1

Kelly, Shaheerah

From: Dave Brown [DBrown@spi-ind.com]

Sent: Thursday, August 15, 2013 1:18 PM

To: Rios, Gerardo

Cc: Kelly, Shaheerah; Eric Albright; Shane Young; George Emmerson

Subject: SPI Anderson PSD - Revised GHG BACT Analysis

Attachments: SPI-Anderson_GHG_BACT_analysis-revised-081513.docx

Categories: Red Category

Gerardo:  

Attached is a revised GHG BACT Analysis for the Anderson Cogeneration project and associated PSD permit.  The

analysis, dated August 15, 2013, incorporates the additional comments indicated by EPA staff last week.  In comparison

to other GHG BACT analyses references in the report, this report further expands certain sections and provides

comparison to approved GHG BACT determinations with respect to this project.   

Additionally in our last conversation and in one of the prior public comments, there was mention that our Power

Purchase Agreement (PPA) and timeframes associated with when the facility may be able to begin commercial operation

in addition to operational flexibility that may require immediate downturn of the boiler (load).   

Below is a summary of our PPA key elements – should EPA require additional information, please do not hestitate to ask:

PPA – The PPA agreement was negotiated between Sierra Pacific Industries and Pacific Gas and Electric Company

commencing in 2010 and ultimately executed on August 9, 2012.

Timing and Key Dates

There are two "Guaranteed Project Milestones" in the Power Purchase Agreement (PPA):

 The Guaranteed Construction Start Date

 The Guaranteed Commercial Operation Date

As agreed in the PPA these milestone dates are specified as follows:

 Guaranteed Construction Start Date ‐ December 3, 2012

 Guaranteed Commercial Operation Date ‐ April 1, 2014

Either or both of these can be extended on a day‐for‐day basis by a "Permitted Extension".

Permitted Extensions include:

 Permitting Delay (not more than 6 months)

 Transmission Delay (not more than 6 months)

The cumulative time for Permitted Delays may not be more than 360 days, thus SPI must have commenced construction

by November 28, 2013.

The PPA specifies that the Anderson project may commence Commercial Operation by as much as 45 days prior to the

agreed Guaranteed Commercial Operation Date, thus contractually the project could commence commercial operation

as early as February 15, 2014.

Operational Considerations
2

The PPA provides that the project may be directed to reduce output to the grid by either the buyer (PG&E) for economic

or other reasons, or the transmission system operator (the California Independent System Operator ‐ CAISO) for

reliability reasons.

The PPA specifies that upon 60 minutes advance notice the project may be directed by the buyer to reduce generation

to the grid by as much as 12 MW (0.2 MW/minute downward ramp).  These Buyer directed curtailment periods can be

for as short a period of time as 4 hours, after which the project may be directed to increase generation to levels

previously scheduled.  Failure to respond to these curtailment orders can result in severe financial penalties.  One of the

operational considerations that is further explained in the GHG BACT analysis is the need for the boiler to accommodate

turndown and then as stated above, achieve this in a relatively short timeframe.   

For purposes of system reliability the project may be required to reduce its output to the grid to zero MwH’s or boiler

load limited to what the facility can consume and utilize.

Attached.

David C. Brown, PE

Environmental Affairs & Compliance Manager

Sierra Pacific Industries

19794 Riverside Avenue

Redding, CA 96049-6028

(530) 378-8179

(530) 378-8139 fax

(530) 391-7650 cell

 

CONFIDENTIALITY STATEMENT: This communication and any accompanying or attached document(s) are confidential and privileged. They are intended for the 

sole use of the addressee(s). If you receive this communication in error, you are advised that any use, disclosure, copying, distribution or taking any action in 

reliance upon this communication is strictly prohibited. If you received this message in error, please immediately telephone Sierra Pacific Industries at (530) 378-

8179, and delete this message without copying it. Thank you.
 

 

F I N A L 

 

Biomass-Fired Cogeneration Project:

Best Available Control Technology

Analysis for Greenhouse Gases

Sierra Pacific Industries

Lumber Manufacturing Facility

Anderson, California

Prepared for: 

Sierra Pacific Industries, Inc.

Redding, California

Prepared by: 

ENVIRON International Corporation

Lynnwood, Washington

Date: 

August 15, 2013

Project Number: 

29-23586A

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Contents 

 Page 

1 Introduction 1

1.1 Project Information 2

1.2 BACT Analysis Process 2

1.2.1 Step 1 – Identify Available Control Technologies 4

1.2.2 Step 2 – Eliminate Technically Infeasible Control Technologies 5

1.2.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness 6

1.2.4 Step 4 – Evaluate Most Effective Controls and Document Results 6

1.2.5 Step 5 – Select BACT 6

1.3 Cost-Effectiveness Analysis 7

1.3.1 Cost Methodology 8

1.3.2 Cost Criteria 8

2 Project Greenhouse Gas Emissions 11

3 Step 1 – Identify Available Control Alternatives 15

3.1 Carbon Dioxide 17

3.2 Methane 17

3.3 Nitrous Oxide 18

4 Step 2 – Eliminate Technically Infeasible Alternatives 19

4.1 Carbon Dioxide 19

4.2 Methane 20

4.3 Nitrous Oxide 21

5 Step 3 – Rank Technically Feasible Alternatives 23

6 Step 4 – Evaluate Economic, Energy, and Environmental Impacts 27

7 Step 5 – Selection of BACT 31

8 Reciprocating Internal Combustion Engines 33

8.1 Step 1 – Identify Available Control Alternatives 33

8.2 Step 2 – Eliminate Technically Infeasible Alternatives 33

8.3 Step 3 – Rank Technically Feasible Alternatives 33

8.4 Step 4 – Evaluate Economic, Energy, and Environmental Impacts 34

8.5 Step 5 – Selection of BACT 34

List of Tables 

Table 2-1. Greenhouse Gas Emission Rate Calculations – Proposed Equipment 11

Table 2-2. Greenhouse Gas Emission Rate Calculations – Existing Equipment 13

Table 5-1 Catalytic Oxidation GHG Emission Reduction 25

Table 5-2 Removal of SNCR GHG Emission Reduction 26
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1 Introduction 

Sierra Pacific Industries, Inc. (SPI) owns and operates an existing lumber manufacturing facility 

located in Anderson, California, and proposes to construct and operate a cogeneration unit at 

that facility. The boiler associated with the proposed cogeneration unit will be designed to burn 

biomass fuel to produce approximately 250,000 pounds of steam per hour. SPI submitted a 

PSD permit application to USEPA Region 9 and Shasta County Air Quality Management District 

(SCAQMD) in March 2010 that included BACT analyses for all criteria pollutants expected to 

increase by more than the PSD Significant Emission Rates (SERs), as well as pollutants 

exceeding the emission rate thresholds in SCAQMD Rule 2:1, Part 301. The intent of this report 

is to supplement the permit application by providing an analysis of BACT for GHG emissions 

from the proposed project. 

On May 13, 2010, USEPA issued the final “Tailoring Rule” with a stated intent to establish a 

“common sense approach” to addressing greenhouse gas emissions from stationary sources, 

by “tailoring” the major source applicability thresholds under the PSD and Title V air operating 

permit programs. On March 21, 2011, USEPA issued a proposed Deferral for CO2emissions 

from bioenergy and other biogenic sources under the Prevention of Significant Deterioration 

(PSD) and Title V Programs (“Proposed Deferral Rule”, 76 Fed. Reg. 15,249, 15,252-54), and 

Deferral Rule 76 Fed. Reg. at 43,492. The Deferral Rule provided a 3-year exemption for 

biogenic sources from a compliance obligation with respect to the Tailoring Rule. For purposes 

of this PSD permit application, the proposed biomass-fired cogeneration unit is a biogenic 

source, and its respective GHG compliance obligation falls within the scope of the deferral rule. 

On February 19, 2013, USEPA made a final decision in issuance of PSD permit SAC 12-01 for 

this project. The PSD permit was subsequently administratively appealed within 30-days of the 

service of notice and heard by the Environmental Appeals Board (EAB). On July 13, 2013, the 

EAB remanded in part and denied in part the submitted appeals. 

On July 12, 2013 (the day prior to the EAB decision), the US Court of Appeals made a decision 

to vacate the Deferral Rule. However, this decision is not, and will not become effective until 

the court issues a ‘mandate’. At the date of this report, a mandate has not been issued and the 

vacatur is not in effect. 

At SPI’s sole discretion, this GHG BACT analysis has been prepared and is being submitted to 

USEPA as part of the PSD supporting documents for the Anderson cogeneration project. For 

purposes of this report, it is anticipated that the court mandate will be effective in the near 

future, and this report is intended to satisfy the compliance obligation under the existing 

Tailoring Rule, regardless of the Deferral Rule. 

The first step of the Tailoring Rule, which began on January 2, 2011, and lasted until June 30, 

2011, required sources already subject to the PSD permitting programs to meet that program’s 

permitting requirements for greenhouse gases. New sources or modifications of existing 

sources expected to increase total greenhouse gas emission rates by 75,000 tpy or more, on a 

carbon dioxide equivalent (CO2e) basis, and whose emissions exceed the PSD threshold for 

one or more criteria pollutants, are subject to PSD review for GHGs. 
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The second step of the rule, which started on July 1, 2011, and lasts until June 30, 2014, casts 

a wider net than the first. New construction projects expected to emit at least 100,000 tpy of 

total greenhouse gases on a CO2e basis, or modifications at existing facilities that are expected 

to increase total greenhouse gas emissions by at least 75,000 tpy CO2e will be subject to PSD 

permitting requirements, even if they do not significantly increase emissions of any other 

pollutant. Because the proposed biomass-fired cogeneration unit is expected to emit GHGs at a 

rate greater than 75,000 tpy CO2e, the project is subject to PSD review for GHGs. Because 

there are no ambient standards or increments for GHGs, the only PSD requirement that applies 

to GHGs is that Best Available Control Technology (BACT) must be employed to reduce GHG 

emissions from the proposed unit. 

