Lockheed Martin Aeronautics Sources .................................................................................... 2-5

Table 2-2 Northrop Grumman Sources .................................................................................................... 2-6

Table 2-3 Granite Rock Construction Sources ......................................................................................... 2-7

Table 2-4 Robertson’s Ready Mix Sources .............................................................................................. 2-7

Table 2-5 Ambient PM2.5 Background Concentrations at 43301 Division St. Lancaster ...................... 2-9

Table 2-6 PHPP Cumulative PM2.5 Modeling Results .......................................................................... 2-10

Table 4-1 Class II Areas Included in VISCREEN Analysis ...................................................................... 4-2

Table 4-2 Dispersion Condition Frequency Analysis – Sheep Mountain Wilderness Area .................... 4-5

Table 4-3 Dispersion Condition Frequency Analysis – Saddleback Butte State Park ............................ 4-6

Table 4-4 Dispersion Condition Frequency Analysis – Antelope Valley Indian Museum SP ................. 4-7

Table 4-5 Dispersion Condition Frequency Analysis – Antelope Valley California Poppy State 

Reserve .............................................................................................................................. 4-8

Table 4-6 Dispersion Condition Frequency Analysis – Arthur B. Ripley Desert Woodland ................... 4-9

Table 4-7 VISCREEN Model Results – All Hours .................................................................................. 4-10

Table 4-8 VISCREEN Model Results – Daytime Hours (6 am – 6 pm) ................................................ 4-11

Table 6-1 Maximum Combustion Turbine Impacts per Unit Emission Within 20 km of PHPP .............. 6-1

Table 6-2 Maximum Combustion Turbine Impacts per Unit Emission More Than 20 km of PHPP ....... 6-2

Table 6-3 Comparison of Maximum Modeled Impacts, Within 20 km vs. 20 to 50 km .......................... 6-2

Table 8-1 Cost Effectiveness for PM10 ..................................................................................................... 8-8

Table 8-2 Estimated Costs for PM Controls1............................................................................................ 8-9

Table 8-3 Combustion Turbine Cost Effectiveness and Degree of Control ............................................ 8-9

Table 8-4 Boiler and Heater Cost Effectiveness and Degree of Control ............................................... 8-16

Table 8-5 Proposed BACT for the Boiler and HTF Heater .................................................................... 8-16

Table 8-6 Cost of SCR Control Per Ton of NOx Removed ................................................................... 8-18

Table 8-7 Cost of NOx Adsorbers and CDPF Control for Emergency Engines .................................... 8-19

List of Figures 

Figure 2-1 Relative Location of PHPP, Non-Project Sources, and Division Street Monitor ................... 2-3

Figure 2-2 Lockheed Martin and Northrop Grumman Sources included in the Modeling Analysis ....... 2-4

Figure 2-3 Receptor Grid Used in PM2.5 Cumulative Modeling Analysis ............................................ 2-12

Figure 4-1 Areas Included in the Visibility Analyses ................................................................................ 4-3
AECOM Environment 1-1

1.0 Introduction 

On April 1, 2009, an application for a Prevention of Significant Deterioration (PSD) permit was 

submitted to U.S. Environmental Protection Agency (EPA) Region 9 for the Palmdale Hybrid Power 

Project (PHPP). During a conference call on March 14, 2010, EPA identified a number of additional 

analyses that were indicated as necessary to deem the PSD application complete, as well as other 

items that were requested. The additional analyses that EPA requested are as follows: 

1. An expanded cumulative fine particulate matter (PM2.5) impact analysis to demonstrate 

compliance with the National Ambient Air Quality Standard (NAAQS). The EPA also 

requested additional analysis regarding the potential applicability of PM2.5 increment 

thresholds proposed in the Federal Register on September 21, 2007; 

2. A 1-hour Nitrogen Dioxide (NO2) NAAQS modeling analysis; 

3. An expanded Soils and Vegetation analysis based on the Environmental Appeals Board case 

In re: Indeck-Elwood, LLC; PSD Appeal No. 03-04; PSD Permit No. 197035AAJ (decided 

September 27, 2006); 

4. A Visibility analysis at local sensitive state or federal Class II areas; 

5. Additional justification/documentation that the receptor grids used in the PSD modeling 

analysis out to 20 kilometers (km) are sufficient to identify the maximum impacts; and 

6. A more detailed growth analysis than was submitted with the PSD application. 

In addition to the above items, the EPA requested the following items that were not “completeness” 

items, but which would expedite the issuance of the permit: 

7. Additional detail regarding the Best Available Control Technology (BACT) analysis that 

evaluates all potential control technologies using a top-down approach to address each of the 

following specific source/control combinations: 

a. Electrostatic Precipitator (ESP), baghouses, and cyclones on gas turbines, 

b. Selective Catalytic Reduction (SCR) on fire water pumps or other internal combustion 

engines, 

c. A range of control options for the Project boilers, and 

d. Reconsideration of the emission limit for carbon monoxide (CO) emissions, with and 

without duct burners. 

8. Provide any lists that the Applicant has developed for notifications, including any Indian tribes. 

All of the above items except for item 8 are addressed in this Supplemental filing. The Applicant does 

not have additional mailing lists, and it is recommended that EPA obtain any updates for mailing lists 

from the California Energy Commission. 
AECOM Environment 1-2

1.1 Project Overview 

The PHPP is designed to use solar technology to generate a portion of the project’s output and 

thereby support the State of California’s goal of increasing the percentage of renewable energy 

supplies. Primary equipment for the generating facility will include two General Electric (GE) Frame 

7FA natural gas-fired combustion turbine-generators (CTGs) rated at 154 megawatt (MW) each, two 

heat recovery steam generators (HRSGs) each rated at 169 MW, one steam turbine generator (STG) 

rated at 267 MW, and 251 acres of parabolic solar-thermal collectors with associated heat-transfer 

equipment. The 251-acre solar field would consist of parabolic solar-thermal collectors and associated 

heat transfer equipment arranged in rows. The proposed PHPP will have a nominal electrical output of 

570 MW. 

PHPP is designed for base load and peaking operations, with capability for rapid startup, shut-down, 

and load regulations, and to provide ancillary services. Compared to most other combined-cycle 

power plants, PHPP will be able to start-up in about half the time of other similar technologies as a 

result of GE’s Rapid Start Process. Annual availability of the PHPP is expected to be in the range of 

90 to 95 percent. During daylight periods when the solar collectors are in use, the solar field will 

provide heat directly to the HRSGs to produce steam, allowing the facility to reduce use of natural gas, 

and contributing up to 50 MW of generation from the STG. 

Air emissions from the combustion of natural gas in the CTGs and duct burners of the HRSGs would 

be controlled using BACT. Oxides of nitrogen (NOx) emissions from the CTGs would be controlled by 

dry low-NOx combustors followed by a selective catalytic reduction (SCR) system in the HRSGs. An 

oxidation catalyst located within each HRSG would control CO and volatile organic compounds (VOC) 

emissions. 

As indicated in the PSD Application submitted in April 2009, PHPP is projected to be a major source 

(i.e., have a potential to emit greater than 100 tons per year [tpy]) of NOx, VOC, CO, and total, 

respirable and fine particulate matter (PM/PM10/PM2.5). The Project will be a minor source of sulfur 

dioxide (SO2), lead and other PSD-regulated pollutants, and hence these minor pollutants are not 

addressed further in this Supplement. 

1.2 Project Application History 

Besides the PSD Application submitted to the EPA in April 2009, applications were submitted to the 

California Energy Commission (CEC) and Antelope Valley Air Quality Management District 

(AVAQMD) in July 2008. The AVAQMD issued a Preliminary Determination of Compliance (PDOC) in 

February 2009, a Revised PDOC in June 2009, and a Final DOC in May 2010. A Preliminary Staff 

Assessment (PSA) was issued by the CEC in two parts, the first in December 2009 and the part that 

addressed air quality in February 2010. 

AECOM Environment 2-1

2.0 PM2.5 Modeling Analyses 

As noted in Section 1, EPA requested two analyses with respect to PM2.5 that are addressed in this 

section: 

• A more extensive PM2.5 cumulative NAAQS analysis; and 

• An analysis regarding the potential applicability of PM2.5 increment thresholds proposed in the 

Federal Register on September 21, 2007. 

2.1 PM2.5 Cumulative Modeling Analysis 

As part of their review of the PHPP PSD application submitted on April 1, 2009, EPA requested that the 

cumulative PM2.5 modeling analysis to determine compliance with the PM2.5 NAAQS that was included in 

the PSD Application be extended to include additional facilities. The details of that analysis are contained in 

this section, including the following information: 

• Facilities included in the modeling; 

• Sources included for each of the chosen facilities; 

• Modeling methodology and analysis; and 

• Discussion of results. 

As shown in the modeling results, PHPP impacts, when modeled cumulatively with nearby major sources 

and with appropriate ambient background values added, show compliance with all applicable NAAQS and 

California Ambient Air Quality Standards (CAAQS) for PM2.5. 

2.1.1 History and Choice of Facilities to be Included in PM2.5 Cumulative Analysis 

The PHPP PSD Application submitted on April 1, 2009 contained a cumulative PM2.5 analysis which 

included other nearby (i.e., U.S. Air Force [USAF] Plant 42) sources of PM2.5 emissions. The USAF Plant 

42 sources were the only ones that the AVAQMD had recommended be included for the cumulative 

modeling analysis for PM10/PM2.5. However, EPA requested that this cumulative analysis be expanded to 

include additional sources up to 50 km from the PM10 Significant Impact Area (SIA) from the power plant 

site. Since modeling had determined that the PM10 24-hour impacts fell to less than the Significant Impact 

Level (SIL) within 400 meters of the PHPP, an area of 51 km was used to assess the cumulative PM2.5 

impacts. 

For the purpose of this analysis, the sources considered (beside the ones in the immediate vicinity of the 

PHPP that were previously included) were major sources (i.e., >80 tpy of actual PM emissions) that were 

expected to have a sufficient emissions gradient to contribute cumulatively to the modeled PHPP impacts. 

Therefore, an inventory of PM emission sources with emissions greater than 80 tpy was requested from the 

AVAQMD on March 25, 2010. Mr. Chris Anderson, permit engineer with the AVAQMD, forwarded the 

request to the Mojave Desert Air Quality Management District (MDAQMD), Kern County Air Pollution 

Control District (KCAPCD) and South Coast Air Quality Management District (SCAQMD). Richard Wales of 

MDAQMD and Glen Stephens of KCAPCD responded quickly for their respective agencies that there were 

no facilities with annual PM emissions of more than 80 tpy within 51 km of PHPP in their district. After 

submitting additional information and follow-up requests over the following months, Lisa Ramos of 

SCAQMD indicated that there were not any sources meeting these criteria within the SCAQMD as well. 
AECOM Environment 2-2

Chris Anderson initially identified two additional (beside the USAF Plant 42 sources previously included) 

facilities in the AVAQMD as candidates for inclusion in the modeling analysis, Granite Construction 

Company and Service Rock Products, now known as Robertson’s Ready Mix. Although Granite 

Construction Company’s emissions have dropped to less than 80 tpy, this source was still included in the 

revised PM2.5 modeling to be conservative. Additionally, because they were included in the prior PSD 

Application (March 2009), and because of their close proximity to the project site, Lockheed Martin 

Aeronautics and Northrop Grumman were also included in the cumulative modeling, despite their relatively 

low PM2.5 emissions (less than 10 tons per year each). The locations of these four facilities relative to the 

PHPP site are shown in Figure 2-1. 

2.1.2 Characterization of Modeled Non-PHPP Sources 

Once the four facilities to be included in the modeling analysis were chosen, the next step was to 

characterize the individual sources to be included in the modeling. The modeling of Lockheed Martin 

Aeronautics and Northrop Grumman had been previously discussed in Section 6.1.3 of the PHPP PSD 

Application. AVAQMD provided HARP model transaction files for all four facilities. In the transaction files 

for Granite Rock Construction and Robertson’s Ready Mix, source coordinates and parameters were not 

available, while for Lockheed and Northrop, there were many sources with minimal emissions. In order to 

resolve these issues and other problems with the source data for these four facilities, the following 

adjustments were made: 

• Lockheed Martin Aeronautics and Northrop Grumman: Because of the large number of sources at 

each facility, the vast majority of which had very low emissions, it was agreed with the AVAQMD, as 

described in Section 5.2.4.3 of the PHPP Application for Certification (AFC), to model all of the sources 

that included five percent or more of the emissions for each given pollutant, and then add the remainder 

of the total emissions to the source that emitted the highest percentage of the emissions in order to 

have a representative mix of source parameters, and to ensure that all criteria pollutant emissions from 

the two facilities were included in the modeling. Figure 2-2 shows the locations of the two facilities and 

the sources that were included in the cumulative modeling. The characteristics and emissions for the 

Lockheed Martin Aeronautics and Northrop Grumman sources included in the cumulative modeling 

analysis are shown in Tables 2-1 and 2-2. 

• Granite Rock Construction: As stated above, source parameters were not available for the emission 

sources located at Granite Rock Construction. The sources located at the facility are primarily crushing 

and mining of aggregate and sand, along with conveyors and other fugitive sources. This facility is 

located over nine miles from the PHPP. As a result, it was decided to represent the emissions from the 

facility as a single area source with the same characteristics as the fugitive emission sources used to 

represent construction activities at PHPP. The emissions for the facility were represented by a single 

area source 54,000 square meters (m2

) in area centered on the part of the facility where the majority of 

the emissions occur. The source characteristics and emissions for Granite Rock Construction are 

shown in Table 2-3. 

• Robertson’s Ready Mix: As with Granite Rock Construction, source parameters were not available for 

the emission sources located at Robertson’s Ready Mix (formerly Service Rock Products). This facility 

is also located over 8.5 miles from the PHPP. There are two primary sets of emissions at the facility: 

sources involved in the concrete batching process, and a number of portable engines that are moved to 

various locations on the property to provide power as needed. As a result, these two processes were 

each represented by an area source with the same source characteristics as the fugitive emission 

sources used to represent construction activities at PHPP. The cement batching process was 

represented by a source with an area of 8,000 m2 covering the area where the majority of the batching 

process occurs, while the remaining emissions were characterized by a source with an area of 45,000 

m2. The source characteristics and emissions for Granite Rock Construction are shown in Table 2-4. 
AECOM Environment 2-3

Figure 2-1 Relative Location of PHPP, Non-Project Sources, and Division Street Monitor 
AECOM Environment 2-4

Figure 2-2 Lockheed Martin and Northrop Grumman Sources included in the Modeling Analysis 
AECOM Environment 

Table 2-1 Lockheed Martin Aeronautics Sources 

Point Sources (annual runs only) 

Source ID 

UTM 

Easting 

(NAD27) 

UTM 

Northing 

(NAD27) 

Base 

Elev. 

(m) 

Stack 

Hgt. 

(m) 

Temp 

(°K) 

Exit Vel.

(m/s) 

Exit. Diam. 

(m) 

S075 398078.7 3830369.0 746.76 3.052 505.4 22.77 1.22 S077 398050.6 3830366.0 746.76 5.351 505.4 21.59 1.22 S099 398083.6 3830535.0 746.76 3.052 477.6 20.01 1.22 S106 399511.6 3831148.0 746.76 2.000 505.4 8.50 0.92 S116 398247.6 3830534.0 746.76 2.000 297.0 20.01 1.22 Volume Source 

Source ID

UTM

Easting

(NAD27)

UTM

Northing

(NAD27)

Base

Elev.

(m)

Rel. Hgt.

(m) Sigma‐Y Sigma‐Z PM2.5 (lb/hr) 

S055 398013.6 3830411.0 746.76 2.75 1.52 1.52 6.50 
AECOM Environment 

Table 2-2 Northrop Grumman Sources 

Point Sources 

Source ID

UTM

Easting

(NAD27)

UTM

Northing

(NAD27)

Base

Elev.

(m)

Stack Hgt.

(m)

Temp

(°K)

Exit Vel.

(m/s)

Exit. Diam.

(m)

S215 (annual only) 402103.5 3833516.0 789.30 10.67 466.48 18.29 0.31 S216 (annual only) 402104.7 3833516.0 789.30 10.67 466.48 18.29 0.31 S279 (annual only) 401099.4 3833145.0 789.30 6.10 288.71 3.05 3.05 

S230 (24-hour only) 402337.0 3833310.0 789.30 12.20 299.82 0.10 3.05 

Volume Source 

Source ID

UTM

Easting

(NAD27)

UTM

Northing

(NAD27)

Base

Elev.

(m)

Rel. Hgt.

(m) Sigma‐Y Sigma‐Z PM2.5 (lb/hr) 

S158 (24-hour only) 401777.9 3833322.0 789.30 12.20 2.84 5.67 0.01 
AECOM Environment 

Table 2-3 Granite Rock Construction Sources 

Area Source 

Source ID

UTM

Easting

(NAD27)

UTM

Northing

(NAD27)

Base

Elev.

(m)

Rel. Hgt.

(m)

Init Sigma‐Z

(m)

Total Area

(m2)

PM

(lb/

GC 407476.8 3821419.8 859.54 2.0 2.13 54,000 6.1

Table 2-4 Robertson’s Ready Mix Sources 

Area Source 

Source ID

UTM

Easting

(NAD27)

UTM

Northing

(NAD27)

Base

Elev.

(m)

Rel. Hgt.

(m)

Init Sigma‐Z

(m)

Total Area

(m2)

PM

(lb

RRM_1 (batch process) 408757.2 3825360.2 818.39 2.0 2.13 8,000 3RRM_2 (all other sources) 408762.5 3824316.1 818.39 2.0 2.13 45,000 3
AECOM Environment 2-8

2.1.3 Modeling Methodology 

On March 23, 2010, EPA issued a memo regarding the modeling of PM2.5 indicating that the use of 

PM10 modeling is no longer an acceptable means of demonstrating NAAQS compliance for PM2.5. 

Instead the following procedures for modeling PM2.5 were identified: 

• 24-hour PM2.5: The high-1st-high impact at each receptor averaged over the number of years 

included in the modeling exercise, added to the average of the 98th percentile ambient 

background concentrations for the most recent 3-years available at a nearby monitoring site. 

• Annual PM2.5: The highest average of the modeled annual averages over the period of years 

included in the modeling, added to the highest annual average background averaged over the 

most recent 3-years available at a nearby monitoring site. 

Based on this recent guidance, the supplemental cumulative PM2.5 modeling for PHPP was 

performed using the methodology described above. The full text of the EPA memo can be found at: 

http://www.epa.gov/region07/air/nsr/nsrmemos/pm25memo.pdf. Although this methodology was 

followed, a discussion is provided in Section 2.2.5 below as to why this guidance is overly 

conservative. 

2.1.3.1 Sources, Stack Parameters, and Emissions for PHPP 

In this modeling analysis, the stack parameters and emissions data for the PHPP sources used were 

the same as in PSD application submitted in April 2009, except for solar field maintenance vehicle 

emissions that were slightly updated in responses to CEC data requests submitted on May 1, 2009. 

For all PHPP sources, it was also conservatively assumed that the PM2.5 emissions for PHPP 

sources were equivalent to their respective PM10 emissions with the exception of the solar field 

maintenance vehicular fugitive emissions. AERMOD version 09292 was used in this analysis. 

2.1.3.2 Meteorological Data 

The meteorological data used in this analysis were the same as was used in the PSD Application 

modeling. Three years of surface observation data collected at the Palmdale Regional Airport in 

Palmdale (2002-2004), along with concurrent upper air data from Mercury Desert Rock Airport in 

Mercury, Nevada, were used in the modeling analysis. 

2.1.3.3 Ambient Background Data 

Ambient background data for PM2.5 are available from the monitor located at 43301 Division St. in 

Lancaster, California, located approximately two miles from the PHPP site, as shown in Figure 2-1. 

Background data from 2006-2008 were used as the data available on the AIRS database website 

(http://www.epa.gov/air/data/geosel.html) are not yet complete for 2009 (note, data for 2005-2007 

were used in the PSD Application). For the 24-hour period, the 3-year average of the 98th percentile 

values was used. For the annual period, the 3-year average annual mean was used. 

The PM2.5 background data for the Division Street Monitor are shown in Table 2-5. 
AECOM Environment 2-9

Table 2-5 Ambient PM2.5 Background Concentrations at 43301 Division St. Lancaster 

Pollutant Period Measure PM2.5 Ambient Background (μg/m3

) 

2006 2007 2008 Max. Avg. 

PM2.5 

24-hour 

1st-high 18 25 24 25 22 

2nd-high 13 20 13 20 15 

98th % 13 20 24 24 19 

Annual Mean 7.4 8.0 7.2 8.0 7.5 

2.1.3.4 Receptor Grid 

The previous PM2.5 modeling in the PSD Application determined that the maximum impacts occur 

close to the PHPP. Therefore, the receptor spacing used within the modeling area is as follows: 

• 50 m spacing along the PHPP facility fence line. 

• 100 meter (m) spacing to 3 km from the plant centroid, 

• 250 m spacing to 5 km from the plant centroid, and 

• 500 m spacing to 10 km from the plant centroid. 

Additionally, during the modeling analysis performed for the AFC for the project, it was discovered that 

both the Lockheed Martin (for 24-hour PM2.5) and Northrop Grumman (for annual PM2.5) facilities 

indicated large impacts at receptors within their own property boundaries. However, a facility may not 

contribute to an air quality impact within its own ambient air barrier1

. Therefore, two additional 

receptor grids were created, one without the receptors located on the Lockheed Martin properties, and 

one without the receptors located on the Northrop Grumman properties. Two sets of model runs were 

done for each PM2.5 modeling period: one containing all of the emission sources for all facilities but 

excluded those receptors on the Lockheed property (24-hour PM2.5) or Northrop property (for annual 

PM2.5), and another with the whole receptor grid but excluding the Lockheed or Northrop emissions 

(for 24-hour and annual PM2.5 respectively). The highest modeled impact from the two runs was then 

used in comparison with the applicable NAAQS. 

The receptor grid used in these model runs is shown in Figure 2-3. 

2.1.4 Results and Discussion 

The results of the cumulative PM2.5 modeling are shown in Table 2-6. In the table, the average of 

the maximum modeled high-1st-high over the three years by receptor is summed with the average of 

the 98th percentile ambient background values for the 24-hour period, and the maximum annual 

impact over the three years is added to the average annual mean ambient background averaged over 

three years. The results are then compared to the 24-hour NAAQS for PM2.5 (35 micrograms per 

cubic meter [μg/m3

]) and annual CAAQS for PM2.5 (12 μg/m3). As shown in the table, the cumulative 

impacts for both periods are below their respective standard and thus compliance is demonstrated. 

 

1

 40 CFR § 50.1(e) and 36 Federal Register 22384 (November 15, 1971)
AECOM Environment 2-10

Note that the modeled impact from PHPP sources alone, when calculated using the conservative 

methodology described in section 2.2.2, decreases from 12.73 μg/m3 as described in the March, 2009 

PSD Application, to 12.57 μg/m3

. Thus, the non-PHPP sources contribute only 0.01 μg/m3 to the total 

impact. 

The modeling and supporting files used in this analysis are included in Appendix A. 

