U.S. Environmental Protection Agency, Region 9 

April 2014 

Responses to Public Comments on the Proposed 

Prevention of Significant Deterioration Permit Major Modification 

for Sierra Pacific Industries - Anderson Division 
TABLE OF CONTENTS

1. INTRODUCTION ..................................................................................................... 1

2. BIOMASS & GHG BACT COMMENTS............................................................... 5

3. CRITERIA POLLUTANT BACT COMMENTS ................................................ 23

4. AIR QUALITY ANALYSIS COMMENTS.......................................................... 29

5. PSD PERMIT COMMENTS ................................................................................. 32

6. GHG AAQIR COMMENTS .................................................................................. 39

7. PROCEDURAL COMMENTS .............................................................................. 41

8. COMPLIANCE COMMENTS .............................................................................. 47

9. OTHER AIR QUALITY-RELATED COMMENTS ........................................... 52

10. OTHER GENERAL COMMENTS ....................................................................... 59
1. INTRODUCTION

Sierra Pacific Industries-Anderson Division (SPI or SPI-Anderson) is an existing lumber 

manufacturing facility located in Anderson, Shasta County, California. The facility is located 

within the jurisdiction of the Shasta County Air Quality Management District (Shasta County 

AQMD or District). The site currently contains a wood-fired boiler with associated air pollution 

control equipment and conveyance systems that produces steam to dry lumber in existing kilns 

and generates up to 4 megawatts of electricity for on-site power needs. Construction of the 

existing equipment was authorized by a Prevention of Signification Deterioration (PSD) permit 

issued by the Shasta County AQMD on June 15, 1995. See online docket # V.10, SPI PSD 

Permit Issued by SCAQMD 15JUN1995. 

On March 3, 2003, the United States Environmental Protection Agency, Region 9 (EPA or EPA 

Region 9) withdrew the PSD delegation from several permitting authorities in Region 9, 

including SCAMQD, making EPA the PSD permitting authority for Shasta County. See 68 FR 

19371. However, the PSD permit issued by the District (Permit No. 94-PO-18) for the existing 

equipment at the SPI-Anderson facility is still in effect. 

In March 2010, SPI submitted a PSD application to EPA for an approval to construct and operate 

a new cogeneration unit and ancillary equipment at its Anderson facility. This change to the 

facility is a PSD major modification under the Clean Air Act and EPA’s PSD regulations at 40 

CFR 52.21. See online docket #III.02, SPI-Anderson Ambient Air Quality Impact 

Report_12SEP12 at pp. 8-9. On October 4, 2010, EPA determined that SPI’s PSD application 

was administratively complete. 

On September 13, 2012, EPA Region 9 proposed to issue a PSD permit modification (2012 

Proposed Permit) for the new cogeneration unit and ancillary equipment for nitrogen oxides 

(NOx), carbon monoxide (CO), particulate matter (PM), PM less than 10 microns in diameter 

(PM10), and PM less than 2.5 microns in diameter (PM2.5). We accepted comments for the 2012 

Proposed Permit from September 13, 2012 through October 17, 2012. On February 19, 2013, 

after consideration of the public comments received, EPA Region 9 issued a PSD permit 

modification and explained that it would be effective in 30 days unless our action was appealed 

to the EPA’s Environmental Appeals Board (EAB) (2013 Permit). Within that 30 day time 

frame, various parties filed appeals with the EAB, which suspended the permit’s effective date. 

On July 18, 2013, the EAB remanded the 2013 Permit to EPA Region 9 because it determined 

that our decision not to hold a public hearing prior to issuing the permit was contrary to 

applicable regulations. The EAB directed EPA Region 9 to reopen the permit proceedings to 

hold a public hearing, issue a final permit decision and respond to any new comments received 

during the hearing. (See In re Sierra Pacific Industries, PSD Appeal Nos. 13-01 to 13-04, slip 

op. at 67 (EAB July 18, 2013)). 

On July 12, 2013, the Court of Appeals for the Circuit for the District of Columbia issued a 

decision that will, upon the date it becomes final and effective, invalidate EPA’s regulation 

deferring from the PSD requirements the carbon dioxide emissions resulting from the 

combustion of certain biological materials, including materials such as wood, wood waste, forest 

residue, and agricultural material. See Ctr. for Biological Diversity v. EPA, 722 F.3d 401 (D.C. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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Cir. 2013). As of this document, the D.C. Circuit’s decision is not yet final and effective and 

could be subject to additional legal proceedings. To facilitate EPA’s ability to proceed on this 

permit application in the interim, SPI submitted material regarding greenhouse gas (GHG) (i.e., 

CO2, methane, and nitrogen oxide) emissions from the proposed new equipment and requested 

that EPA review such materials and include GHG emission limits and related requirements 

Following the EAB’s remand and the D.C. Circuit’s decision, EPA Region 9 revised the 2013 

Permit to incorporate GHG emission limits and related requirements. We also revised certain 

other conditions (primarily related to monitoring, performance testing, and recordkeeping) in the 

2013 Permit to address minor technical issues we identified since February 2013. On November 

8, 2013, EPA Region 9 proposed to issue the revised Proposed Permit (Revised Proposed 

Permit), which included GHG requirements and minor technical changes to other permit 

conditions, and announced a public information meeting and public hearing. On 

November 9, 2013, EPA received a request to extend the public comment period. On November 

22, 2013, EPA granted the request for the extension, and notified the public of the new deadline 

of January 10, 2014 for submittal of public comments. 

EPA announced the public comment period through public notices published in the Record 

Searchlight and on Region 9’s website on November 8, 2013 and November 22, 2013. On both 

these dates, EPA also distributed the public notice to parties in accordance with 40 CFR Part 

124, including notices sent by electronic mail (e-mail) and United States postal mail. Parties 

notified by EPA included (1) agencies, organizations, and public members for whom contact 

information was obtained through a number of different methods, including requests made 

directly to EPA Region 9 through our website (or through other means) from parties seeking 

notification regarding permit actions in California and within the District (i.e., within Shasta 

County); and (2) other parties known to EPA that may have an interest in this action. EPA 

provided notice to numerous government agencies in accordance with 40 CFR Part 124, 

including, but not limited to, the California Energy Commission (CEC), the District and other 

local neighboring air districts, and Indian tribes in the area. Our e-mail list consisted of more 

than 400 individuals, and our postal mailing list consisted of more than 700 individuals who are 

local residents, members of organizations or government agencies. 

The administrative record for the Revised Proposed Permit was made available for public 

inspection at EPA Region 9’s Office in San Francisco, California. Additionally, we made the 

Revised Proposed Permit, Supplemental Fact Sheet/Ambient Air Quality Impact Report for 

Greenhouse Gas Emissions, dated November 2013 (GHG AAQIR), and Fact Sheet/Ambient Air 

Quality Impact Report dated September 2012 (2012 AAQIR), and certain other supporting 

documents available on Region 9’s website. 1 These documents were also available for public 

inspection at the Shasta County AQMD and the following local public libraries within Shasta 

County: (1) Anderson Public Library in Anderson, California; (2) Redding Public Library in 

Redding, California; and (3) Shasta Lake Gateway Library in Shasta Lake, California. 

 

1

 See EPA Region 9’s Air Permit website at http://www.epa.gov/region9/air/permit/r9-permits-issued.html, and the 

electronic docket for the SPI-Anderson PSD permit modification at http://www.regulations.gov (docket number 

EPA-R09-OAR-2012-0634). 
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On December 10, 2013, EPA held a public information meeting at the City of Anderson 

Community Center in Anderson, California to provide the opportunity for the public to speak 

directly to EPA permitting and technical staff regarding the project. EPA staff displayed postersized maps, diagrams and informational materials especially prepared for the public meeting, and 

had hand-out materials available to anyone interested. EPA staff also answered questions from 

the public regarding the proposed permit and the impacts of the proposed project on air quality. 

Following the public meeting, the EPA held the public hearing to receive oral and written 

comments. The public hearing was attended by approximately 40 members of the public. 

During the public comment period, which commenced on November 8, 2013 and ended 

January 10, 2014, EPA received the following comments: 

 Written comments from 10 members of the public and SPI submitted by e-mail or postal 

mail; 

 Oral comments made by 15 members of the public and SPI at the public hearing held on 

December 10, 2013; and 

 Written comments submitted by 4 members of the public provided during the public 

information meeting and public hearing held on December 10, 2013. 

EPA received one public comment after the close of the comment period. EPA’s response to the 

written and oral comments is contained in this document. We have summarized the comment 

letters and oral testimonies. In some cases, we used the original comment given by the 

commenter. 

EPA made the following changes to the proposed PSD permit issued for public comment in 

November 2013. These changes are indicated in strikethough/redline version of the final PSD 

permit in the Administrative Record (See docket #VI.10, SPI-Anderson PSD Permit SAC 12-

01_Strikethru 25APR2014). 

 Permit Condition X.G.1 (Fuel Restrictions) – (1) Added the following to the list of biomass 

fuels allowed for combustion in the biomass boiler: (i) Mill residues including hog fuel, 

shavings, sawdust, trimmings, and bark; and (ii) Forest residues including treetops, nonmerchantable sections of the stem, branches, and bark, left on the ground after logging or 

accumulating as a result of a storm, fire, delimbing, or other similar disturbance; and (2) 

Replaced “wood and wood wastes” with “Non-merchantable forest biomass consisting of 

byproducts and residuals of forest management activities.” 

 Permit Condition X.H.7 (Monitoring Conditions) – Removed redundant permit language 

regarding submittal of a CEMS performance test protocol to EPA, and replaced it with a 

reference to Permit Condition X.I.2.d. 
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 Permit Condition X.I.2.c (Performance Tests) – Clarified that annual performance tests of 

PM10, CO, CO2, and NOx, shall be conducted at no less than 90% of the facility’s maximum 

steam production rate of 250,000 lb/hr.  

 Permit Condition X.J.2 (Recordkeeping and Reporting) – Added calculation procedures for 

restriction that the biomass boiler shall not exceed 468 MMBtu/hr on a monthly basis 

 Permit Condition X.J.3 and 4 (Recordkeeping and Reporting) – Clarified that the Permittee 

shall calculate and record the 12-month rolling sum of CO, NOx, PM, PM10, and PM2.5

emissions in tpy by the last day of the month, rather than the 30th day of the month. 

 Permit Condition X.J.4 (Recordkeeping and Reporting) – Added GHG emission factors for 

CH4 and N2O, and global warming potentials (GWPs) for CO2, CH4, N2O, and SF6 based on 

revisions to the GHG Reporting Rule in 40 CFR Part 98 that became effective on January 1, 

2014. 

 EPA made a number of administrative wording changes to the “Equipment List” and 

“Abbreviations and Acronyms” sections, and permit conditions X.H.11 (Monitoring 

Conditions); X.I.1, 3, and 4 (Performance Tests); X.J.12 (Recordkeeping and Reporting). 

 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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2. BIOMASS & GHG BACT COMMENTS 

2.1 Comment: The Center for Biological Diversity (CBD) stated that although SPI 

characterizes its analysis as voluntary, it is in fact required by the CAA. CBD stated that 

although the D.C. Circuit Court of Appeal has stayed issuance of the mandate vacating 

the PSD deferral, the decision is in all other respects final, and that EPA must apply the 

law as it exists at the time of permit issuance, and the law is that EPA must require 

BACT for all pollutants “subject to regulation.” 

Response: It appears from the context of these statements that CBD did not intend them 

to be comments on the process or substance of EPA’s proposed permit, but rather to 

make a legal argument in response to statements made by SPI. The commenter does not 

state that SPI’s characterization of its GHG analysis as voluntary is manifested in the 

proposed permit or in EPA’s record supporting it. Therefore, EPA is responding only 

that we made our determinations for GHG BACT issues without regard to whether the 

process was voluntary or mandatory, and we note that the proposed and final permits 

impose the GHG related permit conditions as mandatory requirements in the same way 

and to the same extent as the other permit conditions. 

2.2 Comment: CBD commented that the GHG BACT determination is inconsistent with 

CAA requirements because the AAQIR fails to explain why biomass combustion was 

identified as a control measure at Step 1 of the BACT analysis. Citing EPA’s Draft New 

Source Review Manual (October 1990), CBD stated that the purpose of Step 1 of the 

BACT analysis is to identify control measures such as “inherently lower-emitting 

processes/practices,” add-on controls, and combinations thereof and that identifying 

combustion of a primary fuel as a “control measure” for emissions caused by combustion 

of that same fuel is fundamentally illogical because it cannot be “inherently lower 

emitting” than itself. According to the commenter, “there is no basis in science, law, or 

logic for concluding that combustion of biomass is ‘inherently lower-emitting’ than 

combustion of biomass.” In a footnote, CBD stated that the AAQIR does not mention and 

therefore can find no support in an EPA guidance document, specifically, “Guidance for 

Determining Best Available Control Technology for Reducing Carbon Dioxide 

Emissions from Bioenergy Production,” March 2011 (Bioenergy BACT Guidance). 

Response: The function of Step 1 of any BACT analysis is to “[i]dentify all available 

control options with practical potential for application to the specific unit for the 

regulated pollutant under evaluation.” See GHG AAQIR at 17; EPA, “PSD and Title V 

Permitting Guidance for Greenhouse Gases” (March 2011) (PSD and Title V GHG 

Guidance) at 24. As EPA has explained “[t]he purpose of Step 1 of the process is to cast 

a wide net and identify all control options with potential application to the emissions unit 

under review that should be subject to scrutiny under later steps of the process.” 

In Step 1 of the BACT analysis in the GHG AAQIR, EPA identified the following 

options as available technologies to control CO2 emissions: (i) utilization of biomass fuel 
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alone, (ii) carbon capture and sequestration (CCS), (iii) good boiler design, (iv) good 

combustion practices, (v) efficient operation, and (vi) boiler design alternatives (i.e., 

stoker and fluidized bed). See GHG AAQIR at 19. Therefore, EPA identified 

“utilization of biomass fuel alone” as one of several GHG control alternatives at Step 1 of 

our BACT analysis for the SPI PSD Permit. 

Furthermore, the identification of biomass combustion as a control measure at Step 1 at 

this facility is consistent with EPA’s Bioenergy BACT Guidance, which lists this option 

as the first among three categories of options that a permitting authority may choose to 

focus on. Although the Bioenergy BACT Guidance is not cited in the GHG AAQIR, 

EPA relied in part on this guidance and included it in the docket for our proposed action. 

The Bioenergy BACT Guidance recommends that the Step 1 analysis address the extent 

to which the BACT analysis for GHGs should include a comparative evaluation of 

biomass fuels and other fuels types such as fossil fuels. Bioenergy BACT Guidance at 

15. Where a permit applicant can demonstrate that utilizing biomass fuel is fundamental 

to the primary purpose of the project, the permitting authority need not list and undertake 

a comparative evaluation of other fuel types. Id. 

The SPI Anderson facility is a lumber mill that generates a significant amount of sawdust 

and other mill residuals. SPI also operates other lumber mills in the area that generate 

mill residuals and owns and manages forests supplying the mills. The permit application 

states that the proposed project would be located near SPI’s lumber manufacturing 

facility. SPI PSD Permit Application, March 2010 at 3-4. SPI’s application also states 

that the Anderson facility currently generates more wood waste than the existing 

cogeneration unit can consume. Id. Thus, as defined by the permit applicant, the use of 

biomass fuel is a design element of the proposed facility that is inherent to the applicant’s 

purpose for building the cogeneration facility.2

 Since utilizing biomass fuel is 

fundamental to the primary purpose of SPI’s project, EPA identified the use of biomass 

fuel as a Step 1 option in the GHG AAQIR. EPA’s purpose was to inform the public that 

we were not considering other fuel types to be potential control options for this facility 

and that biomass fuel was the only fuel option that would be subject to further 

examination in subsequent steps of the top-down process. 

