19020 33rd Avenue W, Suite 310, Lynnwood, WA 98036-4748 

Tel: +1 425.412.1800 Fax: +1 425.412.1840 

www.environcorp.com

June 8, 2011 

Project No. 29-23586A 

Mr. Gerardo Rios 

U.S. Environmental Protection Agency, Region 9 

75 Hawthorne Street 

San Francisco, California 94105 

Subject: Response to Additional Information Request 

Sierra Pacific Industries Biomass-Fired Cogeneration Project 

Anderson, California 

Dear Mr. Rios:

This letter provides information requested by the U.S. Environmental Protection Agency, 

Region 9 (Region 9) during a conference call with Sierra Pacific Industries (SPI) on 

January 11, 2011 to discuss the cogeneration project proposed by SPI. The information 

requests are provided as italicized introductions to each response. 

Provide greenhouse gas (GHG) emission rates associated with the project. 

The proposed cogeneration unit will be designed to have an annual average heat input of 

425 million British thermal units per hour (MMBtu/hr). GHG emission factors for CO2, 

methane (CH4), and nitrous oxide (N2O) were obtained from Tables C-1 and C-2 of the 

Federal Mandatory GHG Reporting Rule (40 CFR Part 98). Table 1 summarizes the 

calculations and shows that the proposed unit has the potential to generate a maximum of 

approximately 393,000 tons of CO2e per year. The proposed unit combusts a small amount 

of natural gas during a limited number of startup events throughout the year, but the vast 

majority of emissions will be from combustion of solid biomass fuel. 

Table 1. Greenhouse Gas Energy Output Emission Factor Calculations 

Pollutant 

Emission Factor (Heat Input)1

Global Warming 

Potential2

Emission Rate3

(kg/MMBtu) (lb/MMBtu) (lb/hr) (tpy)

CO2 93.8 207 1 87,973 385,322 

CH4 3.20E-02 0.0705 21 30.0 131 

N2O 4.20E-03 0.00926 310 3.94 17 

CO2e -- -- -- 89,824 393,431 

1 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel are from 40 

CFR Part 98, Tables C-1 and C-2; the lb/MMBtu emission factors are calculated by converting the kg/MMBtu 

emission factors using 2.2046 lb/kg. 

2 100-year time horizon global warming potential (GWP – from 40 CFR Part 98, Table A-1. 

3 Calculated by multiplying the emission factor by the annual average heat input (425.419 MMBtu/hr). CO2e 

was calculated by multiplying each individual emission rate by the applicable GWP factor, and summing. 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

June 8, 2011 

Page 2 

Provide a Best Available Control Technology (BACT) analysis for GHG emissions 

associated with the proposed project. 

Please find a GHG BACT analysis attached to this letter. 

Justify the exclusion of circulating fluidized bed (CFB) boiler designs from Step 1 of the 

BACT analysis provided in support of the submitted permit application. 

The Anderson lumber manufacturing facility produces more biomass fuel than the existing 

boiler can combust. Rather than continuing to sell the excess fuel, SPI proposes to install a 

larger cogeneration unit capable of combusting most, if not all (depending upon economic 

conditions), of the fuel generated on site. The steam produced by the proposed cogeneration 

unit would not only heat the lumber drying kilns at the facility, but produce enough 

electricity to power the facility while delivering approximately 24 MW of renewable energy 

to the grid. 

In 2009, the Environmental Review Board (ERB) remanded a permit issued to a proposed 

coal-fired power plant in New Mexico (Desert Rock Energy Co.), stating that Region 9 

“abused its discretion in declining to consider integrated gasification combined cycle (IGCC) 

as a potential control technology in Step 1 of its BACT analysis for the facility.” In light of 

that ruling, Region 9 has requested that SPI retroactively include CFB boiler designs in the 

submitted analysis, or justify the exclusion of CFB designs from Step 1 of the BACT 

analysis. 

The BACT analysis provided as an appendix to the permit application stated that fluidized 

bed boiler technology was not considered for the proposed project. Whereas SPI has 

considerable institutional experience operating biomass-fired boilers, it has no experience 

with fluidized-bed designs. Were a fluidized-bed boiler selected for the project, extensive 

training or replacement of existing personnel at the facility would be required to address the 

significant operational differences between the two design technologies. 

Additionally, SPI is aware of the experience of the 25-MW Rio Bravo Rocklin Power Station 

in Lincoln, California, which recently spent $14 million to improve availability of a biomassfire CFB boiler from 77 percent to 88 percent. In comparison, the proposed boiler is 

expected to have an availability of greater than 90. The business viability of the Anderson 

facility depends upon a near-constant supply of steam to heat the lumber dry kilns, and, 

based on the experience of the nearest CFB boiler combusting similar fuel, a CFB design 

would not provide the long-term reliability SPI requires. 

While not explicitly stated in the permit application or BACT analysis, SPI’s desire to 

incorporate a new, reliable boiler into the existing Anderson facility with minimal alteration 

to operations and personnel was one of the chief reasons for not considering CFB designs. 

