1

Kelly, Shaheerah

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

Sent: Friday, March 14, 2014 4:09 PM

To: Kelly, Shaheerah

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

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

Subject: SPI Anderson PSD Permit - GHG BACT

Attachments: Pre-Combustion CCS GHG BACT analysis.docx

Shaheera,  

In follow‐up to our phone call yesterday, attached is additional  information regarding pre‐combustion CO2 capture and

sequestration (CCS) in the context of the top down BACT analysis.  The attached provides a more thorough explanation

and justification for the current BACT finding – that pre‐combustion CCS amounts to redefining the source.  

Please do not hesitate to call me if you have any questions or require further information.  

Regards,  

Tony Jaegel 

Director of Environmental Affairs

Sierra Pacific Industries 

Bus: (530) 378‐8179

Fax: (530) 378‐8139

tjaegel@spi‐ind.com  

  
    Page 1

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.    

SPI Response:

In March 2011, USEPA issued updated guidance for conducting BACT analyses for GHGs (hereafter

referred to as “the March 2011 Guidance”). USEPA recommended (but did not require) that permitting

agencies apply to GHGs the same “top down” process applied to determine criteria pollutant BACT. In

this process, potentially available control technologies are identified and evaluated for application to the

proposed project. Feasible options are ranked in descending order of control effectiveness. The most

stringent remaining alternative is examined and is established as BACT unless the applicant

demonstrates and the permitting authority agrees that energy, environmental or economic impacts

justify a conclusion that the most stringent technology is not achievable. In that case the next stringent

alternative is considered, and so on.  The top‐down analysis process is comprised of the following steps:

• Step 1 – Identify All Available Control Technologies.  Identify all available control techniques that

could potentially be applied to control emissions of the regulated pollutants from the emission units.  

• Step 2 – Eliminate Technically Infeasible Alternatives.  If any of the control techniques cannot be

successfully used on the emission units due to technical difficulties, document this finding.  Such control

techniques would not be considered further in the BACT analysis.

• Step 3 – Rank Technically Feasible Alternatives.  Assess the performance of each control

technique and rank them beginning with the most effective control technique.

• Step 4 – Evaluate Economic, Energy, and Environmental Impacts.  Estimate emission reductions,

annual costs, cost effectiveness, energy impacts, and other environmental impacts of the controls

techniques.  Detailed cost effectiveness information is presented for the most effective control and for

other control techniques that are in the least cost envelope.

• Step 5 – Select BACT.  Identify the most effective option not rejected based on energy,

environmental, and economic impacts.
    Page 2

The March 2011 guidance states that U.S. EPA classifies Carbon Capture and Storage (CCS) as an

“available” add‐on CO2 control technology for “large CO2‐emitting facilities including fossil fuel‐fired

power plants and industrial facilities with high‐purity CO2 streams (e.g. hydrogen production, ammonia

production, natural gas processing, ethanol production, ethylene oxide production, cement production,

and iron and steel manufacturing).”1 This document further states that “available” means the control

alternative has a potential for practical application to the emissions unit and the regulated pollutant

under evaluation,” and that EPA supports the recommendations of the Interagency Task Force on

Carbon Capture and Storage, which concluded that current CO2 capture technologies, while available for

fossil‐fueled power plants, “are not ready for widespread implementation primarily because they have

not been demonstrated at the scale necessary to establish confidence for power plant application.” The

Task Force’s conclusion went on to say that “[s]ince the CO2 capture capacities used in current industrial

processes are generally much smaller than the capacity required for the purposes of GHG emissions

mitigation at a typical power plant, there is considerable uncertainty associated with capacities at

volumes necessary for commercial deployment.”2

  

In the revised GHG BACT analysis submitted to U.S. EPA in August 2013, SPI listed CCS in Step 1 of the

top‐down BACT analysis, and considered it an “available” technology. In Step 2, CCS featuring post‐

combustion CO2 capture was considered technically feasible, and, in Step 4, it was eliminated from

consideration as a GHG control alternative on the basis of cost. In Step 2, CCS featuring a gasification

system and pre‐combustion CO2 capture was eliminated from consideration as technically infeasible

because it would amount to redefining the source.

Employing a pre‐combustion CO2 capture system as part of a potential CCS system was deemed to

redefine the source because it would replace the proposed biomass‐fired boiler with a gasification

system, syngas cleaning/treatment system, and a gas‐fired boiler. In essence, the proposed biomass

boiler design would necessarily be substituted out and redefined as a biomass refinery operation, in

order to produce an unnecessary intermediate gaseous fuel product using equipment and technology

that was never envisioned, and has never been demonstrated, to serve the purpose of the proposed

project. Pre‐combustion CO2 capture would require a complete redesign of the project and

fundamentally change the nature of the source. As such, pre‐combustion CCS should not be evaluated in

this circumstance, consistent with EPA’s March 2011 PSD and Title V Permitting Guidance for

Greenhouse Gases, which states in part:  

“Under this framework, a permitting authority should look first at the administrative record to

see how the applicant defined its goal, objectives, purpose or basic design for the proposed

facility in its application. The underlying record will be an essential component of a supportable

BACT determination that a proposed control technology redefines the source. The permitting

authority should then take a “hard look” at the applicant’s proposed design in order to discern

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

                                                            

1 U.S. Environmental Protection Agency. “Guidance for Determining Best Available Control Technology for

Reducing Carbon Dioxide Emissions from Bioenergy Production.” March 2011. Pages 13‐14. 2 U.S. Environmental Protection Agency. “Guidance for Determining Best Available Control Technology for