1.1 Project Information 

SPI is a family-owned wood-products company based in Redding, California. SPI currently 

operates an existing lumber manufacturing facility in Anderson, California. SPI intends to 

construct a new cogeneration unit to replace the existing biomass-fired unit at the Anderson 

facility; the new unit would also burn biomass fuel to produce steam that would be used to 

generate electricity and to heat existing lumber dry kilns at the facility. 

The cogeneration unit will consist of a biomass-fired water tube boiler with a step grate and 

dual-chamber pyrolysis and combustion system, a cooling tower, a steam turbine, and an 

electrical generator. The boiler will burn biomass fuels to produce high-pressure steam for the 

steam turbine. The steam turbine will drive the electrical generator, which will be capable of 

generating up to 31 megawatts (MW) of electricity, approximately 7 MW of which will be used to 

power on-site equipment; the remainder will be sold to a public utility. Low-pressure steam will 

be taken from the steam turbine through a controlled extraction and used to heat the dry kilns. 

1.2 BACT Analysis Process 

BACT is defined at 40 CFR 52.21(b)(12) as: 

an emissions limitation (including a visible emission standard) based on the 

maximum degree of reduction for each pollutant subject to regulation under the 

Clean Air Act which would be emitted from any proposed major stationary source 

or major modification which the Administrator, on a case-by-case basis, taking 

into account energy, environmental, and economic impacts and other costs, 

determines is achievable for such source or modification through application of 

production processes or available methods, systems, and techniques, including 

fuel cleaning or treatment or innovative fuel combustion techniques for control of 

such pollutant. In no event shall application of best available control technology 

result in emissions of any pollutant which would exceed the emissions allowed by 

any applicable standard under 40 CFR Parts 60 and 61. If the Administrator 

determines that technological or economic limitations on the application of 

measurement methodology to a particular emissions unit would make the 

imposition of an emissions standard infeasible, a design, equipment, work 

practice, operational standard, or combination thereof, may be prescribed instead 

to satisfy the requirement for the application of best available control technology. 
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Such standard shall, to the degree possible, set forth the emissions reduction 

achievable by implementation of such design, equipment, work practice or 

operation, and shall provide for compliance by means which achieve equivalent 

results. 

The process for conducting BACT analyses for criteria pollutants is relatively well established 

because it has been implemented for decades. Although there is a wide range of controls and 

associated costs that could be considered for criteria air pollutants, permit-issuing agencies 

have an understanding of which emission control options are appropriate and cost effective. In 

contrast, BACT analyses, BACT determinations, and cost-effectiveness criteria for GHGs are 

virtually non-existent. 

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 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. The topdown analysis process is comprised of the following steps: 

 Step 1 – Identify 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. 

Each step is discussed further in the sections that follow. 
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1.2.1 Step 1 – Identify Available Control Technologies 

The first step in the top-down procedure is to identify all available control technologies and 

emission reduction options for each subject pollutant. Available control technologies are those 

with a practical potential for application to the emission unit. For criteria pollutants, applicants 

typically identify appropriate control technologies by reviewing the following sources of 

information: 

 USEPA RACT/BACT/LAER Clearinghouse (RBLC) 

 USEPA Control Technology Center (CTC) 

 Recent Permit Actions by other State and Local Agencies, and 

 Vendor Information 

Because BACT for GHGs is a relatively new requirement, there are few BACT precedents, let 

alone precedents for biomass-fired cogeneration units, and none that include associated lumber 

drying steam requirements. In preparing this BACT analysis, ENVIRON reviewed BACT 

analyses for combined cycle power plants (e.g., Russell Energy Center, Avenal Energy Power 

Plant, and CPV Vaca Station Power Plant), a proposed combination refinery and integrated 

gasification combined cycle (IGCC) facility in South Dakota (Hyperion Energy Center), and 

several recent biomass-fired electric generation and cogeneration facilities (e.g., Montville 

Power, We Energies/Domtar Biomass Energy Project, Abengoa Bioenergy Biomass, Beaver 

Wood Energy, and North Springfield Sustainable Energy). The biomass-fired projects all 

indicated that BACT for GHGs is good boiler design, good combustion practices, and efficient 

operation. 

Consistent with these precedents and EPA’s March 2011 Guidance, this analysis demonstrates 

that the design of the proposed biomass-fired cogeneration unit will achieve a very high degree 

of energy efficiency. In BACT parlance, this is considered “lower-polluting processes/practices” 

as opposed to post-combustion or “end-of-stack” controls. Given the limited technological 

options available for end-of-stack GHG emission controls, EPA’s initial BACT guidance 

emphasizes energy efficiency. In addition to reducing GHG emissions, energy efficiency also 

minimizes criteria and toxic air pollutant emissions. 

A control technology must be “available” to be considered BACT. According to EPA’s draft 

1990 NSR manual “‘[a]vailable’ means that the method’s systems and techniques are 

commercially available.” BACT also does not require the applicant to participate in a research 

and development project to determine if a technology is “available” for a particular use. 

Theoretical, experimental or developing technologies are not “available” under BACT. 

Technologies with questionable or dubious reliability are likewise not considered "available" 

under BACT, and the applicant is not required to use them. BACT does not require an applicant 

to speculate as to whether an undemonstrated technology will effectively control the pollutant in 

question from the proposed source. Applicants are not required to accept the risk that a 
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theoretically feasible, but unproven, technology will effectively and economically reduce 

emissions from the proposed source.1 

1.2.2 Step 2 – Eliminate Technically Infeasible Control Technologies 

The second step in performing the top-down BACT analysis is to eliminate all technically 

infeasible options. The determination that a control technology is technically infeasible is 

source-specific and based upon physical, chemical, and engineering principles. Technical 

feasibility is addressed in EPA’s March 2011 Guidance: 

EPA considers a technology to be technically feasible if it has been 

demonstrated in practice or is available and applicable to the source type under 

review. The term “demonstrated” is focused on the technology being used in the 

same type of source, such as a similar plant producing the same product. 

Therefore, EPA considers a technology to be “demonstrated,” if it has been 

installed and operated successfully on the type of source at issue. 

Prior guidance and judicial decisions confirm that "feasible technology" means design or 

equipment that has progressed beyond the conceptual and pilot testing phases, is commercially 

available, and has been demonstrated on a full-scale emission unit of the type of that is the 

subject of the BACT analysis, for a period of time sufficient to indicate reliable operation. These 

criteria are especially important for GHG BACT analyses due to the unproven nature of many 

GHG control schemes. 

“Demonstrated in practice” is another important concept that addresses the question of whether 

a technology should be considered available. In its New Source Review Improvement Rule 

(issued November 22, 2002), EPA included a definition of “demonstrated in practice.” This 

definition prescribes which technologies must be considered in BACT and LAER determinations 

by defining the information that must be reviewed to identify candidate technologies, the amount 

of time the technology must be in use, and its performance during that time. A technology 

installed and operating on an emissions unit (or units) must meet the following criteria to be 

considered “demonstrated in practice:” 

 Has operated at a minimum of 50 percent of design capacity for at least 6 months; and 

 The pollution control efficiency performance has been verified by either: 

1) a performance test, or 

2) performance data collected at the maximum design capacity of the emissions unit (or 

units) being controlled, or 90 percent or more of the control technology's designed 

specifications. 

 

1 USEPA, “New Source Review Workshop Manual: Prevention of Significant Deterioration and 

Nonattainment Are Permitting, Draft,” October 1990. Pages B.17 – B.21. 
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Although this definition of “demonstrated in practice” does not specifically apply to the analysis 

presented in this report, it does provide some useful guidance for evaluating whether certain 

technologies are “available,” and therefore worthy of consideration as BACT. 

1.2.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness 

The third step in the top-down BACT analysis is to rank all remaining control technologies with 

respect to control effectiveness (i.e., by emission limit or removal efficiency, as applicable). The 

emission limit or removal efficiency used in the ranking process is that which the technology has 

demonstrated can be achieved consistently under reasonably foreseeable worst-case 

conditions with an adequate margin of safety. A limit or removal efficiency that can be achieved 

only occasionally under best-case circumstances is not to be considered. 

For GHGs, control options are ranked based on total CO2e rather than the total mass or mass of 

individual GHGs. 

1.2.4 Step 4 – Evaluate Most Effective Controls and Document Results 

In this step, an analysis is performed on each remaining control technology to determine 

whether the energy, economic, or environmental impacts from a given technology outweigh their 

benefits. Factors such as control efficiency, anticipated emission rate, expected emissions 

reduction, and economic, environmental, and energy impacts, are to be considered. 

If the top-ranked technology is chosen, and there are no significant or unusual environmental 

impacts associated with that technology that have the potential to affect its selection, the BACT 

analysis is complete, and no further analysis is required. However, if the chosen technology is 

not the top-ranked option, the economic, environmental, and energy impacts of the chosen 

technology, and each more-effective technology, must be evaluated and compared to justify 

application of the selected technology. 

In performing economic analyses, USEPA’s Air Pollution Control Cost Manual, published in 

January 2002 (EPA/452/B-02-001) provides capital and annual operating cost factors that can 

be used in determining the installation and operating costs of each control technology. Actual 

vendor installation and operation costs were used where applicable. 

