EPA / SPI Anderson Meeting

EPA Region 9, 75 Hawthorne Street, San Francisco 94105

Conference Room 1714

2:30 PM – 3:30 PM

August 6, 2013

AGENDA

1. Introductions

2. Discuss voluntary inclusion of GHGs in the PSD permit

3. Power Contract

4. Re-notice of Permit

5. Timelines

6. Next Steps
DRAFT

1

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

Proceed with a voluntary GHG PSD Permit

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

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

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

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

 1

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

http://www.epa.gov/chp/technologies.html. 
DRAFT

2

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

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

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

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

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

limit (annual tpy) provided
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