Reducing Carbon Dioxide Emissions from Bioenergy Production.” March 2011. Footnote 27 on page 14.
    Page 3

be changed to achieve pollutant emissions reductions without disrupting the applicant’s basic

business purpose for the proposed facility. In doing so, the permitting authority should keep in

mind that BACT, in most cases, should not be applied to regulate the applicant’s purpose or

objective for the proposed facility. This approach does not preclude a permitting authority from

considering options that would change aspects (either minor or significant) of an applicants’

proposed facility design in order to achieve pollutant reductions that may or may not be deemed

achievable after further evaluation at later steps of the process.” 3

The fundamental design of the project is consistent with multiple biomass boilers, including those that

are owned and operated by SPI that have been demonstrated to serve the basic objective and business

purpose of the proposed facility. While there are certainly elements of biomass boiler design that have

evolved over time, and in fact have been implemented by SPI at its facilities to improve emissions and

efficiency, the changes in fundamental operation and design to achieve pre‐combustion CO2 are so

massive and inconsistent with the proposed project, that the project would become unrecognizable as a

biomass boiler project, raising significant concerns regarding SPI’s ability to construct and operate such a

project to achieve its original purpose.   

This finding in the SPI BACT analysis is consistent with the Kansas Department of Health and

Environment (KDHE) evaluation of the GHG BACT analysis provided by Abengoa Bioenergy Biomass of

Kansas (ABBK) as a supplement to the originally submitted PSD permit application. On page 13 of that

document, which is Attachment C to the PSD Permit Summary Sheet, KDHE states that “ABBK’s basic or

fundamental business purpose or objective for this project is dependent on the biomass boiler as

proposed. Therefore, pre‐combustion as a control technology is technically infeasible.” This assertion

was not challenged by U.S. EPA Region 7 in written comments provided to KDHE.

While we maintain that the changes necessary to accommodate pre‐combustion CO2 capture would

constitute a redefinition of the source, we have, as the result of a request by U.S. EPA Region 9,

conducted further investigation and research into the current status of CCS with pre‐combustion CO2

capture, and the technology required for its application to a bioenergy source. Those investigations have

reinforced our belief that employing a pre‐combustion CO2 capture system to reduce CO2 emissions

from the proposed project would redefine the source, and, in addition, we believe that the components

and designs currently available to reduce CO2 emissions from a bioenergy facility have not been proven

at the capacities and level of reliability necessary for an industrial application such as that proposed by

SPI.

A CCS system is comprised of three parts:  (1) capturing the CO2, (2) compressing and 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.

                                                            

3 U.S. Environmental Protection Agency. “PSD and Title V Permitting Guidance for Greenhouse Gases”. March

2011. Page 26‐27.
    Page 4

Unlike a post‐combustion CO2 capture system, a pre‐combustion system would require wholesale

changes to the equipment proposed by SPI for the project. First, the proposed biomass‐fired boiler

would be replaced by a biomass 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 from the gasification system to additional H2 and CO2. Currently

available technology would require that the syngas be cooled to remove WGS catalyst‐poisoning

impurities, and then reheated to the temperature required by the WGS reactor. At that point, the

cleaned syngas would be ready for the pre‐combustion CO2 capture system.

The changes necessary to accommodate a pre‐combustion CO2 capture system would introduce

significant complexity, and have never been applied to a bioenergy facility of the scale SPI is proposing.

While gasification of biomass is a mature technology, the gasification system is almost always paired

with a close‐coupled oxidizer, and, in that configuration, it will not accommodate the low‐turndown

operation (i.e., ~20 percent load) required by SPI. A gasification system followed by syngas cleanup has

been employed at fossil fuel integrated gasification combined cycle (IGCC) facilities, but this technology

is not directly applicable to a biomass fuel gasification system because the impurities and tarry

compounds produced by biomass gasification differ from those produced by fossil fuel gasification.

Development of technology to clean syngas from a biomass gasification system is a current and ongoing

research topic at universities and research laboratories. While there is, in the words of the Task Force,

“considerable uncertainty,” regarding application of post‐combustion CO2 capture technology to

industrial processes, the technology required to make pre‐combustion CO2 capture a reality is simply not

commercially available for industrial processes utilizing biomass as an energy source.

In summary, the technology that would be required to create a biomass‐to‐syngas facility with pre‐

combustion CO2 capture is not “available.” As a result, this CO2 control alternative is eliminated from

consideration in Step 1 of the top‐down GHG BACT analysis. The remainder of the submitted GHG BACT

analysis is unchanged, including the conclusion that BACT for GHGs generated by bioenergy facilities is

the exclusive use of biomass fuel and efficient operation.

The Global CCS Institute maintains a database of large‐scale integrated CCS projects.4 As of

February 25, 2014, there are 19 projects in the U.S.: 7 operational, 2 under construction, 6 in the

planning stage, and 4 under evaluation. None of the projects involve biomass as an energy source. The

operating facilities involve natural gas processing, creating fertilizer from natural gas, or creating H2 from

natural gas. The two under construction are a coal‐fired ethanol plant5 and an IGCC facility that will use

lignite as an energy source. All of the planned or proposed projects use coal, lignite, petcoke, or natural

gas as the energy source.

                                                            

4 http://www.globalccsinstitute.com/data/status‐ccs‐project‐database   5 The captured CO2 is a by‐product of ethanol production from corn, not from the coal combustion used to heat

the process.