SPI believed then, as now, that consideration of a CFB design would constitute a redefinition 

of the project. 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

June 8, 2011 

Page 3 

Fluidized-bed units differ from most other biomass-fired boiler designs in that the fuel is 

introduced into a suspended bed of sand-like material instead of onto a grate or floor. The 

bed material “scours” the char from fuel particles, allowing oxygen in the combustion air to 

access un-combusted fuel. Notable operational differences between fluidized-bed and other 

biomass-fired boiler designs include: 

 higher parasitic load (additional power needed to operate the fan that suspends and 

circulates the bed materials), 

 shorter boiler life (increased metal erosion due to circulating bed material),and 

 generally more complex operation (the bed must be “tuned” to accommodate 

changing fuel characteristics, and fuel must be sized appropriately) and logistics 

(management and maintenance of the bed material). 

In its Desert Rock ruling, the EAB seeks to provide a redesign test by answering the 

question: “when does the imposition of control technology require enough of a redesign of 

the proposed facility that it strays over the dividing line to become an impermissible 

redefinition of the source?” Referring to a previous ruling (Prairie State) the EAB’s response 

to the question is: “the permit applicant initially ‘defines the proposed facility’s end, object, 

aim, or purpose – that is the facility’s basic design,’ although the applicant’s definition must 

be ‘for reasons independent of air permitting.’” Not anticipating Region 9’s request, the 

permit application did not include an explicit statement of the proposed project’s 

end/object/aim/purpose in terms that would directly address the EAB’s design test. 

Nevertheless, from the outset of the project, the end/object/aim/purpose has been to generate 

more steam and more fully utilize the biomass fuel generated on-site, while minimizing 

changes to the existing facility. 

In the Desert Rock ruling, the EAB explains how the permit issuer should conduct the proper 

test for redesign: 

“...take a ‘hard look’ at the application determination in order to discern 

which design elements are inherent for the applicant’s purpose and which 

design elements ‘may be changed to achieve pollutant emissions reductions 

without disrupting the applicant’s basic business purpose for the proposed 

facility,’ while keeping in mind that BACT, in most cases, should not be 

applied to regulate the applicant’s purpose or objective for the proposed 

facility.” 

Applying this “hard look” to the proposed project, substitution of a CFB design for the 

proposed boiler would disrupt the basic business purpose of the project, which is to increase 

the biomass fuel combustion and steam generation capacity, while minimizing changes to the 

existing facility. In the simplistic view, a CFB boiler would combust biomass fuel and 

produce steam, and is therefore interchangeable with any other boiler with similar inputs and 

outputs. In reality, insertion of a CFB boiler into the proposed project would affect certain 

operations and personnel at the facility to an extent that is difficult to quantify. 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

June 8, 2011 

Page 4 

In addition to the redesign test outlined above, there are important differences between the 

Desert Rock project and SPI’s proposed project that relate to the arguments presented in the 

EAB’s ruling in that case. First, the EAB points out that, in its 2004 application, the Desert 

Rock project permit application included IGCC technology as one of four technologies under 

consideration. In contrast, SPI stated, not only in the permit application submitted in March 

2010, but also in the permit application submitted in May 2007 for a smaller, previously 

proposed project, that fluidized bed technology was not under consideration. 

The second factor cited by the EAB in the Desert Rock ruling was that two permits for 

similar sources (Christian County and Prairie State) issued by Illinois Environmental 

Protection Agency (IEPA) under delegation of authority from EPA Region 5 both considered 

IGCC in Step 1 of the BACT analysis, and the Desert Rock permit application contained no 

explanation as to why IGCC should not be considered in Step 1. It is true that, as with Desert 

Rock, SPI’s permit application does not contain an explanation as to why fluidized bed boiler 

designs were not under consideration (at the time, the boiler design had not been finalized, 

but it was implied that fluidized bed designs were not under consideration). On this point, 

the difference between Desert Rock and the SPI project lies in the fact that other biomassfired boiler permit applications also do not address alternative boiler designs in Step 1 of the 

BACT analysis. As a recent example, a major source permit was issued on March 28, 2011 

by the Wisconsin Department of Natural Resources under delegation authority from EPA 

Region 5 to We Energies for a new facility in Rothschild, Wisconsin. In Step 1 of the BACT 

analysis submitted in support of the permit application, no alternative boiler designs were 

considered. Furthermore, when commenting on the proposed permit in a letter dated 

March 4, 2011, Region 5 raised several issues concerning the BACT analysis, but none of 

them included a request that other boiler designs be considered in Step 1 of the BACT 

analysis. 