Table 2-6 PHPP Cumulative PM2.5 Modeling Results 

Pollutant Averaging 

Period 

AERMOD Predicted 

Concentrations (μg/m3

) Background 2 

(μg/m3) 

Cumulative 

Modeled + 

Background 

(μg/m3) 

NAAQS

(μg/m3

PHPP )

alone 1 

PHPP with 

Cumulative 

Sources 

PM2.5 

24-hour 12.57 12.58 19.0 31.6 35 

Annual 1.2 1.3 7.5 8.8 153

1. High-1st-high value; see discussion below, high-8th-high 24-hour value is 8.92 μg/m3

2. 98th percentile value from Table 2-5 

3. The annual PM2.5 CAAQS is 12 μg/m3, and there is no separate 24-hour PM2.5 CAAQS 

Historically, NAAQS have been written in the form that the standards are not to be exceeded more 

than once per year. Based on this “form” of the standard, the highest observed concentration in a 

given year, even if over the standard, would be allowed, but if the second highest observed value 

exceeded the standard, it is considered a violation. In modeling terms, the highest concentration 

modeled in a receptor grid is called the “high-1st-high”, i.e., the highest concentration at the highest 

receptor, while the second highest concentration is called the “high-2nd-high”, and so on. Therefore, in 

order to show compliance with most of the NAAQS, the modeled high-2nd-high is added to the 

background value, and must be below the applicable NAAQS. 

In the case of the PM2.5 NAAQS, the 24 hour standard is attained when 98 percent of the daily 

concentrations, averaged over three years, are equal to or less than the standard. The value used 

to determine compliance with the 24-hour PM2.5 standard is called the 98th percentile value. In a 

modeling analysis, the 98th percentile value is approximately the same as the 8th highest value at the 

maximum receptor, or the high-8th-high. The methodology described for the modeling of 24-hour 

PM2.5, i.e., use of the high-1st-high impact at each receptor averaged over the years included in the 

modeling exercise, is both inconsistent with the form of the standard and also appears to be overly 

conservative. The memo provides no justification for the use of high-1st-high rather than the 98th

percentile (high-8th-high), which is consistent with the form of the standard, or any other value in 

between (high-2nd-high being the standard for cumulative modeling assessments of most other 

pollutants, for example). The memo infers to an extent that the formation of secondary PM2.5 

requires more than the high-8th-high be used to preserve conservatism; however, it was shown by 

Heinold et. al (AECOM, 2003) that in the near field, where PM2.5 impacts are likely to be the highest, 

primary PM2.5 emissions dominate the modeled impacts, accounting for as much as 99 percent of the 

total modeled concentrations. 

Additionally, as shown below, the current AERMOD model change bulletin (EPA web site) already 

provides the proper approach for computing the modeled source impacts for the 24-hour PM2.5 

NAAQS. 
AECOM Environment 2-11

“The following changes have been made to ensure consistency with the current PM NAAQS: 

a) Added special processing for PM2.5 to calculate design values in accordance with the 

PM NAAQS. The design value for 24-hour averages is based on the high-eighth-high 

(H8H) averaged over N years, as an unbiased surrogate for the 98th percentile. The longterm design value for PM2.5 is based on the highest annual average concentration 

averaged over N years using the ANNUAL keyword on the AVERTIME card. 

Based on the above discussion, AECOM believes that a refined modeling analysis should more 

properly use the high-8th-high modeled concentration added to the three year average 98th percentile 

background concentration. The model is already sufficiently conservative to be protective of the 

PM2.5 NAAQS. With this approach, the maximum cumulative PM2.5 concentration (including 

background) would be 28.6 μg/m3

. 

2.2 PM2.5 Increment Analysis 

On September 21, 2007, EPA published a Proposed Rule in the Federal Register (72 Fed. Reg. 

54144) regarding Prevention of Significant Deterioration (PSD) for Particulate Matter Less Than 2.5 

Micrometers (PM2.5)—Increments, Significant Impact Levels (SILs) and Significant Monitoring 

Concentration (SMC). Among other requirements, the Proposed Rule contemplates three different 

“options” for adopting PM 2.5 “increments” pursuant to the PSD program. As of the date of this 

submission, the Proposed Rule has not been finalized. (See EPA Docket for Proposed Rule, 

available at: http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-HQ-OAR2006-0605.) Thus, the proposed PM 2.5 increment has not been finalized and should not be required 

for a pending application that was originally submitted to the EPA on April 1, 2009. 

Under the Proposed Rule, applications deemed complete prior to the effective of the Final Rule do not 

need to satisfy the requirements of the Final Rule. (See 72 Fed. Reg. 54143.) In other words, if the 

PHPP application is deemed complete before the Final Rule becomes effective, the PM 2.5 increment 

would not be applicable. 

Even after the EPA promulgates the Final Rule (which has not occurred), the Final Rule may not 

become effective for as long as another year pursuant to Section 166(a) of the Clean Air Act. (See 72 

Fed. Reg. 54142.) The EPA has requested comment on using a shorter 60-day period for the 

effective date. (Id.) Even with the shorter approach, there would still be a two-month period after the 

Final Rule is promulgated before it becomes effective. If the PHPP application is deemed complete 

before or during this period, the PM 2.5 increment would not be applicable. 

Under the Proposed Rule, the EPA cannot deny deeming an application complete because it does not 

include a PM2.5 increment analysis that is not yet required. (See proposed 40 CFR 52.21(i)(11), at 

72 Fed. Reg. 54154 [referring to an application that is “otherwise” complete].) Thus, because the 

PHPP application is not required to conform to the Final Rule until it becomes effective, the EPA 

should not base a completeness determination on the absence of a PM 2.5 increment analysis that is 

not yet required. 

2.3 References for Section 2 

EPA web site: http://www.epa.gov/scram001/7thconf/aermod/aermod_mcb1.txt

Heinold, D., S. Toole, and S. Heisler (AECOM), 2003. Evaluating the Impacts of a Power Plant's 

Emissions on PM2.5, A&MWA Paper #69646, presented at the 96th annual conference. 
AECOM Environment 2-12

Figure 2-3 Receptor Grid Used in PM2.5 Cumulative Modeling Analysis 
AECOM Environment 3-1

3.0 1-Hour NO2 NAAQS Modeling 

3.1 Regulatory Background 

On April 12, 2010, the federal 1-hour NO2 NAAQS became effective. The EPA describes this new 

NAAQS as follows: 

“On January 22, 2010, EPA announced a new hourly NO2 standard of 100 ppb 

based on the 3-year average of the 98th-percentile of the annual distribution of daily 

maximum 1-hour concentrations. The final rule for the new hourly NAAQS was 

published in the Federal Register on February 9, 2010, and will be effective on April 

12, 2010”.(http://www.epa.gov/air/nitrogenoxides/actions.html#jan10). 

EPA released a Support Center for Regulatory Atmospheric Modeling (SCRAM) bulletin on the 

modeling of the new 1-hour NO2 NAAQS on February 25, 2010. That bulletin can be found at: 

http://www.epa.gov/ttn/scram/no2_hourly_NAAQS_aermod_02-25-10.pdf. EPA released another 

memorandum titled “Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the 

Prevention of Significant Deterioration Program” on June 28th 2010 in an attempt to further clarify 

the modeling methodology for the 1-hour NO2 NAAQS. That memorandum can be found at: 

http://epa.gov/Region7/air/nsr/nsrmemos/appwno2.pdf. In addition, Roger Brode and Dan DeRoecke 

of the EPA Office of Air Quality Planning and Standards (OAQPS) held a Webinar on July 15, 2010 

where this new NAAQS was discussed from both a policy and dispersion modeling point of view. 

EPA indicated during this Webinar that further guidance would be forthcoming, as there remains a 

great deal of uncertainty in the performance of this analysis. In the meantime, EPA indicated that 

applicants should use their professional judgment in the conduct of these analyses. 

3.2 Modeling Methodology 

Because the EPA preferred air dispersion model, AERMOD, does not output results in a format that 

can be compared to the form of the standard, AECOM developed an AERMOD post-processor that 

uses binary output produced by a 1-hour NO2 AERMOD run and processes the data for comparison 

to the 1-hour NO2 NAAQS. The “POST-1HR” postprocessor fully complies with the modeling 

procedure outlined in the EPA’s SCRAM bulletin and performs the following steps: 

• Using binary output from AERMOD, the hourly impacts for each receptor for each year 

processed are read in, and the time-matched ambient background concentration for each 

hour is added to the modeled impact to produce a total concentration at each receptor for 

each hour. 

• Using the hourly data, the highest total impact at each receptor for each day is then 

determined. This is the “maximum daily impact” referenced in the form of the standard. 

• For each receptor, the 98th percentile of the maximum daily impacts is determined for each 

year modeled. 

• Finally, the 98th percentile of the maximum daily impacts is averaged over the three years 

modeled to determine the final concentration for comparison to the standard. 
AECOM Environment 3-2

The Ozone Limiting Method (OLM) option in AERMOD was used as a refined technique to more 

accurately model the conversion of NOx emissions to ambient NO2 concentrations. The OLM 

analysis is Tier 3 of the EPA’s multi-tiered screening approach for estimating NO2 impacts from point 

sources as provided in the Guideline for Air Quality Models (GAQM). In the OLM analysis, 10 percent 

of the NOx emissions from the source are assumed to convert to NO2 (i.e., fraction associated with 

thermal conversion) while the remaining fraction of NOx (90 percent) is converted based on available 

ambient ozone concentrations. That is, conversion of the remaining 90 percent of NOx to NO2 is 

limited based on the availability of ozone, and the remaining converted NO2 is equivalent to the 

ambient ozone concentration. These are the default values used in AERMOD for the OLM method 

stack-tip conversion of NOx to NO2. The default value was used because there is currently no 

guidance from EPA or other data available on varying the stack tip conversion based on the different 

types of combustion sources and operating scenarios. These computations are conducted internally 

in AERMOD on an hourly basis and require representative hourly monitored ozone that is concurrent 

to the meteorological data used in the modeling. For this analysis, three years of monitored ozone 

concentrations from the Lancaster Division Street monitoring station were used that were concurrent 

with the three years (2002-2004) of meteorological data (see Section 2.2.3.2) used in the modeling. 

3.2.1 Normal Operations 

AECOM applied the “POST-1HR” post-processor to the PHPP 1-hour NO2 modeling for normal 

operations to demonstrate compliance with the 1-hour NO2 NAAQS. As described in the PSD 

Application, concurrent hourly ambient background concentrations for NO2 were taken from the 

Lancaster Division Street monitoring station. The Division Street monitor is about two miles from the 

PHPP site, located well within the city limits of Lancaster and within 200 yards of the Sierra Highway. 

Because of it’s proximity to the Project site, it’s location within a more urban area than the Project site, 

and the fact that it is situated in an area that experiences much denser vehicular traffic than the 

Project site, it is assumed that the Division Street monitor accurately and conservatively reflects the 1-

hour NO2 background at the PHPP site. 

PHPP emissions data for NOx and stack parameters used for this analysis are provided in the March 

2009 PSD Application. 

After processing with the “POST-1HR” post-processor, the 3-year average of the 98th percentile 

maximum daily 1-hour NO2 impacts for normal operations, including ambient background 

concentrations based on OLM, was determined to be 175.3 μg/m3

 (93.2 ppb). The maximum 

contribution by Project sources alone was 106.9 μg/m3

 (56.8 ppb). 

3.2.2 Startup and Shutdown Analysis 

During startup and shutdown of combustion turbine generators, emissions of NOx and CO are much 

higher than the emissions of these pollutants during normal operations. Combined-cycle power plants 

such as PHPP must be brought on-line slowly while the steam turbine generator warms up. The 

emissions control systems (e.g., selective catalytic reduction system for NOx control) is not utilized 

during this period as the catalyst must be at a sufficient temperature to be effective. While PHPP will 

have higher NOx and CO emissions during startup, this power plant’s emissions will be much lower 

than many combined-cycle plants due to the use of the Rapid Start Process (RSP), which minimizes 

the time needed in startup mode, and hence greatly reduces the emissions during startup. 

In the March 2009 PSD Application, an analysis of impacts during CTG startup and shutdown was 

provided for CO emissions from PHPP since there were short-term (1-hour and 8-hour) NAAQS for 
AECOM Environment 3-3

 

CO (Section 6.1.4). Since the 1-hour NO2 NAAQS only became effective in April 2010, a modeling 

analysis2

 for startup or shutdown emissions was not included for this pollutant in the PSD Application. 

However, because there is a 1-hour NO2 CAAQS, an analysis for NOx emissions during startup and 

shutdown had been provided in the PHPP AFC (Section 5.2.4.2.2). 

As described in the AFC, a worst-case emission rate was found to occur during shutdown events, 

which can last up to half an hour. Therefore, the maximum hourly emissions analyzed consisted of a 

half hour at the maximum normal operations emission rate and a half hour at the shutdown emission 

rate as follows: 

Maximum NO2 emissions = (0.5 hours x 16.6 lb/hr) + 57 lb/event (shutdown) = 65.3 lb/hr per turbine. 

The stack parameters (as given in the PSD Application) were an exit temperature of 173.5 o

F and an 

exit velocity of 31.76 ft/sec (based on 20 percent load). The modeling methodology, using OLM and 

the “POST-1HR” post-processor, was applied as described above for normal operations. 

For startup / shutdown periods, the 3-year average of the 98th percentile maximum daily 1-hour NO2, 

including ambient background concentrations based on OLM, was determined to be 180.3 μg/m3

(95.9 ppb). The maximum contribution by PHPP sources alone during startup / shutdown was 136.4 

μg/m3

 (72.5 ppb). 

3.3 Summary of Results 

As the standard is 100 parts per billion (ppb), the impact of PHPP including background is below the 

standard and, therefore, compliance is demonstrated for both normal operations and startup / 

shutdown periods. 

The “POST-1HR” post-processor, along with all files used in the processing, is included in the 

electronic modeling archive provided as Appendix A. 

2

 Although a modeling analysis for startup and shutdown was not included in the March 2009 PSD Application for 

NO2 impacts, a BACT analysis was included in the March 2009 PSD Application for startup and shutdown 

emissions. 
AECOM Environment 4-1

4.0 Visibility Analysis 

PSD regulations require an analysis of visibility impairment at Class I areas be prepared for PSD 

projects. Visibility impairment for Class I areas within 50 km of a proposed PSD project is called 

plume blight and for Class I areas beyond 50 km is referred to as regional haze. Potential impacts to 

visibility were analyzed at several Class I areas located within 100 km of the PHPP and the results 

presented in the PSD Application submitted on April 1, 2009. In addition to those analyses, EPA 

requested in March 2010 that “sensitive” Class II areas located within 50 km also be considered. No 

specific definition was provided as to what would be considered “sensitive” Class II Areas; however, 

these were assumed to be areas such as federal wilderness areas and State parks. 

In order to determine prospective Class II areas for consideration, several data sources were used: 

1. Google Earth in order to catalogue parks that were nearby to the project site. 

2. U.S. Forest Service website: http://www.fs.fed.us/ 

3. The California State Parks website: http://www.parks.ca.gov/ 

From these sources, five sites were identified as candidates for inclusion in the expanded visibility 

analysis, as follows: 

• Sheep Mountain Wilderness Area (WA) 

• Saddleback Butte State Park 

• Antelope Valley Indian Museum State Park 

• Antelope Valley California Poppy State Reserve 

• Arthur B. Ripley Desert Woodland 

All of these five areas are within 50 km of PHPP as shown in Figure 4-1. The plume visibility analysis 

was conducted with the most current version of EPA’s screening model VISCREEN to determine if 

Project emissions will impair visibility in the five areas identified for analysis. VISCREEN was applied 

with the guidance provided in EPA's Workbook for Plume Visual Impact Screening and Analysis 

(Workbook). As such, the VISCREEN model was applied to estimate two visual impact parameters, 

plume perceptibility (ΔE) and plume contrast (Cp). Screening-level guidance indicates that, for PSD 

Class I areas, values above 2.0 for ΔE and +/- 0.05 for Cp are considered perceptible. Note that the 

Class II areas being assessed in this analysis should not be held to the same stringent guidance 

levels. 

The Workbook offers two levels of analyses. A Level 1 screening analysis is the most simplified and 

conservative approach employing default meteorological data with no site-specific conditions. A 

Level 2 analysis takes into account representative meteorological data and site-specific conditions 

such as complex terrain. Initially, the Level 1 analysis was conducted and indicated ΔE and Cp values 

were above the screening thresholds for all five sites. Therefore, a Level 2 analysis was conducted. 

A Level 2 analysis was conducted with the same three years of meteorological data used in the 

Class I air quality impacts analysis. In addition, per Workbook guidance, the stability class of the 

Sheep Mountain WA was reduced by one class (less stable) because the terrain elevation differences 
AECOM Environment 4-2

between the facility (stack-top) location and Sheep Mountain WA is more than 500 meters (m). The 

maximum elevation at Sheep Mountain WA is 3,068 m above mean sea level (amsl) at its highest 

point (Mt. Baldy). The stack-top elevation of the project source is 811 m amsl. This results in a 

difference in elevation of 2,257 m. The other four Class II areas all have base elevations within 500 m 

of the PHPP stack top elevation. Therefore, the stability class was unchanged from the value 

determined in meteorological data frequency analysis. 

The source data required by VISCREEN are total NOx emissions (33.20 pounds per hour [lb/hr]) and 

particulate emissions (36.00 lb/hr) for the CTGs. Included in the particulate emissions were emissions 

of elemental carbon (EC) (9.00 lb/hr) and sulfate (SO4) (0.99 lb/hr) emissions. The speciated PM10 

emissions where derived according to procedures referenced in the PHPP Class I modeling protocol 

and conform to recommendations by the National Park Service (NPS). The NPS guidance specifies 

that of the total PM10, 25 percent should be considered filterable PM10 and 75 percent should be 

considered condensable PM10. The filterable PM10 is conservatively assumed to be EC, while the 

condensable PM10 (minus the primary sulfate) is conservatively assumed to be organic aerosols. It 

was assumed that all NOx is present as NO2. The 22.5 degree (°) wind direction sectors that would 

transport emissions from the PHPP toward the five areas chosen for analysis, along with the closest 

and farthest distances from those areas to the proposed PHPP site, are shown in Table 4-1. The 

locations of the areas relative to the PHPP site are shown in Figure 4-1. 

Table 4-1 Class II Areas Included in VISCREEN Analysis 

Area Name 22.5o

 Wind 

Sector 

Closest 

Distance 

to PHPP 

(km) 

Furthest 

Distance 

from PHPP 

(km) 

Worst 

Case 

Stability 

Class 

Worst 

Case Wind 

Speed 

(m/s) 

Sheep Mountain 

Wilderness Area 303.75-326.25 42.95 59.63 E1 4 

Saddleback Butte 

State Park 258.75-281.25 26.13 30.65 F 3 

Antelope Valley Indian 

Museum State Park 258.75-281.25 22.80 24.04 F 3 

Antelope Valley 

California Poppy State 

Reserve 

101.25-123.75 25.59 31.84 E 5 

Arthur B. Ripley 

Desert Woodland 101.25-123.75 36.64 38.67 E 5 

1. Because Sheep Mountain Wilderness Area is more than 500 m above the stack top elevation of 

PHPP, this source was modeled at one stability class less stable, i.e., class D, per the 

Workbook. 

 
AECOM Environment 4-3

Figure 4-1 Areas Included in the Visibility Analyses

 
AECOM Environment 4-4

Based on this information, and the three years of meteorological data, a table of joint frequency of 

occurrence of wind speed, wind direction, and stability class was developed for each of the five areas 

analyzed as outlined in the Workbook. The dispersion conditions, defined by wind speed and stability 

class, were ranked by evaluating the product of σy, σz, and u, where σy and σz are the Pasquill-Gifford 

horizontal and vertical diffusion coefficients for the given stability class and downwind distance and u 

is the wind speed. The dispersion conditions were then ranked in ascending order according to the 

value of σyσzu as shown in Tables 4-2 through 4-6. 

According to the Workbook, VISCREEN is to be applied with the worst-case meteorological conditions 

that have a σyσzu product with a cumulative probability of one percent. That is, the dispersion 

condition is selected such that the sum of all frequencies of occurrence of conditions worse than this 

condition totals one percent. Note that as recommended by the Workbook, dispersion conditions that 

result in greater than 12 hours of plume transport time are discounted from the analysis, since it is 

unlikely that steady-state plume conditions would persist for more than 12 hours. 

The worst-case dispersion conditions with a cumulative frequency of one percent from Tables 4-2

through 4-6 are also given in Table 4-1. As discussed previously, the stability class used for Sheep 

Mountain WA was reduced from E to D (slightly less stable), as recommended by Workbook for cases 

when the terrain relief is greater than 500 meters as compared from stack top to elevations in the 

Class II area. As recommended by the FLAG guidance (FLM, 2000), a visual range of 246 km was 

used. A visual range of 246 km was used for the San Gabriel Wilderness Area in the PSD application, 

and because it is the closest Class I area to the PHPP, this value was used for all of the Class II areas 

included in this analysis. While the visual range is specific to a particular Class I area, Class I areas 

within the same region typically have visual ranges that are very similar. Additionally, by definition 

Class I areas are held to more stringent standards than Class II areas and thus the use of 246 km as 

a visual range for Class II areas in the vicinity of PHPP is a conservative measure. 