EPA’s GHG AAQIR did not characterize biomass combustion as “inherently loweremitting.” Our GHG AAQIR identified three categories of GHG control alternatives for 

all GHG pollutants: (i) add-on control options; (ii) inherently lower-emitting control 

options; and (iii) other control options. For CO2, under the category of “add-on control 

options,” we identified CCS; under the category of “inherently lower-emitting control 

options,” we identified “good boiler design, good combustion practices, and efficient 

operation;” under the category of “other control options,” we identified “utilization of 

biomass fuel alone” and “boiler design alternatives.” GHG AAQIR at 19, Table 5-2. 

 

2

 The commenter does not appear to question this judgment, as there is no request in the comment that EPA 

consider other fuel types besides biomass in the BACT analysis for this facility. 
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Therefore, as shown by the record, EPA did not categorize combustion of biomass as an 

“inherently lower-emitting control option.” 

EPA is in the process of evaluating the extent to which biomass can be considered 

“inherently-lower emitting” with respect to its emission GHGs. As discussed in the 

Bioenergy BACT Guidance, this assessment is not as straightforward as it has 

traditionally been for other fuels and pollutants because of the role of offsite 

sequestration of CO2 in biogenic material. See Bioenergy BACT Guidance at 20-21. 

EPA believes this unique attribute of biomass fuel is best considered in the context of 

Step 4 of the BACT analysis. Thus, listing the combustion of biomass fuel alone as an 

option in Step 1 of the BACT analysis enables it to be subject to further scrutiny at 

subsequent steps of the BACT analysis. 

In this context, EPA disagrees with the commenter’s view that the Agency should not list 

an option for consideration at Step 1 of the BACT analysis based on an initial judgment 

that is it not “inherently lower emitting” or in fact “control.” This approach would 

prejudge the outcome of subsequent steps of the BACT analysis. Rather than eliminating 

the option of utilizing biomass fuel alone at Step 1, a thorough BACT analysis should 

include the option and examine how the direct emissions from biomass combustion alone 

would rank in relation to other control techniques under consideration. Even if the 

combustion of biomass alone ranks below other options under consideration based on 

direct stack emissions, it is still beneficial to examine the extent to which biomass fuel 

has other environmental benefits or adverse impacts. EPA believes it is appropriate for a 

Step 4 environmental impacts analysis to examine the environmental benefits and adverse 

impacts of all technologies remaining under consideration at this step. This analysis need 

not be limited to only the top or most effective technology. See Bioenergy BACT 

Guidance at 17-18. 

2.3 Comment: CBD stated that the record actually confirms that biomass combustion does 

nothing to “control” the facility’s emissions because, according to CBD, the emissions 

limit in the Revised Proposed Permit (0.36 lb CO2e/lb steam produced or 433,620 tpy) is 

actually higher than the uncontrolled emissions estimate in SPI’s GHG BACT analysis 

(433,000 tpy). 

Response: As discussed above, EPA did not list biomass combustion at Step 1 of the 

BACT analysis on the grounds that it was inherently lower emitting. The option still 

warrants evaluation at subsequent steps of the BACT analysis even if it does not 

necessarily “control” or reduce stack emission in the manner desired by the commenter. 

Furthermore, the comment does not correctly describe the emissions limit in the permit. 

Permit Condition X.A.1. of the Revised Proposed Permit (and the Final Permit) contains 

the following emission limit for CO2e: 

CO2e emissions from U1 [Unit 1, the new stoker boiler authorized by the permit] 

shall not exceed 0.36 CO2e lb steam produced (12-month annual rolling average 
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basis). This CO2e limit shall apply at all times, including during startup and 

shutdown periods. 

The commenter’s reference to an annual limit of 433,620 tpy does not appear in the 

Revised Proposed Permit (or in the Final Permit) or in EPA’s GHG AAQIR. This figure 

appears to be based on the commenter’s conversion of the lb CO2e / lb steam produced 

emission limit that is in the permit into a tons per unit basis. However, the commenter 

did not provide its calculations or any other basis upon which EPA might further evaluate 

this conversion or any discrepancy as alleged by the commenter. 

2.4 Comment: CBD commented that the record confirms that biomass combustion does 

nothing to control emissions because the AAQIR, at Step 3 of the BACT analysis, 

identifies biomass combustion (in combination with other measures such as good boiler 

design and efficient combustion practices) as “the baseline from which all other 

alternatives will be evaluated.” [citing AAQIR at 26.] According to CBD, EPA’s 

proposed control measures are simply a description of the proposed facility design, 

meaning that their implementation as BACT will result in zero actual emissions 

reductions. 

Response: As discussed above, biomass fuel was appropriately listed at Step 1 of the 

BACT analysis because it was a fundamental part of the design of the facility and the 

only fuel type subject to further evaluation at subsequent steps of the BACT analysis. 

Step 3 of EPA’s BACT analysis ranked the effectiveness of the various control methods 

applying a baseline comprised of a group of control methods: good boiler design, good 

combustion practices, and efficient operation / proper combustion practices and use of a 

properly designed boiler and utilization of biomass fuel alone. EPA’s BACT analysis 

also included the add-on control option of capturing and sequestering CO2 emissions. 

There is nothing inappropriate with using a lower-ranked option as the baseline against 

which the permitting authority judges other options. This does not demonstrate that the 

lower-ranked option should not be on the list. 

There is also nothing inappropriate with Step 1 of the BACT analysis including an option 

that is “simply a description of the proposed facility design” and then evaluating whether 

the design can be improved or controls can be added to reduce emissions from that 

baseline. The PSD permit review process works best when the applicant incorporates 

techniques for reducing emissions into its proposed design. It is clear that good design, 

combustion, and efficient operation mean that more steam can be produced with less fuel, 

resulting in fewer emissions. The design and efficiency components of our GHG BACT 

determination for the SPI PSD permit are consistent with GHG BACT determinations 

made by several other permitting agencies permitting agencies for biomass boilers. See

id. at 21, Table 7.1-5 (table of recent BACT determinations by various permitting 

agencies, including several identifying “good combustion practices” as BACT). Finally, 

permitting agencies often make BACT determinations for emissions of criteria pollutants, 

such as carbon monoxide, based on good design and efficient operation. In fact, EPA’s 
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CO BACT determination for this project is 0.23 lb/MMBtu (3-hour block average) 

employing good combustion practices. See, 2012 AAQIR (for criteria pollutants) at 18-

19. 

To the extent that the commenter is alleging that EPA’s action is unsupported and 

erroneous because our BACT analysis is based on combustion of biomass alone, the 

commenter is incorrect. The record is clear that our BACT analysis considered 

combustion of biomass as one component of a multi-part approach to controlling GHG 

emissions. GHG AAQIR at 29. 

2.5 Comment: CBD commented that EPA should evaluate different forms of biomass to 

determine if they could be considered “clean fuels” in relation to other biomass 

feedstocks. According to the commenter, EPA must evaluate whether there is a statutory 

basis for considering certain forms of biomass to be “clean fuels” based on life cycle 

GHG emissions (as opposed to comparing fuels based on stack emissions). CBD also 

commented that EPA must determine whether the text and structure of the CAA’s PSD 

provisions allow consideration of relative carbon debt periods in determining whether 

certain fuels are “inherently lower-emitting” for BACT purposes. According to CBD, 

different forms of biomass will produce roughly the same amount of CO2 at the stack; 

therefore, stack emissions offer little or no basis for identifying whether particular forms 

of biomass are “inherently lower-emitting;” however, biomass fuels may differ in their 

lifecycle emissions or carbon-debt period, depending on the feedstock and what would 

happen to it if it were not burned for energy. CBD stated that there are carbon-debt 

differences between whole trees, logging residues and mill waste. For example, regarding 

mill waste, the carbon debt depends on the likely alternative fate of the material. If mill 

waste would be otherwise stored or disposed of in a manner likely to generate methane, 

for example, the carbon debt associated with combustion would be relatively short. CBD 

states that mill waste could also be crafted into durable wood products and the carbon 

debt associated with that alternative use would be longer. 

Response: EPA is in the process of evaluating the effect of CO2 emissions from biogenic 

feedstocks on the carbon cycle. That process can help inform whether EPA may classify 

certain biomass feedstocks as a “clean fuel” or “inherently lower emitting,” as these 

terms have been used historically by EPA and others in the context of a PSD BACT 

analysis. While EPA has reached no conclusion on this point, EPA has previously 

recognized that a PSD BACT analysis at a bioenergy facility can incorporate 

consideration of the net atmospheric contribution of combusting biomass fuels.3

 For 

example, EPA’s Bioenergy BACT Guidance states, “[B]ecause sequestration of CO2

emissions in living plant material outside the boundaries of the facility may counteract 

the emission from such facilities on a continuous basis, this unique dynamic merits 

consideration in the BACT analysis.” Bioenergy BACT Guidance at 8; see also, id. at 

 

3

 The commenter uses the terms “lifecycle GHG emissions” and “carbon-debt period,” which EPA understands to 

describe essentially the same concept that is intended by EPA’s use of the term “net atmospheric contribution” 
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21-24. EPA also observed that “given its traditional focus on ‘collateral’ environmental 

impacts and benefits, Step 4 of the BACT analysis seems well-suited to enable permitting 

authorities to consider the potential sequestration of carbon in biogenic resources outside 

the boundaries of the facility when evaluating BACT for greenhouse gases.” Id. at 21. 

Thus, EPA has suggested in the Biogenergy BACT Guidance that the text and structure 

of CAA’s PSD provisions allow a PSD permitting authority to consider, at Step 4 of the 

BACT analysis, the net atmospheric contribution of using biomass fuels for energy 

production. The challenge, as EPA has noted, is 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.” Bioenergy BACT Guidance at 23. 

EPA interprets the commenter’s request that EPA determine whether it may classify 

certain forms of biomass (particular biomass feedstocks) as “clean fuels” or “inherently 

lower emitting” as, in effect, calling for EPA to identify different biomass feedstocks as 

options at Step 1 of the BACT analysis. The next step that the commenter appears to 

contemplate is that EPA would then rank these different feedstock options at Step 3 of 

the BACT analysis based on the net atmospheric contribution (“lifecycle emission” or 

“carbon debt period” in the commenter’s lexicon) rather than ranking in the traditional 

manner based on direct stack emissions. This is not the approach that EPA recommended 

in the Bioenergy BACT Guidance, and EPA is not prepared to apply the commenter’s 

apparent process in the context of this permit application. As EPA explained in the 

Bioenergy BACT Guidance, “additional detailed examination of science and technical 

issues is needed to ensure that permitting authorities would be able to reasonably 

calculate and implement accounting for the amount of GHG emissions above [a business 

as usual scenario.]” Id. at 23. Considering the “challenge of conducting a complete 

analysis for each permit application,” EPA has observed that “a more practical approach 

to accounting is needed.” Id. 

 

As previously stated, EPA is not currently prepared to classify any particular biomass 

feedstocks as a “clean fuel” or “inherently lower emitting” or to engage in a quantitative 

ranking and comparison of the net atmospheric contribution of such fuels. EPA is 

currently engaged in revising a tool for assessing GHG emissions and biogenic 

feedstocks, the “Accounting Framework for Biogenic CO2 Emissions from Stationary 

Sources,” September 2011 (Accounting Framework). In September 2012, EPA’s Science 

Advisory Board (SAB) concluded a peer review of the Accounting Framework and 

issued an 81-page report. See, SAB Review of EPA’s Accounting Framework for 

Biogenic CO2 Emissions from Stationary Sources, EPA-SAB-12-011, September 28, 

2012 (SAB Comments). Although EPA has begun the process of assessing the carbon 

cycle implications of biogenic feedstocks, this evaluation involves complex policy and 

technical issues that require further consideration before EPA can specify particular 

categories of biomass as “clean fuels” or “inherently lower-emitting” fuels for the 

purposes of a BACT determination. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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Recognizing the complexity of these issues, EPA chose not to prolong its review of this 

permit application by attempting to complete the type of net atmospheric contribution 

assessment described in the Bioenergy Guidance. After identifying biomass as the only 

fuel under consideration in the BACT analysis for this facility in a manner consistent 

with EPA’s Bioenergy BACT Guidance, EPA’s GHG AAQIR followed EPA’s PSD and 

Title V GHG Guidance and focused on energy efficiency and add-on controls for GHG 

emissions as part of the BACT analysis. 

EPA agrees with the commenter that consideration of the carbon cycle is relevant to the 

determination of BACT for a biomass-fired emissions unit and that case-by-case analysis 

that considers the attributes of particular feedstocks is preferable. Since EPA’s 

Accounting Framework is still under development, EPA lacks the tools at this time to 

undertake a quantitative comparison of the net atmospheric contribution of different 

biomass feedstocks that might be utilized at the facility SPI seeks authorization to 

construct. Nevertheless, in response to several points raised by CBD, EPA is revising 

Permit Condition X.G., Fuel Restrictions to clarify that SPI will be limited to particular 

types of biomass fuels, such as mill residues, untreated wood debris from urban areas, 

agricultural crops and residues, forest residues, and non-merchantable forest biomass. 

EPA is clarifying that the option of using biomass fuel alone identified in Step 1 of the 

analysis entails using the specific types of biomass feedstocks reflected in revised Permit 

Condition X.G. We assume it is technically feasible to use all of the specified feedstocks, 

but have not broken each feedstock out into a distinct Step 1 option or attempted to rank 

them at Step 3 for the reasons discussed above. 

This revision is supported by a basic, qualitative evaluation in a Step 4 context of the 

environmental impacts of the specific biomass feedstocks SPI intends use to fire the 

boiler. Based on its current understanding and information, EPA is able to make a rough 

qualitative assessment that the feedstocks SPI seeks to use are unlikely to result in a 

significant increase in atmospheric CO2 loading. The SPI Anderson facility is a lumber 

mill that generates a significant amount of sawdust and other mill residuals. SPI’s permit 

application states that the Anderson mill generates approximately 160,000 bone dry tons 

(BDT) of mill waste annually, and that the new cogeneration unit is expected to burn a 

maximum of 219,000 BDT annually. See SPI PSD Permit Application, March 2010 at 3-

4. SPI also intends to burn mill residues from lumber mills it owns and operates in 

Shasta Lake, approximately 18 miles from Anderson; Red Bluff, approximately 26 miles 

from Anderson; and Arcata, approximately 155 miles from Anderson. See id.; Second 

Recirculated Draft EIR, February 2012, at 2.0-32. In addition to mill waste, SPI seeks to 

feed the boiler with untreated wood waste (e.g., pallets and crates), agricultural residues, 

and forest management residues. See SPI PSD Permit Application, March 2010 at 3-4. 

