Rio Bravo Poso PSD Permit (SJ 85-06) 

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Ambient Air Quality Impact Report 

Rio Bravo Poso 

PSD Permit Number: SJ 85-06 

This document serves as the statement of basis as required by 40 CFR 124. This document sets 

forth the legal and factual basis for permit conditions, including references to applicable statutory 

or regulatory provisions, including provisions under 40 CFR 52.21. This document is for all 

parties interested in the permit.

I. APPLICANT

Rio Bravo Poso 

19100 Von Karman 

Suite 570 

Irvine, CA 92612 

II. PROJECT LOCATION

This existing biomass power plant is located at 16608 Porterville Highway in Bakersfield, 

California. The facility is located within Rio Bravo Poso’s Heavy Oil Central Stationary 

Source, in the SW 1⁄2 of Section 28, Township 27S, Range 27E at 16608 Porterville. 

III. PROJECT DESCRIPTION

Rio Bravo Poso (Poso) is a 389 MMBtu/hr solid fuel-fired power plant that employs a 

Combustion Engineering- Lurgi circulating fluidized bed boiler. The applicant is 

proposing to add additional types of solid biomass fuel to their allowable fuel feed. The 

additional fuels to be added shall conform to the definition of clean cellulosic biomass as 

defined in 40 CFR Part 241.2. In particular, clean cellulosic biomass means those 

residuals that are akin to traditional cellulosic biomass such as forest-derived biomass 

(e.g., green wood, forest thinnings, clean and unadulterated bark, sawdust, trim, and tree 

harvesting residuals from logging and sawmill materials), corn stover and other biomass 

crops used specifically for energy production (e.g., energy cane, other fast growing 

grasses), bagasse and other crop residues (e.g., peanut shells), wood collected from forest 

fire clearance activities, trees and clean wood found in disaster debris, clean biomass 

from land clearing operations, and clean construction and demolition wood. These fuels 

are not secondary materials or solid wastes unless discarded. Clean biomass is biomass 

that does not contain contaminants at concentrations not normally associated with virgin 

biomass materials. 

An October 22, 1986 Approval to Construct was originally issued to Rio Bravo Refining 

Company for the construction of a coal-fired cogeneration facility near Bakersfield, 
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California. The permit was revised on July 23, 1993, June 9, 1995, October 6, 1998 and 

May 21, 2004. The Poso facility is currently permitted to burn petroleum coke, coal and 

up to 20% by weight of tire-derived fuel. 

The permit was amended on December 13, 2010 to conduct trial burns of the new fuel 

mixtures proposed to be permanently added as a part of this permit action. The trial burns 

were conducted in two consecutive six-month periods with consistent emissions data 

collected and submitted after a continuous 5.5 month period. The proposed modification 

will allow Poso additional flexibility in utilizing various fuel mixtures without increasing 

any emissions limitations in the proposed permit. Emissions data gathered from the test 

burn were used as the basis for the proposed modification. 

IV. EMISSIONS FROM THE PROJECT

The San Joaquin Air Pollution Control District (District) is currently classified as 

attainment or unclassified for carbon monoxide (CO), sulfur dioxide (SO2), inhalable 

coarse particulate matter, (PM10) nitrogen dioxide (NO2) and lead (Pb). The San Joaquin 

APCD is classified as nonattainment for fine particulate matter (PM2.5) and extreme 

nonattainment for 1-hour and 8-hour ozone. 

The Poso facility is a fossil-fuel fired steam electric plant of more than 250 MMBtu/hr 

heat input and is currently classified as a PSD major source for CO, NOx and SO2

according to 40 CFR 52.21(b)(1)(i)(a). The Poso facility is also an existing major source 

of Greenhouse Gases. 

Baseline Actual Emissions (BAE)

Pre-project BAE were calculated by averaging actual emissions data for calendar years 

2006 and 2007. NOx and CO emissions were calculated using CEMS data. SO2 and PM10

emissions were calculated using source test data. BAE of Pb were conservatively 

assumed to be zero. 

PM emissions were calculated using PM10 source test data and AP-42 emissions 

estimates for boilers fired with coal and equipped with an electrostatic precipitator (ESP). 

Emission factors for PM and PM10 when using a fluidized bed boiler are 17 lb/ton and 

12.4 lb/ton respectively. Thus, PM10 emissions were multiplied by an emissions 

adjustment factor of 17/12.4 = 1.37 to estimate PM emissions. 

Greenhouse Gas (GHG) Emissions were calculated using the emission factors found in 

Table C-1 of 40 CFR Part 98-Mandatory Greenhouse Gas Reporting and the average 

annual heat input from 2009 and 2010. Detailed calculations are contained in the 

Appendix of this document. 