The VISCREEN results are summarized in Table 4-7. VISCREEN provides results of ΔE and Cp for 

both sky and terrain backgrounds. The results are below the significance criteria in all cases with the 

exception of Saddleback Butte State Park and Antelope Valley Indian Museum State Park when the 

observer looks at a terrain background. For all other cases, the plume is expected to be 

imperceptible. As a further refinement, plume perceptibility was examined for daylight hours only 

(6 am – 6 pm) at Saddleback Butte State Park and Antelope Valley Indian Museum State Park. Per 

Tables 4-2 and 4-3, the worst-case daytime meteorological conditions with a cumulative probability of 

1 percent are stability class D with a wind speed of 5 meters per second (m/s). VISCREEN was rerun 

using these values to determine plume perceptibility and contrast for those two sites during daylight 

hours. The results, shown in Table 4-8, indicate that the plume will not be perceptible at either site 

during daylight hours. 
AECOM Environment 

Table 4-2 Dispersion Condition Frequency Analysis – Sheep Mountain Wilderness Area - Sector 303.75o – 326

Dispersion 

Condition 

σyσzu 

(m3/s) 

Transport 

Time 

(hours) 

Frequency By Time of Day (%) Cumulative Frequency By T

Wind 

Speed 

(m/s) 

Stability 

Class 0-6 6-12 12-18 18-24 0-6 6-12 12-

F 1 74369 24 0.335 0.046 0.000 0.319 0.000 0.000 0.0F 2 148739 8 0.289 0.030 0.000 0.213 0.289 0.030 0.0

E 1 212980 24 0.030 0.122 0.030 0.122 0.289 0.030 0.0

F 3 223108 5 0.502 0.076 0.000 0.578 0.791 0.106 0.0

E 2 425960 8 0.015 0.106 0.000 0.046 0.806 0.213 0.0

D 1 592377 24 0.076 0.137 0.076 0.046 0.806 0.213 0.0

E 3 638940 5 0.091 0.122 0.030 0.152 0.897 0.335 0.0E 4 851920 3 0.122 0.046 0.030 0.304 1.019 0.380 0.0E 5 1064900 3 0.061 0.000 0.091 0.228 1.080 0.380 0.1

D 2 1184755 8 0.030 0.198 0.015 0.000 1.110 0.578 0.1D 3 1777132 5 0.030 0.228 0.106 0.030 1.141 0.806 0.2D 4 2369509 3 0.122 0.122 0.106 0.030 1.262 0.928 0.3D 5 2961886 3 0.046 0.046 0.030 0.030 1.308 0.973 0.4D 6 3554264 2 0.046 0.061 0.137 0.152 1.353 1.034 0.5D 7 4146641 2 0.000 0.274 0.213 0.137 1.353 1.308 0.7D 8 4739019 2 0.030 0.152 0.259 0.015 1.384 1.460 1.0

Notes: m/s = meters/second m3/s = cubic meters/second 
AECOM Environment 

Table 4-3 Dispersion Condition Frequency Analysis – Saddleback Butte State Park - Sector 258.75o – 281.2

Dispersion 

Condition 

σyσzu 

(m3/s) 

Transport 

Time 

(hours) 

Frequency By Time of Day (%) Cumulative Frequency By T

Stability 

Class 

Wind 

Speed 

(m/s) 

0-6 6-12 12-18 18-24 0-6 6-12 12-

F 1 41711 15 0.623 0.061 0.000 0.654 0.000 0.000 0.0F 2 83422 5 0.730 0.061 0.000 0.502 0.730 0.061 0.0

E 1 115056 15 0.061 0.259 0.000 0.015 0.730 0.061 0.0

F 3 125132 3 1.262 0.091 0.030 1.293 1.992 0.152 0.0

E 2 230112 5 0.061 0.213 0.030 0.061 2.053 0.365 0.0

D 1 295291 15 0.046 0.304 0.000 0.015 2.053 0.365 0.0

E 3 345167 3 0.198 0.228 0.091 0.304 2.251 0.593 0.1E 4 460223 2 0.547 0.015 0.046 0.973 2.798 0.608 0.1E 5 575279 2 0.988 0.015 0.228 1.825 3.786 0.623 0.4

D 2 590583 5 0.061 0.106 0.046 0.015 3.847 0.730 0.4D 3 885874 3 0.182 0.106 0.137 0.106 4.030 0.836 0.6D 4 1181165 2 0.182 0.137 0.030 0.076 4.212 0.973 0.6D 5 1476456 2 0.198 0.137 0.167 0.319 4.410 1.110 0.8D 6 1771748 1 0.380 0.304 0.365 0.867 4.790 1.414 1.1D 7 2067039 1 0.821 0.456 1.125 1.247 5.611 1.870 2.2D 8 2362330 1 0.547 0.547 1.353 1.110 6.159 2.418 3.6
AECOM Environment 

Table 4-4 Dispersion Condition Frequency Analysis – Antelope Valley Indian Museum SP - Sector 258.75o – 28

Dispersion 

Condition 

σyσzu 

(m3/s) 

Transport 

Time 

(hours) 

Frequency By Time of Day (%) Cumulative Frequency By T

Wind 

Speed 

(m/s) 

Stability 

Class 0-6 6-12 12-18 18-24 0-6 6-12 12-

F 1 35386 13 0.623 0.061 0.000 0.654 0.000 0.000 0.0F 2 70771 4 0.730 0.061 0.000 0.502 0.730 0.061 0.0

E 1 96958 13 0.061 0.259 0.000 0.015 0.730 0.061 0.0

F 3 106157 3 1.262 0.091 0.030 1.293 1.992 0.152 0.0

E 2 193915 4 0.061 0.213 0.030 0.061 2.053 0.365 0.0

D 1 242501 13 0.046 0.304 0.000 0.015 2.053 0.365 0.0

E 3 290873 3 0.198 0.228 0.091 0.304 2.251 0.593 0.1E 4 387830 2 0.547 0.015 0.046 0.973 2.798 0.608 0.1E 5 484788 1 0.988 0.015 0.228 1.825 3.786 0.623 0.4

D 2 485002 4 0.061 0.106 0.046 0.015 3.847 0.730 0.4D 3 727502 3 0.182 0.106 0.137 0.106 4.030 0.836 0.6D 4 970003 2 0.182 0.137 0.030 0.076 4.212 0.973 0.6D 5 1212504 1 0.198 0.137 0.167 0.319 4.410 1.110 0.8D 6 1455005 1 0.380 0.304 0.365 0.867 4.790 1.414 1.1D 7 1697506 1 0.821 0.456 1.125 1.247 5.611 1.870 2.2D 8 1940007 1 0.547 0.547 1.353 1.110 6.159 2.418 3.6
AECOM Environment 

Table 4-5 Dispersion Condition Frequency Analysis – Antelope Valley California Poppy State Reserve - Sector 101.2

Dispersion 

Condition 

σyσzu 

(m3/s) 

Transport 

Time 

(hours) 

Frequency By Time of Day (%) Cumulative Frequency By T

Wind 

Speed 

(m/s) 

Stability 

Class 0-6 6-12 12-18 18-24 0-6 6-12 12-

F 1 40674 14 0.167 0.000 0.000 0.350 0.000 0.000 0.0F 2 81348 5 0.228 0.015 0.000 0.137 0.228 0.015 0.0

E 1 112081 14 0.015 0.015 0.000 0.015 0.228 0.015 0.0

F 3 122022 3 0.411 0.000 0.046 0.487 0.639 0.015 0.0

E 2 224161 5 0.015 0.030 0.015 0.015 0.654 0.046 0.0

D 1 286520 14 0.030 0.046 0.061 0.000 0.654 0.046 0.0

E 3 336242 3 0.076 0.015 0.046 0.046 0.730 0.061 0.1E 4 448322 2 0.091 0.000 0.061 0.198 0.821 0.061 0.1E 5 560403 2 0.106 0.000 0.046 0.259 0.928 0.061 0.2

D 2 573040 5 0.015 0.046 0.030 0.000 0.943 0.106 0.2D 3 859561 3 0.030 0.122 0.152 0.000 0.973 0.228 0.3D 4 1146081 2 0.015 0.046 0.076 0.000 0.988 0.274 0.4D 5 1432601 2 0.046 0.061 0.046 0.015 1.034 0.335 0.5D 6 1719121 1 0.091 0.030 0.030 0.076 1.125 0.365 0.5D 7 2005642 1 0.015 0.015 0.046 0.061 1.141 0.380 0.5D 8 2292162 1 0.000 0.015 0.061 0.000 1.141 0.395 0.6
AECOM Environment 

Table 4-6 Dispersion Condition Frequency Analysis – Arthur B. Ripley Desert Woodland - Sector 101.25o – 123

Dispersion 

Condition 

σyσzu 

(m3/s) 

Transport 

Time 

(hours) 

Frequency By Time of Day (%) Cumulative Frequency By T

Wind 

Speed 

(m/s) 

Stability 

Class 0-6 6-12 12-18 18-24 0-6 6-12 12-

F 1 61984 20 0.167 0.000 0.000 0.350 0.000 0.000 0.0F 2 123968 7 0.228 0.015 0.000 0.137 0.228 0.015 0.0

E 1 175674 20 0.015 0.015 0.000 0.015 0.228 0.015 0.0

F 3 185952 4 0.411 0.000 0.046 0.487 0.639 0.015 0.0

E 2 351348 7 0.015 0.030 0.015 0.015 0.654 0.046 0.0

D 1 475491 20 0.030 0.046 0.061 0.000 0.654 0.046 0.0

E 3 527022 4 0.076 0.015 0.046 0.046 0.730 0.061 0.1E 4 702695 3 0.091 0.000 0.061 0.198 0.821 0.061 0.1E 5 878369 2 0.106 0.000 0.046 0.259 0.928 0.061 0.2

D 2 950981 7 0.015 0.046 0.030 0.000 0.943 0.106 0.2D 3 1426472 4 0.030 0.122 0.152 0.000 0.973 0.228 0.3D 4 1901962 3 0.015 0.046 0.076 0.000 0.988 0.274 0.4D 5 2377453 2 0.046 0.061 0.046 0.015 1.034 0.335 0.5D 6 2852944 2 0.091 0.030 0.030 0.076 1.125 0.365 0.5D 7 3328434 2 0.015 0.015 0.046 0.061 1.141 0.380 0.5D 8 3803925 1 0.000 0.015 0.061 0.000 1.141 0.395 0.6
AECOM Environment 

Table 4-7 VISCREEN Model Results – All Hours 

Site Background Distance (km) 

Plume Perceptibility (ΔE) Plume Contrast (Cp) 

VISCREEN1

Criteria 

VISCREEN1

Crite

Theta 10 Theta 140 Theta 10 Theta 140

Sheep Mountain Wilderness Area 

Sky 59.6 0.109 0.225 2.00 0.001 -0.0082 0.0

Terrain 43.0 0.615 0.061 2.00 0.005 0.001 0.0

Saddleback Butte State Park 

Sky 30.6 0.638 1.133 2.00 0.003 -0.0372 0.0

Terrain 26.1 4.9633 0.420 2.00 0.030 0.004 0.0

Antelope Valley Indian Museum State Park 

Sky 24.0 0.569 0.985 2.00 0.002 -0.0322 0.0

Terrain 22.8 5.6453 0.456 2.00 0.032 0.004 0.0

Antelope Valley California Poppy State Reserve 

Sky 31.8 0.240 0.426 2.00 0.001 -0.0142 0.0

Terrain 25.6 1.759 0.139 2.00 0.010 0.001 0.0

Arthur B. Ripley Desert Woodland 

Sky 38.7 0.146 0.258 2.00 0.001 -0.0082 0.0

Terrain 36.6 1.196 0.111 2.00 0.008 0.001 0.0

1. VISCREEN results are provided for the two VISCREEN default worst-case theta angles. The two theta angles represent the s

being in front of the observer (theta = 10 degrees) or behind the observer (theta = 140 degrees). 

2. A negative Cp means the plume has a darker contrast than the background sky. 

3. Exceeds screening value for plume perceptibility. Further refinement to include daylight hours only given in Table 4-8. 
AECOM Environment 

Table 4-8 VISCREEN Model Results – Daytime Hours (6 am – 6 pm) 

Site Background Distance (km) 

Plume Perceptibility (ΔE) Plume Contrast (Cp) 

VISCREEN1

Criteria 

VISCREEN1

Crite

Theta 10 Theta 140 Theta 10 Theta 140

Saddleback Butte State Park 

Sky 30.6 0.109 0.190 2.00 0.000 -.00062 0.0

Terrain 26.1 0.915 0.072 2.00 0.005 .0001 0.0

Antelope Valley Indian Museum State Park 

Sky 24.0 0.102 0.174 2.00 0.000 -0.0062 0.0

Terrain 22.8 1.082 0.081 2.00 0.006 0.001 0.0

1. VISCREEN results are provided for the two VISCREEN default worst-case theta angles. The two theta angles represent the s

being in front of the observer (theta = 10 degrees) or behind the observer (theta = 140 degrees). 

2. A negative Cp means the plume has a darker contrast than the background sky. 
AECOM Environment 5-1

5.0 Soils and Vegetation Analysis 

5.1 Regulatory Overview and Background 

The PSD regulations codified at 40 Code of Federal Regulations (CFR) §52.21(o) require that an 

analysis of the impact to soils and vegetation of significant commercial or recreational value that would 

occur as a result of the project be conducted. The regulation indicates that the owner or operator 

need not provide an analysis of the impact on vegetation having no significant commercial or 

recreational value. 

The EPA guidance document for soils and vegetation, A Screening Procedure for the Impacts of Air 

Pollution Sources on Plants, Soils, and Animals (EPA 450/2-81-078, OAQPS, Research Triangle 

Park, NC. December 12, 1980) was the basis for the analysis previously submitted in the PSD 

application submitted in April 2009. The EPA guidance document establishes the air pollutant 

concentrations that are generally viewed to be protective of soils and vegetation having significant 

commercial or recreational value, including agricultural crops, based on a broad review of pertinent 

scientific literature. 

During a conference call in March 2010, EPA Region 9 requested that the PHPP analysis of soils and 

vegetation impacts be supplemented pursuant to the following Environmental Appeals Board case: In 

re: Indeck-Elwood, LLC; PSD Appeal No. 03-04; PSD Permit No. 197035AAJ (decided September 27, 

2006) (“Indeck”). The Indeck case contemplates the need for additional analysis beyond a “screening 

analysis” with respect to soil and vegetation for a PSD application. 

Accordingly, the Indeck case was reviewed for applicability to the PHPP application. As an initial 

matter, key aspects of the Indeck case are not directly applicable. For example, PHPP is a clean, 

state-of-the-art, hybrid solar-gas-fired combined-cycle facility located within developed city limits, while 

the Indeck facility is a proposed large-scale coal-fired power plant located approximate to a prairie 

reserve of national importance. Although a more rigorous analysis is provided herein, we note that 

the PHPP will have substantially lower air quality impacts than would a coal-fired power plant. 

The key holding of Indeck is that an agency should consider requiring more than a “screening 

analysis” to evaluate soil and vegetation impacts to the extent that the 1990 New Source Review 

(NSR) Manual would result in a different significance conclusion. In particular, the Indeck case 

contemplates an inventory of applicable soils and vegetation and consideration of site-specific effects 

where appropriate to identify potential impacts. See, e.g., Indeck, pp. D.4-5 and D.11-12. 

Following our review of Indeck, we supplemented the PHPP soils and vegetation analysis to ensure 

the analysis reflected the methodology in the 1990 NSR Manual (EPA, 1990). Although we believe 

the prior submittal achieved the standard in the 1990 NSR Manual, we are providing additional 

information in this submittal to better demonstrate consistency. 

The guidance in the 1990 NSR Manual, Section II.C Soils and Vegetation Analysis, is brief, less than 

one page long. The key components of the analysis are to develop an inventory of the soils and 

vegetation types with commercial or recreational value found in the area, and to analyze the impacts 

from regulated pollutants that are proposed to be emitted by the facility. We believe that this 

requirement only applies to regulated pollutants that are to be emitted from the facility in significant 

amounts. While an example related to fluorides is provided in Section II.C, an additional example 
AECOM Environment 5-2

analysis provided in Section III.C of the NSR Manual clearly states “...the sensitivity of the various 

soils and vegetation types to each of the applicable pollutants that will be emitted by the facility in 

significant amounts.” (pg D.11, emphasis added) While it may have appeared that the initial PHPP 

PSD application only focused on criteria pollutants and did not address the other PSD regulated 

pollutants (see Table A-4 in the 1990 NSR Manual), as noted on page 1-2 of this PSD application 

supplement, PHPP will only have significant emissions of NOx, VOC, CO, and PM/PM10/PM2.5, and 

hence the fact that the prior analysis only addressed modeled impacts of these pollutants is 

appropriate. As a clean, natural-gas fired project, PHPP will not emit any of the other regulated, noncriteria pollutants listed in Table A.4 of the NSR Manual in significant amounts. 

5.2 Extent of the Analysis 

The prior PSD soils and vegetation analysis conducted for the PHPP was performed for three 

pollutants: NOx, CO and PM10. The maximum modeled concentrations for PHPP normal operations 

are found in Table 6-6 of the 2009 PSD application. As shown in that table, the predicted annual 

NOx, as well as the 1-hour and 8-hour CO impacts did not exceed the EPA Significant Impact Level 

(SIL). Both the 24-hour and the annual PM10 impacts exceeded the EPA SIL. The peak PM10 

impact occurred at a distance of less than 400 meters from the project boundary, in a small area on 

the USAF Plant 42 property in a small area northeast of the power block. Therefore, the maximum 

extent of the SIA for these pollutants encompasses an approximately 400 meter radius around the 

combined-cycle facility, although PM10 impacts only occurred in a small area near developed 

industrial facilities. 

Because pollutant concentrations associated with Project air emissions are highest within this area, 

the analysis for the SIA provide conservative pollutant concentration values in regard to the regional 

facility impact. In addition, the SIA includes land use, terrain, soil type, and flora that is typical of the 

Antelope Valley in the western Mojave Desert. The SIA circle encompasses industrial land, 

undeveloped land, military land/airport, and commercial/light industrial properties. 

In addition to analyzing impacts within the SIA, soils and vegetation types with respect to the five 

sensitive Class II areas identified in Section 4 (i.e., three state parks, one woodland and one 

wilderness area located within 50 km of the proposed Project) are discussed. The locations of these 

areas relative to the proposed Project are shown in the previous section in Figure 4-1. Due to the 

substantial distance beyond the SIA, pollutant impacts in these areas are significantly lower than 

those in the area of maximum impact within the SIA. 

This supplemental soils and vegetation analysis provides additional information on the vegetation and 

soils inventory in the Project area and examines the potential effects of NOx, CO and PM10/PM2.5 

within the Project area on these soils and vegetation types. 

5.3 Vegetation Types 

Some agricultural crops are grown within the vicinity of the PHPP power plant site. As noted in the 

AFC, these crops include primarily commercial alfalfa and onion production. Agricultural/orchard 

lands lie about two miles northeast and east of the power plant site (see aerial view in Figure 2-1 of 

the AFC, which shows evidence of crop production). 

Within the defined 400 m SIA, the vegetation communities on the proposed PHPP site and immediate 

surrounding area can generally be classified as desert scrub, consisting primarily of perennial shrub 

species with an herbaceous understory of annuals that grows during the wetter and cooler spring 

months, as well as Joshua tree woodland. 
AECOM Environment 5-3

Focused botanical surveys of the proposed project areas (power plant site and laydown area) and 

perimeters of buffer zones conducted in 2006 and 2008 did not reveal the presence of any federal, 

state, or California Native Plant Society (CNPS)-list 1 or 2 sensitive plant species. An additional 

survey conducted in early and late spring of 2010, limited to the power plant site, laydown area, and 

reclaimed water supply pipeline and buffer areas around these project components, also did not 

detect any such listed species. Plant species protected by the City of Palmdale’s Native Desert 

Vegetation Ordinance were observed during these surveys. In particular, the Joshua tree (Yucca 

brevifolia) currently exists throughout the project site, although all of these trees on the PHPP site will 

be removed at the start of construction. 

The closest state parks or sanctuary are located approximately 14 miles east-north-east of the 

proposed Project, i.e., Antelope Valley Indian Museum State Park and Saddleback Butte State Park 

(see Section 4). The vegetation at Saddleback Butte State Park includes spring wildflowers, creosote 

bushes, cholla cacti and Joshua trees at lower elevations. The Antelope Valley Indian Museum State 

Park has vegetation indigenous to the area. The Antelope Valley California Poppy State Reserve is 

on the state’s most consistent poppy-bearing land. Other wildflowers growing there include owl’s 

clover, lupine, goldfield, cream cups, coreopsis, lacy phacelia, Davy Gilia, rabbit brush, red maids, and 

green grasses. The Arthur B. Ripley Desert Woodland State Park protects a major stand of native 

Joshua trees and junipers. This park is very near the Antelope Valley California Poppy Reserve State 

Natural Reserve and has similar wildflowers growing there. The Sheep Mountain Wilderness has 

grazing land, mining activities and is used for water-related recreational use. All of these areas are 

quite distant to PHPP, and hence given that the PHPP emissions are very low and the maximum 

impacts occur in the immediate vicinity of the power plant, there would be only de minimus impacts 

expected to the vegetation in these parks. 

No designated critical habitat areas for federally-listed species occurs within 20 miles of the power 

plant site. The closest Los Angeles County Significant Ecological Areas is the Little Rock Wash, 

which occurs about five miles to the east of PHPP power plant site. 

The analysis of the air pollutants on vegetation submitted with the April 2009 PSD application was 

performed using the EPA 1980 screening document. There is also a screening document developed 

by the U.S. Department of Agriculture (USDA) entitled, A Screening Procedure to Evaluate Air 

Pollution Effects in Region 1 Wilderness Areas, 1991. The 1991 document includes plant speciesspecific pollutant concentration thresholds for western U.S. species, as well as other information that 

complements the 1980 EPA guidance. The two referenced guidance documents have been reviewed 

to identify the most appropriate threshold values (if available) for this region based upon the species 

identified that have significant commercial or recreational value. 

Although the reference documents do not provide values for all of the identified species or pollutants, 

they do provide information about the alfalfa and onion field crops which are the primary crops in the 

vicinity of the project area. Based upon the information provided in Chapter 3 and Appendix B in A 

Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils and Animals, the alfalfa 

were found to be rated as “sensitive” to NO2 and the onions were found to be “resistant” to NO2. The 

“sensitive” rating means that the lowest damage threshold is applied. Based upon this information, 

the proposed impact analysis was based upon compliance with the threshold levels for “sensitive” 

vegetation that are identified in Table 3.1 of A Screening Procedure for the Impacts of Air Pollution 

Sources on Plants, Soils and Animals. These criteria are shown for the applicable pollutants (CO and 

NOx) in Table 6-17 of the April 2009 PSD application. 

In that table, the total modeled air concentrations for the proposed project plus ambient background 

concentrations are compared to the criteria to evaluate impacts. The total concentrations are well 
AECOM Environment 5-4

below the significance criteria for each pollutant and averaging time. Since no thresholds were 

exceeded, there is no potential for adverse impact on vegetation. This approach uses the most 

stringent level of damage threshold to assure conservative results, thus additional evaluation of 

impacts of air pollutants to vegetation is unnecessary. 

5.4 Soils 

5.4.1 Soil Types 

Soils on and around the PHPP site include Adelanto coarse sandy loam, Cajon loamy sand, and 

Cajon loamy fine sand. Section 5.12 Soils of the PHPP AFC includes a complete list of the soil types 

found in Los Angeles County and the Antelope Valley Area, where the proposed project will be 

located. 

5.4.2 Nitrogen Deposition 

In addition to the ambient pollutant exposure levels (that was evaluated in the March 2009 PSD 

application), plants have the potential to be affected by intake of air pollutants that have deposited and 

subsequently accumulated in the soil. Compared to the amount of published information on the 

effects of atmospheric pollution on plants and animals, relatively little has been reported on their 

effects on soils. Often the effect on soils can be seen in plants and animals such that the impacts to 

soil are secondary. For instance, if contaminated soil causes vegetative damage, the result could be 

increased erosion, increase in solar radiation reaching the ground, higher soil temperature and 

moisture stress. In agricultural and populated areas, intentional human actions taken to improve soils 

and assist vegetation growth, such as fertilization and application of insecticides, tend to have a much 

more direct and profound effect on soils than airborne pollutants. 

Nitrogen can be added to soil as a result of atmospheric deposition. Nitrogen deposition in soil can 

have beneficial effects to vegetation if they are currently lacking these elements. At levels above plant 

requirements, gaseous emission impacts on soils can cause acidic conditions to develop. Soil 

acidification and eutrophication can occur as a result of atmospheric deposition of nitrogen. 

Soil Acidification

Nitrogen deposition on proximal soils is expected to occur over time as a result of PHPP operations. 