In the Bioenergy BACT Guidance, EPA observed that it appeared possible to conclude 

that a negligible atmospheric contribution would result from using mill residue in 

bioenergy production. Bioenergy BACT Guidance at 23. The commenter also 

acknowledges that the carbon impacts from burning mill residues are generally viewed as 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

April 2014 

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less significant than the impact of burning trees harvested solely for the purpose of 

biomass fuel. See CBD Comments at 5-7. Although the commenter notes that mill waste 

may be used to create durable wood products, SPI has informed EPA that there is no 

market for its mill waste due to the closure of several former facilities that previously 

manufactured particle board, oriented strand board and pulp and paper.4

 

Based on this assessment, the Final Permit includes a revision to Permit Condition X.G., 

Fuel Restrictions. The revision is intended to clarify that SPI will be limited to the 

following types of biomass fuels: mill residues; untreated wood debris from urban areas 

(e.g., pallets and crates); agricultural crops and residues; forest residues; and nonmerchantable forest biomass. EPA believes that these revisions to Permit Condition X.G. 

will limit the facility to the types of biomass fuels that are generally considered to have 

lower net atmospheric contributions when combusted. In addition, the record reflects that 

SPI’s proposed cogeneration project is not intended to use timber harvested solely for the 

purpose of biomass combustion. See Second Recirculated Draft EIR, February 2012, at 

2.0-20. Nevertheless, in response to the commenter’s concerns, EPA’s revisions to 

Permit Condition X.G. are intended to preclude the use of this type of feedstock.5

 Thus 

our final determination for SPI Anderson facility is that BACT is comprised of three 

components: (i) combustion of specific biomass feedstocks (per the fuel restrictions in 

Permit Condition X.G.); (ii) energy efficient design, operation and maintenance; and (iii) 

operation as a cogeneration unit.6

 

2.6 Comment: CBD commented that EPA must assess whether there are available fuel 

mixes (other than the assumed fuel mix of 75% mill waste and 25% other material) that 

would result in shorter carbon debt periods. According to CBD, requiring the facility to 

use only mill waste rather than forest-sourced material could reduce the carbon debt 

associated with biomass combustion compared to the assumed and permitted fuel mixes, 

depending on what would happen to the mill waste if it were not used as fuel. CBD 

stated that EPA should evaluate a mill waste only alternative under CAA section 

165(a)(2) to determine whether that alternative could reduce air quality and other 

environmental impacts relative to the proposed project. 

 

4

 If there were an existing market for its mills waste, then diverting these wastes to the production of energy would 

have the potential to cause “leakage effects” (i.e., if mill wastes go to a biomass energy facility rather than another 

type of end-user, then the other end-user would need to make up the shortfall, possibly by increasing forest 

harvests). 

5 The assessment of net atmospheric impacts of combustion of roundwood feedstocks is a more a complex exercise, 

and EPA is drawing no conclusions at this time with respect to how the net impact of such feedstocks compares to 

the feedstocks that SPI is authorized to use under the final permit conditions. 

6 Specifically, our BACT determination is: 0.36 pounds of CO2e per pound of steam (12 month rolling average); 

combustion of biomass (as regulated by Condition X.G. “Fuel Restrictions”) at all times except during start up and 

shutdown (during which time the boiler will burn natural gas); and energy efficient design and use of good 

combustion and operational and maintenance practices, including a state of the art stoker boiler, and operation of the 

stoker boiler as a cogeneration unit at the facility. AAQIR at 29. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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Response: As explained above, the assessment of the carbon cycle in connection with 

biogenic feedstocks is a complex evaluation involving a range of policy and technical 

issues. Thus, EPA is not prepared at this time to make the type of bright line 

determinations suggested by the commenter. With the refinements described above, 

Permit Condition X.G. of the Final Permit sets forth the types of biomass fuels that SPI 

will be allowed to burn in the new boiler. These fuels include: mill residues; untreated 

urban wood debris; agricultural crops and residues; forest residues; and non-merchantable 

forest biomass. See Final Permit Condition X.G. EPA has no grounds to require that the 

applicant adhere to a specific fuel use mixture given the complexities associated with 

comparing the net carbon contribution of the fuel types that are permissible under Permit 

Condition X.G. 

2.7 Comment: In a footnote, CBD stated that reliance on the Bioenergy BACT Guidance 

would be unlawful, referencing comments it made on the Bioenergy BACT guidance, 

which CBD attached as Exhibit 1 and incorporated by reference. CBD’s comments on 

the Bioenergy BACT Guidance state that the Act and EPA’s regulations require a caseby-case analysis of BACT and that the Bioenergy BACT Guidance “effectively 

constitutes presumptive BACT” rather than a case-by-case analysis. CBD criticizes the 

guidance for substituting broad policy judgments for the case-by-case analysis required 

by the statute and regulations. Also, CBD’s comments on the Bioenergy BACT 

Guidance criticize EPA’s consideration of net atmospheric contributions at Step 4 of a 

BACT analysis and argue the guidance omits considering other relevant factors in the 

Step 4 environmental impacts analysis. 

Response: CBD’s comments on the Bioenergy BACT Guidance do not appear relevant to 

the SPI Anderson project. For example, EPA’s Bioenergy BACT Guidance simply 

“provides an illustration of reasoning that a permitting authority may use” to support a 

BACT determination. Id. at 1. The document does not “provide a final determination of 

BACT for a particular source, since such a determination can only be made by individual 

permitting authorities on case-by-case record in each case.” Id. at 5. Recognizing this, 

EPA has conducted a case-by-case analysis for the SPI Anderson project. Furthermore, 

the Bioenergy BACT Guidance explains that it is “interim guidance only” and that the 

results of a more “detailed examination of the science and technical issues ... may 

outweigh many of the considerations mentioned in this guidance.” For the reasons 

discussed elsewhere in this document, EPA does yet have the capability to conduct a 

more thorough Step 4 analysis for this facility. 

Moreover, we also point out that our proposed and final BACT determinations do not 

conclude that BACT is combustion of biomass alone. Our final BACT determination for 

the SPI PSD permit is: (i) combustion of specific biomass feedstocks (per the fuel 

restrictions in Permit Condition X.G.); (ii) energy efficient design, operation and 

maintenance; and (iii) operation as a cogeneration unit. Our proposed and final BACT 

limit is: 0.36 pounds of CO2e per pound of steam (12 month rolling average); combustion 

of specific biomass feedstocks at all times except during start up and shutdown (during 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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which time the boiler will burn natural gas); and energy efficient design and use of good 

combustion and operational and maintenance practices, including a state of the art stoker 

boiler, and operation of the stoker boiler as a cogeneration unit at the facility. GHG 

AAQIR at 29. 

Finally, as discussed above, parts of the Bioenergy BACT Guidance reflect the legal 

analysis that the commenter’s request regarding whether the PSD provisions in the Clean 

Air Act afford discretion to examine the net atmospheric contribution of using biomass 

fuels in stationary sources. EPA has concluded in the Biomass BACT Guidance that the 

Act’s instructions that permitting authorities consider “environmental impacts” when 

establishing BACT may be construed to afford discretion to examine the net atmospheric 

contribution of using biomass fuel in the context of a Step 4 of the top-down BACT 

process. 

2.8 Comment: CBD commented that SPI’s GHG cost effectiveness threshold of $7 per ton 

of CO2 is unsubstantiated. CBD stated that SPI does not explain why a comparison of 

CO and CO2 emission factors for external natural gas combustion is an appropriate way 

of scaling the cost effectiveness of CO2 controls at a biomass facility. CBD also stated 

that CO emissions from biomass tend to be considerably higher than those from natural 

gas, and that SPI did not explain why it used CO as a basis for comparison, rather than 

NOx or PM or anything else. 

Response: Our BACT determination for the SPI Anderson project did not set or rely on a 

cost-effectiveness threshold, and did not reference SPI’s $7 per ton of CO2 removed costeffectiveness value. EPA’s evaluation of costs, at Step 4 of the BACT analysis in the 

GHG AAQIR, compared the costs of CCS to the cost of a new cogeneration unit similar 

to that proposed for the SPI Anderson project. In EPA’s cost analysis for CCS, the 

addition of CCS (including both the capture equipment and the pipeline) is expected to 

cost approximately $138,904,547, which would represent a 185% increase in the 

estimated cogeneration project costs of $75,000,000. See GHG AAQIR at 27-28. 

2.9 Comment: CBD also stated that SPI’s GHG cost effectiveness threshold of $7 per ton of 

CO2 is too low. CBD stated that a more relevant comparison would be cost of GHG 

allowance under CA AB32 ($11.48 or $11.10). CBD stated that the EPA has estimated 

the social cost of carbon as ranging from $12 to $116 per ton. CBD stated that SPI’s $7 

per ton cost effectiveness value is below relevant regulatory thresholds and fails to 

internalize even a fraction of the potential social cost of the facility’s emissions. 

Response: As stated above in response to the previous comment, EPA’s BACT analysis 

in the GHG AAQIR did not rely on SPI’s cost effectiveness threshold of $7 per ton of 

CO2 removed. Instead, EPA compared the costs of CCS to the cost of a new 

cogeneration unit similar to that proposed for the SPI Anderson project. See GHG 

AAQIR at 27-28. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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2.10 Comment: CBD commented that EPA must identify, or require SPI to identify, a wellsubstantiated, realistic cost-effectiveness threshold and then evaluate the cost 

effectiveness of alternative biomass fuels with lower life cycle emissions (i.e., shorter 

carbon debt periods) against this threshold and require the facility’s fuel supply to 

comply with the lowest-emitting cost effectiveness mix. 

Response: EPA disagrees with the comment, and we believe our approach of comparing 

the costs of CCS to a new cogeneration unit similar to that proposed for the SPI Anderson 

project is appropriate and consistent with the approach taken in the context of other PSD 

permitting actions, as well as a decision by the Environmental Appeals Board (EAB). 

We note that CBD did not provide a statutory or regulatory basis for its claim that EPA or 

SPI “must” identify a cost-effectiveness threshold. In fact, the CAA’s definition of 

BACT, at section 169(3), requires consideration of “energy, environmental and economic 

impacts and other costs,” but does not mandate any particular type of cost analysis. See

42 U.S.C. 7479(3). The EAB has reviewed a similar issue in the context of an EPA 

Region 9 PSD permit authorizing construction of the Palmdale Hybrid Power Project, a 

570 MW hybrid solar–natural gas power plant. In that case, EPA Region 9 had applied a 

cost comparison approach to evaluate CCS, and similar to Region 9’s consideration of 

CCS for the SPI Anderson project, compared the estimated annualized capital costs for 

the entire project ($35 million) to the estimated annual capital costs for CCS ($78 

million) and eliminated CCS as economically infeasible. In re City of Palmdale, PSD 

Appeal No. 11-07, slip op. (September 17, 2012) (Palmdale). In Palmdale, the EAB 

recognized the that “economic impacts” analysis required by the BACT provisions does 

not mandate the use of the cost-effectiveness approach that permit issuers have typically 

applied based on EPA guidance. Palmdale, slip op. at 54, n.39 (“This general approach 

is based on EPA guidance, see NSR Manual at B.3, and is not mandated by statute or 

regulation, see generally 42 U.S.C. §7479(3) (BACT definition); 40 CFR 

52.21(b)(12)(same).”). The EAB then concluded that the Region’s comparison of costs 

of the entire project to costs of CCS “was neither inappropriate nor inadmissible.” Id. at 

55. 

For these reasons and consistent with the discussion of fuel mixes provided in the 

responses above, EPA also disagrees with CBD’s comment that it must evaluate the 

cost-effectiveness of alternative biomass fuels against a cost-effectiveness threshold and 

restrict fuel use to the lowest-emitting cost-effective mix. 

2.11 Comment: CBD commented that SPI and EPA also failed to evaluate the availability and 

cost-effectiveness of pre-combustion CO2 removal technology in combination with a 

biomass gasification system. CBD stated that SPI rejected gasification on the 

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

did not provide evidence that gasification would not meet SPI’s operational criteria. 

According to CBD, a gasification unit would use the same biomass fuels and the boiler is 

already designed to run on natural gas during startup and shutdown. CBD stated that 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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EPA cannot reject pre-combustion CO2 removal options without first demonstrating that 

gasification would improperly redefine the source. 

Response: EPA agrees with the comment and has revised and supplemented its BACT 

analysis to include pre-combustion CO2 removal and CCS as a control option at Step 1. 

See Supplemental GHG BACT Analysis for Pre-Combustion CCS. Hence, EPA is no 

longer excluding this control option at Step 1 based on a redefining the source rationale. 

EPA’s revised BACT analysis includes pre-combustion CO2 removal and CCS, but, as 

explained in our supplemental analysis, this control option is eliminated at Step 4 based 

on its cost. In particular, we note that the cost of pre-combustion CO2 removal and CCS 

will involve expenditures for transportation and sequestration similar to those associated 

with post-combustion CO2 removal. These aspects of CO2 removal and CCS, whether 

pre-combustion or post-combustion, would require the construction of a CO2 pipeline that 

would exceed 175 miles because the SPI Anderson facility is not located near any 

commercially available geologic storage sites. Therefore, similar to our analysis of postcombustion CO2 removal and CCS, we have determined that the costs of pre-combustion 

CO2 removal and CCS are disproportionately high (e.g., $109 million for the pipeline 

alone) when compared to the costs of the rest of the project (approximately $75 million). 

2.12 Comment: CBD commented that SPI’s BACT analysis and EPA’s AAQIR rejected CCS 

based on excessive costs based in part on assumptions related to construction of a 

pipeline for use in enhanced oil recovery (EOR). CBD stated that EOR is not the only 

possible way to sequester CO2, and that CO2 can also be injected into local geological 

formations under proper conditions. CBD stated that California Department of 

Conservation maps show that the facility is located atop sedimentary basins with historic 

and active gas fields that are potential injection zones for captured CO2.

7

 CBD stated that 

a search performed on the NATCARB GIS viewer for the sedimentary basin within a 10-

mile radius of Anderson, California shows saline formation sequestration capacity 

estimates ranging from 370 million metric tonnes to nearly 5,100 million metric tonnes.8 

CBD also stated that SPI must provide, and EPA must evaluate, information pertaining to 

the technological and economic feasibility of local CO2 storage. 

Response: EPA does not disagree with the commenter’s suggestion that local geological 

formations may provide potential sites for injection of captured CO2. For example, 

EPA’s proposed “New Source Performance Standards for Greenhouse Gas Emissions 

from New Stationary Sources: Electric Generating Units” (NSPS for GHGs from EGUs) 

includes the following statement: “Geologic storage potential for CO2 is widespread and 

available throughout the U.S. and Canada. Estimates based on DOE studies indicate that 

areas of the U.S. with appropriate geology have a storage potential of 2,300 billion to 

more than 20,000 billion metric tons of CO2 in deep saline formations, oil and gas 

 

7

 California Department of Conservation, Oil, Gas & Geothermal Fields in California (2001), available at 

http://energyalmanac.ca.gov/petroleum/documents/MAP_OIL_GAS_GEOTHERMAL.PDF and see online docket # 

IV.49N CBD Public Comments - Ex 14 (MAP_OIL_GAS_GEOTHERMAL)

8 http://www.natcarbviewer.com/ 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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reservoirs and un-mineable coal seams.” 79 FR 1473 (January 8, 2014).9

 However, with 

regard to this permitting action, it does not appear that, at this time, any such potential 

sites have been characterized to ensure safe and secure storage of CO2. Regarding the 

commenter’s reference to the NATCARB GIS Viewer, we note that this tool provides a 

high-level overview of CO2 geologic storage potential and a starting point for further 

investigation, and is not intended to serve as a substitute for site specific assessment and 

testing.10 Thus, availability of potential sequestration sites is just an initial step in a 

complex process to identify actual suitability of such sites for long-term storage.11 As 

EPA’s proposed NSPS for GHG from EGUs also noted, “[E]ach potential geologic 

sequestration site must undergo appropriate site characterization to ensure that the site 

can safely and securely store CO2.” Id. 

