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Kelly, Shaheerah

From: Tony Jaegel <TJaegel@spi-ind.com>

Sent: Wednesday, March 12, 2014 5:54 PM

To: Kelly, Shaheerah

Cc: Shane Young; William Sloan (wsloan@mofo.com); George Emmerson; John Gardner; 

Dave Dun; Eric Albright; Christenson, Kara; Rios, Gerardo

Subject: SPI Anderson PSD Permit

Attachments: Pre-Combustion CCS GHG BACT analysis - draft.docx; PSD_Fuel_Condition.docx

Shaheerah,  

In follow‐up to our phone call on Monday, attached are two documents providing the requested information in support

of advancing the Anderson PSD permit.  

The first document contains requested revisions to Condition G.1. Fuel Restrictions to better define the fuels that will be

used for the project. The language is now consistent with EPA terms used in its March 2011 Accounting Framework.   

The second document provides a brief evaluation of pre‐combustion carbon capture and sequestration, prepared by Eric

Albright/ENVIRON International Corp. In summary, the technology is economically infeasible and is not technically or

commercially viable for this application.  

I will call you tomorrow to follow‐up. We remain committed to resolving all questions and information requests as soon

as possible.  

Best regards,   

Tony Jaegel 

Director of Environmental Affairs

Sierra Pacific Industries 

Bus: (530) 378‐8179

Fax: (530) 378‐8139

tjaegel@spi‐ind.com  
G. Fuel Restrictions 

1. The following biomass fuels shall constitute the only fuel allowed for use as fuel in U1, except 

during periods defined in Condition X.D. and to counteract upset conditions: 

a. Untreated wood pallets, crates, dunnage, untreated manufacturing and construction 

wood debris from urban areas; 

b. All agricultural crops or residues;

c. Mill residues including hog fuel, shavings, sawdust, trimmings, and bark. 

d. Forest residues including treetops, non-merchantable sections of the stem, branches, 

and bark, left on the ground after logging or accumulating as a result of a storm, fire, 

delimbing, or other similar disturbance. 

e. Non-merchantable forest biomass consisting of byproducts and residuals of forest 

management activities Wood and wood wastes identified to follow all of the 

following practices; 

(1) Harvested pursuant to an approved timber management plan prepared in 

accordance with the Z'berg-Nejedly Forest practice Act of 1973 or other locally 

or nationally approved plan; and 

(2) Harvested for the purpose of forest fire fuel reduction or forest stand 

improvement. 
From CBD:

SPI also improperly rejected (and EPA failed to evaluate) the availability and cost‐

effectiveness of pre‐combustion CO2 removal technology in combination with a biomass

gasification system. SPI evaluated only a post‐combustion system based on the

unsubstantiated assertion that gasification “would amount to redefining the source.”

GHG BACT Analysis at 19‐20. SPI fails to provide information demonstrating that this is

the case. A gasification unit would presumably use the same biomass fuels, which SPI

has identified as a primary purpose of the facility. GHG BACT Analysis at 15. SPI has

provided no evidence that biomass gasification could not meet SPI’s operational criteria.

Given that the proposed boiler for the facility is already designed to run on natural gas

during startup and shutdown, SPI and EPA must assess whether it also could run on

syngas. In short, EPA cannot reject pre‐combustion CO2 removal options without first

demonstrating that gasification would improperly redefine the source.    

As stated in the revised GHG BACT Analysis submitted to EPA in August 2013, a carbon capture and

storage (CCS) system is comprised of three parts:  (1) capturing the CO2, (2) transporting the captured

CO2, and (3) permanently storing (i.e., geological storage) the captured CO2 or using it in some beneficial

way (i.e., enhanced oil recovery, industrial use). Substituting pre‐combustion CO2 removal technology

for post‐combustion CO2 removal technology would affect only the first part of the CCS system

(capturing the CO2). The costs involved with compressing, transporting, and storing the captured CO2

would be unchanged.

The primary difference between a pre‐combustion system and a post‐combustion system is that, instead

of removing dilute CO2 from a boiler exhaust stream (approximately 5 to 15 percent), the CO2 capture

system would be removing more concentrated CO2 from a less voluminous syngas stream

(approximately 15 to 60 percent). As a result, a pre‐combustion stripping system could be smaller in

size, and have reduced solvent circulation rates and energy requirements, which decrease the capital

and operating costs of the CO2 capture system.

However, a pre‐combustion system requires additional equipment not required by post‐combustion

system. First, the proposed boiler would be replaced by a gasification system designed to maximize CO2

and H2 production, meaning it would be a high‐pressure system employing O2 rather than air as an

oxidizer. An O2 plant would be required to supply O2 to the gasification system. A water‐gas shift (WGS)

reactor would be used to convert CO in the syngas to H2 and CO2, and currently available technology

requires that the syngas be cooled to remove catalyst‐poisoning impurities and then reheated to the

temperature required by the WGS reactor. This additional equipment adds significant complexity,

energy penalties, and cost to the overall system.  

Costs for biomass‐to‐energy facilities employing either a pre‐ or post‐combustion CO2 capture systems

are scarce, because there are few, if any examples. The Special Report on Carbon Capture and Storage

issued by the Intergovernmental Panel on Climate Change (IPCC) in 2005 states that “[b]iomass fuels

produce similar or slightly greater quantities of CO2 per unit of fuel energy as bituminous coals; thus, the
CO2 concentration of flue gases from these fuels will be broadly similar.” That report states that a coal‐

burning power plant using an amine‐based scrubber to capture CO2 increases the cost of electricity

generation (COE) by approximately 40 to 70 percent, while an integrated gasification combined cycle

(IGCC) system using a WGS reactor followed by a physical absorption system increases COE by 20 to 55

percent. It is not clear whether these calculated values reflect use of a high‐pressure, O2‐blown

gasification system and associated O2 plant, but it implies a small potential cost advantage for pre‐

combustion capture systems. It is also unclear whether or not the added complexity of a pre‐

combustion system (i.e., O2 plant, gasification system, syngas treatment, WGS reactor, CO2 capture

system, H2 storage tanks, CO2 compressors, etc.) would compromise the availability of the overall energy

system

While it is possible that pre‐combustion CO2 capture systems are less costly than post‐combustion

systems, substituting a pre‐combustion system for a post‐combustion system does not change the

economics of CCS presented in the GHG BACT Analysis and additional materials submitted to EPA. The

cost of a CCS system to reduce CO2 emissions attributable to the biomass‐fired cogeneration project

proposed by SPI would have capital and operating costs that are difficult to define, and most likely

several times, the cost of the project as proposed. CCS is currently not cost effective for reducing CO2

emissions from a biomass energy facility, as evidenced by the fact that most, if not all, CCS systems

currently under development are research projects subsidized by one or more government agencies.