As noted above, nitrogen deposition acts as a plant nutrient that can benefit soils, especially soils 

such as sandy loam that exists in the project area. However, this soil amendment can also be 

detrimental where it benefits non-native plants competing with native vegetation important to 

herbivores like the tortoise. For PHPP, no desert tortoises were found in the vicinity of the PHPP 

power plant. Also, as discussed above in Section 5.3, no sensitive vegetative communities have been 

identified in the vicinity of PHPP that would be expected to be negatively impacted by nitrogen 

deposition. 

Project emissions will contain nitrogen, mostly in the form of nitric oxide (NO). The NO will react in the 

air to form other compounds such as nitrogen dioxide (NO2) and nitrate (NO3) compounds. The 

combustion turbine generators and other combustion equipment associated with the Project have 

been estimated to emit up to 115 tons per year of NOx emissions, due to the combustion of natural 

gas and diesel fuels. Of the total NOx emissions, 35 tons of nitrogen per year would be the maximum 

amount of nitrogen deposited on soils situated near the Project site (assumes that all of the nitrogen 

emitted is deposited, rather than converted and transported out of the area, which is an extremely 

conservative assumption). 
AECOM Environment 5-5

The AERMOD modeling that has been done for PHPP does not provide estimates of nitrogen 

deposition. However, in 2008, an analysis of nitrogen deposition was done for the Victorville 2 (VV2) 

Hybrid Power Project (AECOM, 2008) using the CALPUFF model. The CALPUFF model, which was 

used for the PHPP to assess potential Class I area impacts (for areas beyond 50 km), incorporates 

the required atmospheric chemistry and chemical transformations necessary to compute nitrogen 

deposition. The total modeled nitrogen deposition rates are based on the sum of wet and dry fluxes of 

NO3 (as NH4NO3) and HNO3 in addition to dry deposition of NOX (assumed to be NO2). 

The CALPUFF model provides results in units of kilograms per hectare per year (kg/ha/yr). For the 

VV2 Project, nitrogen deposition was modeled at receptors which included the Project fence line and 

three nearby habitat areas of concern: riparian plant communities along the Mojave River, 

southwestern willow flycatcher critical habitat, and desert tortoise critical habitat (Fremont-Kramer 

Desert Wildlife Management Area). The maximum annual deposition rate of 0.083 kg/ha/yr was 

modeled to occur along the fence line to the northeast of the facility, consistent with the predominant 

winds which blow most frequently from the south and south-southwest. The maximum concentrations 

at the three habitat areas of concern were 0.033, 0.002, and 0.003 kg/ha/yr, respectively. 

Another way to state these nitrogen amounts in more easily understood units, is to convert them to 

pounds per unit area. For example, these estimated nitrogen amount correspond to annual modeled 

nitrogen deposition rates for the three areas in the VV2 Project region are as follows: 

• VV2 Power Plant fence line = 0.017 lbs / 10,000 ft2

• Riparian plant communities along the Mojave River (0.8 miles to the east of the power block) 

= 0.007 lbs / 10,000 ft2

• Southwestern willow flycatcher critical habitat (3.5 miles to the south-southeast of the power 

block) = 0.0004 lbs / 10,000 ft2

• Desert tortoise critical habitat (4.3 miles to the north-northwest of the power block) = 0.0006 

lbs / 10,000 ft2

Similarly, the maximum of 0.017 lbs per 10,000 ft2

 estimated for the VV2 Project plant fence line is 

equivalent to approximately 1.2 ounces of nitrogen per acre, with smaller amounts of nitrogen 

expected in areas located at a distance from the Project fence line. Such nitrogen deposition rates 

are considered negligible as a plant growth influence. Based on these results, nitrogen deposition 

associated with either the VV2 Project’s or the PHPP’s air emissions is expected to have a negligible 

impact on plants growing in the vicinity. The screening document mentioned in Section 5.3 above 

(USDA, 1991) indicates that shrubs and herbaceous plants will have “no injury” from nitrogen 

deposition below 3 kg/ha/yr. 

The PHPP is a hybrid solar-gas plant that is nearly identical to the VV2 Project. The predominant 

wind direction for PHPP is also to the northeast of the power block and there have not been any 

pertinent upgrades to the CALPUFF model since the analysis done in 2008. Given the similarities of 

the two projects, the fact that nitrogen deposition was modeled to be very low for VV2 Project, and 

since there are no federal habitat areas of concern near (within 20 miles) to PHPP, project-specific 

modeling for nitrogen deposition is not warranted. 

 
AECOM Environment 5-6

Soil Eutrophication

Eutrophication is an increase in the concentration of chemical nutrients in an ecosystem to an extent 

that increases the primary productivity of the ecosystem. Atmospheric deposition of nitrogen can 

facilitate eutrophication of the soil and vegetation community. 

A measure of the existing ambient deposition in the area was obtained from the most representative 

monitor (Death Valley) in the CASTNET monitoring network (EPA web site). This value is 2.2 kg/ha/yr 

for 2007. No screening thresholds to evaluate soil eutrophication were identified. Since the PHPP 

incremental annual nitrogen is expected to be very small (e.g., less than 1 percent of the ambient 

measured value), the effects of deposition on eutrophication is considered to be insignificant. 

5.5 References for Section 5 

AECOM, 2008. Exhibit C of the Victorville 2 Hybrid Power Project, Biological Assessment, Second 

Addendum, March. 

Environmental Appeals Board case: In re: Indeck-Elwood, LLC; PSD Appeal No. 03-04; PSD Permit 

No. 197035AAJ (decided September 27, 2006). 

EPA. http://www.epa.gov/castnet/. 

EPA, 1990. Draft New Source Review Workshop Manual, EPA OAQPS, October. 

EPA, 1980. A Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and 

Animals (EPA 450/2-81-078, OAQPS, Research Triangle Park, NC. December. 

U.S. Department of Agriculture, 1991. A Screening Procedure to Evaluate Air Pollution Effects in 

Region 1 Wilderness Areas. 
AECOM Environment 6-1

6.0 Receptor Grid Evaluation 

During the March 2010 conference call, EPA questioned whether the 20 km receptor grid used in the 

modeling to support the PSD Application would capture the maximum modeled impacts because the 

grid did not include the higher terrain found at distances beyond 20 km from the project site. A review 

of the modeled impacts for the PSD pollutants indicated that for the 1-hour modeling periods the 

ancillary equipment, such as the emergency generator, controlled the modeled impacts. For those 

modeling periods, where the combustion turbines were the primary contributors to the modeled 

impacts, the location of those impacts were reviewed and found to be along the eastern fence line or 

within 100 meters of the fence line, indicating that the maximum impacts were downwash driven, i.e., 

controlled by the building cavity effects of the HRSG’s, the steam generator, or the cooling tower. 

For further confirmation that the modeled impacts at receptors between 20 and 50 km from the PHPP 

site would not have terrain-driven impacts higher than those nearby the project site caused by 

proximity and building cavity effects, a receptor grid was developed spanning from 20 km to 50 km 

from the project site in 1,000-meter intervals. The two combustion turbines were then modeled with a 

unit emission rate (1 gram per second [g/s]) against the existing receptor grid and the 20 to 50 km grid 

for comparison. The ancillary equipment (emergency engines, heat transfer fluid (HTF) heaters, 

auxiliary boiler, cooling towers and maintenance vehicles) were not included in this modeling due to 

the nature of the sources, i.e., they have short stacks, are area sources, and/or have low exit velocity. 

With these characteristics, their impacts do not extend more than a few hundred meters from the 

project fence line and would therefore have no impact at receptors 20 km or more away. The results 

of the modeling for the original receptor grid, the 20 to 50 km grid, and a comparison of the two are 

shown in Tables 6-1, 6-2, and 6-3 below. As shown in Table 6-1, the maximum impacts from the 

combustion turbines within 20 km of the PHPP site range from double to fifty times higher than those 

at greater than 20 km depending on the period modeled. As the ancillary equipment will only 

contribute to the modeled impacts close to the facility, it can be concluded that the 20 km receptor grid 

is sufficient to capture the highest modeled concentrations. 

Table 6-1 Maximum Combustion Turbine Impacts per Unit Emission Within 20 km of 

PHPP 

Modeled Concentrations (μg/m3

) 

Period 

2002 2003 2004 Max 

1-hr 12.02 12.16 11.96 12.16 

3-hr 11.02 10.89 10.87 11.02 

8-hr 9.62 8.83 9.23 9.62 

24-hr 7.34 6.90 7.03 7.34 

Annual 1.23 1.09 1.12 1.23 

 
AECOM Environment 6-2

Table 6-2 Maximum Combustion Turbine Impacts per Unit Emission More Than 20 

km of PHPP 

Period 

Modeled Concentrations (μg/m3

) 

2002 2003 2004 Max 

1-hr 4.06 4.89 4.46 4.89 

3-hr 1.81 1.63 1.81 1.81 

8-hr 0.78 0.85 0.91 0.91 

24-hr 0.32 0.28 0.39 0.39 

Annual 0.02 0.02 0.01 0.02 

Table 6-3 Comparison of Maximum Modeled Impacts, Within 20 km vs. 20 to 50 km 

Period 

Maximum Modeled Unit Concentrations (μg/m3

) 

Within 20 km 20 to 50 km 

20 to 50 km impacts compared to 

impacts within 20 km 

(%) 

1-hr 12.16 4.89 40.2% 

3-hr 11.02 1.81 16.5% 

8-hr 9.62 0.91 9.4% 

24-hr 7.34 0.39 5.2% 

Annual 1.23 0.02 1.4% 
AECOM Environment 7-1

7.0 Growth Analysis 

Similar to the other sections above, EPA indicated during the March 2010 conference call that the 

analysis of impacts due to project inducing growth provided in the PSD application submitted on April 

1, 2009 was not sufficient. Specific guidance was not provided as to the improvements needed. 

Section 5.11, Socioeconomics, of the PHPP AFC (July 2008) analyzed the potential socioeconomic 

impacts of the construction and operation of the PHPP. It included an evaluation of Project-related 

impacts on public services and infrastructure, as well as an evaluation of environmental justice. The 

following assessment summarizes the findings of the Socioeconomics analysis that pertain to growth 

inducing impacts and also provides additional information regarding the growth inducing impacts 

associated with the provision of electricity. As defined by the California Environmental Quality Act 

(CEQA) Section 15126.2(d), growth inducing impacts of a proposed project shall address the ways in 

which the proposed project could foster economic or population growth or the construction of 

additional housing, directly or indirectly. This includes projects that would remove obstacles to growth 

and projects that would tax existing community service facilities such that construction of new facilities 

would be required. The PSD requirements for analyzing growth inducing impacts is specified at 40 

CFR 52.21(o) which requires simply that the owner provide an analysis of general commercial, 

residential, industrial and other growth associated with the source or modification. 

7.1 Summary of Growth Inducing Impacts Associated with Employment 

7.1.1 Construction Phase Population and Housing Impacts 

The Socioeconomics analysis in the AFC concluded that nearly 350,000 construction workers are 

available within the combined Los Angeles, Kern, and San Bernardino county region to serve the 

Project, which was estimated to require 767 employees. The proposed Project would therefore draw 

from the construction work force in the region. It was assumed that few, if any, construction workers 

would permanently relocate to the nearby communities of Palmdale, Lancaster, Lake Los Angeles, 

Santa Clarita, etc. during the Project construction phase. This is because construction workers 

typically commute relatively long distances to their work sites. Should some construction workers 

choose to stay temporarily at a local area motel or hotel, there are at least 30 hotels in the vicinity 

(Palmdale and Lancaster) with rooms available to meet this demand. Should a portion of the workers 

relocate to the area for the duration of their construction assignments, impacts to available housing 

and population would be minor, as vacancy rates in Palmdale and Lancaster are both estimated at 3.7 

percent. Construction impacts of the Project to population are therefore expected to be minimal, and 

the Project would not induce substantial population growth. Additionally, as the construction 

workforce is expected to either commute to the area or temporarily occupy the available supply of 

hotels or rentals in the area, the demand on the local housing supply is expected to be negligible. 

Construction of the Project would not result in a need for new housing. 

7.1.2 Operation Phase Population and Housing Impacts 

According to the Socioeconomics analysis in the AFC, the Project is expected to employ a total of 36 

workers during operation. Some of the Project operations jobs may involve relocation to the area for 

workers with specialized technical or managerial skills. However, as the overall size of the workforce 

needed for Project operation is small, population impacts would be less than significant, especially as 

some of these workers would likely already be residents of the local area. Further, due to the small 
AECOM Environment 7-2

number of workers needed for operation of the plant and the availability of local housing, operation of 

the Project is expected to have an insignificant impact on housing. 

7.2 Growth Inducing Impacts Associated with the Provision of Electric 

Power Generation 

The purpose of the Project is to generate 570 MW at the PHPP through a hybrid system of natural 

gas-fired combined-cycle generating equipment integrated with solar thermal generating equipment. 

The Project will be fueled with natural gas delivered via a new natural gas pipeline. The PHPP is 

designed to meet the current statutory and regulatory demands for cleaner, renewable electricity in 

place of more traditional fossil-fuel power generation sources, such as coal. 

California is actively pursuing policies to reduce GHG emissions that include adding non-GHG 

emitting renewable generation resources to the system mix (e.g., wind and solar). For example, 

Senate Bill 1078 established the California Renewables Portfolio Standard Program (RPS) program in 

2002 and required 20 percent renewable energy by 2017. In 2006, Senate Bill 107 codified an 

accelerated new deadline into law; 20 percent by 2010. Further, in 2008, Executive Order #S-14-08 

increased the goal again to 33 percent renewable energy by 2020. In addition, the Global Warming 

Solutions Act (Assembly Bill 32) was passed in 2006 and requires the California Air Resources Board 

(CARB) to develop regulations and mechanisms aimed to reduce California's greenhouse gas 

emissions by 25 percent by 2020. 

Because renewable energy technologies are subject to intermittent operation due to variations in the 

weather (e.g., low wind condition or cloud cover), it is important to consider the role and necessity of 

also adding fossil-fuel resources such as PHPP. The roles that PHPP can fill are as follows: 

1. Intermittent generation support 

2. Local capacity requirements 

3. Grid operations support 

4. Extreme load and system emergency 

5. General energy support. 

The Energy Commission staff-sponsored report reasonably assumes that non-renewable power 

plants added to the system would almost exclusively be natural gas-fueled. Nuclear, geothermal, and 

biomass plants are generally base load and not dispatchable. Solid fueled projects are also generally 

base load, not dispatchable, and carbon sequestration technologies needed to reduce the GHG 

emission rates to meet the EPS are not yet developed (CEC 2009). Further, California has almost no 

sites available to add dispatchable hydroelectric generation. 

High GHG-emitting resources, such as coal, are effectively prohibited from entering into new contracts 

for California electricity deliveries as a result of the Emissions Performance Standard adopted in 2007 

pursuant to SB 1368. Between now and 2020, more than 18,000 GWh of energy procured by 

California utilities under these contracts will have to reduce GHG emissions or be replaced. This 

represents almost half of the energy associated with California utility contracts with coal-fired 

resources that will expire by 2030. If the State enacts a carbon adder or carbon tax3

, all the coal 

 

3

 A carbon adder or carbon tax is a specific monetary value added to the cost of a project per ton of associated 

carbon or carbon dioxide emissions. Because it is based on, but not limited to, actual operations and emissions 
AECOM Environment 7-3

contracts may be divested at an accelerated rate as coal-fired energy becomes uncompetitive due to 

the carbon adder or the capital needed to capture and sequester the carbon emissions. As contracts 

expire, new and existing generation resources will replace the lost energy and capacity. Some will 

come from renewable generation; some will come from new and existing natural gas fired generation 

(CEC 2010). PHPP is a new plant that will support these goals. 

New resources like PHPP would also be required to provide generation capacity in the likely event 

that facilities utilizing once-through cooling (OTC) are retired. The State Water Resources Control 

Board (SWRCB) and EPA have proposed significant restrictions on the operation of OTC units, which 

will likely require retrofit, retirement, or significant curtailment of dozens of generating units. In 2008, 

the OTC units collectively produced about 58,000 GWh. While those OTC facilities owned and 

operated by utilities and recently-built combined cycles may well install dry or wet cooling towers, it is 

unlikely that the aging, merchant plants will do so. Most of these units operate at low capacity factors, 

suggesting a limited ability to compete in the current electricity market and rely on capacity contracts, 

offered as these facilities are needed for reliability. Although the timing would be uncertain, new 

resources are expected to out-compete aging plants, displace the energy provided by OTC facilities, 

and facilitate, if not accelerate their retirements. Any additional costs associated with complying with 

the SWRCB and EPA regulation would be amortized over a limited revenue stream today and into the 

foreseeable future. Their energy and much of their dispatchable, load-following capability will have to 

be replaced. These units constitute over 15,000 MW of merchant capacity and 17,800 GWh of 

merchant energy (CEC 2010). 

While the provision of energy supports population and housing growth, the development of power 

infrastructure responds to an already existing demand and projected population growth. For example, 

year 2000 U.S. Census Bureau results showed that the Los Angeles County population was 

9,519,331 (and estimated to be 9,848,011 in 2009). The year 2000 populations of neighboring Kern 

and Riverside Counties were 661,649 (estimated to be 807,407 in 2009) and 1,545,374 (estimated to 

be 2,125,440 in 2009), respectively. In addition, the Southern California Association of Governments 

(SCAG) adopted the Regional Transportation Plan (2008), which showed that the population of the 

SCAG Region (Imperial, Los Angeles, Orange, Riverside, San Bernardino, and Ventura Counties) 

increased by 2 million to 18.6 million in 2007 from the previous estimate in 2000 (a 12 percent 

increase). More growth occurred in the SCAG region between 2000 and 2007 than did throughout the 

1990’s (1.9 million). The 2008 Plan also estimated that the 2035 population in the SCAG Region will 

be 24 million. In addition, since the 2000 U.S. Census, there was a net addition of 410,000 

households to the SCAG region, which brought the regional total to approximately 5.8 million in 2007. 

These growth trends show that the Southern California region is expected to experience substantial 

population growth with or without implementation of the proposed PHPP. Rather than induce growth, 

the PHPP would supply energy in order to accommodate existing demand and already projected 

growth. 

Finally, according to recent Draft Environmental Impact Reports (DEIRs) prepared by the Kern County 

Planning Department for the Pacific Wind Energy and PdV Wind Energy Projects, recent judicial 

review also supports the conclusion that additional energy supports existing demands and already 

projected growth. Plaintiffs in the 2007 Kerncrest Audubon Society v. Los Angeles Department of 

Water and Power case argued that the Environmental Impact Report (EIR) prepared for the Pine Tree 

Wind Development Project did not adequately address growth-inducing impacts of the Project. They 

 

and can be trued up at year end, it is considered a simple mechanism to assign environmental costs to a 

project. 
AECOM Environment 7-4

argued that additional electricity generated by the Pine Tree Wind Development would result in 

additional growth in the Los Angeles area. The court, however, held that the additional electricity 

generated by the Project would meet the current forecast of growth in the Los Angeles area, and not 

cause growth. Therefore, it was not reasonable to require the EIR to include a detailed analysis of 

growth-inducing impacts. The conclusion reached in this case would apply equally to PHPP. 

7.3 References for Section 7 

CEC 2010. California Energy Commission Revised Staff Assessment for the El Segundo Power 

Redevelopment Project, CEC-700-2008-006-REV1, June 2010. 

CEC 2009. Framework for Evaluating Greenhouse Gas Implications of Natural Gas-Fired Power 

Plants in California, CEC-700- 2009-009, MRW and Associates. May 27, 2009. 

The California Energy Commission Renewables Portfolio Standards (RPS) Proceeding. 

http://www.energy.ca.gov/portfolio/index.html, accessed June 21, 2010. 

The California Energy Commission Implementing the Renewable Energy Executive Order. 

http://www.energy.ca.gov/33by2020/index.html, accessed June 21, 2010. 

The California Public Utilities Commission RPS Program Overview. 

http://www.cpuc.ca.gov/PUC/energy/Renewables/overview.htm, accessed June 21, 2010. 

California Environmental Protection Agency Air Resources Board. Assembly Bill 32: Global Warming 

Solutions Act. http://www.arb.ca.gov/cc/ab32/ab32.htm, accessed June 21, 2010. 

Los Angeles County 2000. U.S. Census data http://quickfacts.census.gov/qfd/states/06/06037.htm, 

accessed June 21, 2010. 

Kern County 2000. U.S. Census data http://quickfacts.census.gov/qfd/states/06/06029.html, 

accessed June 21, 2010. 

Riverside County 2000. U.S. Census data http://quickfacts.census.gov/qfd/states/06/06065.html, 

accessed June 21, 2010. 

Southern California Association of Governments 2008. Regional Transportation Plan Executive 

Summary http://www.scag.ca.gov/rtp2008/pdfs/finalrtp/f2008RTP_ExecSum.pdf, accessed June 21, 

2010. 

Southern California Association of Governments 2008 Regional Transportation Plan Chapter 2, 

Transportation Planning Challenges 

http://www.scag.ca.gov/rtp2008/pdfs/finalrtp/f2008RTP_Chapter2.pdf, accessed June 21, 2010. 

County of Kern. Environmental Documents. http://www.co.kern.ca.us/planning/eirs.asp, accessed 

June 21, 2010. 
AECOM Environment 8-1

8.0 Supplemental BACT Analysis 

During the March 2010 conference call, EPA indicated that while not needed as a completeness item, 

additional information for the control technology evaluation would assist EPA with completing the 

permit in a timely manner. Therefore, as requested by EPA, the Applicant has prepared a 

supplemental BACT analysis for specific emission sources at the PHPP. 

Specifically, EPA requested that the Applicant evaluate the following sources and control 

technologies: 

• Electrostatic Precipitator (ESP), baghouses, and cyclones on combustion turbine generators 

(CTG) and heat recovery steam generators (HRSG); 

• A BACT determination for CO emissions from the CTGs with and without duct burners; 

• A more complete top-down BACT analysis for the auxiliary boiler and HTF heater; and 

• SCR on fire-water pumps or other internal combustion engines. 

8.1 Methodology 

BACT is defined as the most stringent emission limitation or control technique which: 

• has been achieved in practice for such category or class of source; or 

• is contained in any state implementation plan (SIP) approved by the EPA for such category or 

class of source. A specific limitation or control technique shall not apply if the owner or 

operator of the proposed source demonstrates to the satisfaction of the Air Pollution Control 

Officer or designee that such limitation or control technique is not presently achievable; or 

• is any other emission limitation or control technique, found by the Air Pollution Control Officer 

or designee to be technologically feasible for such class or category of sources or for a 

specific source, and cost-effective as compared to measures as listed in an Air Quality 

Management Plan (AQMP) or rules adopted by a local or state agency. 

EPA guidance for a “top-down” BACT analysis requires reviewing the possible control options starting 

with the best control efficiency. In the course of the BACT analysis, one or more options may be 

eliminated from consideration because they are demonstrated to be technically infeasible or have 

unacceptable energy, economic, or environmental impacts on a case-by-case (site-specific) basis. 