 

It should be noted that typical CCS projects are expected to inject CO2 into deep 

underground rock formations that are often a mile or more beneath the surface.12 These 

formations consist of porous rock that would hold the CO2 and are covered by 

impermeable, non-porous layers of rock that trap the CO2.

13 Thus, assessment of 

potential geologic sequestration sites to determine their suitability for long-term storage 

is a complex process involving many technical considerations. Before using a geologic 

formation for CO2 injection and storage for a commercial-scale operation, further 

investigation would first involve finding a suitable site (exploration), then a study of the 

site and subsequent monitoring (site characterization).14 The exploration phase involves 

three stages site screening, site selection, and initial site characterization. The 

exploration phase lays the groundwork to ensure safe storage of CO2 and compliance 

with the Underground Injection Control (UIC) program requirements.15 

 

9

 The California Geological Survey has identified more than 100 geologic storage sites in California that 

“collectively underlie approximately 33 percent of the state.” Background Report for the California Carbon Dioxide 

Capture and Storage Review Panel, California Institute for Energy and Environment, December 31, 2010, at

Appendix F, “Review of Saline Formation Storage Potential in California,” at p. 9-4; available at http://ucciee.org/downloads/Background_Reports_for_CCS.pdf. 10 See ‘About Atlas’ at http://www.natcarbviewer.com/ 11 In fact, assessment of the suitability of potential geologic storage sites is just one part of evaluating the storage 

aspects of CCS (and storage is just one part of CCS, which also involves capture and transport). As the Interagency 

Task Force on Carbon Capture and Storage summarized, “CO2 storage projects are multi-phase operations that 

include: (1) a pre-injection phase of site characterization that involves geologic evaluation of site suitability, 

modeling to predict the extent of the CO2 plume and pressure front, and identification and plugging of artificial 

penetrations that could serve as conduits for fluid movement; (2) an operational phase during which CO2 is injected 

and the injection well is tested, ground water geochemistry is monitored, and the CO2 plume is tracked; and (3) a 

post-injection phase of site monitoring to verify that the project poses no risk to underground sources of drinking 

water (USDWs) and site closure.” Report of the Interagency Task Force on Carbon Capture and Storage, August 

2010, at 38. 

12 See http://www.epa.gov/climatechange/ccs/index.html. 13 Id. 14 See NETL and U.S. DOE’s Best Practices for Site Screening, Site Selection, and Initial Characterization for 

Storage of CO2 in Deep Geologic Formations (2013 Revised Edition) at ES-2. 15 Id.
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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The site characterization phase involves classifying the storage resources as “Appraised 

but Sub-Commercial” and builds on the previous studies to develop a more detailed 

characterization of the subsurface similar to what would be expected of a commercial 

project. The large-scale detailed characterization conducted at a site could include: (1) 

additional drilling and testing of wells to understand the geomechanical and geochemical 

properties of the rocks, as well as testing of stimulation techniques to enhance injectivity; 

(2) additional 2D/3D seismic data should be acquired, processed, and integrated with 

rock property data from existing and new wells drilled; (3) subsurface mapping to further 

understand the subsurface architecture of the injection area, define the areal extent of a 

project site, validate contingent storage resource estimates for future financial 

investments, establish continuity of injection zones and confining zone, and identify 

potential leakage issues that could be created by regional small-scale reservoir faulting or 

juxtaposition of injection or confining zone(s).16 Additionally, DOE best practices 

guidance states that the costs associated with detailed site characterization in this phase 

are expensive and should be conducted only for sites being planned for commercial 

project status.17

One important reason for careful initial site characterization for geologic sequestration of 

CO2 is to ensure that sequestration will not threaten actual or potential underground 

sources of drinking water (USDWs). In 2010, pursuant to its authority to protect USDWs 

in the Safe Drinking Water Act, EPA promulgated regulations regarding the injection of 

CO2 into geologic formations. 75 FR 77229-77282 (December 10, 2010). The new 

regulations, established a new class of well, Class VI, and technical criteria for 

permitting, geologic site characterization, area of review (AoR), well construction, 

operation, integrity testing, monitoring, plugging and post-closure care. 75 FR 77230, 

77235. In the preamble to the final rule, EPA summarized the “unique risks” to 

underground sources of drinking water (USDWs) from CO2 sequestration as: “[l]arge 

CO2 injection volumes, the buoyant and mobile nature of the injectate, the potential 

presence of impurities in the CO2 stream, and its corrosivity in the presence of water . . . 

.” 75 FR 77234. EPA also stated, “Proper siting, well construction, operation and 

monitoring of GS [geologic sequestration] projects are therefore necessary to reduce the 

risk of USDW contamination.” Id. 

Although there may be potential for CO2 storage in local sedimentary basins, EPA is not 

aware of any geological storage sites near the SPI Anderson facility that have actually 

been properly surveyed, characterized and assessed for CO2 sequestration. Nor has EPA 

received any applications for Class VI UIC permits in the vicinity of the SPI Anderson 

facility. Thus, it is reasonable to conclude that there are no commercial entities that are 

presently willing and able to take CO2 from SPI Anderson’s project and inject it in a local 

geologic formation. Moreover, there is no precedent for requiring a lumber mill and 

bioenergy producer like SPI to undertake such a process absent the availability of such a 

 

16 See NETL and U.S. DOE’s Best Practices for Site Screening, Site Selection, and Initial Characterization for 

Storage of CO2 in Deep Geologic Formations (2013 Revised Edition) at 42. 17 Id.
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commercial entity, given the technical complexities of assessing potential formations for 

suitability, constructing wells likely more than one mile deep, as well as proper operation 

and monitoring of a geologic storage site, and the relatively small quantities of CO2

expected from the SPI Anderson project.18 

Finally, it is important to note the economic infeasibility of local CO2 storage for SPI 

Anderson at this time. CCS is a new technology, for which high start-up costs can be 

expected.19 Although EPA’s proposed NSPS for GHGs from EGUs summarized several 

examples of CCS demonstration projects, the costs of those projects were offset in part 

either by (1) an industrial application such as food processing or soda ash production; (2) 

an associated enhanced oil recovery (EOR) operation; or (3) technical and/or financial 

support from the Department of Energy.20 As noted in EPA’s AAQIR for the SPI 

Anderson project, the SPI Anderson facility is located in a small town,21 with little 

associated industry that could purchase its CO2, no EOR operations, and no immediate 

expectation of financial support from DOE. 

Other than asserting that SPI and EPA must assess the technological and economic 

feasibility of local CO2 storage, CBD did not appear to question SPI’s cost estimate for 

the pipeline. We note, however, that it was reasonable to include an assumption in the 

BACT analysis for the SPI Anderson project that CCS would involve a pipeline to a 

location where EOR operations could be located. EPA’s proposed NSPS for GHGs from 

EGUs identified availability of EOR as an opportunity to reduce the costs of CCS. 79 FR 

1478.22 In this case, SPI’s estimate for a 175 mile pipeline was for a “hypothetical” EOR 

operation in Brentwood, California, which is 25 miles west of Stockton, and not for a 

pipeline to an actual EOR operation. Most EOR operations in California are located in 

the southern part of the San Joaquin Valley, even further from Anderson, which is located 

in the northern part of the state. Thus, it is would be reasonable to assume that a CO2

pipeline would be at least 175 miles in length and possibly even longer to reach an EOR 

operation in California, in which case the costs associated with CCS for this project 

 

18 The SPI Anderson project is expected to emit approximately 400,000 tpy of CO2; a single 550 MW coal-fired 

power plant would emit approximately 5,000,000 metric tons of CO2 per year. Report of the Interagency Task Force 

on Carbon Capture and Storage, August 2010, at 28. 

19 See EPA’s proposed NSPS for GHGs from EGUs, describing CCS as an “emerging technology” that involves 

“unique cost premiums associated with FOAK [first-of-a- kind] plants that must demonstrate emerging technologies 

and iteratively improve upon initial plant designs.” 79 FR 1476. 

20 For example, see Carbon Capture and Sequestration: Research, Development, and Demonstration at the U. S. 

Department of Energy (February 10, 2014); 79 FR 1475. 21 According to the 2010 Census, the population of Anderson was 9,932 persons. 

http://quickfacts.census.gov/qfd/states/06/0602042.html 

22 See also 79 FR 1482: “EPA expects that for the immediate future, captured CO2 from affected units will be 

injected underground for geologic sequestration at sites where EOR is occurring. Underground injection is currently 

the only technology available that can accommodate the large quantities of CO2 captured at EGUs, and EOR 

provides an associated economic incentive and benefit.” 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

April 2014 

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would be even higher than those estimated. We note further that a recent survey of CO2

pipelines in the United States showed that there are no CO2 pipelines in California.23

2.13 Comment: One individual expressed the following concern: I am concerned on the 

BACT determinations specific for greenhouse gas emissions, and the examples in the 

AAQIR relate to five other facilities. Each one of these facilities, three of them, are 

within the past year. The other two are within the past two years. Being an engineer 

myself, I am concerned about having a hard greenhouse gas emission limit for a project 

where there really isn't a history of making sure the greenhouse gas emission limits even 

work. I would suggest that instead of a hard limit, that this becomes something else for 

the first year or three years to really watch and see what happens. What I mean by that is 

right now having a hard limit with the facility when there’s so much other open burning 

and areas of pollution in this region seems to discourage having good combustion. It 

seems like we're trying to encourage open burning because a guy can get a permit over 

the counter. (David Brown)

Response: In EPA’s GHG BACT analysis for the SPI-Anderson facility, EPA considered 

recent GHG BACT determinations made at similar facilities according to the 

RACT/BACT/LAER Clearinghouse (RBLC), as well as other permit determinations not 

included in the RBLC. (See Table 5-8 of GHG AAQIR at 27.) Based on our review of 

the available control methods for GHG emissions from biomass-fired boilers and other 

pertinent information used to evaluate the feasibility of these methods, we have 

concluded that BACT for the proposed biomass-fired stoker boiler is 0.36 pounds of 

CO2e per pound of steam (12-month rolling average basis), (2) combustion of biomass at 

all times except during periods of startup, shutdown and flame stabilization (in which 

natural gas fuel is allowed to be combusted), and (3) energy efficient design and use of 

good combustion and operational and maintenance practices as described in SPI’s permit 

application and subsequent submissions to the EPA, which include, but are not limited to, 

(i) construction and operation of an efficient, state-of-the-art, air-cooled, reciprocating 

stepgrate stoker boiler that ensures good combustion; (ii) operation of the boiler as a 

cogeneration unit at the Facility; and (iii) operation and maintenance of the boiler in 

accordance with the manufacturer’s recommendations. We presume the commenter is 

referring to the proposed GHG BACT limit of 0.36 pounds of CO2e per pound of steam 

(12-month rolling average basis). This limit is consistent with other GHG BACT 

determinations made at similar facilities. Additionally, the limit was proposed by the 

SPI-Anderson facility, and the applicant has not proposed alternate limits. The comment 

does not include any specific information or facts demonstrating that EPA’s analysis or 

determination was incorrect or flawed. Therefore, the PSD permit and our evaluation for 

this project has not changed. 

 

23 U.S. Department of Energy, “An Assessment of the Commercial Availability of Carbon Dioxide Capture and 

Storage Technologies as of June 2009,” (June 2009) PNNL-18540 at 14, Fig. 2. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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2.14 Comment: One individual provided the following comment: [R]esearch says that a 50 

MW plant produces 650,000 tons of CO2/year. That equals 13,200 per MW. So, 

4MW=52,800 tons/year and 31MW= 409,200 tons/year, or an ~87% increase. Since the 

permit from the Region would allow both plants to operate, combined emissions equal 

462,000 tons per year. Not something to be tacked on after a final permit has been 

issued. (Heidi Strand of Citizens for Clean Air/ Marily Woodhouse of Battle Creek 

Alliance)

Response: The comment discusses GHG emissions from “both plants.” We understand 

the commenter’s reference to “both plants” to mean the proposed new equipment (i.e., 

proposed 31 MW cogeneration unit employing a 468 MMBtu/hr biomass-fired boiler, 

and emergency engine unit), and the existing equipment currently at the facility (i.e., 

existing 4 MW cogeneration unit employing a 116.4 MMBtu/hr biomass-fired biomass 

boiler, and switchgear and associated equipment). The commenter’s reference to 

emissions being “tacked on” is unclear. To the extent the commenter is referring to the 

inclusion of CO2 emissions limits in this permit, we note that EPA’s February 2013 

Permit relied on the Biomass Deferral Rule and did not include BACT determinations or 

include permit conditions regulating GHG emissions. In July 2013, the Court of Appeals 

for the District of Columbia vacated the Deferral Rule. Center for Biological Diversity v. 

EPA, 722 F.23d 401 (D.C. Cir. 2013). Although the D.C. Circuit has not issued the 

mandate in its decision, SPI requested that EPA review materials related to GHG 

emissions from the proposed new equipment and include appropriate emission limits and 

related requirements in the proposed permit modification. EPA’s 2013 AAQIR for the 

Revised Proposed Permit provides additional information regarding the reasons for 

reviewing GHG emissions and including CO2 emission limits in the permit. 

The comment has not provided any specific information or facts demonstrating that 

EPA’s analysis or determination was incorrect or flawed. Thus, EPA has not changed its 

evaluation or the PSD permit as a result of the comment. 

2.15 Comment: One individual provided the following comment: [W]ithout knowing the 

outcome of the legal [proceeding]/decision from the court of appeals, we have no real 

way of knowing exactly what will or will not be allowed. [W]hat is the truth? (Elray 

Kleis)

Response: In July 2013, the Court of Appeals for the District of Columbia vacated the 

Deferral Rule. Center for Biological Diversity v. EPA, 722 F.23d 401 (D.C. Cir. 2013). 

Although the D.C. Circuit has not issued the mandate in its decision, SPI requested that 

EPA review materials related to GHG emissions from the proposed new equipment and 

include appropriate emission limits and related requirements in the proposed permit 

modification. EPA’s AAQIR for the proposed permit provides additional information 

regarding the reasons for reviewing GHG emissions and including CO2 emission limits 

in the permit. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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The comment does not include any specific information or facts demonstrating that 

EPA’s analysis or determination was incorrect or flawed. Therefore, EPA has not 

changed its evaluation or the PSD permit as a result of the comment. 

 
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3. CRITERIA POLLUTANT BACT COMMENTS

3.1 Comment: Include “Post Final Decision Material Not Included in the Administrative 

Record”; include my original comments. Include a copy of EPA’s March 6, 2013 email 

response to Ms. Celeste Draisner. (Celeste Draisner)

Response: The commenter submitted comments on October 17, 2012 during the 

comment period for the 2012 Proposed Permit; however, the commenter submitted these 

comments to an EPA address that was not specified in the public notice for that action. 

