19020 33 rd 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 PacificMr. 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 toMr. 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 (NO X ) 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 fromdownstream 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 ofexhaust 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 permitMr. 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**

NO X 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/PM 10 /PM 2.5 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