The steps required for a “top-down” BACT review are: 

1. Identify available control technologies; 

2. Eliminate technically infeasible options; 

3. Rank remaining technologies; 

4. Evaluate remaining technologies (in terms of economic, energy, and environmental impacts); 

and 

5. Select BACT (the most efficient technology that cannot be rejected for economic, energy, or 

environmental impact reasons). 
AECOM Environment 8-2

A device-specific and pollutant-specific BACT determination is provided in the following subsections. 

Each BACT determination is made through the five-step process to identify available control 

technologies, eliminate technically infeasible options, rank and evaluate remaining technologies, and 

select BACT. 

8.2 Supplemental BACT for Combustion Turbines 

The proposed combustion turbines will operate in combined-cycle mode. In a combined-cycle 

configuration, hot exhaust from the CTG is ducted through a HRSG, which is also fired, to produce 

steam to drive a STG. Since the combustion turbine and HRSG are coupled together in a combinedcycle configuration, and exhaust through a single stack, they are considered to be one combustion 

train for purposes of this evaluation of emissions control. 

Because permitting activity within the past several years has resulted in lower emission standards for 

combined-cycle combustion turbines and a BACT analysis for the CTGs and HRSGs was prepared in 

the application that was submitted in April 2009, the database review focused only on determinations 

from April 2009 and later. The majority of determinations reviewed are based on exclusively natural 

gas-fired turbines. The determinations reviewed include combined-cycle turbines with a capacity 

greater than 100 MW. Section 8.2.1 discusses add-on particulate controls for the CTG and HRSG 

system. Section 8.2.2 evaluates CO emissions from the CTGs and HRSGs with and without duct 

burners. 

8.2.1 Evaluation of Add-on Particulate Controls for the Combustion Turbines and 

HRSG 

Unlike other criteria pollutants, particulate matter (PM, PM10, and PM2.5) includes a wide range of 

particle sizes and chemical constituents. PM consists of mostly nitrates, sulfates, ammonium, 

elemental carbon, and organic and inorganic compounds. PM can be emitted directly from their 

sources as particles, or produced as secondary particles by complex atmospheric reactions from 

precursor gases. SOx and NOx are currently viewed as the most significant precursors to PM; in 

southern California, PM contains more nitrates than in other areas of the countries (STAPPA 2006). 

Since PHPP has already applied BACT for NOx and SOx emissions (as well as other criteria 

pollutants) such that the secondary formation of PM is controlled with BACT, additional control of 

precursor gases will not be discussed herein. 

8.2.1.1 Identification of Available Technologies 

Step 1 of the five step, top-down BACT determination process is the identification of available control 

technologies. Particulate matter from natural gas combustion has been estimated to be less than one 

micron in size and has filterable and condensable fractions. In addition, AP-42 estimates the 

condensable fraction to be 75 percent of the total particulate emissions from natural gas combustion 

(EPA 2000). Note that because PM, PM10 and PM2.5 emissions generally result from impurities in 

the natural gas or combustion air, the controls recommended as BACT for normal operations would 

also represent BACT during startup and shutdown. Therefore, a separate evaluation of BACT for 

these transient periods was not performed. 

Publicly-available information on emission control technologies was reviewed as the first step of this 

analysis. Databases reviewed include South Coast Air Quality Management District (SCAQMD) 

BACT/lowest achievable emission rate (LAER) Guidelines, EPA’s Reasonably Available Control 

Technology/BACT/LAER Clearinghouse (RBLC), and recent or pending projects in the CEC 

database. Note, AVAQMD does not maintain a separate BACT database. A summary of recent 

RBLC evaluations is provided in Appendix B. Because of the limited number of applications in which 
AECOM Environment 8-3

add-on controls have been applied to PM2.5 emission sources, AECOM expanded its investigation to 

include a review of EPA guidance for particulate emissions controls, internet-based research, and 

general knowledge of emission control technologies based on industry experience. 

EPA divides the PM2.5 control options into four different categories (STAPPA 2006): 

1. Combustion of clean fuels; 

2. Combustion control technologies; 

3. Post-combustion control technologies; and 

4. Multi-pollutant control technologies. 

As PHPP has already proposed to combust pipeline-quality natural gas fuel, and to control 

combustion pollutants by applying BACT for NOx, SOx, CO, VOC and PM10, the cleanest selections 

for options 1 and 2 have already been satisfied and will not be discussed in detail. Additionally, EPA 

discusses the options and cost effectiveness of controlling PM2.5 with multi-pollutant control 

technologies rather than single-pollutant controls. The multi-pollutant controls proposed by EPA were 

not applied to natural gas fired equipment and, therefore, are not applicable to the CTGs and HRSGs 

at PHPP (STAPPA 2006). 

Based on this research, the post-combustion control technologies potentially available for PM, PM10 

and PM2.5 emissions from natural gas-fired equipment including CTGs and HRSGs at combinedcycle power facilities are listed below, in no particular order: 

• Cyclone or multi-clone; 

• Venturi (wet) scrubber; 

• Electrostatic precipitator; 

• Baghouse; 

• Pipeline-quality natural gas fuel; and 

• Good engineering (combustion and maintenance) practice. 

A description of the principle of operation and general limitations for cyclones or multi-cyclones, 

venturi scrubbers, electrostatic precipitators and baghouses is presented below. 

Cyclone 

Cyclones use centrifugal and inertial forces to separate particulates from gas streams. The cyclone 

imparts centrifugal force on the gas stream and operates by creating a double vortex inside the 

cyclone body. The incoming gas is forced into circular motion down the cyclone near the inner 

surface of the cyclone tube, turning at the bottom of the tube, spiraling up through the center and out 

the top of the cyclone (EPA 2003a). 

The centrifugal force of the spinning gas battles with inertial drag force of the gas traveling though the 

cyclone to force the particulates towards the cyclone walls. The inertial momentum of the larger 

particles is able to overcome the drag forces, so the particulates reach the walls and are collected at 

the bottom of the cyclone. Gravity also helps the larger particles reach the bottom to be collected. 

With smaller particulates, the centrifugal and gravitational forces are overcome by the inertial drag 

force and the smaller particulates are carried out of the top of the cyclone with the exiting gas 

(EPA 2003a). 
AECOM Environment 8-4

The collection efficiently of cyclones vary with particle size and cyclone design. The collection 

efficiency is dependent on multiple factors such as particle size, particle density, inlet duct velocity 

cyclone length, dust loading, and number of gas revolutions in the cyclone. Note that the centrifugal 

force in, and hence efficiency of, a cyclone increases with the gas flow rate through the cyclone. 

Cyclones on CTGs and HRSGs are most effective at high flue gas flow rates, with collection efficiency 

decreasing at lower flow rates (ICAC 2010). 

Cyclones are primarily used to control PM larger than 10 microns, but multiple cyclones can be used 

to achieve high control efficiencies for small particulates. A multiple cyclone is an array of a large 

number of small (several inch diameter) cyclones in parallel. Multiple cyclones have overall mass 

removal efficiencies of 70 to 90 percent. However, cyclone collection efficiencies fall off rapidly with 

particle size, so that control of fine particulate (PM2.5) is limited. While no accurate statement of 

collection efficiency can be made without precise details of the cyclone design and particulate 

properties, cyclone removal efficiencies will be 90 percent or greater for PM10, dropping to perhaps 

70 percent for PM2.5, and 50 percent for one micron particles. Addition of a second multiple cyclone 

in series with the first will allow for increased removal efficiency. 

Venturi Scrubbers 

The operation of venturi (wet) scrubbers as based on the collection of particles in liquid droplets. A 

venturi scrubber is designed for optimal gas-liquid contact, between the waste gas and the scrubbing 

liquid, and optimal droplet formation. A “throat” section is built into the duct that forces the gas stream 

to accelerate as the duct narrows and expands. As the gas enters the venturi throat, both gas velocity 

and turbulence increase. Depending on the scrubber design, the scrubbing liquid is sprayed into the 

gas stream before the gas encounters the venture throat, or in the throat or upwards against the gas 

flow in the throat. The scrubbing liquid is then atomized into small droplets by the turbulence in the 

throat and droplet-particle interaction, which is responsible for particulate collection, is increased. 

After the throat section, the mixture decelerates, and further impacts occur causing the droplets to 

agglomerate. Once the particles have been captured by the liquid, the wetted PM and excess liquid 

droplets are separated from the gas stream by an entrainment section, which usually consists of a 

cyclonic separator and/or mist eliminator (EPA 2003a). Typically, venturi scrubbers are applied to 

control emission sources with high concentrations of submicron PM. Venturi scrubbers PM collection 

efficiencies range from 70 percent to greater than 99 percent depending on the application and are 

effective in controlling both PM less than or equal to 10 microns in diameter (PM10) and PM2.5 

(EPA 2003b). The control efficiency increases with increased pressure drop, which also increases 

operating costs. 

One consideration for venturi scrubbers is that the process generates waste in the form of a slurry or 

wet sludge and creates the need for both wastewater treatment and solid waste disposal, which can 

be costly. 

Electrostatic Precipitators 

Electrostatic precipitators use electrical fields to remove particulate matter from CTG and HRSG flue 

gas. Because precipitators act only on the particulate to be removed, and only minimally hinder flue 

gas flow, they have very low pressure drops, and thus low energy requirements and operating costs. 

In an electrostatic precipitator, an intense electric field is maintained between high-voltage discharge 

electrodes, typically wires or rigid frames, and grounded collecting electrodes, typically plates. A 

corona discharge from the discharge electrodes ionizes the gas passing through the precipitator, and 
AECOM Environment 8-5

gas ions subsequently ionize other particles. The electric field drives the negatively charged particles 

to the collecting electrodes. Periodically, the collecting electrodes are rapped mechanically to 

dislodge collected particulate, which falls into hoppers for removal. 

While several factors determine electrostatic precipitator removal efficiency, precipitator size is of 

paramount importance. Size determines treatment time: the longer a particle spends in the 

precipitator, the greater its chance of being collected, other things being equal. 

Precipitator size also is related to the specific collection area (SCA), the ratio of the surface area of the 

collection electrodes to the gas flow. Collection areas normally are in the range of 200 to 800 square 

feet per 1000 actual cubic feet per minute (ft2/1000 acfm). In order to achieve collection efficiencies of 

99.5 percent, specific collection areas of 350 to 400 ft2/1000 acfm are typically used (ICAC 2010). 

Higher collection areas lead to better removal efficiencies. 

Factors limiting precipitator performance are flow non-uniformity, reentrainment, and particle 

resistivity. More uniform flow will ensure that there are no high gas velocity, short treatment time 

paths through the precipitator. Attaining flow uniformity also will minimize "sneakage," or gas flows 

bypassing the electrical fields. Reentrainment of collected particles may occur during rapping. Proper 

rapper design and timing will minimize rapper reentrainment. Maintenance of appropriate hopper ash 

levels and of flow uniformity will minimize reentrainment of ash from the hoppers. 

A key determinant of electrostatic precipitator collection efficiency is the resistivity of the particles to 

the flow of electric current, which affects the collection efficiency. Particles with resistivity in the range 

of 107 - 1010 ohm-centimeters (ohm-cm) are amenable to collection with precipitators: these particles 

are easy to charge, and only slowly lose their charge once deposited on a collecting electrode. 

Particles with low resistivity (less than 107 ohm-cm), on the other hand, lose their charge to a 

collecting electrode so rapidly that they tend not to adhere to the electrode, resulting in high rapping 

reentrainment losses. Highly carbonaceous particulate matter from natural gas combustion is an 

example of a low resistivity material. 

Particles with high resistivity (greater than 1010 ohm-cm) can be difficult to remove with an ESP since 

such particles are not easily charged, and thus are not easily collected. High-resistivity particles also 

form particulate layers with very high voltage gradients on the collecting electrodes. Electrical 

breakdowns in these layers lead to injection of positively charged ions into the space between the 

discharge and collecting electrodes ("back corona"), thus reducing the charge on particles in this 

space and lowering collection efficiency. 

Electrostatic precipitator overall (mass) collection efficiencies can exceed 99.9 percent, and 

efficiencies in excess of 99.5 percent are common. Precipitators with high overall collection 

efficiencies will have high collection efficiencies for particles of all sizes, so that excellent control of 

PM10 and PM2.5 will be achieved with well designed and operated electrostatic precipitators. 

Precipitator collection efficiencies will be somewhat lower for particles with diameters near 0.3 

microns. The reason for a minimum in collection efficiency for 0.3 micron particles is that both particle 

charge and the resistance of the gas to particle motion both increase with particle size. Near 0.3 

micron, the particle charge is low enough and the resistance to particle motion is high enough that 

particles are collected relatively poorly. In practice, however, this effect means only that a precipitator 

with a 99.9 percent overall mass collection efficiency will collect over 90 percent of 0.3 micron 

particles, and over 97 - 98 percent of all zero to five micron particles (ICAC, 2010). 
AECOM Environment 8-6

Baghouses 

The Institute of Clean Air Companies describes the operation of baghouses as “conceptually simple: 

by passing flue gas through a tightly woven fabric, particulate in the flue gas will be collected on the 

fabric by sieving and other mechanisms.” The dust cake which forms on the filter from the collected 

particulate can contribute significantly to collection efficiency. 

Practical application of fabric filters requires the use of a large fabric area in order to avoid an 

unacceptable pressure drop across the fabric. To provide a large fabric area in a small space, the 

fabric is formed into cylindrical bags (hence the term baghouse). Each bag may be 20 to 30 feet long 

and 5 to 12 inches in diameter, and a baghouse contains multiple bags to provide sufficient fabric 

surface area for dust collection. For example: a 250 MW coal-fired utility boiler may have 5,000 

separate bags with a total fabric area approaching 500,000 square feet (ICAC 2010). 

Baghouse size for a particular unit is determined by the ratio of air flow to cloth area, typically 

expressed in feet per minute (cubic feet per minute of flow divided by square feet of fabric area). The 

selection of air-to-cloth ratio depends on the particulate loading and characteristics, and the cleaning 

method used. A high particulate loading will require the use of a larger baghouse in order to avoid 

forming too heavy a dust cake, resulting in an excessive pressure drop. 

Baghouses often are capable of 99.9 percent removal efficiencies. Baghouse removal efficiency is 

relatively level across the particle size range, so that excellent control of PM10 and PM2.5 can be 

obtained. 

Determinants of baghouse performance include fabric selection, the cleaning frequency and methods, 

and the particulate characteristics. Fabrics can be chosen which will intercept a greater fraction of 

particulate, and some fabrics are coated with a membrane with very fine openings for enhanced 

removal of submicron particulate. 

Cleaning intensity and frequency are important variables in determining removal efficiency. Because 

the dust cake can provide a significant fraction of the fine particulate removal capability of a fabric, 

cleaning which is too frequent or too intense will lower the removal efficiency. On the other hand, if 

removal is too infrequent or too ineffective, then the baghouse pressure drop will become too high. 

Baghouses are useful for collecting particles with resistivity either too low or too high for collection with 

electrostatic precipitators. Baghouses therefore may be good candidates for fly ash containing high 

unburned carbon levels, which have low resistivity, and thus are relatively difficult to collect with 

electrostatic precipitators” (ICAC 2010). 

8.2.1.2 Technical Feasibility 

Step 2 of the five step, top-down BACT determination process is the elimination of infeasible options. 

From the discussion of operating methods above, it can be concluded that cyclones or multi-clones 

are not feasible as they are inefficient for particles less than one to three microns (EPA 1999). 

As this facility will be located in the desert where water is scarce and consumption needs to be 

minimized, the use of any wet technology, e.g., wet or venturi scrubbers or wet electrostatic 

precipitators would have adverse environmental impacts to water resources. In addition, due to the 

impurities in the water in this desert area, a wet scrubber could have PM2.5 emissions from drift 

(similar to a cooling tower) that might exceed the PM2.5 emissions that it was intended to remove. 
AECOM Environment 8-7

For these reasons, wet technologies are determined to be technically infeasible and have 

unacceptable environmental impacts, and have been eliminated from further consideration. 

With dry electrostatic precipitators, there is a difficult-to-control range between 0.1 to 1.0 microns due 

to the size-dependent limitations of both of the contact and diffusing charging mechanisms. The 

precipitator is least effective for the particles in this size range. In industrial sources that generate 

highly carbonaceous particulate matter (e.g., natural gas combustion), the particulate resistivity can be 

extremely low due to the high bulk conductivity of this material at all temperatures. These resistivities 

can be below the levels where good performance can be obtained by flue gas conditioning. Severe 

rapping reentrainment problems can persist during routine operation due to the weak electrical forces 

bonding the dust layer to the collection plate and the ease of particle dispersion during rapping. 

Electrostatic precipitators are not an ideal choice for particulate matter control in these applications 

due to the probable emission problems (EPA 1999). Based on this information, although dry 

electrostatic precipitators do not appear to be an ideal choice, they cannot be considered technically 

infeasible and will be evaluated further. 

A baghouse would not be able to capture condensable particulates, which may be as much as 75 

percent of the total particulate emissions from natural gas combustion, according to EPA (EPA 2000). 

With the exhaust air flow being approximately 1,000,000 cubic feet per minute, the amount of filter 

area required could be on the order of 125,000 square feet. The pressure drop across such a large 

area could require a significant amount of energy to overcome. Due to the very low PM loading in the 

exhaust stream, the time that would be needed to establish residual dust cake on the surfaces of the 

fabric is a significant concern. As discussed above, it is the dust cake that is ultimately responsible for 

the high efficiency particulate matter removal. The particles on the fabric surface are termed the 

residual dust cake because they remain after normal cleaning of the bag (EPA 1999). Based on this 

information, although baghouses do not appear to be an ideal choice, they cannot be considered 

technically infeasible and will also be evaluated further. 

Based on the available information, use pipeline-quality natural gas fuel and good engineering 

(combustion and maintenance) practice have been achieved in practice and thus cannot be 

eliminated from further consideration. 

8.2.1.3 Rank Remaining Technologies 

Step 3 of the five step, top-down BACT determination procedure is to rank the remaining 

technologies. Of the six potential control technologies identified for evaluation, two technologies have 

been eliminated from consideration as technically infeasible: cyclones and wet venturi (wet) 

scrubbers. Based on the qualitative information available, the remaining technologies are ranked in 

order of expected control effectiveness, as follows: 

1. Baghouse; 

2. Electrostatic precipitator; 

3. Pipeline-quality natural gas fuel; and 

4. Good engineering (combustion and maintenance) practice. 

Note that there is limited information available on the effectiveness of either a baghouse or 

electrostatic precipitator for PM2.5 emissions, thus the ranking is speculative for these two 

technologies. 
AECOM Environment 8-8

8.2.1.4 Evaluate Technologies 

Step 4 of the five step, top-down BACT determination procedure is to evaluate the remaining 

technologies on the basis of economic, energy, and environmental impacts. For this analysis, the 

economic considerations are evaluated first. 

State law (California Health and Safety Code [HSC] §40405) defines BACT as the lowest achievable 

emission rate which is the more stringent of either 1) the most stringent emission limitation contained 

in the SIP, or 2) the most stringent emission limitation that is "achieved in practice". There is no 

explicit reference to or prohibition on cost considerations. 

When evaluating costs of pollution control equipment, the term “cost effectiveness” is often used. As 

no definition of what is considered cost-effective within the AVAQMD was found, the SCAQMD’s “cost 

effectiveness” definition was used in this analysis. Cost effectiveness is defined by the SCAQMD to 

mean: 

“Cost effectiveness is measured in terms of control costs (dollars) per air emissions 

reduced (tons). If the cost per ton of emissions reduced is less than the maximum 

required cost effectiveness, then the control method is considered to be cost 

effective” (SCAQMD 2000). 

While the AVAQMD does not discuss cost effectiveness, guidance is available from several relevant 

sources, as explained below. 

• SCAQMD guidelines do not allow for routine consideration of the cost of control in 

BACT/LAER determinations for major sources of air pollutants; however, if a proposed BACT 

determination results in extraordinary costs to a facility, the applicant may bring the matter to 

SCAQMD management for consideration. 

• The SCAQMD does allow consideration cost effectiveness when BACT is established for 

minor sources. 

• EPA guidelines state that BACT is not considered achievable if the cost of control is so great 

that a new source could not be built or operated with a particular control technology; however, 

if a facility in the same or comparable industry already uses the control technology, then such 

use constitutes evidence that the cost to the industry is not prohibitive. 

• Several air districts in California have established guidelines for cost effectiveness in BACT 

determinations, as shown in Table 8-1. 

Table 8-1 Cost Effectiveness for PM10 

Agency $/ton of Emissions Reduced 

SJVAPCD $11,400 

SCAQMD1 $4,950 

BAAQMD $5,300 

1. The SCAQMD lists the value in 2003 dollars and requires that the value be adjusted 

using the Marshall & Swift cost index. The cost effectiveness value shown reflects 

the adjustment to 2009 dollars using the adjustment factor of 1.1. (Note: The 2010 

Marshall & Swift cost index is not yet available) 
AECOM Environment 8-9

In the absence of specific guidance from the AVAQMD or EPA, it is assumed that EPA would take into 

consideration the cost of controls, if those controls were prohibitively expensive.

In absence of published cost-effectiveness values for controls on natural gas fired combustion 

turbines, cost estimates were compiled from a number of data sources, including the cost estimating 

methodology followed guidance provided in the EPA Air Pollution Cost Control Manual, published 

information available from equipment vendor and equipment costs recently developed for similar 

projects (EPA 2002), and the STAPPA/ALAPCO document Controlling Fine Particulate Matter Under 

the Clean Air Act: A Menu of Options (STAPPA 2006). For costing, it was assumed that each 

combined CTG and HRSG units would require one pollution control device; the two natural gas-fired 

CTGs and two HRSGs for the Project would require two PM control devices. 

Capital costs include the equipment, material, labor, and all other direct costs needed to install the 

control technologies. Operating and Maintenance (O&M) costs were developed for each control 

system; only fixed operating costs were considered. Fixed O&M costs include operating labor, 

maintenance labor, maintenance material, and administrative labor. Variable O&M costs including the 

cost of consumables, including reagents (if applicable), and byproduct management were not 

considered for this cost analysis. Utility consumption, such as additional water and power 

requirement, and replacement parts were also not considered in the O&M costs. The calculated 

capital costs and operating costs are presented in Table 8-2. More detailed cost calculations are 

provided in Appendix C. 

Table 8-2 Estimated Costs for PM Controls1

Control Device 

Annualized 

Capital Costs 

($/yr) 

O&M Costs 

($/yr) 

Total Annualized 

Costs 

($/yr) 

Electrostatic Precipitator - 99% Control $2,430,489 $5,728,003 $8,158,492 

Baghouse - 99% Control $1,093,720 $6,873,604 $7,967,324 

1. Cost is based upon the air flow required through the control devices. 

In order to estimate cost effectiveness, the total annualized cost of the control devices were divided 

over 99 percent of the emissions from the CTG and HRSG units. As shown in Table 8-2, the lowest 

calculated cost effectiveness value for 99 percent control efficiency is in excess of $135,000 per ton 

reduced, for either technology. Since AVAQMD does not have cost effectiveness thresholds, for this 

analysis, the highest cost effectiveness value of $11,400 per ton from the SJVAPCD is used for 

comparison. 