Cost-effectiveness evaluations for greenhouse gases are to be conducted based on reductions 

in CO2e. However, as acknowledged by EPA in its March 2011 Guidance, no cost effectiveness 

criteria have been established for GHGs. Furthermore, there are no means by which to 

evaluate the environmental impacts of GHG emissions at the stationary source level. 

Consequently, comparisons of environmental impacts associated with GHG emissions with 

those of collateral criteria pollutant emissions are not possible. 

1.2.5 Step 5 – Select BACT 

The final step is selection of the most stringent and technically feasible emission limit and 

corresponding technology that was not eliminated based upon adverse economic, 

environmental, and energy impacts. EPA’s March 2011 Guidance notes that a GHG permit may 

limit CO2e based on a mass emission rate (lb/hr) or other metrics. EPA also notes that “since 

the environmental concern with greenhouse gases is with their cumulative impact in the 
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environment, metrics should focus on longer-term averages (e.g., 30- or 365-day rolling 

average) rather than short-term averages (e.g., 3- or 24-hr rolling average).” 

 Given decades of experience with the top-down BACT analysis, the process has resulted in a 

number of agency and judicial decisions that have served to guide subsequent BACT 

determinations: 

 BACT determinations are made “on a case-by-case basis,” taking into account site-specific 

and source-specific characteristics. These characteristics may include, among other 

things, the type of fuel or raw materials that will be used, and the type and size of the 

emissions unit. A high degree of technical judgment must be exercised in any BACT 

analysis as there are various sizes and ages of the emissions units covered by an 

analysis. 

 BACT must be achievable. The Environmental Appeals Board (EAB) has recently stated 

that, while BACT is forward-looking, “the word ‘achievable’...constrains the permit issuer’s 

discretion by prohibiting BACT limits that would require pollution reductions greater than 

what can be achieved with available methods.” The EAB concluded that “the permit issuer 

may take into account the absence of long-term data, or the unproven long-term 

effectiveness of the technology, in setting the emissions limitation that is BACT for the 

facility.” The EAB further stated that the BACT analysis “must be solidly grounded on what 

is presently known about the selected technology’s effectiveness,” and that “emissions 

limitations achieved by other facilities, and corresponding control technologies used at 

other facilities are an important source of information in determining” BACT. 

EPA’s March 2011 Guidance affirms that vendor confidence in emission control efficiency 

should be considered: “[t]he willingness of vendors to guarantee a certain level of performance 

should be considered by the permitting authority later in the BACT process when proposing a 

specific emissions limit or level of performance in the PSD permit.” 

Finally, the chosen BACT emission limit must not be less stringent than any applicable federal 

NSPS, NESHAP, or state-specific emission standard. It should be noted, however, that 

currently there are no federal NSPS, NESHAP, or California State GHG emission standards that 

apply to biomass-fired cogeneration units. 

1.3 Cost-Effectiveness Analysis 

In Step 4 of the top-down BACT analysis process, cost effectiveness is used to assess the 

economic impact of emission reduction alternatives. The cost effectiveness of a control option 

is defined as dollars per ton ($/ton) of pollutant removed or avoided when compared with some 

baseline (usually the uncontrolled emission rate), and is calculated as follows: 

In cases where more than one control option is being considered, an incremental cost 

effectiveness is often calculated, as follows, to determine the cost per ton of the additional 

quantity of pollutant reduced at some additional expense: 

  Baseline Annual Emissions - Control Option Annual Emissions

Total Annualized Costs of Control Option
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1.3.1 Cost Methodology 

The total annualized cost of each control is calculated as follows: 

i) Total Annual Costs = Annualized Capital Costs + Annual Operations & 

Maintenance Costs 

ii) Annualized Capital Costs = Capital Recovery Factor x Total Direct and Indirect 

Capital Costs 

Where: 

Capital Recovery Factor (CRF) = 

and, assuming: 

Life of Equipment, n = 20 years 

Annual Interest Rate, i = 7% 

CRF = 0.094393 

1.3.2 Cost Criteria 

Step 4 of the BACT process addresses economic, energy, and environmental impacts 

associated with feasible control options. The economic evaluation enables an applicant an 

opportunity to demonstrate that the costs of pollutant removal for a particular control option are 

disproportionately high. However, EPA’s March 2011 Guidance acknowledges “there is not a 

wealth of GHG cost effectiveness data from prior permitting actions for a permitting authority to 

review and rely upon when determining what cost level is considered acceptable for GHG 

BACT.” EPA also acknowledges that cost effectiveness criteria historically applied to criteria 

pollutant emissions are not appropriate for greenhouse gases because greenhouse gas 

emissions tend to be orders of magnitude greater than criteria pollutant emissions. Given this 

early stage of greenhouse gas BACT review, there is very little information that enables 

applicants or reviewing agencies to determine whether a control option is cost effective. 

An Interim Report issued in February 2010 by the Climate Change Work Group of the Permits, 

New Source Review and Toxics Subcommittee to the EPA’s Clean Air Act Advisory Committee, 

which includes industry, environmental, and regulatory groups, provided no consensus on 

greenhouse gas cost effectiveness, with values ranging from $3 per ton to $150 per ton. Some 

members supported not setting fixed cost effectiveness thresholds, and recommended that EPA 

provide guidance to permitting authorities on the range of cost effectiveness values based on 

the status of various control technologies. 

An obvious source of carbon cost information is the value of carbon allowances or offsets. 

Analogous to EPA’s acid rain program, an allowance is an authorization under a regulatory 

 

  Control Option Annual Emissions - Next Control Option Annual Emissions

Total Annualized Costs of Control Option - Total Annualized Costs of Next Control Option
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program to emit a certain quantity of carbon. However, a carbon offset is typically an emission 

reduction established outside of a regulatory program, and may or may not be recognized by a 

regulatory program. 

The Regional Greenhouse Gas Initiative (RGGI, http://www.rggi.org) is the first mandatory, 

market-based effort in the United States to reduce greenhouse gas emissions. Ten 

Northeastern and Mid-Atlantic states have implemented a CO2 cap, effective until 2014, after 

which the cap will be reduced by 2.5 percent each year until a total reduction of 10 percent is 

achieved by 2018. States sell nearly all emission allowances through auctions and invest the 

proceeds in consumer benefits such as energy efficiency, renewable energy, and other clean 

energy technologies. 

At a RGGI auction held March 9, 2011, allowances averaged $1.89 per ton of CO2. “Future” 

allowances also averaged $1.89 per ton, implying that the value of CO2 allowances is not 

expected to change significantly in the near future. Eighty-five percent of the allowances 

available at the auction were purchased by electric utilities and affiliates. 

RGGI-participating states currently allow regulated power plants to use a carefully-chosen group 

of qualifying offsets to meet up to 3.3 percent of their CO2 compliance obligation. Examples of 

offset-eligible project categories include those that capture or destroy methane from landfills or 

through agricultural manure management operations. 

Similar in nature to RGGI allowances, European Union Allowance units (EUAs) are sold in 

Europe as a mechanism for achieving an EU objective of a 20 percent reduction in carbon 

emissions by 2020 (compared to 1990 levels). The price of an EUA in April 2011 was 

approximately 16 euros (equivalent to about $23) per metric tonne. 

The Chicago Climate Exchange (CCX) was a voluntary, legally binding, GHG reduction and 

trading system until it closed in November 2010. At that time, the price of carbon credits (which 

had not traded on the CCX since February 2010) ranged between $0.05 and $0.10 per metric 

tonne of CO2e. 

The third, and most recent, auction of greenhouse gas allowances by the California Air 

Resources Board (CARB) for the California Cap-and-Trade program, held on May 3, 2013, 

resulted in a per-allowance price of $14.00 for 2013 vintage allowances. An allowance gives 

the holder the right to emit 1 ton of GHG on a CO2e basis. On the same date, the advance 

auction of 2016 vintage allowances resulted in a per-allowance price of $10.71. 

When developing the GHG Tailoring Rule, EPA used scaling to derive a Significant Emission 

Rate for greenhouse gases from the Significant Emission Rates for criteria pollutants. Applying 

a similar rationale, one could derive a greenhouse gas cost effectiveness criterion by scaling 

CO2 emissions from CO emissions. Using a relatively conservative cost effectiveness criterion 

of $10,000/ton, and emission factors for external natural gas combustion from EPA’s AP-42 

emission factor database (84 and 120,000 lb/scf for CO and CO2, respectively), a comparable 

cost-effectiveness criterion for CO2 would be $7/ton (i.e., $10,000 x 84 / 120,000). 
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In October 2010, Hyperion Energy Center (a proposed combination oil refinery and integrated 

gasification combined-cycle power plant) submitted a greenhouse gas BACT analysis to South 

Dakota Department of Environment and Natural Resources in support of a renewal of a 

previously issued PSD permit that calculated the cost effectiveness of implementing Carbon 

Capture and Storage (CCS) on a CO2 vent, refinery process heaters, and combined cycle gas 

turbines. The calculated cost effectiveness of the various control options ranged from $43 to 

$124 per ton of CO2e. Absent any established cost effectiveness criteria, the Hyperion BACT 

analysis cited the Chicago Climate Exchange offset prices (less than $1 per ton at the time) and 

the EU allowance prices ($12 per tonne at the time) and concluded that CCS was not cost 

effective. 

We Energies provided a GHG BACT analysis in support of a permit application submitted to 

Wisconsin Department of Natural Resources proposing to install and operate a biomass-fired 

boiler. The GHG BACT analysis included cost-effectiveness calculations for systems to control 

methane (CH4) and nitrous oxide (N2O), but did not provide any cost-effectiveness criteria for 

comparison. 