Because these comments were not submitted in accordance with EPA’s public notice for 

the 2012 Proposed Permit, they were not addressed in EPA’s responses to public 

comments document that issued with the final permit on February 19, 2013 (2013 RTC), 

and were not included in the administrative record for the 2013 Permit. However, EPA 

addressed these comments in a March 6, 2013 letter that was mailed directly to 

commenter. EPA is including the commenter’s comments submitted on October 17, 

2012, and EPA’s March 6, 2013 responses as part of the administrative record for this 

action, and is also including the comments and EPA’s responses to them below, at 

comments 3.2 through 3.11; 4.1 and 4.2; and 9.1 

3.2 Comment: I am disappointed in EPA Region 9’s decision to not address BACT (Best 

Available Control Technology) seriously. What specific and actual examples of filtering 

technology are being provided by EPA Region 9 in their “fact sheet”? SPI-Anderson Fact 

Sheet AAQIR/ Fact Sheet, available at: http://epa.gov/region9/air/permit/r9-permitsissued.html#pubcomment. (Celeste Draisner)

Response: To the extent of the commenter’s reference to “filtering technology” refers to 

the application of BACT for PM emissions from the project, the 2012 AAQIR and 2013 

RTC contained a detailed BACT analysis for particulate emissions from each emissions 

unit in the project. Pages 19-22 of the 2012 AAQIR discuss BACT for PM, PM10 and 

PM2.5 from the stoker boiler in the Project. Pages 24-26 of the 2012 AAQIR discuss 

BACT for PM, PM10 and PM2.5 from the cooling tower. Pages 51-53 of the 2013 RTC 

discusses BACT for PM, PM10 and PM2.5 from the emergency engine. We concluded that 

BACT for PM emissions from the stoker boiler is 0.02 lb/MMBtu (3-hour block average) 

using a multiclone and ESP during normal operation. This emissions limit is in 

conjunction with a 9.4 lb/hr (3-hour block average) mass emission rate limit during 

normal operations. BACT during periods of startup and shutdown, during which the ESP 

will be required to be in operation, is 8.93 lbs/hr (24-hour average). 

3.3 Comment: Are wet electrostatic precipitators (WESP or wet ESP) being considered for 

use at the proposed Anderson manufacturing facility? A WESP operates with saturated 

air streams (100% relative humidity). WESPs are commonly used to remove liquid 

droplets such as sulfuric acid mist from industrial process gas streams. The WESP is also 
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commonly used where the gases are high in moisture content, contain combustible 

particulate, or have particles that are sticky in nature. (Celeste Draisner)

Response: The 2012 AAQIR discusses BACT for PM, PM10 and PM2.5 from the stoker 

boiler on pages 19-22: “[t]he applicant has proposed a total PM, including filterable and 

condensable particulate, emission limit of 0.02 lb/MMBtu (3-hour block average) 

utilizing an ESP preceded by a multiclone. SPI has proposed the most stringent PM, 

PM10, and PM2.5 emission limit of biomass stoker boilers that have been constructed.” 

2012 AAQIR at 20. We concluded that BACT for PM, PM10 and PM2.5 for the stoker 

boiler to perform this operation is 0.02 lb/MMBtu (3-hour block average) using a 

multiclone and ESP. See 2012 AAQIR at 21. 

Section 169(3) of the Clean Air Act defines BACT as an emission limitation, not a 

control technology. Therefore, our BACT analysis for PM, PM10, PM2.5 does not 

differentiate between wet ESP and ESP. We will note, however, that wet ESPs are not 

typically used for this type of application. As noted by your comment, wet ESPs are used 

in situations for which dry ESPs are not suited, such as when the material to be collected 

is wet, sticky, flammable, explosive, or has a high resistivity. 

3.4 Comment: The preferred and most modern type of WESP is a downflow tubular design. 

This design allows the collected moisture and particulate to form a slurry that helps to 

keep the collection surfaces clean. Will the downflow tubular design be utilized here? 

(Celeste Draisner)

Response: As we explained in our response to comment 3.2 above, SPI proposed the 

most stringent PM, PM10, and PM2.5 emission limit for biomass stoker boilers that have 

been constructed, and EPA concluded that BACT for PM, PM10 and PM2.5 for the stoker 

boiler is 0.02 lb/MMBtu (3-hour block average) using a multiclone and ESP. Section 

169(3) of the Act defines BACT as an emission limitation, not a control technology. 

Therefore, our BACT analyses for PM, PM10, PM2.5 did not differentiate between 

different types of ESP technologies. 

3.5 Comment: Plate style and upflow design WESPs are very unreliable and should not be 

used in applications where particulate is sticky in nature. Are the particulates at the 

proposed Anderson facility of a type that could be effectively filtered out by a plate style 

and unflow design? (Celeste Draisner)

Response: See EPA’s responses to comments 3.3 and 3.4 above. 

3.6 Comment: ESPs continue to be excellent devices for control of many industrial 

particulate emissions, including smoke from electricity-generating utilities (coal and oil 

fired), salt cake collection from black liquor boilers in pulp mills, and catalyst collection 

from fluidized bed catalytic cracker units in oil refineries to name a few. These devices 

treat gas volumes from several hundred thousand ACFM to 2.5 million ACFM (1,180 
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m3/s) in the largest coal-fired boiler applications. For a coal-fired boiler the collection is 

usually performed downstream of the air preheater at about 160°C (320°F) which 

provides optimal resistivity of the coal-ash particles. For some difficult applications with 

low-sulfur fuel hot-end units have been built operating above 371°C (700°F). (Celeste 

Draisner)

Response: EPA appreciates the additional information. We do not interpret this 

comment as requesting a response. 

3.7 Comment: The original parallel plate–weighted wire design has evolved as more 

efficient (and robust) discharge electrode designs were developed, today focusing on 

rigid (pipe-frame) discharge electrodes to which many sharpened spikes are attached 

(barbed wire), maximizing corona production. Transformer-rectifier systems apply 

voltages of 50 – 100 kV at relatively high current densities. Modern controls, such as an 

automation voltage control, minimize electric sparking and prevent arcing (sparks are 

quenched within 1/2 cycle of the TR set), avoiding damage to the components. 

Automatic plate-rapping systems and hopper-evacuation systems remove the collected 

particulate matter while on line, theoretically allowing ESPs to stay in operation for years 

at a time. Which of these BACT methods, procedures and determinations have you, as 

the EPA Region 9 Presiding Officer, considered? (Celeste Draisner)

Response: See EPA’s responses to comments 3.3 and 3.4 above. 

3.8 Comment: Please provide and describe what tests have been conducted to determine 

resistivity under the previous Sierra Pacific permit and how that would apply to this 

“modified PSD permit.” A widely taught concept to calculate the collection efficiency is 

the Deutsch model, which assumes infinite remixing of the particles perpendicular to the 

gas stream. Was the Deutsch model used here, as part of your agency’s BACT analysis? 

(Resistivity can be determined as a function of temperature in accordance with IEEE 

Standard 548. This test is conducted in an air environment containing a specified 

moisture concentration. The test is run as a function of ascending or descending 

temperature or both. Data are acquired using an average ash layer electric field of 4 

kV/cm. Since relatively low applied voltage is used and no sulfuric acid vapor is present 

in the environment, the values obtained indicate the maximum ash resistivity.) (Celeste 

Draisner)

Response: Permit Condition X.I.2.c. of the Final Permit requires annual PM10

performance tests for the new stoker boiler (U1). Permit Condition X.I.1 of the Final 

Permit specifies the EPA test methods required for these tests. These EPA test methods 

along with monitoring, recordkeeping, reporting requirements in the Final Permit will 

ensure compliance with our BACT determination for the new stoker boiler. Resistivity 

may be an indicator of ESP performance; however, the EPA’s permit requires actual 

emissions testing to directly quantify emissions. 
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3.9 Comment: Ideally, BACT considers energy, environmental, and economic impact. How 

specifically are these issues being addressed by EPA Region 9? (Celeste Draisner)

Response: The EPA considered energy, environmental and economic impacts in its 

BACT analyses for each emissions unit included in the Project. See 2012 AAQIR at 15-

16, 18, 21 and 26; see also 2013 RTC at 15, 33, 49 and 51-53 (i.e., EPA’s responses to 

comments 18, 53, and 87, and the Appendix to the 2013 RTC). See also, GHG AAQIR. 

3.10 Comment: BACT can be add-on control equipment or modification of the production 

processes or methods. Were any add-ons to the previous factory, under this permit, 

looked at? Were any add-ons used? (Celeste Draisner)

Response: The Project involves the construction of new equipment at the existing SPIAnderson facility, including a new stoker boiler equipped with a selective non-catalytic 

reduction (SNCR) system to control NOx emissions and a multiclone and ESP to control 

PM emissions. The Project also includes a new cooling tower, and a new emergency 

engine. The PSD requirements for BACT apply to the Project for NOx, CO, PM, PM10, 

and PM2.5. (Table 6-1 of the 2012 AAQIR.) 

The facility’s existing equipment is permitted by the Shasta County AQMD. Our BACT 

analyses for NOx, CO, and PM for the Project considered many recent BACT 

determinations made by different state agencies nationwide. We consider these recent 

BACT determinations to be more relevant to our PSD permit than the permits issued by 

Shasta County Air Quality Management District for the existing equipment. Please refer 

to Tables 7.1-1, 7.1-3 and 7.1-5 of the 2012 AAQIR for comparisons of similar units for 

various pollutants. In addition, please see our response to comments 16 and 54 of the 

2013 RTC document. 

3.11 Comment: BACT includes fuel cleaning or treatment and innovative fuel combustion 

techniques. BACT may also be a design, equipment, work practice, or operational 

standard, if imposition of an emissions standard is infeasible. Were any of the above 

items and conditions considered in your BACT determination? (Celeste Draisner)

Response: The EPA found that emissions standards were feasible. The following is a 

summary of the BACT determinations and emissions standards imposed through the 

Final Permit: 

 For U1 (boiler), emissions limitations for NOx, CO, PM, PM10, PM2.5 are located 

in Sections X.C. and X.D. 

 For U2 (cooling tower), emissions limitations for PM, PM10 are located in Section 

X.E. Also, Permit Condition X.F.14. of the final permit states that the drift rate of 

the cooling tower shall not exceed 0.0005%. The cooling tower is not expected to 

have measurable emissions of CO or NOx. 
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 For U3 (emergency engine), emissions limitations for NOx, CO, PM and PM10 are 

located in Section X.E. 

3.12 Comment: A commenter provided general information on PM and NOx controls. This 

information appears to have come from Chapter 1.6 of EPA’s AP-42 Manual for Wood 

Residue Combustion in Boilers. The commenter stated that EPA should consider BACT 

more carefully. (Celeste Draisner)

Response: The 2012 AAQIR contains our top-down BACT analyses for PM and NOx

emissions. Additionally, our 2013 RTC for the 2013 Permit responded to all comments 

regarding these analyses. The comment has not provided any specific information or 

facts demonstrating that EPA’s analysis or determination was incorrect or flawed. Thus, 

we have not changed our evaluation or the permit as a result of the comment. 

3.13 Comment: [W]hat guarantee do we have that best available control technology is 

sufficient and what does “the greatest extent [feasible]” actually mean? (Elray Kleis)

Response: A BACT analysis is performed on a case-by-case basis, and considers energy, 

environmental, and economic impacts in determining the maximum degree of reduction 

achievable for a proposed new facility or modification at an existing facility. EPA 

Region 9 performed a BACT analysis in accordance 40 CFR 52.21 and EPA’s relevant 

BACT guidance and policies for the proposed modification of the SPI-Anderson facility, 

which consists of a proposed 468 MMBtu/hr biomass-fired boiler, 256 hp (190 kW) 

natural gas-fired emergency engine, and three-cell cooling tower. These BACT analyses 

are contained in the 2012 AAQIR and GHG AAQIR documents. For the proposed 

emission units, each BACT determination specifies an emissions limitation that reflects 

the maximum degree of reduction achievable for each applicable pollutant, or require the 

use of design, alternative equipment, work practices or operational standards to reduce 

emissions to the maximum extent. As required in 40 CFR 52.21 and the Clean Air Act, 

these BACT determinations are at least as stringent as any applicable standard of 

performance under 40 CFR Parts 60 (New Source Performance Standards), or 61 or 63 

(National Emission Standards for Hazardous Air Pollutants). Thus, the control 

technologies and measures determined as a result of the BACT analysis for minimizing 

emissions for the proposed equipment reflect emissions reductions achievable at the 

facility to the greatest extent feasible. 

3.14 Comment: So I think a good enough proposal would be 10-mile radius where they 

compensate the surrounding areas with stoves or wood stoves or whatever it may be. I 

think it’s a lot of pollution and it should maybe be taken down a notch. See if this is the 

best technology available that we can get to bring those ambient air numbers down if 

there's nothing else available. I mean, the technology -- we don’t know what the best 

technology is. I guess that’s kind of the ongoing factor. (Antonio Damian, Jr.)
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Response: The commenter requests that EPA consider requiring SPI to provide stoves or 

wood stoves to areas surrounding the facility within a 10 mile radius as compensation for 

the air pollution increases resulting from the proposed new equipment at the SPIAnderson facility. The Clean Air Act and EPA’s PSD regulations provide authority for 

permitting agencies to impose BACT in PSD permits through a case-by-case analysis. 

The commenter’s proposal for wood stove purchases is not consistent with the concept of 

BACT as set forth in the Act and EPA’s regulations. Pursuant to the Clean Air Act and 

EPA’s PSD regulations, BACT is an emissions limitation (including a visible emission 

standard) based on the maximum degree of reduction for each applicable NSR pollutant 

that would be emitted from any proposed new facility or major modification at an 

existing major facility that EPA determines is achievable taking into account energy, 

environmental, and economic impacts and other costs. (See Section 169(3) of the Clean 

Air Act; 40 CFR 52.21(b)(12).) BACT is applied to the proposed pollutant-emitting 

equipment within a facility that is subject to the PSD permitting program. (See 40 CFR 

52.21(j).) Thus, we have not changed our evaluation or the PSD permit as a result of the 

comment. 

3.15 Comment: I realize that -- I'm hoping that it's being built with the best available control 

technology. I think that is important considering the air basin that we have here. (David 

Craft)

Response: EPA Region 9 performed a BACT analysis in accordance 40 CFR 52.21 and 

EPA’s relevant BACT guidance and policies for the proposed modification of the SPIAnderson facility, which consists of a proposed 468 MMBtu/hr biomass-fired boiler, 256 

hp (190 kW) natural gas-fired emergency engine, and three-cell cooling tower. These 

BACT analyses are contained in the 2012 AAQIR and 2013 AAQIR documents. EPA’s 

BACT determinations, as well as associated monitoring, testing, recordkeeping and 

reporting requirements, are contained in the Final Permit for the project. Thus, SPI is 

required to construct the proposed new equipment in accordance with the terms and 

requirements in the permit. 
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4. AIR QUALITY ANALYSIS COMMENTS

4.1 Comment: PSD increment is the amount of pollution an area is allowed to increase. 

PSD increments prevent the air quality in clean areas from deteriorating to the level set 

by the NAAQS. The NAAQS is a maximum allowable concentration “ceiling.” A PSD 

increment, on the other hand, is the maximum allowable increase in concentration that is 

allowed to occur above a baseline concentration for a pollutant. Please explain how the 

baseline concentration in Shasta County was determined and where our “ceiling” is 

currently at. What efforts, if any, were considered in regards to PSD increments at the 

proposed Anderson facility? (Celeste Drainser)

Response: Please refer to our response to comment 3.1 for additional information 

regarding this comment, which was originally submitted to EPA on October 17, 2012. 