Table 8-3 Combustion Turbine Cost Effectiveness and Degree of Control 

Control Device 

Cost 

Effectiveness 

($/ton PM) 

SJVAPCD BACT Cost 

Effectiveness 

Threshold 

($/ton PM) 

Cost 

Effective 

(Yes/No?) 

Electrostatic Precipitator - 99% Control $140,750 $11,400 No 

Baghouse - 99% Control $137,450 $11,400 No 
AECOM Environment 8-10

As shown in Table 8-3, electrostatic precipitators and baghouses exceed the SJVAPCD BACT cost 

effectiveness threshold and, therefore, electrostatic precipitators and baghouses are not cost effective. 

8.2.1.5 BACT Determination 

Based on this evaluation, cyclone or multi-clone and venturi (wet) scrubbers were determined to be 

technically infeasible and electrostatic precipitators and baghouses are determined to be not cost 

effective. A review of BACT determinations by the EPA and CARB since the original application was 

submitted in April indicate that no agency has required installation of add-on controls for PM10 or 

PM2.5. 

The most specific reference to how to minimize PM10 or PM2.5 emissions from low sulfur fuel and 

good combustion practices was found in RBLC ID FL-0303 for the Florida Power and Light 

Company’s West County Energy Center Unit 3. The Pollutant/Compliance Notes state: 

“The sulfur fuel specifications combined with the efficient combustion design and 

operation of each CTG represents BACT for PM/PM10/PM2.5 emissions. 

Compliance with the fuel specifications, CO standards, and visible emissions 

standards shall serve as indicators of good combustion. Compliance with the fuel 

specifications shall be demonstrated by keeping records of the fuel sulfur content. 

Compliance with the visible emissions standard shall be demonstrated by conducting 

tests in accordance with EPA Method 9 (EPA, 2010).” 

The lowest levels of PM10 emissions listed for similar combined-cycle turbines that use pipelinequality natural gas and good combustion practices in the SCAQMD BACT Guidelines include 

Magnolia Power and Vernon City Power & Light which were discussed in the original PSD Application, 

which was submitted in April 2009; thus the BACT determination for PM, PM10 and PM2.5 the CTGs 

and HRSGs have not changed since the original application. 

Based upon the results of the RBLC data search discussed previously, the use of low sulfur fuel, i.e., 

pipeline-quality natural gas, and good combustion practices can be considered achieved in practice. 

Therefore, the use of pipeline-quality natural gas and good combustion practices is determined to be 

BACT for the CTG and HRSGs. The applicant has proposed those technologies, low sulfur fuel and 

good combustion practices, for the control of PM, PM10 and PM2.5 emissions. 

As the equipment and BACT determination has not changed since the application was submitted in 

April 2009, the proposed hourly mass emissions limits for the CTGs and HRSGs still represent BACT. 

The proposed hourly mass emissions limits for two turbines are 12 pounds per hour when the duct 

burners are off and 18 pounds per hour when the duct burners are on, with the exclusive use of 

pipeline-quality natural gas. 

8.2.2 BACT for CO Emissions from the Combustion Turbines and HRSGs 

PHPP has previously proposed to use an oxidation catalyst with good combustion practice to control 

CO emissions from the CTGs and HRSGs. PHPP originally proposed CO emissions limits of 2.0 

ppmv dry, corrected to 15 percent O2 over a one-hour averaging time without duct burners, and 3.0 

ppmv dry (corrected to 15 percent O2) over a one-hour averaging time when duct burners are firing 

through the use of an oxidation catalyst. The selection of control technology has not been disputed; 

however, at the request of EPA, the Applicant has reevaluated the emission limits when duct firing is 

utilized. 
AECOM Environment 8-11

This supplemental BACT discussion focuses on the achievable CO emission limits and averaging 

periods for oxidation catalyst on CTGs with and without duct burners. Only emission limits below the 

previously proposed limits and findings after the application was submitted in April 2009 will be 

discussed. All systems permitted for 2 ppm CO or less employ oxidation catalyst to control CO. 

Since the original application was submitted April 2009, no additional facilities were listed in the RBLC 

with permitted emissions limits below 2.0 ppm for CO from similar natural gas fired combined-cycle 

turbines. The power projects with proposed CO limits of less than 2 ppm were all permitted after April 

2009 and currently are either not on-line or have not been constructed; therefore, these proposed 

limits have not been verified through performance testing. 

A database review of the pending projects in the CEC database identified the GFW Tracy Combined 

Cycle Power Plant Project. The Final Staff Assessment for this project was released on October 30, 

2009. This project would install two CTG and HRSG systems equipped with natural gas-fired duct 

burners controlled with a new higher efficiency oxidation catalyst system to limit the CO concentration 

to 2.0 ppmvd at 15 percent O2 with a one-hour rolling average period (CEC 2009). Similar to the 

GFW Tracy Combined Cycle Power Plant Project, the to 2.0 ppmvd at 15 percent O2 with a one-hour 

rolling average period should be considered as BACT for PHPP. 

It is noted in the March 2009 PHPP PSD Application that the use of the Rapid Start Process (RSP) 

requires some modification of the CTG and HRSG to maintain the tighter seals and rapid temperature 

change. PHPP will also have relatively large duct burners. These differences make it more difficult to 

ensure that a low 2.0 ppmv emission limit can be met as there are no comparable operating power 

plants at which this limit is demonstrated in practice. However, based on this BACT review, the 

Applicant is willing to agree to a CO BACT emission limits of 2.0 ppmv dry, corrected to 15 percent O2

over a one-hour averaging time both without duct burners and when duct burners are firing. This 

emission limit will be achieved with use of an oxidation catalyst. 

8.3 BACT Determination for Boilers and HTF Heaters 

The proposed Project will include a 110 MMBtu/hr auxiliary boiler and a 40 MMBtu/hr HTF heater. 

Both will be fired on pipeline-quality natural gas. The auxiliary boiler will operate a maximum of 500 

hours per year, and the HTF heater will operate no more than 1,000 hours per year. The auxiliary 

boiler is primarily designed to shorten the duration of start-ups as part of GE’s RSP technology; 

therefore, the boiler itself is part of the control technology designed to minimize emissions during startup of the combustion turbines. The boiler and heater emit criteria pollutants (NOx, SOx, CO, VOC, 

PM10, and PM2.5) due to the combustion of natural gas. 

EPA specifically requested a more complete top-down BACT analysis for the auxiliary boiler and HTF 

heater; this section contains BACT determinations for NOx, CO, PM/PM10/PM2.5, and VOC. PHPP 

is not a major source of SOx and, therefore, a SOx analysis was not conducted, although it is likely 

that the use of pipeline quality natural gas as fuel would also be determined to be BACT for SOx. 

Because the auxiliary boiler and the HTF heater are similar sources, the BACT analyses for those 

units are combined. A BACT analysis was provided in the original application, which was submitted in 

April 2009; therefore, the information review was focused only on BACT determinations from April 

2009 and later. 
AECOM Environment 8-12

8.3.1 NOx 

NOx is formed during combustion through two primary mechanisms: 

1. Thermal NOx, which is the oxidation of elemental nitrogen in combustion air; and 

2. Fuel NOx, which is the oxidation of fuel-bound nitrogen. 

Since natural gas is relatively free of fuel-bound nitrogen, the contribution of this second mechanism 

to the formation of NOx emissions in natural gas fired equipment is minimal and thermal NOx is the 

chief source of NOx emissions. Since fuel-bound NOx minimal from the combustion of natural gas, 

additional controls for fuel-bound NOx will not be discussed in this BACT analysis. 

There are two basic means of controlling thermal NOx emissions from boilers: combustion controls 

and post-combustion controls. Combustion controls act to reduce the formation of NOx during the 

combustion process, while post-combustion controls remove NOx from the exhaust stream. 

Combustion control technologies for this type of boiler application include low-NOx burners, flue gas 

recirculation and staged combustion. Post-combustion controls include Selective Catalytic Reduction 

(SCR), non-catalytic reduction (SNCR). The technologies employed for NOx emissions control are 

listed below and discussed in descending order of effectiveness: 

• SCR; 

• SNCR; 

• Ultra-low NOx burners; 

• Low-NOx burners with flue gas recirculation (FGR); 

• Flue gas recirculation; and 

• Good combustion practice.

Selective Catalytic Reduction (SCR) 

SCR was mentioned as an alternative control technology for boilers by the BAAQMD in their BACT 

guidance document. SCR is known to successfully control NOx to very low concentrations in large 

furnaces and boilers, although there is little evidence that this technology has been applied to boilers 

or heaters less than 50 MMBtu per hour. One key limitation relative to the technical feasibility of SCR 

for the proposed boiler is that the temperature of the exhaust gas (~300°F [148.89°C]) will be below 

the lower end of the proper temperature range for the SCR catalyst (~500°F [260°C]). The auxiliary 

boiler will be operated to shorten the duration of start-ups as part of GE’s RSP technology and will be 

operated only up to 500 hours per year. The HTF heater will only be operated for 1,000 hours per 

year. Most of the boiler operation is expected to be at a low load, where the exhaust gas temperature 

will be below the minimum needed for effective SCR control. While the boiler and HTF heater will 

operate at full load periodically, the length of time at which the boiler and HTF heater will operate are 

expected to be so short that the SCR system would rarely come to full operating temperature and 

would rarely, if ever, achieve design control efficiency. 

SCR also requires a substantial capital investment for the catalyst bed, additional power for operations 

(additional blower power is required to overcome the pressure drop in the catalyst bed), and the use 

of hazardous aqueous or anhydrous ammonia as the reducing agent. Based on the database review 

of boilers with similar heat rates, SCR is not used for NOx control on natural gas fired boilers in the 

size range of the proposed units, as evidenced by the large number of applications cited that use low 

NOx or ultra-low NOx burner technologies. Due to the temperature inconsistency, limited number of 
AECOM Environment 8-13

hours of operation, higher cost, additional energy requirements, the need to use a hazardous material 

(ammonia), and lack of evidence that SCR is used on boilers or heaters in the size range of the 

proposed units, SCR is determined to be infeasible for these devices. 

Selective Non-catalytic Reduction (SNCR) 

SNCR involves injection of ammonia or urea with proprietary conditions into the exhaust gas stream 

without a catalyst. SNCR technology requires gas temperatures in the range of 1,200 to 2,000°F. The 

exhaust temperature (~300°F [148.89°C]) for the proposed auxiliary boiler and HTF heater is well 

below the minimum SNCR operating temperature. Therefore, SNCR is not technically feasible for this 

application. 

Ultra-Low NOx Burners with Flue Gas Recirculation 

The next most effective NOx control option is the use of ultra-low NOx burners with FGR. Ultra-lowNOx burners with FGR are commonly used on industrial-sized package boilers and heaters. These 

burners minimize the formation of thermal NOx, and FGR reduces the oxygen in the combustion zone 

to further reduce NOx formation. Ultra-low NOx burners with FGR can typically achieve NOx emission 

rates of nine ppm at three percent oxygen without post-combustion controls. This emission rate was 

recently accepted as BACT and is considered the lowest technologically feasible emission rate for this 

application. 

PHPP will use ultra-low NOx burners with FGR and the emission limit of nine ppm as BACT for the 

proposed auxiliary boilers and HTF heaters. The auxiliary boiler and HTF heater will be limited to a 

stack NOx concentration of nine ppm at three percent oxygen with a recommended averaging period 

of one hour in order to comply with BACT. 

The EPA, CARB, BAAQMD and SCAQMD BACT websites were researched to find actual recent 

BACT determinations. The most stringent requirements were those of the SCAQMD: for units with a 

heat input of less than 20 MMBTU/hr, the maximum allowable NOx concentration is 12 ppmv, and for 

units with a heat input of greater than or equal to 20 MMBTU/hr, the maximum allowable NOx 

concentration is 9 ppmv if a low NOx burner is utilized, and 7 ppmv if add-on controls are employed. 

A summary of all determinations is provided in Appendix B. 

8.3.2 CO and VOC 

CO and VOC emissions during natural gas combustion result from incomplete combustion of the gas. 

CO and VOC emissions are minimized by good combustion practices that promote high combustion 

temperatures, long residence times, and turbulent mixing of fuel and combustion air. Since these 

combustion practices also increase NOx emissions, the effectiveness of the NOx control system may 

affect the ability of the boiler and HTF heater to achieve low CO and VOC emission rates. 

The technologies employed for CO and VOC emissions control in boilers and heaters are listed below 

in descending order of effectiveness: 

• Oxidation catalyst; and 

• Good combustion practice. 
AECOM Environment 8-14

Oxidation Catalysts 

Oxidation catalysts are known to successfully control CO and VOC to very low concentrations in large 

furnaces and boilers with heat rates, and little evidence that this technology has been applied to 

boilers or heaters of less than 50 MMBtu per hour. Oxidation catalysts are mentioned as an 

alternative control technology by the BAAQMD in their BACT guidance document for larger 

combustion sources (i.e., greater than 50 MMBtu/hour). Oxidation catalysts require a substantial 

capital investment for the catalyst bed, and additional power for operations (additional blower 

horsepower is required to overcome the pressure drop in the catalyst bed). 

Based on the database review of process heaters and boilers with similar heat rates, it appears that 

oxidation catalysts are not used for CO and VOC control on boilers or heaters in the size range of the 

proposed units. Due to the limited hours of operation of the boilers and heaters, the significant 

number of hours of operation at low-load, substantially higher cost, additional energy requirements, 

and lack of evidence that oxidation catalysts are used on small boilers or heaters, oxidation catalysts 

are determined to be infeasible for these devices. 

Good Combustion Practices 

The next most effective CO and VOC control option is the use of good combustion practices. Good 

combustion practice is recommended as BACT for this application. Today’s generation of low NOx 

burners seek to provide low NOx profiles through staged combustion, while simultaneously adding 

back oxygen to effectively burn out CO and VOC. This represents the top level of control for 

products of incomplete combustion from this source type. 

Based on several recent BACT determinations since April 2009, 50 ppm at three percent oxygen is 

recommended as BACT for CO emissions. A one-hour averaging period is recommended. Both units 

will burn only natural gas and will achieve BACT using good combustion practices during normal 

operation as well as during startup and shutdown. Good combustion practice is recommended as 

BACT for VOC, with no specific concentration recommended for this pollutant. 

The EPA, CARB, BAAQMD and SCAQMD BACT websites were researched to find actual recent 

BACT determinations. The most stringent control requirement for VOCs and CO was listed as flue gas 

recirculation, which was required primarily for NOx control. The vast majority of determinations spoke 

of operating in accordance with manufacturer’s specification or using good combustion practices. A 

summary of all determinations is provided in Appendix B. 

8.3.3 PM, PM10 and PM2.5 

The technologies potentially available for PM, PM10 and PM2.5 control natural gas-fired boilers 

combined-cycle power facilities include the following: 

1. Cyclone or multi-clone; 

2. Venturi (wet) scrubber; 

3. Electrostatic precipitator; 

4. Baghouse; 

5. Pipeline-quality natural gas fuel; and 

6. Good engineering (combustion and maintenance) practice. 
AECOM Environment 8-15

8.3.3.1 Technical Feasibility 

Step 2 of the five step, top-down BACT determination process is the elimination of infeasible options. 

Technical feasibility of the above mentioned technologies as add-on controls for the PHPP boiler and 

HTF heater will be similar to the feasibility as add-on controls for the CTGs and HRSGs, as discussed 

in Section 8.2.1. 

From the discussion of operating methods in Section 8.2.1, it can be concluded that cyclones or 

multi-clones, wet-technologies are determined to be technically infeasible, have unacceptable 

environmental impacts, and have been eliminated from further consideration. Only electrostatic 

precipitators, baghouses and of pipeline-quality natural gas fuel and good engineering (combustion 

and maintenance) were considered technically feasible and evaluated further. 

8.3.3.2 Rank Remaining Technologies 

Step 3 of the five step, top-down BACT determination procedure is to rank the remaining 

technologies. Of the six potential control technologies identified for evaluation, two technologies have 

been eliminated from consideration as technically infeasible: cyclones and wet venturi (wet) 

scrubbers. Based on the qualitative information available, the remaining technologies are ranked in 

order of expected control effectiveness, as follows: 

1. Baghouse; 

2. Electrostatic precipitator; 

3. Pipeline-quality natural gas fuel; and 

4. Good engineering (combustion and maintenance) practice. 

Note that there is limited information available on the effectiveness of either a baghouse or 

electrostatic precipitator for PM2.5 emissions, thus the ranking is based on the expected effectiveness 

for PM and PM10. 

8.3.3.3 Evaluate Technologies 

Step 4 of the five step, top-down BACT determination procedure is to evaluate the remaining 

technologies on the basis of economic, energy, and environmental impacts. For this analysis, the 

economic considerations are evaluated first. In the absence of specific guidance from the AVAQMD 

or EPA, it is assumed that EPA would take into consideration the cost of controls, if those controls 

were prohibitively expensive. The cost for PM, PM10 and PM2.5 control is higher on a dollar per ton 

basis for the auxiliary boiler and HTF heater compared to the CTGs and HRSGs due to the limited 

number of hours of operation and lower emission rates of the heater and boiler compared to the CTG 

and HRSG. The highest cost effectiveness value identified from the SJVAPCD is used for 

comparison purposes, as AVAQMD does not publish a threshold. As shown in Table 8-4, add-on 

controls are not cost effective for either source. 
AECOM Environment 8-16

Table 8-4 Boiler and Heater Cost Effectiveness and Degree of Control 

Control Device 

Cost 

Effectiveness 

($/ton PM) 

SJVAPCD BACT Cost 

Effectiveness Threshold 

($/ton PM) 

Cost 

Effective

(Yes/No?)

Electrostatic Precipitator - 99% Control on 

Auxiliary Boiler $1,236,674 $11,400 No 

Baghouse - 99% Control on Auxiliary Boiler $1,207,697 $11,400 No 

Electrostatic Precipitator - 99% Control on 

HTF Heater $461,841 $11,400 No 

Baghouse - 99% Control on HTF Heater $451,019 $11,400 No 

8.3.3.4 BACT Determination for PM, PM10 and PM2.5 

Based on this evaluation, cyclone or multi-clone and venturi (wet) scrubbers were determined to be 

technically infeasible and electrostatic precipitators and baghouses are determined to be not cost 

effective. Based upon the results of the RBLC data search discussed previously, the use of low sulfur 

fuel, i.e., pipeline quality natural gas, and good combustion practices can be considered achieved in 

practice. Therefore, pipeline-quality natural gas and good combustion practices is determined to be 

BACT for the boiler and HTF heater. 

The applicant has proposed the use of these technologies: low sulfur fuel and good combustion 

practices for the control of PM, PM10 and PM2.5 emissions. As all PM2.5 are considered to be 

PM10, the BACT emissions level for PM2.5 from the auxiliary boiler and HTF heater should be the 

same. 

8.3.4 Summary of Proposed BACT for Boiler and HTF Heater 

Based on this review, the proposed BACT for the boilers is presented in Table 8-5. 

Table 8-5 Proposed BACT for the Boiler and HTF Heater 

Pollutant Emission Limit1 Technology Reference 

NOx 

9 ppm at three percent O2, 

for units >20 MMBTU/hr 

heat input 

Ultra-low NOx burner SCAQMD Part D BACT for 

non-major polluting facilities 

CO 50 ppm at three percent 

O2, 1-hr average 

Good combustion 

practice 

SCAQMD Part D BACT for 

non-major polluting facilities 

VOC None Good combustion 

practice Various 

PM, PM10, 

PM2.5 None Natural gas Various 

1. The emission limits for NOx and CO would not apply during start up, shutdown or malfunction. 
AECOM Environment 8-17

8.4 Add-on NOx Controls for Emergency Diesel Generator and Fire Water 

Pump Engine 

The PHPP will include an emergency diesel generator rated at approximately 2,000 kW and a diesel 

fire water pump rated at approximately 135 kW. These emergency diesel engines will each operate 

for a maximum of 50 hours per year for testing. Duration of emergency operation of the engines is 

unknown. EPA requested an evaluation of SCR on fire water pumps or other internal combustion 

engines. This section contains BACT determinations for NOx control on diesel-fired fire water pumps 

and other diesel-fired emergency engines. 

The technologies employed for NOx emissions control for internal combustion engines are listed 

below in descending order of effectiveness: 

• Selective Catalytic Reduction (SCR); 

• NOx Reducing Catalyst; 

• NOx Adsorber; 

• Catalyzed Diesel Particulate Filter; 

• Catalytic converter; 

• Oxidation catalyst; and 

• New Source Performance Standard (NSPS)- or Air Toxic Control Measure (ATCM)-compliant 

engine. 

Selective Catalytic Reduction (SCR) 

SCR was suggested as an alternative control technology for emergency engines by the EPA. SCR 

systems are being developed to control NOx emissions from stationary compression ignition engines, 

although there is little evidence that this technology has been applied emergency engines. SCR 

control systems introduce a reducing agent such as ammonia or urea into the diesel exhaust over a 

catalyst. The catalyst reduces the temperature needed to initiate the reaction between the reducing 

agent and NOx to form nitrogen and water. Both precious metal and base metal catalysts have been 

used in SCR systems. Base metal catalysts, typically vanadium and titanium, are used for exhaust 

gas temperatures between 450o

F and 800oF. For higher temperatures (675 to 1,100oF), zeolite 

catalysts may be used. Concerns with SCR control systems include catalyst deactivation and 

poisoning. Sulfur compounds in the exhaust can poison SCR catalysts and reduce the catalyst 

activity. 

With all catalyst control systems, including SCR, oxidation, or lean-NOx catalytic controls on an IC 

engine, conditions exist that can reduce catalyst activity. Catalytic deactivation may result from (1) 

chemical poisoning, (2) masking, or (3) thermal sintering. In most cases, the reduced performance 

results from catalysts being masked by contaminants in the exhaust. Contaminants in diesel-fired 

compression ignition exhaust include oxides of sulfur and particulates. A catalyst that has been 

deactivated will not be as effective at reducing the target pollutants. Spent catalysts must be properly 

managed to prevent improper disposal. Other limitations relative to the feasibility of SCR is the 

substantial capital investment for the catalyst bed, additional power for operations (additional blower 

power is required to overcome the pressure drop in the catalyst bed), and the use of hazardous 

aqueous or anhydrous ammonia as the reducing agent. Based on the database review of emergency 

engines, SCR is not used for NOx control, as evidenced by the large number of applications cited 

NSPS compliant or CARB certified engines as BACT. Due to the limited number of hours of 
AECOM Environment 8-18

operation, higher cost, additional energy requirements, the need to use a hazardous material 

(ammonia), and lack of evidence that SCR is used on emergency engines, SCR is determined to be 

infeasible for the emergency generator and fire water pump. 

Since EPA specifically requested the discussion of SCR on emergency engines, the cost 

effectiveness of SCR was also evaluated. EPA posted a memo from Alpha Gamma Technologies, 

Inc. (AGTI) on their website that evaluates the cost effectiveness for additional controls on stationary 

compression ignition engines (AGTI 2005). The costs effectiveness was estimated the new NSPS for 

stationary engines, but the cost analysis is still applicable for a BACT determination. The cost 

estimates are based on the annual cost for SCR of $36 per horsepower per engine, 90 percent control 

of the SCR, and 37 hours of operation per year. Table 8-6 presents the costs estimates prepared by 

AGTI for the EPA. 