In summary, the EAB ruled (in Desert Rock) that Region 9 “abused its discretion” by not 

considering an alternative source design. To avoid the potential for a similar ruling regarding 

SPI’s proposed project, Region 9 requested that SPI include an alternative boiler design (i.e., 

CFB) in the BACT analysis. The Desert Rock EAB ruling was based on two findings: (1) 

that the original statement of the project goals included the alternative source design in 

question as a possible approach, and (2) recently submitted permit application for similar 

proposed sources had considered the alternative source design in question. The project 

proposed by SPI differs from Desert Rock on both counts: (1) a CFB design was never under 

consideration for the proposed project, and (2) recently proposed biomass-fired boilers have 

not considered alternative boiler designs. In light of these differences, SPI proposes that 

retroactive consideration of CFB boiler design for the proposed project would constitute 

redefinition of the source, and Region 9 would not be abusing its discretion by allowing CFB 

boiler designs to be excluded from Step 1 of the BACT analysis. 

Provide more detailed information regarding BACT during startup and shutdown periods, as 

well as proposed emission limits for startup and shutdown. 

As stated in the September 7, 2010 letter responding to Region 9’s second incompleteness 

determination, SPI will limit the frequency and duration of startup and shutdown periods 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

June 8, 2011 

Page 5 

through the implementation of the manufacturer’s recommended procedures and operator 

training. However, because the final boiler design is better defined than it was at that time, 

additional details regarding the startup process can be provided. 

The boiler startup process begins by igniting a pile of biomass fuel on the grate and firing the 

2 (two) 62.5 MMBtu/hr natural gas burners located near the steam tubes. Once the biomass 

fuel is burning, the fuel feed system will be activated at a low feed rate. After approximately 

12 hours, the boiler will be at about 50 percent of full load, at which point the selective noncatalytic reduction (SNCR) system, used to reduce oxides of nitrogen (NOX) in the exhaust, 

and the electrostatic precipitator (ESP), used to control particulate matter (PM) emissions, 

can be activated. From this point on, the boiler will meet the normal operation emission rates 

presented in the permit application. 

The boiler manufacturer does not have emissions data for the startup period. Emissions of 

NOX and SO2 during startup are expected to be less than during normal operation as a result 

of reduced furnace temperatures and fueling rate. Emissions of CO, VOC, and PM are 

expected to be mitigated to some extent by simultaneous operation of the natural gas burners. 

However, the relative influences of the various competing factors are difficult to assess 

without concentration data obtained during startup. 

Ideally, permit limits for startup and shutdown periods will be both operationally feasible and 

protective of the national ambient air quality standards (NAAQS). The ambient impacts 

predicted by the air quality dispersion modeling results developed for the PSD permit 

application and in response to Region 9 information requests were used to determine whether 

the increased emission rates expected during startup or shutdown will comply with the 

NAAQS. Based on this analysis, SPI proposes the following hourly emission limits for 

startup and shutdown periods: 

Pollutant

Proposed

Startup/Shutdown

Emission Rate 

(lb/hr) 

Averaging

Period Basis 

NOX 94.3 1-Hour 55% greater than normal operation emission rate; NAAQS 

compliance demonstration discussed in Sep. 7, 2010 letter 

CO 400 1-Hour NAAQS compliance demonstration for this emission rate 

discussed in March 2010 permit application 

PM/ 

PM10/ 

PM2.5

18.7 24-Hour 

Twice normal operation emission rate; scaling predicted 

ambient impacts is less than the applicable PM10 SIL, and 

in compliance with PM2.5 NAAQS; see March 2010 permit 

application 

SO2 4.68 1-Hour 

Twice normal operation emission rate; scaling predicted 

ambient impact of project is less than the applicable SO2

SILs; see March 2010 permit application 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

June 8, 2011 

Page 6 

What emission limits does SPI propose be included in the permit, and what averaging 

periods should be associated with those limits? 

SPI proposes the following permit limits and averaging periods: 

Pollutant 

Emission Limit

(lb/MMBtu) 

Averaging

Period Basis 

NOX

0.15 3-Hour Protective of NAAQS; accounts for fuel variability 

0.13 Annual Protective of NAAQS; reflects BACT 

CO 0.35 3-Hour Protective of NAAQS; reflects BACT; 

complies with MACT limit for new Dutch Oven-type boilers

PM/PM10/PM2.5 0.0011 3-Hour Protective of NAAQS; reflects BACT; 

complies with MACT limit for new biomass-fired boilers 

SO2 0.005 3-Hour Protective of NAAQS; based on source test results 

We believe that the information provided in this letter addresses the information requested by 

Region 9, and should be considered to amend the submitted PSD permit application. Please 

let me know if Region 9 requires any additional information to finalize the draft permit. If 

you or your staff has any additional questions or need additional information, please do not 

hesitate to contact me at 425.412.1804. 

Sincerely yours, 

ENVIRON INTERNATIONAL, INC. 

Eric Albright 

Senior Manager 

Enclosures 

cc: Omer Shalev, USEPA, Region 9 

Shane Young, Sierra Pacific Industries 

Dave Brown, Sierra Pacific Industries 

Cedric Twight, Sierra Pacific Industries