Section 8 of the 2012 AAQIR discusses air quality impacts. Since PSD increment 

consumption calculations reflect only the ambient pollutant concentration change 

attributable to increment-affecting emissions a determination of the baseline 

concentrations in Shasta County was not necessary for the project. The increment 

modeling conducted to determine compliance with the PSD increments for the project 

was conservative because it only considered increment-consuming sources rather than 

including both increment-consuming and increment-expanding sources. Only incrementchanging sources are included when demonstrating compliance with the PSD increments 

since the predicted increment consumption concerns only changes occurring since the 

applicable baseline dates. 

PSD increments have been established for some pollutants, but not all. For the Project, 

only the increments for PM10, PM2.5 and NO2 pollutants (and applicable averaging times) 

apply because there are no established increments for CO. Section 8.4 of the 2012 

AAQIR provides the analysis of Class II increment consumption resulting from the 

Project. As explained in section 8.4.1 of the 2012 AAQIR, EPA expects that emissions 

from the project will exceed “significant emission rates” (SERs) for CO, NO2, PM10 and 

PM2.5; therefore, we conducted additional analyses of how the Project would affect NO2, 

PM10 and PM2.5 PSD increments. In section 8.4.2 of the 2012 AAQIR, we explained that 

we use “significant impact levels” (SILs) to characterize impacts on air quality – 

generally, if modeling indicates that a source’s impacts will be below a SIL for a given 

pollutant, further air quality analysis is usually not necessary. On the other hand, if 

modeling indicates that a source’s impacts will exceed a SIL, EPA requires additional 

modeling that looks at impacts from a project as well as impacts from nearby sources of 

air pollution to determine the impact on PSD increments and the national ambient air 

quality standards (NAAQS). In the case of this project, EPA determined that the project 

could exceed SILs for annual and 1-hour NO2 and 24-hour PM2.5. (See 2012 AAQIR at 

32 and Table 8.4-2.) Section 8.4.3 of the 2012 AAQIR discusses the additional 

modeling, called a cumulative impact analysis, and EPA’s conclusions. 
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For the cumulative analyses, the “ceiling” for the applicable pollutant and averaging time 

are given in the “NAAQS” column of Table 8.4-3. As can be seen for each of the 

pollutants in Table 8.4-3 the “Cumulative Impact w/ Background” column is lower than 

the NAAQS or “ceiling.” Moreover, the “PSD Increment Consumption” column from 

Table 8.4-3 shows that the maximum increment consumed in the Project area for the 

applicable pollutant and averaging time is less than its respective PSD increment. As 

summarized in section 8.4.3.5 and Table 8.4-3, EPA found that emissions from the 

project will not cause or contribute to exceedances of the NAAQS or increments. 

4.2 Comment: The baseline concentration is defined for each pollutant and, in general, is the 

ambient concentration existing at the time that the first complete PSD permit application 

affecting the area is submitted. Significant deterioration is said to occur when the amount 

of new pollution would exceed the applicable PSD increment. It is important to note, 

however, that the air quality cannot deteriorate beyond the concentration allowed by the 

applicable NAAQS, even if not all of the PSD increment is consumed. Will significant 

deterioration be the case here? How were ambient concentrations determined at this 

proposed facility? (Celeste Drainser)

Response: Please refer to our response to comment 3.1 for additional information 

regarding this comment, which was originally submitted to EPA on October 17, 2012. 

Section 8 of the 2012 AAQIR discusses air quality impacts and EPA’s conclusion that the 

project will not cause or contribute to an exceedance of the applicable NAAQS or 

applicable PSD increments. For each of the NAAQS analyses, the applicant assessed 

maximum measured background concentration data from representative monitors in the 

Project area from 2011. These background concentrations and the project’s modeled 

impacts, included with other nearby modeled source impacts when appropriate, were 

compared to the NAAQS to demonstrate that the project will not cause or contribute to an 

exceedance of any applicable NAAQS. 

Section 8.2 of the 2012 AAQIR discusses background ambient air quality. It explains 

that the basis for NO2 background values are ambient air concentrations recorded at a 

monitor located on Manzanita Avenue in Chico, California which EPA determined was 

the closest and most representative NO2 monitor to the site. CO (1-hour and 8-hour) 

background concentrations were also recorded from the monitor located on Manzanita 

Avenue in Chico. Section 8.2 of the 2012 AAQIR also explains that the basis for PM2.5

and PM10 background values are ambient air concentrations recorded at monitors located 

at the Redding Department of Health and Anderson, respectively. Table 8.2-1 of the 

2012 AAQIR shows the maximum background concentrations in the area and the 

corresponding NAAQS. 

EPA’s 2012 RTC document contains additional information regarding our analysis of 

PM2.5 increments and NAAQS. In particular, with respect to PM2.5 (annual) standard, we 

found that adding the project’s predicted PM2.5 (annual) impact (0.27 ug/m3) to the 
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existing background concentration yields a total PM2.5 (annual) concentration of 5.57 

ug/m3

, which is less than [40%] of the PM2.5 (annual) NAAQS. (See 2013 RTC at 3-4.) 

 
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5. PSD PERMIT COMMENTS 

5.1 Comment: In our review of the fuel conditions included in the proposed permit, we do 

not see a requirement that the fuel be “clean cellulosic biomass” as defined in 40 CFR 

241.2. We would request that this condition be included in the proposed permit language 

[as was done in the PSD permit SJ 85-06 issued by EPA Region 9 for the Rio Bravo Poso 

facility in Irvine, California (permit amendment issued May 15, 2012)]. Testing of urban 

wood waste fuel associated with the Oroville POPI facility (attached) has indicated that 

wood fuel associated with urban wood waste contains high levels of metals including 

lead and arsenic exceeding levels found in virgin wood materials. Contaminants 

associated with urban wood waste including plastics and plastics associated with orchard 

waste have resulted in levels of dioxin in fly ash as high as 2600 ppt WHO TEQ. We 

have attached a report of findings prepared for the Butte County District Attorney. (Hal 

Thomas, Special Deputy District Attorney for Yolo, Glenn, and Butte Counties in 

California)

Response: While we understand the commenter’s concerns regarding emissions from the 

combustion of contaminated wood debris, we do not believe that the term “clean 

cellulosic biomass” will add to or enhance the regulatory basis for the PSD permit, and 

therefore we are not adding it to the Final Permit. As noted by the commenter, EPA has 

promulgated a definition of the term “clean cellulosic biomass” pursuant to the Resource 

Conservation and Recovery Act (RCRA) at 40 CFR 241.2. See also “Identification of 

Nonhazardous Secondary Materials That Are Solid Waste,” 76 FR 15456 (March 21, 

2011) (NHSM Rule). EPA’s definition of “clean cellulosic biomass” includes “clean 

construction and demolition wood” and provides that these fuels are not considered 

“secondary materials” or “solid wastes” unless they are discarded. See 40 CFR 241.2. 

EPA’s NHSM Rule explains that combustion of clean cellulosic biomass is regulated 

under section 112 of the Clean Air Act and EPA’s National Emission Standards for 

Hazardous Air Pollutants (NESHAP) regulations at 40 CFR part 63 for major and area 

sources, whereas the combustion of solid waste is regulated pursuant to Section 129 of 

the Clean Air Act and EPA’s New Source Performance Standards (NSPS) regulations at 

40 CFR part 60.24 (76 FR 15545.) Thus, the primary regulatory significance of the term 

“clean cellulosic biomass” is to distinguish this type of fuel from “solid waste.” The 

substantive requirements that would actually regulate combustion of these fuels are found 

 

24 As EPA explained in the NHSM Rule preamble, “The definition of solid waste incineration unit in CAA section 

129(g)(6) states that the term ‘‘solid waste’’ will have the meaning established by the Administrator of EPA under 

RCRA. Today’s rule would establish under RCRA which non- hazardous secondary materials constitute ‘‘solid 

waste’’ when used as a fuel or an ingredient. This definition of ‘‘solid waste’’ is being used by EPA to establish 

CAA emissions standards for CISWI units (under CAA section 129) and boilers and process heaters (under CAA 

section 112). . . . If . . . renewable energy sources or biogenic fuels qualify as clean cellulosic biomass, they are an 

alternative fuel (see the full definition in today’s rule at 40 CFR 241.2) and are not subject to the section 129 AA 

standards, but rather, would be subject to the section 112 CAA standards.” 76 FR 15545. 
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in either EPA’s section 112 rules applicable to boilers at 40 CFR part 63, Subparts 

DDDDD (major sources)25 and JJJJJJ (area sources),26 or EPA’s section 111 rules for 

commercial and institutional solid waste incinerators, 40 CFR part 60, Subparts CCCC 

and DDDD.27 

EPA anticipates that SPI’s new boiler will be subject to the boiler NESHAP for either 

major or area sources. The Final Permit includes Permit Condition X.G., Fuel 

Restrictions, which authorizes SPI to burn untreated wood debris from urban areas (such 

as pallets and crates), in addition to agricultural crops and residues, mill residues, forest 

residues, and non-merchantable forest biomass. The Final Permit’s reference to 

“untreated wood debris” falls within the scope of “clean cellulosic biomass,” as defined 

at 40 CFR 241.2. As a result, SPI’s new boiler would be subject to EPA’s part 63 

regulations promulgated under CAA section 112 as either a major or area source. The 

part 63 regulations, which apply independently of the PSD permit, require an owner or 

operator to keep records of monthly fuel use, including types of fuel and amounts used. 

See 40 CFR 63.7555(d)(1) and 40 CFR 63.11225(c)(2)(iv). If a NHSM is used, the 

owner or operator must keep records demonstrating that the material is not a solid waste 

pursuant to 40 CFR part 241. See 40 CFR 63.7555(d)(2) and 63.11225(c)(2)(ii). EPA’s 

part 63 regulations also require an owner or operator to submit initial notifications and 

periodic compliance certifications signed by a responsible official regarding fuel types 

used and whether solid wastes were combusted. See 40 CFR 63.7545(e)(8)(iii) and 

63.7550(c)(5)(vi); 40 CFR 63.11225(a)(4)(v) and (b)(4). Finally, EPA’s part 63 rules 

require an owner or operator to provide at least 30 days prior notice if the owner or 

operator will start or restart combustion of solid waste. See 40 CFR 63.7545(g); 40 CFR 

63.11225(f). 

5.2 Comment: The proposed permit does not restrict the distribution of fly ash to 

agricultural lands and both Butte and Glenn Counties have been the disposal site for 

biomass ash contaminated with metals above hazardous waste levels. Dioxin 

contaminated fly ash was deposited on agricultural lands in the Chico area at levels 

exceeding the State agricultural soils health standard of 40 ppt. Adequate testing and 

waste characterization of fly ash generated in the Anderson facility must be required to 

protect public health as fly ash from Anderson may be disposed of in our counties. As 

contaminants in urban wood fuel are effectively unregulated by the proposed permit, it is 

important to public health and the quality of North Valley soils that biomass fuel be 

restricted to clean cellulosic biomass and that distribution of fly ash to agricultural soils 

be limited to ash that meets applicable state and federal standards including metals 

 

25 National Emissions Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial and 

Institutional Boilers and Process Heaters, 78 FR 7138 (Jan. 31, 2013); codified at 40 CFR 7480-7560. 26 National Emissions Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial and 

Institutional Boilers, 78 FR 7488 (Feb. 1, 2013); codified at 40 CFR 11193-11226. 27 Commercial and Industrial Solid Waste Incineration Units: Reconsideration and Final Amendments; NonHazardous Secondary Materials That Are Solid Waste, 78 FR 9117 (Feb. 7, 2013); codified at 40 CFR 60.2000-

60.2265 and 40 CFR 60.2500 – 60.2875. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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standards for agricultural soil amendments. (Hal Thomas, Special Deputy District 

Attorney for Yolo, Glenn, and Butte Counties in California) 

Response: Please see our response regarding the Final Permit’s fuel restrictions and 

clean cellulosic biomass in our response to comment 5.1 above. In addition, since the fly 

ash is solid waste, the Final Permit does not directly regulate the distribution and fate of 

fly ash produced from the new biomass boiler. 

5.3 Comment: To ensure the health of residents in Northern California, the Butte 

Environmental Council (BEC) requests that language be included in proposed permit NO. 

SAC 12‐01 to limit feedstock at the Sierra‐Pacific Industries Anderson Facility 

incinerator to clean cellulosic biomass. 

SPI may intend to burn only the timber waste of its own industry. However, the financial 

incentive to accept urban wood waste from other counties is compelling. This is 

particularly true for the Bay Area, which has a “zero‐waste” policy within its own 

borders that does not extend to poorer Northern California counties. BEC has addressed 

the result of this practice at Pacific Oroville Power Industries Covanta facility in Oroville, 

CA. 

High levels of dioxin were found in samples taken from waste ash piles originating from 

the POPI facility. These elevated levels of dioxin were found in the waste ash and in soil 

samples taken within a two‐mile radius of the POPI facility even when fuel stocks were 

found to have as low as 3% contamination of non‐wood materials. 

Biomass facilities are only required to test for criteria pollutants. Although Butte County 

Air Quality Management District (BCAQMD) did monitor POPI’s burn piles, the 

percentage of “other materials” in the piles was not found to exceed allowable levels. 

The facility voluntarily conducted a stack test for toxics in 2009 that also showed toxic 

emissions within allowable levels. Nevertheless, several ash tests, and even soil tests 

proximal to the facility, showed elevated levels of dioxins that exceeded state standards, 

endangering human and environmental health. 

Dioxin from incinerators is carried in the smoke plume to depose on soil, where it can 

remain for decades. Dioxin from soil bioaccumulates in the fat of food and game 

animals. Residents in the Anderson area are raising food animals and are therefore at 

higher risk of exposure to dioxin pollution. The Anderson area is similar to the area 

surrounding the Oroville POPI plant, which showed in a recent survey (Gary Bess 

Consultants, 2013) that 12% of survey respondents raised animals for consumption. 

The practice of paying orchardists and farmers to take waste ash for use as an agricultural 

soil amendment necessitates that burn stock is restricted to clean cellulosic biomass. Our 

experience trying to hold Covanta accountable for remediating their toxic legacy from 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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burning other materials has taught us: prevention is the most cost‐effective way to 

address contamination. (Robyn Di Falco of Butte Environmental Council)

Response: See EPA’s response to comment 5.1 above. 

5.4 Comment: No railroad ties or other contaminated railroad ties should be burned. (John 

Livingston of Sierra Club Shasta Group)

Response: The PSD permit does not allow the SPI-Anderson facility to combust railroad 

ties or other contaminated material in the proposed 468 MMBtu/hr biomass-fired boiler. 

Permit Condition X.G.1 restricts fuel used in the boiler to the following biomass fuels: 

 Untreated wood pallets, crates, dunnage, untreated manufacturing and 

construction wood debris from urban areas; 

 All agricultural crops or residues;

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

 Forest residues including treetops, non-merchantable sections of the stem, 

branches, and bark, left on the ground after logging or accumulating as a result 

of a storm, fire, delimbing, or other similar disturbance.

 Non-merchantable forest biomass consisting of byproducts and residuals of 

forest management activities identified to follow all of the following practices;

o Harvested pursuant to an approved timber management plan prepared in 

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

locally or nationally approved plan; and

o Harvested for the purpose of forest fire fuel reduction or forest stand 

improvement.