As shown in Table 8-6, SCR on emergency diesel-fired engines is on the order of $200,000 per ton of 

NOx and exceeds the SJVAPCD cost effectiveness threshold of $5,700. SCR on the firewater pump 

and emergency generator engine is determined to be infeasible and not cost effect; therefore, SCR 

cannot be considered as BACT. 

Table 8-6 Cost of SCR Control Per Ton of NOx Removed 

Source SCR Annual Control 

Costs Per Engine1

($/yr) 

NOx Reduction per 

Engine2

(g/bhp-hr) 

Cost per Ton NOx 

Removed2

($/ton) 

Firewater Pump 

(182 hp) $6,225 0.022 $396,886 

Emergency Generator 

(2,683 hp) $96,588 0.312 $242,493 

1. Calculated annual costs based on $36/hp 

2. Numbers are presented for the applicable engine hp range. (AGTI 2005) The firewater pump is classified 

in the 175-300 hp range and the emergency generator is in the 1,200 to 3,000 hp range. 

NOx Reducing Catalyst 

A NOx reducing catalyst (NRC) system works in the same way as an SCR system, but it uses 

diesel fuel as a reductant instead of a urea solution. The NRC catalyst is installed in the exhaust 

stream much like an oxidation catalyst or diesel particulate filters and the diesel fuel reductant is 

injected into the exhaust ahead of the catalyst. Hydrocarbons from the injected fuel contribute to a 

chemical reduction reaction with the NOx in the exhaust, across the NRC catalyst. Similar to SCR, 

NRC will have operational limitations due to the temperature requirements of the catalyst and the 

limited number of hours of operation for emergency engines. Additionally, since diesel fuel is not as 

effective a reductant as urea, NRC systems reduce less than half as much NOx as SCR systems 

(STAPPA 2006). NRCs will have a high capital costs associated with the catalyst bed and there is 

no evidence that NRCs are used on emergency engines. NRCs are not considered as BACT for 

the emergency generator and fire water pump.

NOx Adsorbers and Catalyzed Diesel Particulate Filters 

Unlike catalysts, which continuously convert NOx to nitrogen (N2), the zeolite catalyst in a NOx 

adsorber chemically combines with NOx and stores NOx under typical lean (high oxygen content) 
AECOM Environment 8-19

conditions and then catalytically reduces the stored NOx under rich conditions. Since rich operation 

is not typical of diesel engine operation, this reduction is done by injecting fuel into the exhaust 

(similar to an NRC system). NOx adsorbers are typically set up as a dual bed system with a series 

of dampers to minimize the fuel penalty. NOx adsorber technology is expected to take a leading 

role in complying with the more stringent EPA Tier 4 non-road NOx standards when combined with 

catalyzed diesel particulate filters. 

As shown in Table 8-7, NOx adsorbers and CDPF exceed the SJVAPCD cost effectiveness threshold 

of $5,700 even when combining the reductions from PM and NOx. NOx adsorbers and CDPF on the 

firewater pump and emergency generator engines are determined to be not cost effect; therefore, 

NOx adsorbers and CDPF cannot be considered as BACT for these emergency engines.

Table 8-7 Cost of NOx Adsorbers and CDPF Control for Emergency Engines 

Source Annual NOx Control 

Costs Per Engine1 

($/ton NOx) 

Annual PM Control 

Costs Per Engine1 

($/ton PM) 

Annual NOx + PM 

Control Costs Per 

Engine1

($/ton PM+NOx) 

Firewater Pump 

(182 hp) $22,049 $232,626 $20,140 

Emergency Generator 

(2,683 hp) $13,472 $969,121 $13,287 

1. Numbers are presented from the applicable engine hp range. (AGTI 2005) The firewater pump is 

classified in the 175 to 300 hp range and the emergency generator is in the 1,200 to 3,000 hp range. 

Catalytic Converters and Oxidation Catalysts 

The next most effective NOx control option is the use of catalytic converters and oxidation catalysts. 

Catalytic converters and oxidation catalysts have been proposed and used on a limited number of 

diesel engines in California; however, neither have been used on emergency engine installations due 

to the high cost and limited environmental benefit (due to the low number of hours of operation). 

Catalytic converters and oxidation catalysts are, therefore, determined to be infeasible for this 

application. 

NSPS- and ATCM-Compliant Engines 

NSPS Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines, has been adopted for non-road engines that limit emissions of NOx, VOC and 

CO. The specific limits vary depending upon the size, intended use, and date of manufacture of the 

engine. A review of the RBLC indicates that compliance with the NSPS is BACT. Compliance with 

the applicable NSPS is feasible and has been achieved in practice. 

Title 17 Code of California Regulations (CCR) Section 93115, the California ATCM for Stationary 

compression ignition Engines, provides standards for new stationary emergency standby diesel-fueled 

engines. The California emission standards specified in Title 13 CCR Section 2423 and the PM 

emission limits specified in Title 17 CCR Section 93115 are at least as stringent as the requirements 

for a NSPS-compliant engine. Therefore, compliance with the California ATCM emission standards 

and limits constitutes BACT for the emergency diesel generator and fire water pump engines. 
AECOM Environment 8-20

8.5 References for Section 8 

Alpha Gamma Technologies, Inc., 2005. Cost Per Ton for NSPS for Stationary compression ignition 

internal combustion engine. Available online at: 

http://www.epa.gov/ttn/atw/nsps/cinsps/cost_per_ton_ci_nsps_6-9-05.pdf. June 

BAAQMD, 2009. Bay Area Air Quality Management District (BAAQMD) BACT Guidelines at 

http://www.baaqmd.gov/pmt/bactworkbook/default.htm, accessed January 2009. 

CARB, 2010. California Air Resources Board BACT Clearinghouse at: 

http://www.arb.ca.gov/bact/bact.htm, accessed May 2010. 

CEC, 2009. Final Staff Assessment: GWF Tracy Combined Cycled Power Plant Project. October 

EPA, 1999. APTI 413: Control of Particulate Matter Emissions, Student Manual: Chapter 4. Available 

online at: http://www.epa.gov/air/oaqps/eog/Materials/APTI percent20413 percent20student/413 

percent20Student percent20Manual/SM_ch percent209.pdf

EPA, 2000. Compilation of Air Pollutant Emission Factors (AP-42), Chapter 3.1, Stationary Gas 

Turbines. April. 

EPA, 2002. EPA Air Pollution Control Cost Manual. Available online at: 

http://www.epa.gov/ttn/catc/dir1/c_allchs.pdf. January 2002. 

EPA, 2003a. Air Pollution Control Technology Fact Sheet: Cyclone. Available online at: 

http://epa.gov/ttn/catc/dir1/fcyclone.pdf July. 

EPA, 2003b. Air Pollution Control Technology Fact Sheet: Venturi Scrubber. Available online at: 

http://epa.gov/ttn/catc/dir1/fventuri.pdf July. 

EPA, 2010. EPA’s RACT/BACT/LAER Clearinghouse (RBLC), at http://cfpub.epa.gov/RBLC/, 

accessed May 2010. 

Institute of Clean Air Companies (ICAC), 2010. Particulate Controls Technology. Available online at: 

http://www.icac.com/i4a/pages/Index.cfm?pageID=3398. Accessed June 2010. 

SCAQMD, 2000. South Coast Air Quality Management District, Best Available Control Technology 

Guidelines, August. 

SDAPCD, 2002. New Source Review Requirements for Best Available Control Technology (BACT) 

Guidance Document.’ 

SJVAPCD, 2010. Draft Best Available Control Technology Policy. Available online 

at:http://71.6.68.10/Workshops/postings/2010/03-01-10/Draft%20BACT%20policy%20-

%20Mar%202010%20_2_.pdf. March. 

STAPPA, 2006. State and Territorial Air Pollution Program Administrators (STAPPA) and Association 

of Local Air Pollution Control Officials. Controlling Fine Particulate Matter Under the Clean Air Act: A 

Menu of Options. March 
AECOM Environment 

Appendix A 

Electronic Archive of Modeling 

Files 
AECOM Environment 

Appendix B 

Summary of BACT Evaluations 
 Combustion equipment form date 7/17/2002 

Section I: AQMD BACT Determinations 

Application No.: 394164 

Equipment Category - Gas Turbine 

1. GENERAL INFORMATION DATE: 1/30/2004

A. MANUFACTURER: Alstom 

B. TYPE: Combined Cycle C. MODEL: GTX100

D. STYLE: With duct burner

E. APPLICABLE AQMD RULES: 212, 218, 401, 402, 403, 407, 431.1, 475, Reg. XIII, 1401, Reg. XX, 

Reg. XXX, CEQA, 40CFR Part 60 subpart GG, 40CFR Part 63 NESHAPS, 40CFR Part 64, 

40CFR Part 72

F. COST: $ (NA) SOURCE OF COST DATA: Owner/Operator 

G. OPERATING SCHEDULE: 24 HRS/DAY 7 DAYS/WK 52 WKS/YR

2. EQUIPMENT INFORMATION APP. NO.: 394164-165

A. FUNCTION: Power Generation 

B. MAXIMUM HEAT INPUT: 525 mmbtu/hr (turbine) 

and 73 mmbtu/hr (duct burner)

C. MAXIMUM THROUGHPUT: 43 MW gas turbine, 55 

MW steam turbine

D. BURNER INFORMATION: NO.: TYPE: Dry Low-NOx

E. PRIMARY FUEL: Natural Gas F. OTHER FUEL: 

G. OPERATING CONDITIONS: Baseload, load following

3. COMPANY INFORMATION APP. NO.: 394164-165

A. NAME: Vernon City Light & Power B. SIC CODE: 4911 

C. ADDRESS: 2715 E 50th Street 

CITY: Vernon STATE: CA ZIP: 90058

D. CONTACT PERSON: Mr. Carlos Fandino E. PHONE NO.: (323) 583 - 8811x573

4. PERMIT INFORMATION APP. NO.: 394164-165

A. AGENCY: SCAQMD B. APPLICATION TYPE: new construction 

C. AGENCY CONTACT PERSON: Chandrashekhar S. Bhatt D. PHONE NO.: (909) 396 - 2653

E. PERMIT TO CONSTRUCT/OPERATE INFORMATION: P/C NO.: 394164 ISSUANCE DATE: 5/27/2003

 CHECK IF NO P/C P/O NO.: ISSUANCE DATE: 

F. START-UP DATE: Fall 2004 (est.)

5. EMISSION INFORMATION APP. NO.: 394164-165

A. PERMIT

A1. PERMIT LIMIT: ppmvd @15% O2 : NOx 2.0 (1-hr), CO 2.0 (3-hr), VOC 2.0 (1-hr), NH3 5.0 (1-

hr). PM 0.01 gr/scf and 11 lb/hr. Monthly mass limits on CO, PM10, VOC and SOx.
 Combustion equipment form date 7/17/2002 

Section I: AQMD BACT Determinations 

Application No.: 386305 

Equipment Category – Gas Turbine 

1. GENERAL INFORMATION DATE: 1/30/2004

A. MANUFACTURER: General Electric 

B. TYPE: Combined Cycle C. MODEL: PG7241FA

D. STYLE: Includes inlet air evaporative cooling and steam injection for power augmentation

E. APPLICABLE AQMD RULES: 

F. COST: $ (NA) SOURCE OF COST DATA: 

G. OPERATING SCHEDULE: 24 HRS/DAY 7 DAYS/WK 52 WKS/YR

2. EQUIPMENT INFORMATION APP. NO.: 386305

A. FUNCTION: Power Generation 

B. MAXIMUM HEAT INPUT: 1,700 MMBtu/hr 

(turbine), 583 MMBtu/hr (duct burner)

C. MAXIMUM THROUGHPUT: 181 net MW (gas 

turbine with steam injection), 147 net MW 

(steam turbine) 

D. BURNER INFORMATION: NO.: TYPE: Dry Low-NOx

E. PRIMARY FUEL: Natural Gas F. OTHER FUEL: 

G. OPERATING CONDITIONS: Baseload, load following

3. COMPANY INFORMATION APP. NO.: 386305

A. NAME: Magnolia Power Project, SCPPA B. SIC CODE: 4911 

C. ADDRESS: 164 W. Magnolia Blvd. 

CITY: Burbank STATE: CA ZIP: 91502

D. CONTACT PERSON: Bruce Blowey E. PHONE NO.: 661-252-6908

4. PERMIT INFORMATION APP. NO.: 386305

A. AGENCY: SCAQMD B. APPLICATION TYPE: new construction 

C. AGENCY CONTACT PERSON: John Dang D. PHONE NO.: 909-396-2427

E. PERMIT TO CONSTRUCT/OPERATE INFORMATION: P/C NO.: 386305 ISSUANCE DATE: 5/27/2003

 CHECK IF NO P/C P/O NO.: ISSUANCE DATE: 

F. START-UP DATE: 5/2005 (est.)

5. EMISSION INFORMATION APP. NO.: 386305

A. PERMIT

A1. PERMIT LIMIT: PPMVD@15% O2: NOx-2.0 (3-hr), CO-2.0(1-hr), VOC-2.0(1-hr), NH3-5.0(1-

hr), PM: .01 gr/scf and 11 lb/hr. Monthly mass limits on CO, VOC, SOX, and PM10.
2 of 3 Combustion equipment form date 7/17/2002 

5. EMISSION INFORMATION APP. NO.: 386305

A2. BACT/LAER DETERMINATION: Above limits on NOx, VOC and NH3 were believed to represent prior 

BACT for combined cycle gas turbines. The CO limit is more stringent than prior BACT in 

that the concentration is lower and the averaging time is shorter.

A3. BASIS OF THE BACT/LAER DETERMINATION: Prior BACT was based on CARB's Guidance Document for 

Power Plant Sitings, dated September 1999 and AQMD Part D BACT. Other similar 

recently AQMD permitted combined cycle powerplants include LADWP Valley, LADWP 

Haynes, and Mountainview Power Plant. These plants were permitted with the same or 

similar emission concentration limits for NOx, CO, VOC, and NH3 however, they were not 

considered achieved in practice at the time of BACT determination. The more stringent 

limit on CO was proposed by the applicant.

B. CONTROL TECHNOLOGY 

B1. MANUFACTURER/SUPPLIER: Cormetech (SCR system), Engelhard (oxidation catalyst)

B2. TYPE: SCR system and oxidation catalyst.

B3. DESCRIPTION: SCR and oxidation catalysts are integral in the HRSG. SCR catalyst nominal 

operating temperature is 700F; allowable operating temperature range is 450 to 850F. 

Aqueous ammonia (max. 19.5 wt. %) is used. 

B4. CONTROL EQUIPMENT PERMIT APPLICATION DATA: P/C NO.: 386306 ISSUANCE DATE: 5/27/2003 

 P/O NO.: ISSUANCE DATE: 

B5. WASTE AIR FLOW TO CONTROL EQUIPMENT: FLOW RATE: ACTUAL CONTAMINANT LOADING: BLOWER HP: 

B6. WARRANTY: 

B7. PRIMARY POLLUTANTS: NOx, CO, VOC, PM, SOx

B8. SECONDARY POLLUTANTS: NH3

B9. SPACE REQUIREMENT: SCR Catalyst: 1,100 cu. ft; CO Catalyst: 360 cu. ft.

B10. LIMITATIONS: B11. UNUSED

B12. OPERATING HISTORY: B13. UNUSED B14. UNUSED

C. CONTROL EQUIPMENT COSTS 

C1. CAPITAL COST: CHECK IF INSTALLATION COST IS INCLUDED IN EQUIPMENT COST 

EQUIPMENT: $ INSTALLATION: $ (NA) SOURCE OF COST DATA: 

C2. ANNUAL OPERATING COST: $ (NA) SOURCE OF COST DATA: 

D. DEMONSTRATION OF COMPLIANCE

D1. STAFF PERMFORMING FIELD EVALUATION: 

ENGINEER'S NAME: INSPECTOR'S NAME: DATE: 

D2. COMPLIANCE DEMONSTRATION: CEMS for NOx and CO, annual RATA, annual NH3 test, source 

test for SOX, VOC, and PM every three years. 

D3. VARIANCE: NO. OF VARIANCES: DATES: CAUSES: 

D4. VIOLATION: NO. OF VIOLATIONS: DATES: CAUSES: 
3 of 3 Combustion equipment form date 7/17/2002 

5. EMISSION INFORMATION APP. NO.: 386305

D5. MAINTENANCE REQUIREMENTS: D6. UNUSED

D7. SOURCE TEST/PERFORMANCE DATA RESULTS AND ANALYSIS:

DATE OF SOURCE TEST: no later than 180 days after initial start-up CAPTURE EFFICIENCY: DESTRUCTION EFFICIENCY: OVERALL EFFICIENCY: SOURCE TEST/PERFORMANCE DATA: OPERATING CONDITIONS: TEST METHODS: 

6. COMMENTS APP. NO.: 386305

It should be noted that the CO emission limit has not yet been verified by performance data. 
2 of 3 Combustion equipment form date 7/17/2002 

5. EMISSION INFORMATION APP. NO.: 394164-165

A2. BACT/LAER DETERMINATION: Above limits on NOx, VOC and NH3 were believed to represent 

BACT for a combined cycle gas turbine. The CO limit is more stringent than prior BACT.

A3. BASIS OF THE BACT/LAER DETERMINATION: Prior BACT determination was based on CARB's Guidance 

Document for Power Plant Sitings, dated September 1999 and the ANP Blackstone 

combined-cycle power plant in Massachusetts (AQMD Public Notice 1/16/2003). The 

more stringent limit for CO was proposed by the applicant to reduce the offset 

requirements. Magnolia Power Project (A/N 386305) has similar concentration limits of 

NOx, CO, VOC and NH3 except for differences in averaging times (3-hr for NOx and 1-hr 

for VOC). 

B. CONTROL TECHNOLOGY 

B1. MANUFACTURER/SUPPLIER: Mitsubishi/Cormetec (SCR system), Emerachem (oxidation catalyst)

B2. TYPE: SCR system and oxidation catalyst

B3. DESCRIPTION: Low temperature SCR catalyst with aqueous ammonia (19% by weight)

B4. CONTROL EQUIPMENT PERMIT APPLICATION DATA: P/C NO.: 394166 ISSUANCE DATE: 5/27/2003 

 P/O NO.: ISSUANCE DATE: 

B5. WASTE AIR FLOW TO CONTROL EQUIPMENT: FLOW RATE: ACTUAL CONTAMINANT LOADING: BLOWER HP: 

B6. WARRANTY: 

B7. PRIMARY POLLUTANTS: NOx, CO, PM,VOC, SOx

B8. SECONDARY POLLUTANTS: NH3

B9. SPACE REQUIREMENT: SCR catalyst total space requirement = 1,816 cu. ft; SCR catalyst volume 

= 537.1 cu. ft.; CO catalyst total space requirement = 638 cu. ft; CO catalyst volume: 63 cu. 

ft. There are 2 such units at MGS Power Plant.

B10. LIMITATIONS: B11. UNUSED

B12. OPERATING HISTORY: B13. UNUSED B14. UNUSED

C. CONTROL EQUIPMENT COSTS 

C1. CAPITAL COST: CHECK IF INSTALLATION COST IS INCLUDED IN EQUIPMENT COST 

EQUIPMENT: $ INSTALLATION: $ (NA) SOURCE OF COST DATA: 

C2. ANNUAL OPERATING COST: $ (NA) SOURCE OF COST DATA: 

D. DEMONSTRATION OF COMPLIANCE

D1. STAFF PERMFORMING FIELD EVALUATION: 

ENGINEER'S NAME: INSPECTOR'S NAME: DATE: 

D2. COMPLIANCE DEMONSTRATION: Source test within 180 days after startup. NOx/CO CEMS.

D3. VARIANCE: NO. OF VARIANCES: DATES: CAUSES: 

D4. VIOLATION: NO. OF VIOLATIONS: DATES: CAUSES: 
3 of 3 Combustion equipment form date 7/17/2002 

5. EMISSION INFORMATION APP. NO.: 394164-165

D5. MAINTENANCE REQUIREMENTS: D6. UNUSED

D7. SOURCE TEST/PERFORMANCE DATA RESULTS AND ANALYSIS:

DATE OF SOURCE TEST: CAPTURE EFFICIENCY: DESTRUCTION EFFICIENCY: OVERALL EFFICIENCY: SOURCE TEST/PERFORMANCE DATA: OPERATING CONDITIONS: TEST METHODS: 

6. COMMENTS APP. NO.: 394164-165

There is also an identical power production unit and SCR system (A/N's 394165 and 394167). 
SCIENTIFIC REVIEW COMMITTEE MEETING 

January 22, 2004 

MEETING HIGHLIGHTS 

The handouts and audiotapes can be obtained through the Public Records 

Section of the Chief Prosecutor’s Office. There may be a fee for this service. 

 

 SRC Members

Todd Wong (by phone) Nahid Zoueshtiagh (absent) 

Stan Romelczyk (by phone) Greg Adams (represented by Seong Min) 

Katy Wolf Gary Rubenstein 

Hal Taback Karl Lany 

William Dennison (absent) Steve Simons (represented by Noel Muyco) 

Martin Ledwitz Ted Guth 

Anoosheh Mostafaei (absent) Russell Greenhouse (absent) 

Phillip Hodgetts Ronald Wilkness 

Ron Joseph (absent) 

Attendees

Duc Tran (by phone) Millie Yamada 

Gabe Trinidad Steve Hurlock 

John Billheimer Dale Botts 

Viji Sadasivan Ken Hudson 

Jerry Kraim 

 AQMD Staff

Marty Kay Alfonso Baez 

Howard Lange John Yee 
SRC Meeting Minutes January 22, 2004 

2 

Marty Kay welcomed the SRC members and the audience to the meeting. The topics 

listed below were discussed during the meeting. 

 Minutes of November 20th Meeting 

 Responses to Comments from November 20th Meeting 

 New and Updated BACT - Part B Listings 

 Proposed Updates of BACT - Part D (MSBACT) guidelines 

 Other Business 

Minutes of the November 20th Meeting 

A committee member requested the following clarification: on page 3 of the minutes, in 

the phrase “...with the Rule 1171 limits on the VOC content of blanket and roller washes 

dropping from 600 to 800 g/l to 100 g/l in July 2005...”, the words “600 to 800” should 

more appropriately be “600 and 800”. AQMD staff agreed to make the change. (Katy 

Wolf, IRTA; Marty Kay, AQMD) 

Responses to Comments from the November 

20th Meeting 

AQMD staff stated that changes in the listings presented at the November 20th meeting 

that had been agreed upon at the meeting, as well as any agreed-upon changes in the 

minutes from the prior meeting, had been made. Committee and audience members 

could check the final listings and minutes as posted on AQMD’s web site. 