Lacking specific guidance from EPA or local agencies, and weighting several sources that imply 

values less than $2/ton against an EU Allowance of $23/tonne, SPI proposes a GHG costeffectiveness threshold of $7/ton, derived by scaling the commonly-accepted cost-effectiveness 

threshold for criteria pollutants ($10,000/ton) using natural gas combustion emission factors. 
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2 Project Greenhouse Gas Emissions 

The Tailoring Rule defined GHGs as an aggregate of: carbon dioxide (CO2), methane (CH4), 

nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur 

hexafluoride (SF6). The proposed project has the potential to emit only three of these: CO2, 

CH4, and N2O. All GHG emissions associated with the project will be generated by the 

cogeneration unit; the cooling tower will not emit any GHGs. The Tailoring Rule further defined 

CO2e as the sum of the mass emissions of the constituent GHG, each multiplied by the 

appropriate global warming potential (GWP) factor provided in Table A-1 of the Federal 

Mandatory GHG Reporting Rule (MRR, codified in 40 CFR Part 98). 

The proposed cogeneration unit is assumed to have a maximum annual average heat input of 

468 million British thermal units per hour (MMBtu/hr). A natural-gas-fired emergency feedwater 

pump used to circulate water through the cogeneration unit boiler in case of an emergency 

shutdown while disconnected from the grid, will have a maximum heat input of 2.16 MMBtu/hr, 

and will be operated a maximum of 100 hours per year for maintenance and testing purposes, in 

addition to any emergency use. Table 2-1 summarizes the calculations and shows that the 

proposed project has the potential to generate a maximum of approximately 433,000 tons of 

CO2e per year. 

Table 2-1. Greenhouse Gas Emission Rate Calculations – Proposed Equipment 

Emission 

Unit GHG 

Emission Factor1 Global 

Warming

Potential2

Emission Rate3

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

Cogeneration 

Unit 

CO2 93.8 207 1 96,800 424,000 

CH4 3.20E-02 0.0705 21 33.0 145 

N2O 4.20E-03 0.00926 310 4.33 19.0 

CO2e -- -- -- 98,800 433,000 

Gas-Fired 

Emergency 

Feedwater 

Pump 

CO2 53.02 116.9 1 253 12.6 

CH4 0.001 0.0022 21 0.00476 0.000238 

N2O 0.0001 0.00022 310 0.000476 0.0000238 

CO2e -- -- -- 253 12.6 

Total 

CO2 -- -- 1 97,000 424,000 

CH4 -- -- 21 33.0 145 

N2O -- -- 310 4.33 19.0 

CO2e -- -- -- 99,100 433,000 

1 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel, and natural gas, are 

from 40 CFR Part 98, Tables C-1 and C-2; these were converted to lb/MMBtu 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 maximum annual average heat input (468 MMBtu/hr for the 

cogeneration unit and 2.16 MMBtu/hr for the emergency pump engine). Annual emission rates are based on 8,760 

hr/yr operation for the cogeneration unit, and 100 hr/yr for the emergency pump engine. CO2e was calculated by 

multiplying each individual emission rate by the applicable GWP factor, and summing. 

While the vast majority of emissions will be from combustion of wood and wood-residual solid 

biomass fuel, the proposed unit will be equipped with two 62.5 MMBtu/hr natural gas burners 

that will be used during startup, and, potentially, during shutdown and for flame stabilization. 
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Operation of the natural gas burners will not exceed 10 percent of the annual heat input 

capacity of the boiler, or 409,934 MMBtu/yr (468 MMBtu/hr * 8.760 hr/yr * 10%). Based on that 

maximum annual heat input and the CO2e emission factor for natural gas combustion from 40 

CFR Part 98 (117 lb/MMBtu), the maximum GHG emissions from the natural gas burners will be 

23,981 tpy. It should be noted that the CO2e emission factor for natural gas combustion is less 

than the CO2e emission factor for biomass fuel, so any displacement of biomass fuel by natural 

gas combustion would reduce the maximum annual GHG emission potential of the unit. 

The proposed cogeneration unit will be started and shutdown as infrequently as possible. There 

is typically at least one outage period each year for maintenance; any additional shutdown-andstartup cycles will be the result of an unscheduled event. It takes approximately 12 hours to 

start the cogeneration unit; natural gas burners are used to heat the refractory for the first 

6 hours, and then biomass fuel is phased in, which the gas firing is phased out over the final 

6 hours. Shutdown takes approximately 1 hour to accomplish, and the natural gas burners are 

used only if elevated carbon monoxide (CO) levels are indicated by the continuous emissions 

monitoring system (CEMS). Based on the startup protocol outlined above, a calculated 

estimate of GHG emissions is provided in Table 2-2. 

Table 2-2. Greenhouse Gas Emission Rate Calculations – Cogeneration Unit Startup 

Firing Biomass Fuel 

GHG 

Emission 

Factor 

(lb/MMBtu) 

Hourly 

Emission Rate1

(lb/hr) 

Event 

Emission Rate2

(lb/event) 

CO2 207 96,770 580,622 

CH4 0.2823 132 792 

N2O 0.03703 17 104 

CO2e4 104,916 629,498 

Firing Natural Gas 

GHG 

Emission 

Factor 

(lb/MMBtu) 

Hourly 

Emission Rate1

(lb/hr) 

Event 

Emission Rate2

(lb/event) 

CO2 117 14,611 87,666 

CH4 0.0022 0.276 1.65 

N2O 0.00022 0.0276 0.165 

CO2e4 14,625 87,752 

Total 

GHG 

Average Hourly

Emission Rate1

(lb/hr) 

Event 

Emission Rate2

(lb/event) 

Event 

Emission Rate 

(ton/event) 

CO2 55,691 668,288 334 

CH4 66 794 0.397 

N2O 9 104 0.0521 

CO2e4 59,771 717,250 359 

1 Hourly emission rates are based on 468 MMBtu/hr when firing biomass, and 125 MMBtu/hr when firing natural gas. 

2 Event emission rate is the hourly emission rate multiplied by 6 hours. 

3 The CH4 and N2O emission rates were increased by a factor of 4 to reflect incomplete combustion during startup; a 

similar approach was taken when calculating CO and VOC emission rates during startup. 

4 Calculated using 100-year time horizon global warming potentials (GWPs) from 40 CFR Part 98, Table A-1. 
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The facility currently includes a biomass-fired boiler with a maximum annual average heat input 

capacity of 116.5 MMBtu/hr, and a circuit breaker and two switches that utilize sulfur 

hexafluoride (SF6) as a dielectric medium. The existing boiler will not be used concurrent with 

the proposed cogeneration unit, but the existing switchgear will continue to be used by the new 

unit, unchanged from its current configuration. During the period that the new unit is 

commissioned it will operate concurrent with the existing unit, but none of the steam will be used 

for commercial purposes, and the new generator will not be connected to the existing 

switchgear. Table 2-3 summarizes the GHG emission rate calculations for the existing 

equipment at the facility. 

Table 2-3. Greenhouse Gas Emission Rate Calculations – Existing Equipment 

Emission 

Unit GHG 

Emission Factor (Heat Input)1 Global 

Warming

Potential2

Emission Rate3

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

BiomassFired 

Boiler 

CO2 93.8 207 1 24,100 105,000 

CH4 3.20E-02 0.0705 21 8.21 36.0 

N2O 4.20E-03 0.00926 310 1.08 4.72 

CO2e -- -- -- 24,600 108,000 

Switchgear SF6 1% leakage/year 23,900 0.000217 0.000950 

CO2e -- -- -- 5.18 22.7 

Total 

CO2 -- -- 1 24,100 105,000 

CH4 -- -- 21 8.21 36.0 

N2O -- -- 310 1.08 4.72 

SF6 -- -- 23,900 0.000217 0.000950 

CO2e -- -- -- 24,600 108,000 

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 The hourly emission rate for the existing biomass-fired boiler was calculated by multiplying the emission factor by 

the maximum heat input (116.4 MMBtu/hr); annual emission rates are based on 8,760 hr/yr operation. The annual 

SF6 emission rate for the switchgear was calculated by multiplying the SF6 capacity of the existing breaker and two 

switches (190 lb) by the annual leak rate of (1%, which was the industry standard at the time the equipment was 

installed); the hourly emission rate was based on the assumption that the leak rate is uniform throughput the year. 

CO2e was calculated by multiplying each individual emission rate by the applicable GWP factor, and summing. 
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3 Step 1 – Identify Available Control Alternatives 

The first step of a top-down BACT analysis is to identify all available pollutant reduction options. 

Options typically fall into three categories: inherently low-emitting processes, clean fuels, and 

add-on control technologies. While step 1 is intended to include all possibilities, there are limits 

to the scope of the first two option categories (i.e., inherently low-emitting processes and clean 

fuels). The list of options in step 1 need not include those that fundamentally redefine the 

nature of the proposed source or modification. The EPA’s RBLC (RACT/BACT/LAER 

Clearinghouse database) was queried to identify GHG BACT determinations associated with 

recently permitted biomass-fired boilers. The five most recent facilities are summarized in Table 

3-1. In each case, BACT for GHGs was determined to be efficient operation and good 

operating practices (also referred to as good combustion practices). In all cases where the 

BACT process was available for review, carbon capture and sequestration/storage (CCS) was 

rejected as a viable option. In one of the recent BACT analyses, other add-on control 

alternatives (oxidation catalysts, thermal oxidation, non-selective catalytic reduction (NSCR), 

selective catalytic reduction (SCR) with N2O catalyst, elimination of selective non-catalytic 

reduction (SNCR)) were evaluated to reduce one or more GHG, but all were rejected. 