Additionally, Permit Condition X.D.1 allows SPI to use Public Utilities Commission 

(PUC) quality pipeline natural gas in the boiler during periods of boiler startups, 

shutdowns and flame stabilization. EPA has not revised its evaluation or the PSD permit 

based on this comment. 

5.5 Comment: Page 3, Table 1. In the “Description” column, please change “Maximum 

annual average heat input of approximately 468 MMBtu/hr and steam generation rate of 

250,000 lbs/hr” to “Maximum heat input of approximately 468 MMBtu/hr, a maximum 

annual average heat input of 425 MMBtu/hr, and a nominal steam generation rate of 

approximately 250,000 lbs/hr.” (Shane Young of SPI-Anderson)

Response: EPA has made this clarification to the “Description” in the Final Permit. This 

change is administrative in nature and does not significantly change the permit or EPA’s 

analysis.
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5.6 Comment: Page 4, Table 2. In the “Description” column, please change “Biomass-fired 

with natural gas burners for start-up” to “Biomass-fired.” The existing boiler does not 

include natural gas-fired burners. (Shane Young of SPI-Anderson) 

Response: EPA has made this clarification to the “Description” in the Final Permit. This 

change is administrative in nature and does not significantly change the permit or EPA’s 

analysis.

5.7 Comment: Page 4, Table 2. In the “Description” column, please change “Equipped with 

one 30,400 ft3, 2 hog fuel bins, 2 wood chip fuel bins” to “Equipped with one 30,400 ft3 

fuel storage bin, 2 hog fuel bins, 2 wood chip fuel bins.” (SPI-Anderson)

Response: EPA has made this clarification to the “Description” in the Final Permit. This 

change is administrative in nature and does not significantly change the permit or EPA’s 

analysis.

5.8 Comment: [Change Permit Condition X.H.7 as follows:] “The Permittee shall submit a 

CEMS performance test protocol to the EPA no later than 30 days prior to the test date to 

allow review of the test plan and to arrange for an EPA observer to be present at the test. 

The performance test shall be conducted in accordance with the submitted protocol and 

any changes required by EPA.” 

The term “observer” by itself does not clearly distinguish or limit the type of person that 

may qualify as an observer. This is understood to be an EPA representative or contracted 

individual with EPA to provide observations and not a 3rd party or non-EPA 

representative that may interpret this condition otherwise to entitle them to be present at 

the test. The addition of “EPA” to observer does not limit or modify any other permits 

for the facility or the respective person(s) that are allowed access by those permits. 

(Shane Young of SPI-Anderson) 

Response: Since the CEMS performance test protocol must be submitted to the agency 

for review and to arrange an observer, the observer would be an actual employee of EPA 

or a person who has been given the authority to represent EPA in an official capacity 

(e.g., an EPA contractor). This would not include a third-party or non-EPA employee. 

Therefore, we do not agree that the requested change is necessary. 

5.9 Comment: [Permit Condition X.H.7:] As a second comment pertaining to this language, 

this item (X.H.7) is redundant in its entirety and duplicative with I.2.D (Performance 

Test). We suggest removing from the “Monitoring Conditions” section (X.H.7) and leave 

with the suggested language change above within the “Performance Test” section only 

(I.2.D) (Shane Young of SPI-Anderson) 

Response: EPA agrees that Permit Conditions X.H.7 and X.I.2.d (rather than I.2.D) are 

similar. Permit Condition X.H.7 requires SPI to submit a continuous emissions 
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monitoring system (CEMS) performance test protocol no later than 30 days prior to the 

test date. This condition applies to CEMS performance tests for NOx, CO and CO2

emissions since, according to Permit Condition X.H, these are the only pollutants for 

which SPI is required to install a CEMS. Permit condition X.I.2.d requires SPI to submit 

a performance test protocol no later than 30 days prior to the test date, and applies to all 

pollutants for which SPI is required to conduct a performance test. According to Permit 

Condition X.I.2.a, these pollutants include lead, PM, PM10, PM2.5, SO2 and volatile 

organic compound emissions, as well as NOx, CO and CO2 emissions. Since Permit 

Conditions X.H.7 and X.I.2.d are similar, EPA has revised Permit Condition X.H.7 to 

state the following: “The Permittee shall submit a CEMS performance test protocol in 

accordance with Condition X.I.2.d.” This change is administrative in nature and does not 

significantly change the permit or EPA’s analysis. 

5.10 Comment: [Change Permit Condition X.H.11as follows:] “The Permittee shall furnish 

the EPA with a written report of the results of performance tests as identified in this 

Permit within 60 days of completion.” 

This item should limit the requirement to relate to the PSD permit. Suggest to add the 

language above to clearly distinguish and identify the “tests” required for the facility to 

submit to EPA. There are other “tests” that may and will be performed at the facility that 

are not required or related to the PSD permit. The above clarity is intended to minimize 

confusion. (Shane Young of SPI-Anderson) 

Response: EPA has made the suggested change to Permit Condition X.H.7 of the Final 

Permit. This change is administrative in nature and does not significantly change the 

permit or EPA’s analysis.

5.11 Comment: [Change Permit Condition I.2.C as follows:] “Annual performance tests of 

PM10, CO, CO2, and NOx, shall be conducted at no less than 90% of the facility’s 

maximum steam production rate of 250,000 lb/hr. The performance test requires for CO, 

NOx, and CO2 shall be demonstrated using the annual relative accuracy test auditing of 

the CEMS, for each applicable pollutant, required in Condition X.H.6.” 

It is impractical from a compliance/enforcement perspective to require a facility to 

conduct performance testing at 100% of design. Typically the requirement is to be within 

10% of the design (or 90% of the maximum heat or design steam for the facility). It is 

also important to clearly distinguish that the design steam production rate is 250,000 lb/hr 

for performance testing purposes. (Shane Young of SPI-Anderson) 

Response: The comment is actually referring to Permit Condition X.I.2.c. EPA has made 

the suggested change which does not significantly change the permit or EPA’s analysis. 
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5.12 Comment: [Permit Condition J.2 states:] “The Permittee shall record the efficiency of 

U1 daily. The heat input, as determined from the U1 efficiency and steam production 

rate, shall not exceed 468 MMBtu/hr on a monthly basis.” 

This condition is confusing and uncertain as to the intent. It appears the intent is to 

compare the maximum heat rating design value (468 MMbtu/hr) with actual heat average 

on a daily basis, also in mmbtu/hr (24-hr average). If this is correct, then “efficiency” is 

the incorrect term for this item and design heat would be more appropriate. The 

calculation of daily boiler heat in MMbtu/hr units is performed by multiplying the 

manufacturer ratio of maximum heat design to design steam (468 MMbtu/hr divided by 

250,000 lb/hr) by the total steam generated each day (lbs/day), then dividing by 24 

(hours). Suggest to strike J.2 above in its entirety and replace with condition below: 

The Permittee shall calculate and record on a daily basis, the average boiler heat 

(MMbtu/hr). The calculation shall be based on manufacturer ratio of maximum 

design heat rating to design steam [max design (MMbtu/hr) divided by design steam 

(lb/hr)]. The heat input, as determined from this, shall not exceed 468 MMbtu/hr on a 

monthly basis. (Shane Young of SPI-Anderson) 

Response: EPA has made the suggested change, based on the comment, to Permit 

Condition X.J.2 which does not significantly change the permit or EPA’s analysis.

5.13 Comment: [Change Permit Condition J.3 as follows:] “By the last 30th day of each 

month, the Permittee shall calculate and record the 12-month rolling sum of CO, NOx, 

PM, PM10 and PM2.5 emissions in tpy for U1 for the previous 12 months in accordance 

with Condition X.A.1.” 

The month of February does not have 30 days and many months have 31. It appears the 

intent of the condition is to have the report on the last day of a month. (Shane Young of 

SPI-Anderson) 

Response: EPA has made the suggested clarification to Permit Condition X.J.3 of the 

Final Permit. This change is administrative in nature and does not significantly change 

the permit or EPA’s analysis.

5.14 Comment: Apply the above comments regarding Permit Condition J.3 to J.4. (Shane 

Young of SPI-Anderson) 

Response: EPA has made the suggested clarification to Permit Condition X.J.4 of the 

Final Permit. This change is administrative in nature and does not significantly change 

the permit or EPA’s analysis.

 
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6. GHG AAQIR COMMENTS

6.1 Comment: Page 10, Table 3-1. In the “Unit” column, please change “Stoker Boiler with 

Vibrating Grate” to “Stoker Boiler with Reciprocating Grate.” (Shane Young of SPIAnderson) 

Response: This correction has been made in the Final Permit. This change is 

administrative in nature and does not significantly change the permit or EPA’s analysis. 

6.2 Comment: Page 10, Table 3-1. In the “Description” column, please change “Biomassfired with natural gas burners for start-up and shutdown” to “Biomass-fired with natural 

gas burners for startup, shutdown, and flame stabilization.” (Shane Young of SPIAnderson) 

Response: This correction has been made in the Final Permit. This change is 

administrative in nature and does not significantly change the permit or EPA’s analysis. 

6.3 Comment: Page 10, Table 3-1. In the “Description” column, please change “Composed 

of two-cells with an expected water load of 4.24 gallons per minute per square foot” to 

“Composed of three cells with an expected water load of 4.24 gallons per minute per 

square foot.” (Shane Young of SPI-Anderson) 

Response: This correction has been made in the Final Permit. This change is 

administrative in nature and does not significantly change the permit or EPA’s analysis. 

6.4 Comment: Page 10, Table 3-1. In the “Description” column, please change “Biomassfired with natural gas burners for start-up” to “Biomass-fired.” The existing boiler does 

not include natural gas-fired burners. (Shane Young of SPI-Anderson) 

Response: This correction has been made in the Final Permit. This change is 

administrative in nature and does not significantly change the permit or EPA’s analysis. 

6.5 Comment: Page 10, first paragraph, first sentence. Please change “The proposed biomass 

boiler of the cogeneration unit is expected to have a maximum annual average heat input 

of 468 million British thermal units per hour (MMBtu/hr), and an annual average heat 

input of 425 MMBtu/hr” to “The proposed biomass-fired boiler that is part of the 

cogeneration unit is expected to have a maximum heat input of 468 million British 

thermal units per hour (MMBtu/hr), and an annual average heat input of 425 MMBtu/hr.” 

(Shane Young of SPI-Anderson) 

Response: The requested change would not change the PSD permit or EPA’s analysis. 

As a general matter, we do not revise or reissue the AAQIR for issues that are primarily 

administrative or editorial in nature. 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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6.6 Comment: Page 30, under “Clean Fuels”, last sentence. Please change “This control 

option is technically feasible only for natural gas since already SPI proposes to use this 

fuel in the engine” to “This control option is technically feasible only for natural gas 

since SPI already proposes to use this fuel in the engine.” (Shane Young of SPIAnderson) 

Response: EPA notes this requested change. This change is administrative in nature and 

does not change the PSD permit or EPA’s analysis. 

 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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7. PROCEDURAL COMMENTS

7.1 Comment: I am deeply concerned that EPA Region 9 (Region) is only providing the 

public with 30 days to research, write and submit written comments on a multitude of 

substantial changes. Changes your agency instituted. Region alluded to substantial 

changes in the proposed permit in your November 8th, 2013 notice. Region’s changes to 

the permit are of a substantial magnitude and warrant a 90 day written comment period 

after the hearing. I am officially requesting the written comment period be extended to 

90 days after the December 10th, 2013 public hearing. I [cannot] help but notice this 

hearing falls in between Thanksgiving and Christmas. I think it would benefit everyone 

involved to extend the comment period. (Heidi Strand of Citizens for Clean Air)

Response: On November 22, 2013, EPA issued a public notice to announce that we were 

extending the public comment period for an additional 28 days. The public comment 

period, which commenced on November 8, 2013, ran for a total of 64 days and ended on 

January 10, 2014 instead of on December 13, 2013. EPA found no basis for extending 

the public comment period by an additional 90 days after the December 10, 2013 date of 

the public hearing. 

7.2 Comment: The Appeals Board ruled Region 9 must consider Best Available Control 

Technology (BACT) and hold a public hearing. (Heidi Strand of Citizens for Clean Air) 

Response: EPA disagrees with the commenter’s characterization of the EAB’s decision. 

The EAB decision, issued on July 18, 2013, ordered EPA Region 9 to reopen the permit 

proceedings to hold a public hearing, issue a final permit decision and respond to any 

new comments received during the hearing. See In re Sierra Pacific Industries, PSD 

Appeal Nos. 13-01 to 13-04, slip op. at 67 (EAB July 18, 2013). Additionally, in light of 

the July 12, 2013 decision from the Court of Appeals for the Circuit for the District of 

Columbia vacating EPA’s Biomass Deferral Rule, the Board declined to reach the 

challenge to the Region’s decision to rely on this rule. See Ctr. for Biological Diversity v. 

EPA, 722 F.3d 401 (D.C. Cir. 2013). The Board denied review of all other procedural 

and substantive challenges that Petitioners raised during the appeal process. Therefore, 

the Board’s decision did not order EPA Region 9 to consider or re-consider BACT. 

However, we note that EPA did consider relevant BACT issues and addressed public 

comments related to BACT. See 2012 AAQIR, Section 7; see also, 2012 RTC. 

7.3 Comment: One of the major concerns raised in this EAB appeal was Region 9’s attempt 

to “modify” the expired and out of compliance 4 MW facility’s permit. Not only do they 

plan to issue a significantly out-of compliance 4 MW facility a new 5 year permit without 

coming into compliance, they want to “modify” that expired permit to also allow Sierra 

Pacific to build a new 31 megawatt biomass facility next door. (Heidi Strand of Citizens 

for Clean Air)
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Response: When the commenter states “4 MW facility,” we understand the commenter 

to be referring to the existing 116.4 MMBtu/hr biomass-fired boiler, and associated 

equipment, currently at the SPI-Anderson facility. This unit is capable of generating 4 

MW of electrical power. SPI submitted a PSD application to EPA to construct a new 468 

MMBtu/hr biomass-fired boiler and other associated ancillary equipment at the SPIAnderson facility. The new biomass-fired boiler will be capable of producing 31 MW of 

electrical power. Thus, the existing and new equipment will be located at the site of the 

SPI-Anderson facility. 

The commenter refers to a “5 year permit.” We understand the commenter to be referring 

to the Clean Air Act title V operating permit that was issued to the facility by the Shasta 

County AQMD. The SPI-Anderson facility currently has both a PSD permit and a title V 

operating permit for the existing equipment at the facility. Both permits were issued by 

the Shasta County AQMD. The PSD permit was issued by the AQMD in 1995 and 

authorized the construction of the 116.4 MMBTU/hr biomass-fired boiler and associated 

equipment.28 The facility’s initial title V operating permit was issued in July 2000, and 

renewed in September 2006 and again in September 2013. The title V operating permit 

covers the existing equipment at the facility and contains the Clean Air Act requirements 

that apply to these units, such as the PSD permit. For the proposed new equipment, SPIAnderson has 12 months after the new equipment commences operation to apply for a 

title V permit for this equipment. 

Regarding the commenter’s concern regarding modifying the existing PSD permit issued 

by the Shasta County AQMD, EPA has addressed this comment in the 2013 RTC. (See 

2013 RTC at 15, response to comment #15). On July 18, 2013, the EAB responded to all 

issues appealed to the Board regarding the PSD permit modification for the SPIAnderson facility. The EAB ordered the EPA Region 9 to hold a public hearing, declined 

to reach the challenge to the Region’s decision to rely on the Agency’s Biomass Deferral 

Rule, and denied review of all other procedural and substantive challenges, including the 

issue regarding categorizing SPI’s proposed boiler as a “major modification” rather than 

as a “major stationary source.” 