Table IV-1 below summarizes the pre-project baseline actual emissions. 
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Table IV-1

Pre-project Baseline Actual Emission Rates 

Pollutant Short Tons/year 

Nitrogen Oxides (NOx) 141.6 

Carbon Monoxide (CO) 79.9 

Sulfur Oxides (SO2) 50.7 

Particulate Matter (PM) 12.1 

Inhalable Coarse Particles (PM10) 8.8 

Lead (Pb) 0 

Greenhouse Gases (CO2e) 334,334 

Projected Future Actual Emissions (PFAE)

Post-project PFAE were calculated using CEMS and source testing data during the trial 

burn period and EPA emissions factors. CEMS data for NOx, SO2 and CO were 

submitted on October 26, 2011 and PM10 source tests were submitted on November 7, 

2012. Tables IV-2 and IV-3 below summarize the post-project facility-wide PFAE and 

the emission increase/decrease for each pollutant. Detailed calculations are contained in 

the Appendix of this document. 

NOx, SO2 and CO emissions were calculated using CEMS data collected during the trial 

burn period in which the facility was allowed to combust various biomass fuels. Postproject PFA emissions for NOx, SO2 and CO were calculated by projecting an annual 

emissions output from monthly emissions over the trial period. 

PM and PM10 emissions figures were calculated using source test data for PM10 obtained 

during the trial burn period. PM emissions from the boiler were calculated using the same 

emission adjustment values as those used for the pre-project baseline actual emissions 

section described above, e.g. PM10 emissions from the boiler were multiplied by a factor 

of 1.37 for coal. AP-42 emission factors for PM and PM10 when burning woody biomass 

while using an ESP are 0.054 lb/MMBtu and 0.04 lb/MMBtu respectively. Thus, PM10

emissions from biomass would multiplied by an emissions adjustment factor of 1.35 

(0.054/0.04 = 1.35) to estimate PM emissions from biomass. However, for calculation 

purposes, EPA chose to use the more conservative estimate of 1.37 for the new fuel 

mixture. The plant was also assumed to operate 8,760 hours per year. 

Pb emissions were calculated using the AP-42 emission factor for woody biomass and the 

projected annual heat input. The estimated annual lead emissions rate from the facility 

with either biomass or coal is substantially below the significance threshold. 

GHG emissions, measured in CO2e, were calculated using projected power output 

estimates and EPA emissions factors. PFAE of CO2e were calculated using biomass 

emission factors to account for the differing chemical composition and energy density of 

coal and biomass fuels. Detailed calculations are contained in the Appendix of this 
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document. 

Table IV-2

Post-project Projected Future Actual (PFA) Emission Rates 

Pollutant Short Tons/ year

Nitrogen Oxides (NOx) 132.8 

Carbon Monoxide (CO) 88.2 

Sulfur Oxides (SO2) 44.4 

Particulate Matter (PM) 15.8 

Inhalable Coarse Particles (PM10) 11.5 

Lead (Pb) 0.08 

Greenhouse Gases (CO2e) 376,657 

Table IV-3

Emission Increases from Project 

Pollutant Short Tons/ year 

Nitrogen Oxides (NOx) - 8.8 

Carbon Monoxide (CO) 8.3 

Sulfur Oxides (SO2) - 6.3 

Particulate Matter (PM) 3.7 

Inhalable Coarse Particles (PM10) 2.7 

Lead (Pb) 0.08 

Greenhouse Gases (CO2e) 42,322 

V. APPLICABILITY OF PREVENTION OF SIGNIFICANT DETERIORATION

The PSD regulations (40 CFR 52.21) define a major source as any source type belonging 

to a list of 28 source categories which emits or has the potential to emit 100 tons per year 

(tpy) or more of any attainment pollutant regulated under the Clean Air Act, or any other 

source type which emits or has the potential to emit such pollutants in amounts equal to 

or greater than 250 tpy. Since fossil fuel fired steam electric plants greater than 250 

MMBtu/hr are included in the 28 source categories specified in the PSD regulations, the 

100 tpy threshold applies to this project. 

The facility is a major source for the attainment pollutants of CO, NOx and SO2 based on 

the potential to emit calculated for the facility in SJ 85-06 issued on October 24, 1986. 

Based on the pre-project BAE, the facility is also an existing major source of GHGs. 

Using the data provided in Tables IV-1 through IV-3 above, Table V-1 below 

summarizes the projected emission increases and significant thresholds for each 
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attainment pollutant. As shown by the data provided by the applicant and summarized in 

Table V-1, the project will not result in a significant increase of any attainment pollutant 

subject to the PSD regulations. Accordingly, the proposed project does not trigger any 

major source PSD requirements. 

Table V-1 

Significant Emission Threshold Evaluation (tons per year)

Pollutant Projected 

Increase 

Significant 

Thresholds 

Significant 

Increase? 

Nitrogen Oxides (NOx) -8.8 40 No

Carbon Monoxide (CO) 8.3 100 No

Sulfur Oxides (SO2) -6.3 40 No 

Particulate Matter (PM) 3.7 25 No 

Inhalable Coarse Particles (PM10) 2.7 15 No 

Lead (Pb) .08 0.6 No 

Greenhouse Gases (CO2e)1 42,322 75,000 No 

VI. BEST AVAILABLE CONTROL TECHNOLOGY

PSD regulations require that a Best Available Control Technology (BACT) determination 

be made for each pollutant subject to major PSD requirements. As noted in Section V, 

this project does not trigger any major PSD requirements; therefore the application of 

BACT is not required for this project. 