Table 2-3. Summary of GHG BACT Determinations for Biomass-Fired Boilers in RBLC 

Facility State 

Permit 

Issuance

Date 

Heat Input 

(MMBtu/hr) 

GHG BACT 

Determination 

Rejected GHG 

Control Alternatives 

North Springfield 

Sustainable 

Energy Project 

VT 4/19/2013 464 

Efficient Operation, 

Combined Heat & 

Power (CHP), Good 

Operating Practices 

(GOP) 

Carbon Capture & 

Storage (CCS), Fuel 

Switching 

Beaver Wood 

Energy Fair 

Haven LLC 

VT 2/10/2012 482 Efficient Operation, 

CHP, GOP CCS, Fuel Switching 

WE Energies – 

Rothschild WI 3/28/2011 781 Efficient Operation, CHP, GOP 

CCS, Oxidation 

Catalysts, Thermal 

Oxidation, Non-Selective 

Catalytic Reduction 

(NSCR), Selective 

Catalytic Reduction 

(SCR) with N2O Catalyst, 

Elimination of Selective 

Non-Catalytic Reduction 

(SNCR) 

Abengoa 

Bioenergy 

Biomass of 

Kansas LLC 

KS 9/16/2011 500 

Use of Low-Carbon or 

Carbon-Neutral Fuel, 

Efficient Operation, 

CHP, GOP 

CCS 

Montville Power 

LLC CT 4/6/2010 600 Efficient operation, 

GOP N/A1

1 Issued permit does not outline the BACT determination process for GHGs; unable to obtain an associated 

technical support document 

Considerable argument and litigation has been generated previously over what constitutes 

“redefinition of the source.” One of the most recent approaches, outlined by the Environmental 
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Appeals Board (EAB), is contained in a 2009 ruling to remand a permit issued to Desert Rock 

Energy Co., LLC. In that ruling, which referred extensively to a previous ruling (Prairie State 

Generation Co., LLC), the EAB says that the reviewing agency should seek to answer 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?” 

In response to its own question, the EAB stated that “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.” Furthermore, the 

permit issuer should “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.” 

The discussion in the prior paragraphs notwithstanding, EPA has requested that SPI consider 

fluidized bed boiler (FBB) designs in step 1 of the BACT process. SPI contacted FBB 

manufacturers and sought out facilities with operations similar to that of the Anderson facility 

that employed FBBs. Manufacturers of FBBs indicated that their designs were not appropriate 

for use when the boiler would be operated at loads less than 50 percent of the rated capacity 

(i.e., in “turndown” mode). First, the extent of turndown that will be required of the installed unit 

makes FBBs impractical. Second, the unit will be expected to achieve significant load changes 

(e.g., 100 percent load to 50 percent load) within a short period of time (e.g., 1 hour). The 

thermal inertia of the fluidized bed material, which allows introduced fuel to be heated to ignition 

temperature without significantly affecting the bed temperature, prevents FBB units from 

accommodating abrupt load changes. 

Furthermore, SPI was unable to identify any lumber manufacturing facilities using biomass fuel 

to generate steam to heat lumber dry kilns that utilized an FBB. An additional practical concern 

is that the proposed cogeneration unit will supply steam to generate electricity in addition to 

heating lumber dry kilns. The power purchase agreement associated with supplying generated 

electricity to the grid requires a high level of availability; the electrical generation commitments 

for this unit are not compatible with accommodating an exploratory or innovative application of 

existing technology. 

As discussed in a letter sent to USEPA Region 9 on January 23, 2012 by ENVIRON on behalf 

of SPI, a stoker boiler design was chosen for the project because operation in turndown modes 

less than 50 percent would be possible. A USEPA information document estimates that FBB 

designs are capable of unburned fuel rates as low as 0.25 percent, which suggests more 

efficient operation.2

 Teaford (now Dieffenbacher), the designer and manufacturer of the boiler 

selected by SPI for the proposed cogeneration unit, estimates that their stoker design can 

 

2 USEPA, Combined Heat and Power Partnership. “Biomass Combined Heat and Power Catalog of 

Technologies.” September 2007. 
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achieve an unburned fuel rate of approximately 1 percent. Nevertheless, more efficient 

operation does not mitigate the fact that FBB designs are incapable of accommodating the 

project’s intended objectives (i.e., ability to achieve turndown modes less than 50 percent and 

abrupt load changes), and are therefore rejected as viable alternatives. 

In the March 2011 Guidance document, USEPA acknowledges that, although “clean fuels” are 

to be considered in step 1 of the BACT analysis, the initial list of control options does not need 

to include “clean fuel” options that would fundamentally redefine the source. In this case, use of 

the biomass fuel generated by the existing facility is a central purpose for the project. 

Substitution of any other fuel, lower-carbon-containing or otherwise, would drastically alter the 

overall goals of the proposed project. 

3.1 Carbon Dioxide 

Carbon dioxide (CO2) is a by-product of complete combustion. Altering the combustion process 

to reduce CO2 emissions would increase emissions of “traditional” air pollutants such as carbon 

monoxide (CO) and volatile organic compounds (VOCs). Maximizing the heat transfer 

efficiency of the boiler and the mechanical efficiency of the steam turbine and generator 

minimizes the quantity of fuel combusted, and therefore the quantity of CO2 generated, per unit 

of steam or electricity generated. Approaches intended to reduce fuel consumption while 

increasing output are typically referred to as “good boiler design, good combustion practices, 

and efficient operation.” 

Add-on technologies that are able to remove, or “capture,” CO2 from the post-combustion 

exhaust stream have been developed, though none have been used to capture CO2 from a 

biomass combustion unit. Following capture, the CO2 would be transported and stored 

permanently, or “sequestered,” in a geologic formation. Such systems, referred to as “carbon 

capture and sequestration/storage” (CCS), are not yet commercially available, and the U.S. 

Department of Energy does not expect them to be available until approximately 2025. 

The March 2011 Guidance document states that, if the proposed emission unit “can 

demonstrate that utilizing a particular type of biogenic fuel is fundamental to the primary 

purpose of the project,” then “the options listed as Step 1 of a top-down BACT analysis of GHGs 

may be limited to (1) utilization of biomass fuel alone, (2) energy efficiency improvements, and 

(3) carbon capture and sequestration.” 

3.2 Methane 

Like carbon monoxide (CO) and volatile organic compounds (VOCs), methane (CH4) emissions 

are generally the result of incomplete fuel combustion. In the case of biomass, volatile 

compounds (including CH4) are released as the fuel is heated in the furnace, some portion of 

which escapes combustion by improper mixing with oxygen or being confined to zones of 

relatively low temperature. 

Proper combustion practices and use of a properly designed boiler maximizes complete 

combustion, and minimizes emissions of volatiles, including CH4. Add-on controls used to 

remove volatile compounds from gas streams include adsorption systems and thermal or 

catalytic oxidation systems. Adsorption systems pass the gas stream though canisters filled 
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with activated carbon or zeolite, and the volatile compounds are trapped in pores located on the 

carbon or zeolite particles. When the carbon approaches saturation, the canister is replaced 

and processed to remove the volatile compounds, which are recovered or destroyed. Oxidation 

systems increase the temperature of the gas stream until the CH4 oxidizes, forming CO2 and 

water. Thermal oxidizers destroy volatile compounds using a flame, while catalytic oxidation 

uses a catalyst to promote oxidation reactions at temperatures lower than those at which 

combustion typically takes place. 

3.3 Nitrous Oxide 

Unlike nitric oxide (NO), which is the product of high combustion temperatures (greater than 

730 °C or 1,350 °F), nitrous oxide (N2O) is the result of lower combustion temperatures (less 

than 800 °C or 1,475 °F). Its formation can be limited to some extent by using proper 

combustion techniques and a properly designed boiler that promotes uniform furnace 

temperatures. Typically, furnace conditions that favor CH4 formation, also favor N2O formation. 

Add-on controls to reduce N2O emissions include: non-selective catalytic reduction (NSCR), 

thermal destruction, and catalytic destruction. In the 1970s, NSCR systems were widely used to 

control N2O and oxides of nitrogen (NOX) emissions from adipic and nitric acid production 

operations, but high energy costs reduced the popularity of this approach. Currently, NSCR 

systems have been used to reduce emissions from reciprocating engines operated in a richburn or stoichiometric mode. In general, NSCR systems pass the exhaust gases over catalysts, 

which use metals (e.g., platinum, rhodium, palladium) to convert NOX, CO, and VOCs to water, 

nitrogen, and carbon dioxide. Unburned hydrocarbons in the exhaust are used as a reducing 

agent to enable one catalyst to convert N2O and NOX, while CO and VOCs are oxidized by 

another catalyst. In cases where the option to consistently operate in a fuel-rich or 

stoichiometric mode to provide the reducing agent is not available, natural gas can be injected 

to act as the reducing agent. 

Thermal destruction of N2O is achieved using a reducing flame burner combusting premixed 

methane or natural gas. The flame temperature must be maintained high enough to destroy the 

N2O, but below 1,500 °C to minimize NOX formation. Catalytic destruction is accomplished at 

lower temperatures (400 to 700 °C) using metal- or zeolite-based N2O-decomposing catalysts. 

Conventional commercially-available selective catalytic reduction (SCR) systems (i.e., those 

using titanium, tungsten, and vanadium-based catalysts) used to reduce emissions of nitric 

oxide (NO) and nitrogen dioxide (NO2), as well as selective non-catalytic reduction (SNCR) 

systems, generate N2O, so removal of such control systems would reduce N2O emissions. 

However, at least two companies (BASF and Heraeus) have developed catalysts designed to 

simultaneously remove both N2O as well as NO and NO2. 
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4 Step 2 – Eliminate Technically Infeasible Alternatives 

In the second step of a top-down BACT analysis, the available pollutant reduction options listed 

in Step 1 are considered, and, if found to be technically infeasible for the specific emission unit 

under review, eliminated. 