At the November 20th meeting, AQMD staff had agreed to investigate and report back to 

the committee on the following two items: 

1. Regarding the new Part B LAER/BACT listing for publication rotogravure 

printing (Quad Graphics in West Virginia), a committee member had requested 

that AQMD staff attempt to obtain information on the VOC loading of the air 

entering the VOC removal system. AQMD staff reported that the information had 

been obtained and added to the listing. (Howard Lange, AQMD)

2. Regarding the proposed update of the Part D guideline for lithographic printing, a 

committee member had suggested that the vapor pressure limit on blanket and 

roller washes be deleted as of July 2005, when the washes must comply with a 

100 g/l VOC limit (Rule 1171). AQMD staff had discussed this with the 

permitting team that handles lithographic printing, and the team had agreed to 

modify the BACT guideline to allow the 100 g/l rule requirement to be met in lieu 

of the vapor pressure limit. (Howard Lange, AQMD)
SRC Meeting Minutes January 22, 2004 

3 

New BACT Part B, Section I Listings 

Fiberglass Impregnation System, Nelco Products (A/N 394320) 

In this facility, Nelco Products manufactures resin-impregnated fiberglass cloth, 

commonly known as “pre-preg”. Pre-preg is an intermediate product that is used in 

manufacture of printed circuit boards, golf clubs, fishing poles, etc. Fiberglass cloth is 

drawn through a dip tank containing a resin-solvent mixture and then through an oven for 

driving off the solvent and partially curing the resin. AQMD staff noted that this 

equipment is subject to Rule 1128 and suggested that the term “fiberglass impregnation 

system” should perhaps be changed to “fiber coating system” to be consistent with the 

rule. 

In that Nelco Products had claimed confidentiality in its application for this equipment, 

only limited information regarding equipment dimensions and process rate was included 

in the listing. The air flow rate through the oven in part 2 of the listing (4900 cfm) was 

incorrect and was to be changed. In addition to compliance with Rules 1128 and 1171, 

the facility meets a permit condition requiring 98% overall control of VOC. Compliance 

with Rule 1171 is by use of acetone for cleanup. Since the facility uses a resin-solvent 

mixture with 375 g/l VOC content, which exceeds the 265 g/l maximum in Rule 1128, 

compliance with Rule 1128 is by the 98% overall VOC control. However, the 98% 

substantially exceeds the 85.5% required by the rule. The 98% control is achieved by 

permanent total enclosure of the dip tank and oven and venting to a thermal oxidizer. A 

source test certified the permanent total enclosure and showed the thermal oxidizer to 

achieve 99.4% destruction efficiency. (Marty Kay, AQMD; Howard Lange, AQMD)

Discussion: A committee member expressed concern with the widespread use of acetone 

as a cleanup solvent in various plastic-based industries and asked whether there have 

been any acetone explosions reported. Another committee member responded that fire 

departments limit the amounts that can be stored and that, to her knowledge, no 

explosions have occurred. An audience member asked about a statement in part 6 of the 

listing (Comments) that the oxidizer had failed to meet the 98% destruction efficiency. 

AQMD staff explained that the statement referred to a previous source test and that the 

problem had been fixed and the unit retested. AQMD staff agreed to clarify the 

statement. Another audience member noted that the oxidizer was required to have a 

minimum temperature of 1400F and asked where that temperature is measured. AQMD 

staff responded that the temperature is measured at the outlet end of the oxidizer 

chamber. (Hal Taback, HTC; Katy Wolf, IRTA; ; Howard Lange, AQMD; Marty Kay, 

AQMD) 

Gas Turbine, Combined Cycle – Magnolia Power (A/N 386305) 

This is a combined cycle power plant consisting of a 181 MW gas turbine with a 

separately fired heat recovery steam generator and a 147 MW steam turbine. Permit 

limits are as follows (ppmvd@15%O2): NOx-2.0 (3-hr avg.), CO-2.0 (1-hr avg.), VOC2.0 (1-hr avg.), NH3-5.0 (1-hr avg.). These limits were considered BACT at the time the 

Permit to Construct was drafted. The limits were based on 1999 CARB guidance for 
SRC Meeting Minutes January 22, 2004 

4 

power plants and AQMD Part D BACT. The CO limit is, however, more stringent than 

either of those guidelines and was offered by the applicant. To achieve these emission 

limits, the gas turbine is equipped with a dry low-NOx burner and the plant includes an 

SCR and oxidation catalyst. The plant is still under construction. (Howard Lange, 

AQMD) 

Discussion: A committee member noted that the Permit to Construct issue dates of this 

plant and the Vernon plant, to be discussed next, were the same and yet the NOx 

averaging times were different—3-hr in this case (Magnolia) and 1-hr in the other case 

(Vernon). AQMD staff explained that the Magnolia permitting process had begun earlier 

than the Vernon permitting process, and the Vernon permit conditions therefore reflected 

more recent, and more stringent, BACT. An audience member asked whether BACT for 

NOx for gas turbines of this type is now 2.0 ppm with a one-hour averaging time. 

AQMD staff responded that it is. A committee member clarified that this BACT applies 

to large combined cycle gas turbines and not necessarily to smaller, simple cycle gas 

turbines. (Gary Rubenstein, Sierra Research; John Yee, AQMD; Marty Kay, AQMD; 

Howard Lange, AQMD) 

Gas Turbine, Combined Cycle – Vernon City (A/N 394164) 

This power plant consists of two identical combined cycle power trains. Each power 

train includes a 43 MW gas turbine, separately fired heat recovery steam generator and 

55 MW steam turbine. Each gas turbine has a dry low-NOx burner, and each power train 

includes SCR and oxidation catalyst for additional emission control. Permit limits are as 

follows (ppmvd@15%O2): NOx-2.0 (1-hr avg.), CO-2.0 (3-hr avg.), VOC-2.0 (1-hr 

avg.), NH3-5.0 (1-hr avg.). These limits were considered BACT at the time the Permit to 

Construct was drafted. The limits were based on 1999 CARB guidance for power plants 

and AQMD Part D BACT. The permit conditions also include a monthly mass limit on 

VOC that is equivalent to 1.2 ppmvd@15%O2, which was requested by the applicant. 

(Howard Lange, AQMD) 

Discussion: Several committee members noted that the 5 ppm ammonia limits on both 

combined cycle plants has not been achieved in practice and may be difficult to achieve. 

One committee member asked whether the 5 ppm limit is now BACT for NH3 for this 

equipment category and whether AQMD may potentially relax this BACT guideline if it 

proves to be too difficult to meet. AQMD staff responded that the 5 ppm limit is now 

considered to be BACT but it can be relaxed if necessary. AQMD staff noted that for 

low-NOx turbines such as the GE 7FA used in the Magnolia case (6-9 ppm NOx), 

meeting a 5 ppm NH3 limit should not be difficult. Committee members responded that 

meeting the limit may still be difficult because of imperfect mixing and gas sneakage 

through inadequately sealed spaces between catalyst blocks. A committee member 

pointed out that large combined cycle plants now frequently have low utilization, and 

evaluation of achieved-in-practice should consider actual operation time. 

A committee member noted that the SCR and oxidation catalyst volumes specified in the 

two listings, on a comparative basis, seemed inconsistent with the plant sizes. AQMD 

staff agreed to investigate and correct any erroneous data. 
SRC Meeting Minutes January 22, 2004 

5 

A committee member asked how the monthly mass limit on VOC is enforced. AQMD 

staff responded that enforcement of that limit will be based on the results of an annual 

source test and noted that if the 1.2 ppm limit was not met, the plant would simply have 

to purchase additional offsets. Committee members suggested that since the 1.2 ppm 

limit is essentially a “soft” limit, it should not be included as BACT. AQMD staff agreed 

to clarify this in the listing. (Hal Taback, HTC; Gary Rubenstein, Sierra Research; Ted 

Guth, Consultant; Karl Lany, SCEC; Marty Kay, AQMD; John Yee, AQMD; Howard 

Lange, AQMD) 

Gas Turbine, Simple Cycle – EI Colton (A/N 406065) 

This is a simple cycle gas turbine power plant rated at 48.7 MW. The turbine is equipped 

with water injection for NOx control and also with SCR and oxidation catalyst. Permit 

limits are as follows (ppmvd@15%O2): NOx-3.5 (3-hr avg.), CO-6.0 (3-hr avg.), VOC2.0 (3-hr avg.), NH3-5.0 (3-hr avg.). These limits were considered BACT at the time the 

Permit to Construct was drafted. The BACT determination was based on CARB’s 

guidance for power plants. The 3.5 ppm NOx limit, however, is lower than the 5 ppm 

suggested in the CARB guidance, and was offered by the applicant. The unit was source 

tested and met all permit limits. (Howard Lange, AQMD) 

Discussion: A committee member suggested that the SCR catalyst design temperature be 

noted in LAER/BACT listings for simple cycle gas turbines because it is a key parameter 

affecting what NOx and NH3 limits can be met. This committee member noted also that 

two or three similar (GE LM6000) projects in AQMD jurisdiction with similar limits are 

not meeting their limits and are under variance. AQMD staff agreed to investigate this 

and add appropriate information to the listing. Another committee member suggested 

that AQMD staff also look at the CEMS data and Rule 218 (c) CO data., and AQMD 

staff agreed to check this information if available. (Gary Rubenstein, Sierra Research; 

Karl Lany, SCEC; Marty Kay, AQMD) 

New BACT Part B, Section II Listing 

Gas Turbine, Simple Cycle – Lambie Energy Center (BAAQMD 

A/N 6510) 

This 49.9 MW simple cycle power plant was cited in CARB’s report to the legislature on 

NOx controls for power plants. The turbine is equipped with SCR and oxidation catalyst. 

Permit limits are as follows (ppmvd@15%O2): NOx-2.5 (3-hr avg.), CO-6.0 (3-hr avg.), 

VOC-2.0, NH3-10. These limits were based on CARB guidance for power plants, 

however, the 2.5 ppm limit on NOx is more stringent than the 5 ppm limit suggested by 

the CARB guidance, and was offered by the applicant. The unit has been source tested 

and met all permit limits. (Howard Lange, AQMD) 

Discussion: A committee member noted that the mass limit on PM10 emissions in this 

permit is 3 lb/hr whereas the corresponding limit in the EI Colton permit (above) is 11 

lb/hr. Another committee member explained that the 3 lb/hr limit is probably based on 
SRC Meeting Minutes January 22, 2004 

6 

the guarantee normally offered with this size turbine, which is based, in turn, on the 

resolution capability of the test method. Another committee member pointed out that the 

11 lb/hr limit is probably based on an old AQMD prohibitory rule. 

A committee member requested that AQMD staff add information on catalyst 

manufacturers, catalyst volumes, guarantees provided by the catalyst system vendor and 

catalyst design temperatures. AQMD staff agreed to attempt to obtain this information. 

A committee member noted that the plant has not accumulated sufficient operation for 

the concentrations limits to be deemed achieved in practice. AQMD staff agreed that 

there apparently has not been enough operation but noted that BAAQMD changed their 

BACT guideline to these limits in July 2003. AQMD staff agreed, however, to hold back 

the listing until sufficient operating days have been accumulated or a permit is issued 

with a BACT determination requiring the same limits. Two other committee members 

noted that the Modesto Electric Generating System (MEGS) project in the San Joaquin 

valley air district is probably going to have similar limits, but were not sure whether it 

was a BACT determination or offered by the applicant. The same committee member 

requested that AQMD staff add information regarding NOx exceedances mentioned in 

part 5D2 of the listing—specifically, what were the design errors causing these 

exceedances. AQMD staff agreed to attempt to obtain this information. (Ted Guth, 

Consultant; Gary Rubenstein, Sierra Research; Noel Muyco, Southern California Gas 

Co.; Karl Lany, SCEC; Howard Lange, AQMD)

Proposed Updates of Part D (MSBACT) 

Guidelines 

Update of MSBACT for Stationary (Non-Emergency) I.C. Engines 

Rated at or above 2064 BHP 

Current MSBACT guidelines for stationary I.C. engines rated at or above 2064 bhp for 

NOx and CO are 21 ppmvd@15%O2 multiplied by engine efficiency (HHV) divided by 

33 and 33 ppmvd@15%O2, respectively. There is no MSBACT for VOC or NH3. The 

new Part B listing of NEO California Power’s large stationary engines presented at the 

September 2003 SRC meeting (16 engines rated at 3870 bhp and approximately 39% 

efficiency [HHV], started up in 2001) documented permit conditions of 9 

ppmvd@15%O2 NOx, 56 ppmvd@15%O2 CO, 25 ppmvd@15%O2 VOC and 10 

ppmvd@15%O2 NH3, all of which had been demonstrated in a source test. Based on 

that case, AQMD proposed to lower the NOx MSBACT guideline for this equipment 

category to 9 ppmvd@15%O2 and add MSBACT for VOC and NH3 of 25 and 10 

ppmvd@15%O2, respectively. AQMD proposed to leave the MSBACT guideline for 

CO unchanged since the CO limit in the NEO California Power permit is less stringent 

than the existing MSBACT guideline. Handouts showing the proposed changes and cost 

effectiveness calculations were available to all attendees. (Marty Kay, AQMD) 

Discussion: A committee member suggested that it would be simpler to adjust the 

guidelines for NOx, VOC and CO to 0.15, 0.15, 0.6 g/bhp-hr, respectively, to be 

consistent with the guideline for smaller stationary I.C. engines. AQMD staff responded 
SRC Meeting Minutes January 22, 2004 

7 

that concentration limits are preferable because uncertainty in determining the power 

level at which an engine is operating makes g/hp-hr limits difficult to enforce. AQMD 

staff added that applying an efficiency ratio to the ppm guideline is also undesirable 

because of uncertainty in determining the engine’s efficiency (e.g., even the specified 

full-load efficiency is frequently uncertain because the information available with the 

engine frequently does not specify LHV or HHV basis). The same committee member 

expressed concern that a fixed ppm limit based on the NEO engines may be difficult for 

other engines that are more efficient. AQMD staff responded that the NEO engines have 

rated efficiency of about 39% (HHV), which is quite high for this type of engine. 

Another committee member suggested that applying an efficiency ratio would allow a 

higher ppm limit for more efficient engines. AQMD staff responded that that approach 

would also make it more difficult for less efficient engines. 

A committee member pointed out that the NEO engines do not have CEMS whereas 

similar engines in the South Coast would be required to have CEMS and it would be 

more difficult to comply with the emission limits with CEMS monitoring as opposed to 

annual source testing. AQMD staff responded that two NEO engines, selected by the 

APCD, had been tested a year after the initial source test and were found to be still in 

compliance, although the NOx and CO levels had increased. Another committee member 

noted that the NEO limits may not be suitable for all similar engines because I.C. engines 

operate in a wide range of duty cycles. 

A committee member asked what was the averaging time associated with the NEO limits. 

AQMD staff responded that there were no apparent averaging times in the permits, but 

AQMD would lean toward a 1-hr average. Another committee member expressed 

concern regarding keeping the MSBACT guideline for CO the same while lowering the 

NOx guideline. AQMD staff noted that the CO levels measured in the source test were 

less than 33 ppmvd@15%O2 for all engines and pointed out that there should not be a 

NOx-CO tradeoff in this case because the emission control technology (SCR and 

oxidation catalyst) affords independent control of NOx and CO. 

It was agreed that since AQMD did not plan to bring this matter before its Board until 

June 2004, it could be discussed again at the next meeting. (Karl Lany, SCEC; Gary 

Rubenstein, Sierra Research;Marty Kay, AQMD; Howard Lange, AQMD) 

Update of MSBACT for Dry Cleaning; Incinerator—NonInfectious, Non-Hazardous Waste; Pharmaceutical 

Manufacturing; Polystyrene Manufacturing 

Staff stated that AQMD also planned to update MSBACT guidelines for several other 

equipment categories including Dry Cleaning, Incinerator—Non-Infectious, NonHazardous Waste, Pharmaceutical Manufacturing and Polystyrene Manufacturing. A 

handout was available to all attendees showing the proposed changes. The proposed 

changes to the Dry Cleaning and Pharmaceutical Manufacturing guidelines consisted of 

adding “compliance with Rule 1102” and “compliance with Rule 1103”, respectively. 

The proposed change in the guideline for Incinerator—Non-Infectious, Non-Hazardous 

Waste was to delete the words “upon final promulgation of the regulation” from a 
SRC Meeting Minutes January 22, 2004 

8 

footnote that refers to 40 CFR 60, Subpart CCCC since that regulation has now been 

promulgated. Polystyrene Manufacturing was to be deleted as a separate equipment 

category and become a subcategory under Resin Manufacturing. (Marty Kay, AQMD)

Discussion: Regarding the MSBACT guidelines for Dry Cleaning, a committee member 

suggested that: (1) the requirement of a refrigerated condenser be deleted from the 

guideline for petroleum solvent dry cleaning in that AQMD has permitted numerous 

petroleum solvent dry cleaning systems without refrigerated condensers and (2) the 

subcategory “Valclene” be deleted in that Valclene is no longer used for dry cleaning. A 

second committee member agreed that Valclene is probably no longer used for dry 

cleaning. The first committee member also noted that Valclene is chemically equivalent 

to “CFC-113” and was banned from production in 1996. AQMD staff agreed to 

investigate and consider these suggestions. (Katy Wolf, IRTA; Todd Wong, CARB; Marty 

Kay, AQMD) 

Other Business 

Marty Kay announced that the date of the next meeting would be March 25 and thanked 

all attendees for their participation.

There was no further discussion, and the meeting was closed. 

Attachments 
Appendix B - BACT Determinations

Palmdale Hybrid Power Project

Supplemental PSD Submittal

RBLCID FACILITY NAME PROCESS NAME THROUGHPUT UNIT NOX CONTROL METHOD DESCRIPTIO

AR-0090 NUCOR STEEL, ARKANSAS PICKLE LINE BOILERS 12.6 MMBTU/H LOW NOX BURNERS LA-0192 CRESCENT CITY POWER FUEL GAS HEATERS (3) 19 MMBTU/H LOW NOX BURNERS AND GOOD COMNV-0046 GOODSPRINGS COMPRESSOR STATION COMMERCAIL/INSTITUTION BOILER 3.85 MMBTU/H GOOD COMBUSTION PRACTICE NV-0047 NELLIS AFB BOILERS/HEATERS 6.5 MMBTU/H LOW NOX BURNER AND FLUE GAS RENV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT HA08 8.37 MMBTU/H LOW NOX BURNER NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT FL01 14.34 MMBTU/H LOW NOX BURNER AND FLUE GAS RENV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT BA01 16.8 MMBTU/H LOW NOX BURNER AND FLUE GAS RENV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT BA03 31.38 MMBTU/H LOW NOX BURNER NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT CP01 35.4 MMBTU/H LOW NOX BURNER NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT CP03 33.48 MMBTU/H LOW NOX BURNER NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT CP26 24 MMBTU/H LOW NOX BURNER NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT PA15 21 MMBTU/H LOW NOX BURNER NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT IP04 16.7 MMBTU/H LOW NOX BURNER OH-0310 AMERICAN MUNICIPAL POWER GENERATING STATION AUXILIARY BOILER 150 MMBTU/H OR-0046 TURNER ENERGY CENTER, LLC ELECTRICAL POWER GENERATION 34507448 MMBTU/YR SELECTIVE CATALYTIC REDUCTION OR-0046 TURNER ENERGY CENTER, LLC AUXILIARY BOILER 417904 MMBTU/YR SELECTIVE CATALYTIC REDUCTION WA-0301 BP CHERRY POINT REFINERY PROCESS HEATER, IIHT 13 MMBTU/H ULTRA LOW NOX BURNERS WV-0023 MAIDSVILLE AUXILIARY BOILER 225 MMBTU/H LOW NOX BURNERS AND GOOD COMAR-0090 NUCOR STEEL, ARKANSAS PICKLE LINE BOILERS 12.6 MMBTU/H GOOD COMBUSTION PRACTICE LA-0192 CRESCENT CITY POWER FUEL GAS HEATERS (3) 19 MMBTU/H GOOD COMBUSTION PRACTICES NV-0046 GOODSPRINGS COMPRESSOR STATION COMMERCAIL/INSTITUTION BOILER 3.85 MMBTU/H GOOD COMBUSTION PRACTICE NV-0047 NELLIS AFB BOILERS/HEATERS 6.5 MMBTU/H FLUE GAS RECIRCULATION NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT HA08 8.37 MMBTU/H OPERATING IN ACCORDANCE WITH T

SPECIFICATION 

NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT FL01 14.34 MMBTU/H FLUE GAS RECIRCULATION NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT BA01 16.8 MMBTU/H FLUE GAS RECIRCULATION NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT BA03 31.38 MMBTU/H OPERATING IN ACCORDANCE WITH T

SPECIFICATION 

NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT CP01 35.4 MMBTU/H FLUE GAS RECIRULATION AND OPER

MANUFACTURER'S SPECIFICATION 

NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT CP03 33.48 MMBTU/H OPERATING IN ACCORDANCE WITH T

SPECIFICATION 

NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT CP26 24 MMBTU/H OPERATING IN ACCORDANCE WITH T

SPECIFICATION 

NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT PA15 21 MMBTU/H N/A NV-0049 HARRAH'S OPERATING COMPANY, INC. BOILER - UNIT IP04 16.7 MMBTU/H OPERATING IN ACCORDANCE WITH T

SPECIFICATION 

WA-0301 BP CHERRY POINT REFINERY PROCESS HEATER, IIHT 13 MMBTU/H N/A 

 60138827-040 1 of 1 
AECOM Environment 

Appendix C 

Preliminary Cost Effectiveness 

Calculation 
Appendix C - Cost Analysis

Palmdale Hybrid Power Project 

Supplemental PSD Submittal

Direct costs Electrostatic 

precipitator Venturi scrubber Fabric filter Electrostatic precipitator Venturi scrubber Fabric filter Electrostatic precipitator Ve

Purchased equipmentExhaust Flow Rate (Ft3/min) 946,777 946,777 946,777 28,416 28,416 28,416 10,612 Capital costs $18,935,547.60 $2,366,943.45 $8,520,996.42 $568,314.11 $71,039.26 $255,741.35 $212,239.30 Adjustment factor 0.11 0.11 0.11 0.11 0.11 0.11 0.11 Annualized Capital Costs $2,430,489.07 $303,811.13 $1,093,720.08 $72,946.46 $9,118.31 $32,825.91 $27,242.16 Operating & maintenance costs

$4,733,886.90 $4,165,820.47 $5,680,664.28 $142,078.53 $125,029.10 $170,494.23 $53,059.82 

Annualized capital costs + operating costs x CPI 2002 - 2010 (21%)

$8,158,492.22 $5,344,453.90 $7,967,323.86 $244,861.48 $160,403.52 $239,123.93 $91,444.55 

Emissions from 99% Removal 57.96 57.96 0.20 0.20 0.20 

Cost

CTGs and HRSG Auxiliary Boiler 

effectiveness for 99% removal ($/ton PM)

$140,749.81 $137,451.78 $1,236,674.15 $1,207,696.62 $461,841.17 

ReferencesSTAPPA/ALAPCO. Controlling Fine Particulate Matter Under the Clean Air Act: A Menu of Options, Chapter 5, Boiler Technologies, March 2006 - low end o

Equipment type Capaital cost , $/scfm O&M cost, $/scfm

Reverse-air cleaned filter 9 - 85 6 - 27Wet wire-plate ESP 20 - 40 5-40Venturi scrubber 2.5 - 21 4.4 - 120

 60138827-040 1 of 1