VII. REVISED EMISSION LIMITS AND CONDITIONS

We are revising the permit to include certain types of biomass to the list of acceptable 

fuels at the facility. We are adding clean cellulosic biomass to the previously permitted 

fuels of pet coke, coal and tire-derived fuel. As EPA considers new standards of 

performance for commercial and industrial solid waste incinerators, it is important to 

distinguish that the clean cellulosic biomass fuels that the facility is proposing to burn are 

not secondary materials or solid wastes unless discarded, according to 40 CFR Part 241.2. 

Fuel consumption restrictions were changed to compliance on a 30-day rolling average 

rather than an hourly basis. In order to account for the increased variability in allowable 

fuels, the fuel restrictions for coal, pet coke and tire-derived fuel have been changed from 

 

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 The proposed modification will not cause a significant increases in GHG emissions; however, the Deferral for 

CO2 emissions from Bioenergy and Other Biogenic Sources under the Prevention of Significant Deterioration and 

Title V Programs (76 FR 43490 July 20, 2011) would apply to this project if the anticipated increase were 

significant. 
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34,855 pounds per hour of solid fuel to 836,520 (34,855 x 24= 836,520) pounds per day 

on a 30-day rolling average. Moreover, in response to the disparate energy density 

between biomass and the other permitted fuels, the facility will be allowed to substitute 

two pounds of biomass for every pound of coal or pet coke. All emission limits and 

averaging times will remain the same for all criteria pollutants, regardless of the amount 

or type of fuel consumed. 

Previous versions of the PSD permit did not have emission limitations for PM or PM10. 

District permits, however, include PM10 emissions limitations, which we have 

incorporated into the PSD permit. In addition, we have also included PM 10 emissions 

limits from 40 CFR Part 60 Subpart D-a: Standards of Performance for Electric Utility 

Steam Generating Units for Which Construction is Commenced After September 18, 

1978. In order to verify these emissions limitations, annual performance tests for PM10

using EPA Methods 201A and 202 were added to this permit. 

 

VIII. AIR QUALITY IMPACTS

As noted in Section V of this review, this project will not result in a major PSD 

modification; therefore an Air Quality Impact Analysis is not required. 

IX. ADDITIONAL IMPACT ANALYSIS

As noted in Section V of this review, this project will not result in a major PSD 

modification; therefore no Additional Impact Analysis is required. 

X. ENDANGERED SPECIES ACT

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. '1536, and its 

implementing regulations at 50 CFR Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued 

existence of any endangered species or threatened species or result in the destruction or 

adverse modification of such species or designated critical habitat. EPA determined that 

this PSD permitting action is subject to ESA Section 7 requirements. 

Since this project will not result in any new construction outside the current physical 

footprint of the facility; and NOx and SO2 emissions will likely decrease; and the increase 

of CO, PM, PM10 and Pb emissions are well below significance levels, EPA concludes 

that the project will have no likely adverse effect on any endangered or threatened species 

or designated critical habitat. Discussions with the United States Fish and Wildlife 

Service support EPA’s conclusion. 

XI. CONCLUSION AND ACTION
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Based on the information supplied by the Applicant, and the evaluation provided which 

determined this project will not result in a major PSD modification, EPA is proposing to 

issue a modified PSD permit with the attached draft permit conditions (PSD Permit 

number SJ 85-06). 

APPENDIX 

 

Post-project PFA Emissions Calculations 

Given: 

Trial Burn Period P = 5.5 months

Months in a Year M = 12 months 

Maximum hours of operation hMAX = 8760 hours 

Projected Future Actual Heat Input HI= 3,188,758 MMBTU/yr 

Pound to ton conversion PT = 2000 lbs/ton 

Carbon Monoxide (CO)

Total Emissions During Trial Burn TECO = 40.43 tons 

PFACO = TECO x (M/P) 

= 88.2 tpy 

Oxides of Nitrogen (NOx)

Total Emissions During Trial Burn TENOx = 60.89 tons 

PFANOx = TENOx x (M/P) 

= 132.8 tpy 

Sulfur Dioxide (SOx)

Total Emissions During Trial Burn TESO2 = 20.35 tons 

PFASO2 = TESO2 x (M/P) 

= 44.4 tpy 

Particulate Matter (PM)

New Fuel Mixture PM10 Source Test Emission Rate FERPM10 = 2.63 lbs/hour 

Boiler AP-42 adjustment factor AFbio = 1.37 

PFAPM = FERPM10 x AFbio x hMAX x (1/PT) 

= 15.8 tpy 
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Inhalable Coarse Particles (PM10)

New Fuel Mixture PM10 Source Test Emission Rate FERPM10 = 2.63 lbs/hour 

Boiler AP-42 adjustment factor AFbio = 1.37 

PFAPM10 = FERPM10 x hMAX x (1/PT) 

= 11.5 tpy 

Lead (Pb)

Woody Biomass AP-42 Lead Emissions Rate ERPb = 4.8 x 10-5 lbs/MMBTU 

Projected Future Actual Heat Input HI = 3,188,758 MMBTU/yr 

PFAPb = HI x ERPb x (1/PT) 

= .08 tpy