4.1 Carbon Dioxide 

In Step 1, use of biomass fuel, energy efficiency, and CCS were identified as potential control 

technologies, consistent with the EPA’s March 2011 guidance. 

Biomass Fuel

Combustion of biomass fuels, alone or in combination with other fuels, in boilers to generate 

steam is a long-standing practice. Biomass is one of the original boiler fuels, and it remains a 

feasible and often-used fuel. 

Good Boiler Design, Good Combustion Practices, Efficient Operation

Maximizing the quantity of steam or electricity generated per unit of fuel combusted is the goal 

of most boiler designers and operators. Striving for energy efficiency is technically feasible 

within the limitations of the second law of thermodynamics. At maximum operation, the 

efficiency of the proposed boiler (i.e., the fraction of the energy in the fuel that is transferred to 

the steam) is expected to be approximately 70 percent. The efficiency of the electrical 

generator is, at full load, approximately 96 percent. The overall efficiency of the cogeneration 

unit will vary depending upon the quantities of steam used to heat the kilns and generate 

electricity, but is expected to vary between 37 and 53 percent. 

Carbon Capture and Sequestration

In its findings and recommendations report, issued on January 24, 2011, the California Carbon 

Capture and Storage Review Panel concluded, among other things, that the technology “for the 

safe and effective capture, transport, and geological storage of CO2 from power plants and other 

large industrial facilities” currently exists. However, not all components that comprise an 

effective CCS program are currently commercially available. Nevertheless, for purposes of this 

BACT Analysis, CCS is considered to be a technically feasible control alternative for biomassfired boilers. 

There are three approaches to CO2 capture that are generally applicable to power generation: 

 Pre-combustion systems designed to separate CO2 and hydrogen (H2) from produced 

syngas, 

 Post-combustion systems designed to separate CO2 from flue gas, and 

 Oxy-combustion that uses high-purity oxygen (O2) instead of air, which produces flue 

gas composed largely of CO2. 
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Of these, only post-combustion systems will be considered in this BACT analysis for application 

to a biomass-fired boiler, notwithstanding the fact that it has never been applied to exhaust from 

such a unit. Use of a pre-combustion system would require a gasification unit to produce 

syngas from the biomass fuel, which would amount to redefining the source. Oxy-combustion of 

biomass fuels is currently in the experimental phase, and is typically in the context of being cofired with coal. 

4.2 Methane 

In Step 1, proper combustion, thermal oxidation, and catalytic oxidation were identified as 

possible alternatives for CH4 reduction. 

Good Boiler Design, Good Combustion Practices, Efficient Operation

For boilers combusting biomass, good boiler design, good combustion practices, and efficient 

operation are ubiquitous approaches used to reduce CO and hydrocarbon (including CH4) 

emissions, therefore, they are considered technically feasible for control of CH4 emissions. 

Adsorption

Adsorption systems use porous material such as activated carbon or zeolite to capture gaseous 

pollutants. However, compounds are captured with varying efficiencies, and light hydrocarbons 

e.g., CH4) have poor removal efficiencies, typically less than 50 percent. In addition, the CH4

concentration in the cogeneration unit exhaust stream will be small (i.e., less than 1 percent by 

volume), further reducing the capture efficiency. For these reasons, adsorption systems have 

never been used to remove CH4 from combustion unit exhaust streams. Using adsorption 

technology to reduce CH4 emissions from a biomass-fired boiler in not considered technically 

feasible. 

Thermal Destruction

To thermally oxidize a pollutant in an exhaust stream, a combustor is located in the exhaust 

duct, and fuel (typically natural gas) and enough supplemental air to support a flame are 

introduced. While the thermal oxidizer may destroy a portion of the small amount of CH4

present in the exhaust (i.e., less than 1 percent by volume), the oxidizer itself is likely to 

generate additional air pollutants (e.g., NOX, CO, VOCs, and CH4) such that there is a net 

increase in emissions. In addition, a thermal oxidizer has never been used to reduce CH4

emissions from a biomass-fired boiler. Control of CH4 using thermal oxidation is considered 

speculative and not achieved in practice for a biomass-fired boiler, and, therefore, not 

technically feasible for reducing CH4 emissions from a biomass-fired boiler. 

Catalytic Destruction

When applied to boilers, the intent of a catalytic oxidation system is to reduce CO and, to a 

lesser extent, VOC and PM emissions. As discussed in the criteria pollutant BACT analysis 

submitted with the PSD permit application, while catalytic oxidation is not experimental, 

application to biomass-fired boilers is uncommon and difficult. Regardless of whether the 
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catalyst is located upstream of downstream of a particulate control device (e.g., an electrostatic 

precipitator), alkali compounds in the exhaust gas deactivate the catalyst. To counteract the 

deactivation, large quantities of catalyst must be deployed and frequently replaced, resulting in 

unpredictable boiler availability and control system costs. Nevertheless, application of a 

catalytic oxidation system to reduce CH4 emissions from a biomass-fired boiler is technically 

feasible. 

4.3 Nitrous Oxide 

In Step 1, proper combustion, thermal destruction, catalytic destruction, NSCR, removal of SCR 

systems, and addition of N2O-abating SCR systems were identified as possible alternatives for 

N2O reduction. 

Good Boiler Design, Good Combustion Practices, Efficient Operation

For boilers combusting biomass, good boiler design, good combustion practices, and efficient 

operation are ubiquitous approaches used to reduce combustion byproducts other than CO2

and water (including N2O), therefore, they are considered technically feasible for control of N2O 

emissions. 

Thermal Destruction

Similar to the application of a thermal oxidizer to destroy CH4, discussed above, the thermal 

oxidizer may destroy the relatively small amount of N2O in the exhaust (i.e., less than 1 percent 

by volume), but the combustor itself is likely to generate air pollutants (e.g., NOX, CO, SO2, and 

N2O) such that there is a net increase in emissions. As for CH4, a thermal oxidizer has never 

been used to reduce N2O emissions from a biomass-fired boiler. Use of this technology to 

reduce N2O emissions from biomass-fired boilers is considered speculative and not achieved in 

practice, and therefore not technically feasible for reducing N2O emissions from a biomass-fired 

boiler. 

Catalytic Destruction

When applied to boilers, the intent of a catalytic oxidation system is to reduce CO and, to a 

lesser extent, VOC and PM emissions. As discussed in the criteria pollutant BACT analysis 

submitted with the PSD permit application, while catalytic oxidation is not experimental, 

application to biomass-fired boilers is uncommon and difficult. Regardless of whether the 

catalyst is located upstream of downstream of a particulate control device (e.g., an electrostatic 

precipitator), alkali compounds present in the exhaust gas deactivate the catalyst. To 

counteract the deactivation, large quantities of catalyst must be deployed and frequently 

replaced, resulting in unpredictable boiler availability and control system costs. Nevertheless, 

application of a catalytic oxidation system to reduce N2O emissions from a biomass-fired boiler 

is technically feasible. 
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Non-Selective Catalytic Reduction Systems

NSCR systems have primarily been developed to reduce N2O emissions from adipic and nitric 

acid production operations; as acid production facility designs improve, NSCR is being phased 

out in favor of more economical alternatives. There are no instances of an NSCR system being 

applied to reduce N2O emissions from a biomass-fired boiler, and because significant 

differences exist between the exhaust from adipic and nitric acid operations and that of a 

biomass-fired boiler (i.e., typical N2O concentration in exhaust from a nitric acid plant is typically 

over 1,000 ppm, while the concentration in biomass-fired boiler exhaust is approximately 10 

ppm), it is unlikely that the technology could be transferred effectively and economically. NSCR 

is therefore considered not technically feasible for control of N2O from biomass-fired boilers. 

Removal of Selective Non-Catalytic Reduction Systems

An SNCR system is proposed by SPI to reduce NOX emissions from the biomass-fired boiler. It 

is technically feasible to not install such a system. 

Removal of Conventional Selective Catalytic Reduction Systems

SPI does not propose to install a conventional SCR system to reduce NOX emissions from the 

biomass-fired boiler. The criteria pollutant BACT analysis provided with the PSD permit 

application indicated that SCR was technically feasible, but had a still-unproven track record of 

reliable performance associated with biomass-fired boilers. Since no SCR system is proposed 

for installation on the biomass-fired boiler, it is technically infeasible to not install such a system. 

Addition of N2O-Abating Selective Catalytic Reduction Systems

The criteria pollutant BACT analysis provided with the PSD permit application concluded that 

conventional SCR systems were technically feasible for reducing NOX emissions from biomassfired boiler; therefore, N2O-abating SCR systems are also considered technically feasible. 
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5 Step 3 – Rank Technically Feasible Alternatives 

In Step 3, the remaining alternatives that have not been removed from consideration due to 

technical infeasibility, are ranked, starting with the most effective. The March 2011 Guidance 

says that “to best reflect the impact on the environment, the ranking of control options should be 

based on the total CO2e rather than the total mass or mass for the individual GHGs. Before 

ranking all feasible control alternatives from the previous section are ranked together, the 

effectiveness of each on a CO2e basis is discussed. 

Good Boiler Design, Good Combustion Practices, Efficient Operation

The proposed project would operate in a manner that minimizes emissions of all pollutants, and 

maximizes the energy derived from the fuel consumed. Thus, these measures, in combination, 

are considered the baseline from which all other alternatives will be evaluated, and it is 

assumed that all other options would be applied in addition to these measures. 

