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Kelly, Shaheerah

From: Kelly, Shaheerah

Sent: Wednesday, August 07, 2013 6:51 PM

To: 'Dave Brown'

Cc: Rios, Gerardo; Christenson, Kara

Subject: SPI Anderson GHG BACT Analysis

Attachments: Draft SPI GHG BACT Additional Info Needed - EPA notes 08072013.docx; EPA-SPI Meeting 

Participants 06AUG2013.pdf

Hi Dave,

It was a pleasure meeting you and the other SPI representatives. Per our discussion at the meeting, the attached

document contains our responses regarding the revised GHG BACT analysis. Also attached is the list of meeting

participants.

In addition, I understand that you will be providing us with a summary of the power contract agreement, share

deadlines and operational requirement timelines, and include how the agreement requires the SPI Anderson facility to

have the operational flexibility it needs.   

I will be away from the office until Tuesday, August 20.  

Thanks.   

************************************ 

Shaheerah Kelly 

U.S. Environmental Protection Agency, Region 9 

Permits Office, Air Division 

San Francisco, CA 94105 

Phone: 415-947-4156 

Fax: 415-947-3579 

Email: kelly.shaheerah@epa.gov
DRAFT 

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Additional Information EPA Will Need from Sierra Pacific Industries-Anderson Division to 

Proceed with a voluntary GHG PSD Permit 

(Note: SPI’s responses as in red; EPA’s follow-up responses are in yellow highlight)

EMISSION ESTIMATES

1. In addition to the information provided in Table 2-1 in the Sierra Pacific Industries’s (SPI) June 

2011 Best Available Control Technology (BACT) analysis for greenhouse gas (GHG) 

emissions: 

a. GHG emission estimates and calculations (and assumptions used in these calculations) for 

each of the new and modified emission units (e.g., biomass boiler, emergency engine, 

circuit breakers,etc) for (1) maximum worst case annual emission estimates of GHG 

pollutants (i.e., CO2e, CO2, N2O, CH4, SF6,etc) expected from the emission units in tons per 

year (tpy); Revised and expanded Table 2-1

b. Emission estimates of GHG pollutants expected during startup periods, shutdown periods, 

and normal operation expected from the emission units in tpy; and Added explanatory text

(Please provide actual quantified estimates of GHG emissions during startup and shutdown 

periods.)

c. Emission estimates of GHG pollutants for existing equipment at the facility in tpy. Added 

Table 2-2

GHG BACT ANALYSIS

1. An assessment of the use of stoker and fluidized bed boiler in the design of the cogeneration 

unit for minimizing GHG emissions. For your information, EPA’s combined heat and power 

(CHP) website has information on biomass conversion technologies, and includes information 

on stoker and fluidized bed boilers that may be useful.1 Added explanatory text (Please provide 

a technical assessment of use of a stoker and fluidized bed boiler in Step 1, and throughout the 

BACT analysis if applicable, which includes a comparison of efficiencies. In addition, please 

consider adding a cost effectiveness analysis for stoker vs fluidized in Step 3 as another 

argument to their redesigning source argument.)

2. A GHG assessment of any new circuit breakers that potentially emit SF6 in the GHG BACT 

analysis. Added explanatory text; existing circuit breakers will remain and be used by proposed 

cogeneration unit, therefore, no evaluation is needed

3. A GHG assessment of the proposed natural gas-fired 256 horsepower emergency engine. Added 

section 8 

 

1

 See the section titled “Biomass CHP Catalog of Technologies” at 

http://www.epa.gov/chp/technologies.html. 
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4. An assessment that considers GHG BACT determinations made for other biomass boiler units. 

We are aware of the following projects in Table 1 that have been evaluated and issued final 

permits with GHG emission and operational limits. Obtained and reviewed permit materials for 

all facilities in table below, added text briefly summarizing findings (Compare the BACT limits 

and requirements for these facilities with those proposed for the SPI biomass boiler. If there are 

any determinations for these facilities that are not accepted by SPI, please explain why the 

control option or limit is not feasible for the SPI cogeneration unit.)

Table 1: Recent Permit Decisions containing GHG Determinations 

Facility State Permit Issuance Date 

Montville Power LLC CT 4/6/2010 

Beaver Wood Energy Fair Haven LLC VT 2/10/2012 

North Springfield Sustainable Energy Project VT 4/19/2013 

WE Energies (Rothschild facility) WI 3/28/2011 

Abengoa Bioenergy Biomass of Kansas LLC KS 9/16/2011 (Effective date) 

5. An evaluation of the technical feasibility of using carbon adsorption in Section 4. Section 3.2 

identifies carbon adsorption as a potential control technology for minimizing methane 

emissions. Added clarifying text (Explain why this technology is not technically feasible for the 

SPI biomass boiler (e.g., concentration of methane is expected to be low in the exhaust stream). 

Please provide specific information about the operation or emissions from the biomass boiler 

and the optimum or expected conditions for a carbon adsorption unit to work properly.)

6. An evaluation of the technical basis that explains why thermal oxidation is not technical feasible 

for the boiler. Section 4.2, under Thermal Destruction, eliminates thermal oxidation as 

technically infeasible for control of methane from the boiler because “it is not clear that use of 

such system would result in a net reduction in methane.” Added clarifying text (Explain why 

this technology is not technically feasible for the SPI biomass boiler (e.g., concentration of 

methane is expected to be low in the exhaust stream). Please provide specific information about 

the operation or emissions from the biomass boiler and the optimum or expected conditions for 

a thermal oxidizer to work properly.)

7. An evaluation of the technical basis that explains why non-selective catalytic reduction (NSCR) 

is not feasible for the boiler. Section 4.3, under Non-Selective Catalytic Reduction Systems, 

eliminates NSCR as technically infeasible for control of nitrous oxide from the boiler because 

“significant differences exist between the exhaust from adipic and nitric acid operations and that 

of a biomass-fired boiler, it is not clear that the technology could be transferred effectively.” It 

would be helpful if SPI would explain these differences. Removed text to jibe with 

determination that NSCR was not technically feasible, also added clarifying text (Explain why 

this technology is not technically feasible for the SPI biomass boiler (e.g., concentration of 

methane is expected to be low in the exhaust stream). Explain the “significant differences” 

between the SPI’s cogeneration unit and the adipic/nitric acid operations. For example, SPI can 

compare the differences in concentrations in the exhaust streams. Also, please provide specific 

information about the operation or emissions from the biomass boiler and the optimum or 

expected conditions for a NSCR unit oxidizer to work properly.
DRAFT 

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8. Emission calculations (and assumptions used) for the estimates of “percent reduction in emitted 

GHGs on a CO2e basis” in section 5 of the analysis. This is currently not provided in the 

analysis. Added references and reduction calculations 

9. Cost calculations (and assumptions used) for the estimates of “percent reduction in emitted 

GHGs on a CO2e basis” in section 6 of the analysis. This is currently not provided in the 

analysis. Biomass Fuel Use – no cost calculation needed; CCS – referenced cost calculation 

from NETL document; Catalytic Destruction – calculated cost threshold from calculated 

potential reduction and value of CO2e reduction; Removal of SNCR System – unacceptable 

from environmental standpoint, so no cost calculation needed; Proper Combustion/Energy 

Efficiency – no cost calculation needed (Provide specific cost calculations, including capital and 

annualized costs, for CCS in Step 4. Also provide specific environmental impacts and quantity 

of energy impacts to the extent that it can be quantified. )

10. A proposed annual CO2e emission limit in tpy for the proposed project. Proposed GHG BACT 

limit (annual tpy) provided (See comment #4 above.)
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