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

Tel: +1 425.412.1800 Fax: +1 425.412.1840 

www.environcorp.com

January 23, 2012 

Project No. 29-23586A 

Mr. Gerardo Rios 

U.S. Environmental Protection Agency, Region 9 

75 Hawthorne Street 

San Francisco, California 94105 

Subject: Supplemental Control Technology Analysis 

Sierra Pacific Industries Biomass-Fired Cogeneration Project 

Anderson, California 

Dear Mr. Rios:

This letter provides information to supplement the best available control technology (BACT) 

analysis submitted to date in support of the Prevention of Significant Deterioration (PSD) 

permit application to construct and operate a new biomass-fired cogeneration unit submitted 

by Sierra Pacific Industries (SPI). This supplemental information is provided in response to a 

letter from the U.S. Environmental Protection Agency (USEPA) Region 9, dated August 5, 

2011, that requested further analysis of BACT for the proposed project. In summary, Region 

9 has requested that SPI revise the BACT analysis to consider boiler designs other than 

traditional stoker boiler designs or the proposed step-grate furnace design, and, more 

specifically, to include fluidized bed designs in the reconsideration. Additionally, updated 

emission limits for the proposed cogeneration unit and associated averaging periods are 

provided. 

When requesting that SPI include alternative biomass boiler designs such as bubbling bed 

and circulating fluidized bed boilers, Region 9 acknowledged that SPI could potentially 

eliminate alternative boiler designs as options through Steps 2 or 4 of USEPA’s top-down 

BACT analysis process. Step 2 is where all potential BACT alternatives identified in Step 1 

are evaluated to determine each alternative’s feasibility for application to the proposed 

project. Step 4 is where energy, environmental, and economic impacts, as well as other costs 

are considered. In this letter we propose that, based on a Step 2 analysis, fluidized bed 

boilers, as well as catalyst-based add-on controls should be removed from consideration as 

control alternatives for the proposed boiler due to technical infeasibility. 

Proposed Use of the Boiler 

Prior to consideration of alternative boiler designs, a review was made of the operating 

conditions the boiler will be expected to accommodate. These operating conditions were used 

to assess the suitability of various potential boiler designs for SPI’s proposed use. 

Under “normal” operating conditions, the boiler will be operated at or near full capacity, and 

the steam produced will be used to generate electricity for sale to the grid, as well as to heat 

the lumber dry kilns. In this scenario, the quantity of electricity produced meets the terms of 

SPI’s Renewable Energy Credit (REC) Power Purchase Agreement (PPA) with the Pacific 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

January 23, 2012 

Page 2 

Gas and Electric Company (PG&E), while providing sufficient steam to the kilns to dry 

enough lumber to keep the mill operating at or near full capacity. 

However, there are circumstances under which the full steam generating capacity of the 

boiler is not needed. Examples of situations that would require less than 50 percent of 

maximum steam production capacity include the steam turbine and electrical generator being 

offline for service or due to malfunction, and power production being capped or suspended 

by the power purchaser. The steam turbine and generator are taken off-line for one or two 

weeks each year for maintenance. Capping or suspension of power production can occur at 

any time, and can last for a few hours, days, weeks, or even months. 

Projections by PG&E indicate that between 2014 and 2017, and perhaps beyond, there will 

be an excess of renewable energy to fulfill the requirements of the renewable energy standard 

(RES). As a result, the PPA between SPI and PG&E for the power to be produced by the 

cogeneration unit proposed for the Anderson facility will almost certainly allow PG&E to 

vary the power production to suit their needs. Going forward, it will be critical for the 

Anderson facility to have the capacity to vary steam production between 20 percent and 100 

percent load. Because PG&E will provide advance notice of power needs, it is unlikely that 

the steam demand variations will require quick responses from the boiler; the variability will 

be on a day-to-day basis, rather than hour-to-hour. 

Periods of reduced steam demand do not necessarily coincide with reduced sawmill 

operation. If the steam turbine is not operating, or is at extremely low load, and the boiler 

cannot reduce steam output to meet the reduced steam demand, the boiler must be shut down, 

which means the kilns cannot operate. If the kilns are not operating, lumber cannot be dried, 

and, in the current market, there is no demand for undried, or “green” lumber. It is possible 

for the sawmill to continue operating and stockpile the undried lumber at the facility, but in a 

relatively short time, the space available for stockpiling will be exhausted, at which point the 

sawmill must be shut down. 