Biomass Fuel

The proposed boiler will be fired exclusively using biomass fuel, and SPI expects approximately 

75 percent of that fuel to be comprised of sawmill residues from the Anderson sawmill and the 

nearby Shasta Lake sawmill. The remaining 25 percent is expected to be a combination of inforest residues, agricultural residues from orchards in the Sacramento Valley, and urban wood 

residues diverted from landfills. Efficiently combusting mill residues, in-forest residues, and 

agricultural residues to generate steam and electricity results in less net GHG emissions (i.e., 

less CH4 and N2O are generated) than if those same residues were allowed to decompose or be 

subject to open burning. In the March 2011 Guidance, EPA acknowledges that the combustion 

of lumber manufacturing residues to generate energy does not increase net atmospheric GHG 

stock. 

Furthermore, SPI manages nearly 1.7 million acres of forest land in California using sustainable 

forestry practices, and most of the carbon in the wood harvested from those forest lands 

remains sequestered in produced lumber. SPI replants harvested areas within a year, and 

plants an average of 6 million seedlings each year. The combined effect of: (1) younger trees 

taking up more carbon than harvested mature trees, (2) the sequestration of carbon in produced 

lumber, and (3) the most-effective conversion of residues to CO2 by combustion in the proposed 

boiler is that SPI’s operations serve to reduce atmospheric CO2 stocks. 

Carbon Capture and Sequestration

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

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

enhanced oil recovery, industrial use). The effectiveness of the system to reduce CO2

emissions is determined by the removal rate of CO2 from the flue gas, and degree to which the 

CO2 is retained while being transported and stored. Currently available technology can capture 
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approximately 90 percent of the post-combustion CO2 in flue gas.3 However, due to the 

considerable energy requirements for the capture and compression of the CO2, the electrical 

generating capacity of the proposed cogeneration unit would have to be increased by 40 to 

60 percent, which would increase the project’s emission “footprint” by increasing both criteria 

pollutants and GHGs. Although 90 percent of the additional CO2 generated would also be 

captured, the net CO2 reduction would be reduced from 90 percent to 86 percent.4

Transport of CO2 by pipeline is a mature technology, and expected losses of CO2 in a pipeline 

would be minimal. While the fundamental physical processes and engineering aspects of 

geological storage of CO2 are well understood, and there are active successful demonstration 

projects, it is not yet a commercially available alternative.5

 Enhanced oil recovery (EOR) uses 

CO2 extract additional crude oil from producing wells. The majority of EOR activity is in the 

Permian Basin covering west Texas and southeastern New Mexico, and almost all of the CO2

used there comes from large, high purity, geological CO2 reservoirs in the same area. Projects 

that use anthropogenic CO2 for EOR exist, or are under development, in Wyoming, 

Saskatchewan, and west Texas.6

 The best candidates for using captured CO2 industrially 

include: 

 Feedstock for urea yield boosting 

 Working fluid for enhanced geothermal systems (EGS) 

 Feedstock for polymer processing 

 Algae cultivation 

 Feedstock for carbonate mineralisation 

 Concrete curing 

 Bauxite residue carbonation 

 Feedstock for liquid fuel production 

 Enhanced coal bed methane recovery (ECBM) 

 

3 National Energy Technology Laboratory (NETL), “Cost and Performance Baseline for Fossil Energy 

Plants – Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2,” November 2010. 

DOE/NETL-2010/1397. Page 18. 

4 424,000 tpy CO2 increased by 40 percent to account for the additional energy requirements of a CCS 

system is approximately 593,600 tpy CO2; assuming 90 percent of the CO2 is removed from the exhaust, 

results in an emission rate of approximately 59,360 tpy CO2. The net reduction in CO2 emissions is 1 – 

(59,360 / 424,000) = 0.86. 

5 International Energy Agency (IEA, “Technology Roadmap: Carbon Capture and Storage,” 2013. Pages 

16-17. 

6 NETL, “Carbon Dioxide Enhanced Oil Recovery: Untapped Domestic Energy Supply and Long Term 

Carbon Storage Solution,” March 2010. 
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Of these, only urea yield-boosting is considered a mature technology that is already applied on 

a large scale, and has the potential for significant growth in the short term.7

In summary, CO2 capture, transporting captured CO2 by pipeline, and using captured CO2

industrially for EOR or urea yield boosting are considered technically feasible. Geological 

storage of captured CO2 is considered technically infeasible based on the lack of viable 

commercial availability. 

A CCS system would not decrease the quantities of CH4 and N2O in the exhaust; in fact, the 

increase in emissions of those GHG compounds as a result of the additional capacity needed to 

power the CCS systems would degrade the net GHG reduction. On a CO2e basis, CCS has the 

potential to reduce GHG emissions by approximately 83 percent. 

Catalytic Destruction

Catalysts are a notoriously ineffective means of destroying CH4 at typical exhaust temperatures 

(i.e., less than 450 °C), and the low availability of oxygen in combustion exhaust would further 

degrade the effectiveness. At best, a 40 percent reduction in CH4 emissions has been 

documented when applied to internal combustion engines.8

When applied to exhaust from an adipic acid operation, catalytic destruction systems are 

effective, reducing N2O emissions by up to 95 percent.9

 Although it is unclear that the same 

reductions would be realized when similar catalysts are applied to a biomass-fired boiler, the 

stated levels of control will be assumed valid. Catalysts would have no effect on CO2 in the 

exhaust. As shown in Table 5-1, applying oxidation catalysts technology would result in a 

potential GHG emission reduction of, at most, 1.6 percent on a CO2e basis. 

Table 5-1 Catalytic Destruction GHG Emission Reduction 

GHG 

Emission Rate 

(tpy) GWP 

Uncontrolled 

CO2e 

(tpy) % Control 

Controlled 

CO2e 

(tpy) 

CO2 424,000 1 424,000 0 424,000 

CH4 145 21 3,050 40 1,830 

N2O 19.0 310 5,890 95 295 

Total -- -- 433,000 -- 426,000 

Net Control Efficiency (1 – Controlled CO2e / Uncontrolled CO2e) 1.6% 

 

 

7 Global CCS Institute, “Accelerating the Uptake of CCS: Industrial Use of Captured Carbon Dioxide,” 

March 2011. 

8 Wark, K. and C.F. Warner, “Air Pollution: Its Origin and Control,” 2nd Edition, Harper Collins Publishers, 

1981. Page 333. 

9 Intergovernmental Panel on Climate Change (IPCC), “Good Practice Guidance and Uncertainty 

Management in National Greenhouse Gas Inventories,” 2000. Page 188. 
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Removal of NOX Control System (SNCR)

SNCR systems convert, depending upon the reagent and furnace conditions, between 10 and 

20 percent of NOX in the exhaust to N2O. SNCR systems do not generate any CO2 or CH4, so 

elimination of the system would not affect concentrations of these compounds in the exhaust 

gas. Assuming the SNCR system accounts for all of the N2O generated by the boiler, and that 

removal of the SNCR system would reduce N2O emissions to zero, the reduction in GHG 

emissions would be 1.4 percent on a CO2e basis. 

Table 5-2 Removal of SNCR GHG Emission Reduction 

GHG 

Emission Rate 

(tpy) GWP 

Uncontrolled 

CO2e 

(tpy) % Control 

Controlled 

CO2e 

(tpy) 

CO2 424,000 1 424,000 0 424,000 

CH4 145 21 3,050 0 3,050 

N2O 19.0 310 5,890 100 0 

Total -- -- 433,000 -- 427,000 

Net Control Efficiency (1 – Controlled CO2e / Uncontrolled CO2e) 1.4% 

Ranking GHG Control Alternatives by Effectiveness

Below is a ranking of the technically feasible GHG control alternatives, starting with the most 

effective, on a CO2e basis: 

 Biomass Fuel – Net reduction in atmospheric CO2 stocks 

 Carbon Capture and Sequestration – 83 percent reduction in emitted GHGs on a CO2e 

basis 

 Catalytic Destruction – 1.6 percent reduction in emitted GHGs on a CO2e basis 

 Removal of NOX Control System (SNCR) – 1.4 percent reduction in emitted GHGs on a 

CO2e basis 

 Good Boiler Design, Good Combustion Practices, Efficient Operation – Baseline 
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6 Step 4 – Evaluate Economic, Energy, and Environmental Impacts 

In the March 2011 Guidance, EPA suggests that, instead of the more traditional approach 

where the options are considered and either eliminated or adopted in order of effectiveness, the 

economic, energy, and environmental impacts of all options are considered. In light of this 

guidance, each technically feasible option was evaluated, regardless of the Step 3 ranking. 

Biomass Fuel

Over 75 percent of the fuel combusted in the proposed boiler is expected to be derived from 

residues generated by SPI’s primary business (i.e., harvesting logs and manufacturing lumber). 

Use of this fuel provides an economic benefit by allowing SPI to avoid the cost of purchasing 

fuel to heat the on-site lumber dry kilns, purchasing electricity to power the facility, and to 

generate revenue by the sale of excess electricity. Similarly, an energy benefit is derived by 

combusting a renewable fuel instead of a fossil fuel to generate steam. 

The March 2011 Guidance states that “a case-by-case analysis of the net atmospheric impact of 

biomass fuels would likely be prohibitively time-consuming and complex for facilities and 

permitting authorities.” In lieu of such an analysis, the net environmental benefit described in 

Step 3 is realized through the combination of converting virtually all of the carbon in the fuel to 

CO2, replanting harvested forest land with saplings, and sequestering the majority of the carbon 

harvested from forest land in produced lumber. Because of the positive economic, energy, and 

environmental impacts of burning biomass fuel in lieu of fossil fuels, this alternative is 

considered BACT for GHG emissions from the proposed boiler. 

Carbon Capture and Sequestration

As discussed in Step 3, CCS systems require additional energy to remove CO2 from the boiler 

flue gas, as well as to compress it for transport and storage. In the case of a biomass boiler, the 

concentration of CO2 in the exhaust gas is relatively dilute (i.e., between 10 and 20 percent by 

weight), which would require a strong solvent to capture the CO2, as well as a considerable 

amount of energy to regenerate the solvent. The additional energy required to compress the 

captured CO2 to approximately 2,200 psig would necessitate increasing the energy footprint of 

the proposed boiler by between 40 and 60 percent, which would increase criteria and GHG 

emissions. 

Captured and compressed CO2 must be transported to some storage facility or end use. 

Storage facilities are not currently commercially available, so the only real alternative at this time 

is to use the CO2 for enhance oil recovery (EOR) or use in an industrial process. There are no 

petroleum extraction operations or industrial processes that would be able to accept the volume 

of CO2 SPI would be making available. 

The economic impacts of this additional energy requirement would be in addition to the capital 

and operating costs associated with equipping and maintaining a CCS system. 
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Most cost information related to CCS technology focuses on fossil fuel (particularly coal) 

combustion, natural gas processing, and syngas production operations. U.S. Department of 

Energy analyses indicate that application of post-combustion CO2 capture technology to a new 

550 MWe net output coal-fired power plant would cost approximately $86 per ton of CO2

avoided.10 A study by the Global CCS Institute estimates that cost of avoided CO2 emitted by a 

pulverized coal power plant with a first-of-its-kind CCS system would range between $62 and 

$81 per tonne.11 For comparison, the cost of naturally sourced CO2 used for EOR is between 

$10 and $15 per tonne.12 There is no existing or planned EOR market in the Anderson, 

California area, and no existing pipeline to deliver captured CO2 to such a market; even if such a 

market or pipeline were available to receive CO2 captured from the proposed cogeneration unit 

exhaust, the captured CO2 could not compete with naturally-available CO2. Based on the least 

expensive cost mentioned above ($62 per tonne of CO2 avoided) and the calculated annual CO2

emission rate attributable to the proposed cogeneration unit, the CCS system would cost 

approximately $29,000,000. 

The considerable monetary and energy requirements of a CCS system suggest unacceptable 

economic, energy, and environmental impacts. The increased energy requirements would 

result in additional emissions of all pollutants other than CO2, and, therefore, CCS systems have 

an unacceptable collateral environmental impact as well. As a result, CCS systems are 

removed from consideration as BACT for GHGs emitted by the proposed boiler. 

Catalytic Destruction

Because this alternative reduces emissions of GHGs other than CO2, the cost effectiveness was 

calculated on a CO2e basis. Catalytic oxidation was estimated to reduce GHG emission by less 

than 6,000 tons per year. To be considered cost effective, and assuming the cost-effectiveness 

threshold of $7 per ton proposed in Section 1.3.2, the annual cost would have to be less than 

$42,000 annually, which is unlikely, based on the costs of catalytic systems used to reduce 

criteria pollutants. The economic analysis provided in the criteria pollutant BACT analysis for a 

catalytic oxidation system to reduce CO and VOC emissions indicated that the economic impact 

of these systems, due to uncertainties regarding the reliability and cost of the systems, would be 

unacceptable. Because the GHG reduction associated with these systems (on a percent basis) 

is less than the expected reduction in CO and VOC associated with an oxidation catalyst 

system, and the cost-effectiveness threshold for GHGs is lower than what is typical for CO and 

VOC, this alternative is considered to have unacceptably high collateral economic impacts, and 

is removed from consideration as BACT for GHG emissions from the proposed boiler. 

 

10 National Energy Technology Laboratory (NETL), “Cost and Performance Baseline for Fossil Energy 

Plants – Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2,” November 2010. 

DOE/NETL-2010/1397. Page 300. 

11 Global CCS Institute, “Economic Assessment of Carbon Capture and Storage Technologies,” 2011. 

12 NETL, “Carbon Dioxide Enhanced Oil Recovery: Untapped Domestic Energy Supply and Long Term 

Carbon Storage Solution,” March 2010. 
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Removal of NOX Control System (SNCR)

Elimination of the SNCR system used to reduce NOX emissions from the boiler would result in 

an increase in NOX emissions. Because the criteria pollutant BACT analysis associated with the 

submitted PSD permit application proposed SNCR as BACT for NOX emissions from the boiler, 

elimination of the SNCR system would result in unacceptable NOX emissions from the boiler, 

and is therefore not an acceptable alternative for GHG BACT based on unacceptable collateral 

environmental impacts, and are removed from consideration as BACT for GHG emissions from 

the proposed boiler. 

Good Boiler Design, Good Combustion Practices, Efficient Operation

For the proposed biomass-fired cogeneration unit, utilizing good boiler design, and then 

operating the boiler efficiently and with good combustion practices are the control alternatives 

that SPI proposes as BACT for the project. As stated previously, these options are considered 

the baseline for the BACT analysis, and all other options were considered to be applied over 

and above these options. Each of these options have a positive energy and environmental, and 

most likely economic, impact, and are considered to be BACT for GHG emissions from the 

proposed boiler. 
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7 Step 5 – Selection of BACT 

Based on the analysis presented here, SPI proposes that BACT for GHGs from biomass-fired 

boilers is the exclusive use of biomass fuel (aside from natural gas use during startup and for 

flame stabilization), good boiler design, proper combustion practices, and efficient operation. 

For the cogeneration unit, SPI proposes an annual GHG BACT limit of 433,000 tpy CO2e, or 

0.36 lb CO2e per lb steam (900 °F, 1,250 psig), on a 12-month block average basis. 

For comparison, Table 7-1 summarizes the GHG BACT limits in the permits of the facilities 

listed in Table 2-3. 

Table 7-1. Summary of GHG BACT Limits for Biomass-Fired Boilers in RBLC 

Facility 

GHG 

Limit GHG Limit Units 

GHG Limit 

Averaging Period 

North Springfield Sustainable 

Energy Project 

15,5641 Btu/kWh (gross) 12-month rolling average 

Beaver Wood Energy Fair Haven 

LLC 

2,993 lb CO2e/MWh 30-day rolling avg 

WE Energies – Rothschild 2,6752 lb CO2e/MWh (net) 12-month rolling average 

Abengoa Bioenergy Biomass of 

Kansas LLC 

3,050 lb CO2e/MWh (gross) 12-month rolling average 

Montville Power LLC 0.34 lb CO2e/lb steam 

produced 

30-day rolling avg 

1 Annual limit of 590,109 CO2e/yr. Includes biomass, natural gas, and diesel fuel combustion, as well as SF6 from 

switchgear. Roughly equivalent to 3,208 lb CO2e/MWh (net). 

2 Phased in: first two years of operation, limits is 2,668 lb CO2e/MWh (net electrical output) 
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8 Reciprocating Internal Combustion Engines 

The proposed facility design includes a natural gas-fired emergency boiler feedwater pump, that 

would be used if the cogeneration unit had to be shut down when power from the grid was 

unavailable. Planned operation for this piece of emergency equipment will be restricted to 

testing and maintenance (i.e., a maximum of 100 hours per year). 

8.1 Step 1 – Identify Available Control Alternatives 

The first step of a top-down BACT analysis is to identify all available pollutant reduction options. 

Options typically fall into three categories: inherently low-emitting processes, clean fuels, and 

add-on control technologies. 

The purpose of the emergency boiler feedwater pump is to provide a quickly deployable source 

of power that will be available when electrical power from grid is not available to operate the 

electric motors that power the feedwater pumps that would be relied upon to circulate water 

through the boiler during a normal shutdown process. Natural gas is considered the fossil fuel 

that generates the least GHG emissions per unit of energy produced. The only real alternative 

to a natural gas-fired pump is a diesel-fired pump, and diesel fuel is less desirable from a GHG 

emission perspective. For this reason, no alternative processes or fuels are considered for this 

analysis. However, within the category of reliable natural gas-fired engines that provide 

sufficient power for the assigned task, use of the most efficient model available will result in the 

least GHG emissions. 

GHG-reducing add-on technology exists (e.g., carbon capture and storage), and has been 

discussed at length elsewhere in this document. Because the pump must be available quickly 

and reliably, an add-on control that complicates operation and potentially reduces engine 

readiness, compromises the emergency role of the engine, and is therefore unacceptable for 

consideration as GHG-reducing technology for the proposed emergency natural gas-fired 

engine. 

8.2 Step 2 – Eliminate Technically Infeasible Alternatives 

In the second step of a top-down BACT analysis, the available pollutant reduction options listed 

in Step 1 are considered, and, if found to be technically infeasible for the specific emission unit 

under review, eliminated. 

Use of the most efficient commercially available natural-gas fired engine that is capable of 

reliably operating an appropriate boiler feedwater pump in a timely manner is a technically 

feasible means of limiting GHG emissions from the emergency natural gas-fired engines. 

8.3 Step 3 – Rank Technically Feasible Alternatives 

In Step 3, the remaining alternatives that have not been removed from consideration due to 

technical infeasibility, are ranked, starting with the most effective. 

The only alternative considered is the use of the most efficient commercially available, natural 

gas-fired engine that does not compromise the availability and rapid deployment of the boiler 

feedwater pump for emergency duty. 
 34 29-23586A 

8.4 Step 4 – Evaluate Economic, Energy, and Environmental Impacts 

Because only one alternative is considered, there is no opportunity to compare and contrast the 

collateral impacts of competing technologies. 

8.5 Step 5 – Selection of BACT 

Based on the analysis presented here, SPI proposes that BACT for GHGs from the natural gasfired engine used to power the emergency boiler feedwater pump is the use of the most efficient 

commercially-available engine capable of providing reliable and timely operation to fulfill the 

assigned emergency role.