As a practical example, steam demand data from the SPI facility in Lincoln, California was 

examined. Over the course of 2011, the boiler at the Lincoln facility operated throughout the 

year, except for 212 hours of scheduled downtime for maintenance, but the steam turbine and 

generator were offline for a total of 1,742 hours, which includes 244 hours of scheduled (for 

boiler maintenance), and 1,498 hours of unscheduled (for repairs to the steam turbine) 

downtime. Because the boiler at the Lincoln facility is a stoker capable of operating in a 

turndown mode (to approximately 30 percent of full load, on a daily average basis), the kilns 

were able to operate when the steam turbine and generator were offline. Without this 

capability, the facility would have had to shut down for most, if not all, of the downtime 

periods, with the accompanying loss of revenue for SPI and wages for employees. 

Boiler Design Suitability 

Manufacturers, vendors, and combustion system experts were consulted to determine the 

suitability of various boiler designs for SPI’s proposed use, which includes the need to 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

January 23, 2012 

Page 3 

operate the boiler in “turndown” mode, where steam is generated at rates as low as 

20 percent of maximum load. 

There are several examples of biomass-fired fluidized-bed boilers currently in operation. 

However, most, if not all, produce steam solely for power generation, and do not provide 

process steam. Steam used to heat industrial processes is often subject to varying demand, 

especially for batch processes (e.g., lumber dry kilns). The primary reason for fluidized bed 

boiler designs lack of representation among biomass-fired process steam generators is the 

inability to operate in a turndown mode. Energy Products of Idaho, a manufacturer of 

fluidized bed boilers, confirmed that they were unable to provide a fluidized bed boiler with a 

design that could operate at less than 50 percent of maximum load. Based on this 

incompatibility with SPI’s planned use of the proposed boiler to generate steam for electrical 

generation as well as process steam for the kilns, fluidized bed boiler designs are considered 

technically infeasible. 

Add-On Control Systems 

The permit application submitted for the proposed cogeneration unit was submitted in March 

2010. At that time there were few boilers with a stoker design that employed catalyst-based 

add-on controls to control oxides of nitrogen (NOX) and carbon monoxide (CO). The primary 

reason for this is that adding catalyst-based add-on controls such as selective catalytic 

reduction or catalytic oxidation systems significantly increases the complexity and cost of a 

given boiler. 

The exhaust passing through a catalyst-based control system must be at a temperature that 

falls within a relatively narrow range for the desired reactions to occur. Virtually all modern 

boilers employ heat recovery systems to increase the efficiency of the system. Reheating the 

exhaust gases using natural gas to achieve the desired temperature would run counter to the 

greenhouse gas BACT finding that energy efficiency should be maximized. The solution is to 

split the heat recovery system, typically placing the catalyst between an economizer and an 

air heater. To protect the catalyst from plugging, the particulate control is moved from 

downstream of the heat recovery system to upstream of the catalyst; as a result, a larger-thannormal particulate control system (e.g., an electrostatic precipitator) is needed to 

accommodate the increased exhaust gas temperature. Additionally, a sorbent injection system 

(e.g., trona, sodium bicarbonate) is added upstream of the particulate control system to 

remove catalyst poisons (e.g., arsenic, chlorine, fluorine, potassium, phosphorous) from the 

exhaust, to further protect the catalyst. 

Over the past few years, new and retrofitted biomass-fired, stoker-design boilers have been 

proposed and constructed that use the scheme outlined above to accommodate catalyst-based 

control systems. Whether these systems will provide reliable emission over the long term 

remains to be seen. Regardless, as with fluidized bed boiler designs, the catalyst-based 

systems will not function properly because, when in turndown mode, the temperature of 

exhaust gases, even with the rearranged heat recovery system, will not support the emissionreducing reactions the catalysts are intended to promote. As a result, there would potentially 

be extended periods of time when those control systems could not be employed and permit 
Mr. Gerardo Rios 

SPI-Anderson Biomass-Fired Cogeneration Project 

January 23, 2012 

Page 4 

limits would be exceeded. For this reason, catalyst-based add on controls are considered 

technically infeasible for application to the proposed boiler. 

Proposed Emission Limits 

SPI proposes the following emission limits and averaging periods for the proposed biomassfired boiler: 

Pollutant 

Emission Limit

(lb/MMBtu) 

Averaging

Period Basis 

NOX

0.15 3-Hour Protective of NAAQS; use of SNCR reflects BACT 

and accounts for fuel variability 

0.13 Annual Protective of NAAQS; use of SNCR reflects BACT 

CO 0.23 3-Hour Protective of NAAQS; use of proper combustion 

reflects BACT 

PM/PM10/PM2.5 0.02 3-Hour Protective of NAAQS; use of multiclone and ESP 

reflects BACT 

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