7.4 Comment: Deborah [Jordan] has decided not to address any of the concerns we raised in 

our petition to the EAB. Instead, she has scheduled the ordered hearing with every 

intention of issuing the ‘modified’ permit without addressing the concerns we raised in 

our petitions and as if no objection existed. (Heidi Strand of Citizens for Clean Air)

Response: EPA believes it has addressed the concerns raised in comments from the 

public and in proceedings before the EAB. See e.g., 2013 RTC, 2014 RTC.29 The EAB’s 

 

28 EPA stated in previous documents that Shasta County AQMD issued the PSD permit in 1994. This is incorrect. 

The AQMD received SPI’s PSD application on November 21, 1994. The District issued the draft permit (as defined 

in 40 CFR 126.6) and public notice for the permit action for public comment on May 1, 1995. The District issued its 

final PSD permit on June 15, 1995. 29 EPA’s EAB filings are available at: http://yosemite.epa.gov/oa/EAB_Web_Docket.nsf/EAB+Dockets?OpenPage 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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decision regarding the 2013 Permit held that EPA Region 9 clearly erred in failing to 

grant the requests for a mandatory public hearing under 40 CFR 124.12(a)(1); however, 

the EAB denied review of all other procedural and substantive challenges made by 

Petitioners. See In re Sierra Pacific Industries, PSD Appeal Nos. 13-01 to 13-04, slip op. 

at 67 (EAB July 18, 2013). The comment does not include any specific information or 

facts demonstrating that EPA’s evaluation or the PSD permit was incorrect or flawed. 

7.5 Comment: A public hearing always follows environmental review. (Heidi Strand of 

Citizens for Clean Air)

Response: The comment suggests that the PSD permit is part of an environmental review 

under the National Environmental Policy Act (NEPA), which applies to federal agencies. 

NEPA, however, does not apply to EPA’s action in issuing the PSD permit. EPA’s PSD 

permit action does not trigger NEPA because Congress exempted all Clean Air Act 

actions from NEPA under the Energy Supply and Environmental Coordination Act of 

1974. In addition, the California Environmental Quality Act (CEQA) applies to State and 

local agencies, and not to federal agencies such as EPA. We understand that the project 

was subject to CEQA, as carried out by the Shasta County Resource Management 

Planning Division. 

EPA’s regulations governing the PSD permitting process are the implementing federal 

regulations at 40 CFR 52.21, and the public participation and decision-making 

regulations at 40 CFR part 124. Pursuant to these regulations, EPA provided notice to 

the public on November 8, 2013 to commence the public comment period and to 

announce a public hearing that was scheduled and held on December 10, 2013. 

7.6 Comment: Deborah Jordan has chosen to ignore the pleas of Shasta County residents for 

an authentic environmental review process under the Clean Air Act. (Heidi Strand of 

Citizens for Clean Air)

Response: See EPA’s response to comment 7.5 above. 

7.7 Comment: Region 9 Air Director Deborah Jordan went against the intent of the Appeals 

Board by still not conducting the permitting process in this case according to EPA’s 

guidelines. 

EPA REGULATIONS 

Title 40. Protection of Environment 

Part 70 – State operating permit programs 

S/S 70.7 Permit issuance, renewal, reopenings, and revisions. 

(2) Proceedings to reopen and issue a permit shall follow the same procedures as apply to 

initial permit issuance and shall effect only the parts of the permit for which cause to 

reopen exists... 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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That procedures for an initial permit it to: 

...The Clean Air Act calls for any permit that undergoes significant changes to undergo a 

new review process. A new Environmental Review and the review process that follows is 

required according to the Clean Air Act. [emphasis added] (Heidi Strand of Citizens for 

Clean Air)

Response: The commenter is referring to the implementing regulations for a title V 

operating permit program which are at 40 CFR Part 70. The PSD and title V operating 

permitting programs are separate and distinct programs. 

The PSD program applies to the proposed construction of a new major facility or the 

major modification of an existing facility that is located in an area that is classified as 

attainment or unclassifiable with the National Ambient Air Quality Standards (NAAQS). 

EPA Region 9 is currently the permitting authority for issuing PSD permits in Shasta 

County, California, which is classified as attainment or unclassifiable with the National 

Ambient Air Quality Standards (NAAQS). EPA Region 9’s action is a PSD permit 

modification for the construction of new emission units at the SPI-Anderson facility. 

EPA’s regulations governing the PSD permitting process are the implementing federal 

regulations at 40 CFR 52.21, and the public participation and decision-making 

regulations at 40 CFR Part 124. 

The title V operating permitting program applies after a facility or emission unit has 

begun operation. Shasta County AQMD is the title V operating permitting authority for 

facilities in Shasta County. The AQMD has an approved title V operating permitting 

program and has regulations that EPA has approved as meeting the requirements of 40 

CFR Part 70. 

Therefore, the regulations cited by the commenter do not apply to EPA’s action on the 

PSD permit modification for the SPI-Anderson facility. 

7.8 Comment: In order for a meaningful public hearing, the Region first must conduct a new 

Environmental Study on the project. This study would include CO2 emissions. Tacking 

Best Available Control Technology on after Region 9’s Air Director has issued the final 

permit is a slap in the face to the citizens who gave so generously of their time to be 

meaningfully involved in this process. (Heidi Strand of Citizens for Clean Air)

Response: It is unclear what is meant by this comment. EPA Region 9’s action is a PSD 

permit modification for the construction of new emission units at the SPI-Anderson 

facility. EPA has prepared the 2012 Proposed Permit and Revised Proposed Permit for 

this project in accordance with the implementing PSD regulations at 40 CFR 52.21, and 

followed EPA’s public participation regulations at 40 CFR Part 124. Moreover, EPA has 

prepared the 2012 AAQIR and the GHG AAQIR, which is a new analysis of GHG 

emissions that would result from the project. These documents and other supporting 
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documentation were made available to the public during the public comment periods held 

from September 13, 2012 – October 17, 2012, and from November 8, 2013 – January 10, 

2014. The comment does not include any specific information or facts demonstrating 

that EPA’s evaluation or determination, or that EPA’s process for carrying out the public 

participation regulations at 40 CFR Part 124 for the PSD permit was incorrect or flawed. 

The comment does not supply sufficient detail for EPA to respond further. 

7.9 Comment: Include any other RTC documents that are BACT-related. (Celeste Draisner)

Response: Any public comments and supporting documents referenced in EPA’s 2013 

RTC and in this 2014 RTC are included in the administrative record for the permit or 

referenced appropriately in the applicable document. See RTC 3.1 for additional 

information.

7.10 Comment: Please include all public comments. (Celeste Draisner) 

Response: All public comments submitted in accordance with EPA’s public notice 

issued on November 8, 2013 and public notice extension issued on November 22, 2013 is 

in the administrative record for EPA’s action on the PSD permit. See RTC 3.1 for 

additional information.

7.11 Comment: February 10th, 2013 is the very earliest they can approve the permit if they 

don’t recirculate this one as a draft. 

ENVIRONMENTAL IMPACT STATEMENT (EIS) DATABASE 

The Environmental Impact Statement (EIS) Database provides information about EISs 

prepared by federal agencies, as well as EPA's comments concerning the EISs. 

All EISs are filed with EPA, and EPA publishes a “Notice of Availability” each week in 

the Federal Register. The “Notice of Availability” is the start of the 45-day public 

comment period for Draft EISs. This notice is also the start of the 30-day “wait period” 

for Final EISs, in which agencies are generally required to wait 30 days before making a 

decision on a proposed action. (Heidi Strand of Citizens for Clean Air)

Response: The comment quotes the guidance document NEPA and CEQA: Integrating 

State and Federal Environmental Reviews. This document was prepared to help integrate 

the processes for NEPA, which applies to federal agencies, and CEQA which applies to 

State and local agencies and is essentially the state version of NEPA. The regulations 

governing the NEPA and CEQA processes do not apply to EPA’s action on the PSD 

permit. EPA’s regulations governing the PSD permitting process are the implementing 

federal regulations at 40 CFR 52.21, and the public participation and decision-making 

regulations at 40 CFR part 124. 

Moreover, EPA’s PSD permit action does not trigger NEPA because Congress exempted 

all Clean Air Act actions from NEPA under the Energy Supply and Environmental 
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Coordination Act of 1974. Documents prepared under NEPA are referred to as 

Environmental Impact Statements (EIS) and documents prepared under CEQA are 

referred to as Environmental Impact Reports (EIR). We understand from our 

Environmental Review Office at EPA Region 9 that NEPA was not triggered for this 

project; thus, no federal agency was required to prepare an EIS. In addition, to our 

knowledge, we understand that the project was subject to CEQA which was carried out 

by the Shasta County Resource Management Planning Division, and that the County 

issued a final EIR for the project in 2013. 

7.12 Comment: If the PSD permit process is not part of CEQA or NEPA, is it part of the 

Clean Air Act? (Heidi Strand of Citizens for Clean Air)

Response: In response to this comment submitted directly to EPA staff, we stated in a 

December 10, 2013 email to the commenter that the PSD permitting process is a Clean 

Air Act permitting program. We also stated that general information about the PSD 

permitting process can be found at the following webpages. 

Overview: http://www.epa.gov/region9/air/permit/psd-public-part.html 

PSD permitting process: http://www.epa.gov/region9/air/permit/psd-issuing.html 

Public participation: http://www.epa.gov/region9/air/permit/psd-public-guidelines.html

7.13 Comment: According to Sierra Pacific’s PSD Permit SAC 12-01 signed by Deborah 

Jordan on Feb 19th, 2013 (page 1): “The PSD permit previously issued by the District to 

SPI is still in effect and applies to existing equipment at the SPI-Anderson site.” Could 

you tell me the date Shasta County renewed this permit? (Heidi Strand of Citizens for 

Clean Air)

Response: To our knowledge, the PSD permit issued by Shasta County AQMD (Permit 

No. 94-PO-18) for the existing equipment currently at the SPI-Anderson facility was 

issued on June 15, 1995.30 This permit is currently still in effect. 

 

 

30 Id. at 28 
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8. COMPLIANCE COMMENTS

8.1 Comment: The Anderson, California facility has been in “significant non-compliance” 

of their 4 MW PSD permit for the entire 5 years it was in existence. (Heidi Strand of 

Citizens for Clean Air)

Response: EPA’s action is a PSD permit modification for the construction of new 

emission units at the SPI-Anderson facility. EPA Region 9 is currently the permitting 

authority for issuing PSD permits in Shasta County, California. EPA’s regulations 

governing the PSD permitting process are the implementing federal regulations at 40 

CFR 52.21, and the public participation and decision-making regulations at 40 CFR Part 

124. 

The commenter appears to be referring to the facility’s title V operating permit, which is 

renewed on a 5-year basis, for the existing biomass-fired boiler that is capable of 

generating 4 MW of electricity and other associated equipment at the SPI-Anderson 

facility. Shasta County AQMD is the title V operating permitting authority for facilities 

within Shasta County, California. The AQMD has an approved title V operating 

permitting program and has regulations that EPA has approved as meeting the title V 

implementing regulations in 40 CFR Part 70. 

The commenter has not provided any specific information or facts demonstrating that 

EPA’s current action on the PSD permit modification incorrect or flawed. EPA does not 

have enough information to respond further. 

8.2 Comment: The commenter provided information on various SPI facilities located in the 

cities of Anderson, Arcata, Lincoln, Loyalton, Quincy, Sonora and Susanville, all of 

which are located within California. This information appears to be title V operating 

permit actions and enforcement and/or compliance-related actions taken by the applicable 

local air pollution control agency and/or the Air Resources Board in the state of 

California. The commenter indicates that this information shows a pattern and practice of 

the agency’s disregard for the public good. (Heidi Strand of Citizens for Clean Air)

Response: EPA Region 9’s action is a PSD permit that authorizes the construction of 

new emission units at the SPI-Anderson facility. The PSD permitting program is a preconstruction program that requires a new major facility or major modification at an 

existing facility obtain a PSD permit before construction. The PSD permit contains 

BACT emissions and operational limits for the proposed new emission units, and testing, 

monitoring, recordkeeping and reporting to ensure that the facility is complying with 

these limits. If SPI fails to comply with any condition or term set forth in the PSD 

permit, the facility may be subject to enforcement action pursuant to section 113 of the 

Clean Air Act. Our enforcement office ensures compliance with environmental 

requirements and, when warranted, will take civil or criminal enforcement action. 
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Shasta County AQMD is the title V operating permitting authority for facilities within 

Shasta County, California. The AQMD has an approved title V operating permitting 

program and has regulations that EPA has approved as meeting the title V implementing 

regulations in 40 CFR part 70. 

8.3 Comment: The Best Available Control Technology (BACT) will allow the operator to 

collect data on the performance of the system. The operator should not be allowed to 

collect data that is relied upon by the EPA to ensure permit compliance. The operator 

should be required to have an independent company do the daily monitoring or a fee 

should be charged by EPA to allow the Shasta County Air Pollution Agency to do the 

monitoring. There are many instances where owners of the facility will choose when to 

take the data and when it is not in their best interest to take the data. If the operator is 

allowed to take the data then a fee should be paid to the County to allow them to 

randomly check for compliance. (John Livingston of Sierra Club Shasta Group)

Response: EPA finds no basis for requiring conditions in the PSD permit for an 

independent company to conduct daily monitoring at the facility, nor for charging the 

facility fees to allow the SCAQMD to do the monitoring. EPA Region 9’s action is a 

PSD permit modification for the construction of new emission units at the SPI-Anderson 

facility. The PSD permit contains BACT emissions and operational limits for the 

proposed new emission units, as well as testing, monitoring, recordkeeping and reporting 

to ensure that the facility is complying with these limits. If SPI fails to comply with any 

condition or term set forth in the PSD permit, the facility may be subject to enforcement 

action pursuant to section 113 of the Clean Air Act. Our enforcement office ensures 

compliance with environmental requirements and, when warranted, will take civil or 

criminal enforcement action. We have not revised the permit based on this comment. 

8.4 Comment: [W]ho is physically going to be the watchdog, and if they are not maintaining 

it properly, will it be closed? (Elray Kleis)

Response: EPA Region 9’s action is a PSD permit modification for the construction of 

new emission units at the SPI-Anderson facility. The PSD permit contains BACT 

emissions and operational limits for the proposed new emission units, as well as testing, 

monitoring, recordkeeping and reporting to ensure that the facility is complying with 

these limits. If SPI fails to comply with any condition or term set forth in the PSD 

permit, the facility may be subject to enforcement action pursuant to section 113 of the 

Clean Air Act. Our enforcement office ensures compliance with environmental 

requirements and, when warranted, will take civil or criminal enforcement action. 

8.5 Comment: Probably the real reason why I’m here is because we had a brief history that 

the -- the history of SPI -- the history of SPI when I did my research besides living here, I 

thought I would do some research online. When I did research online, I got concerned 

about a commitment to environmental standards, past fines and so forth. So I’m hoping 

that the testing and the accuracy and so forth of the emission control devices will be on a 
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fairly strict basis, as strict as practical in terms of calibration and so forth, and they would 

seriously consider remote testing, so that we know what’s going on off site in real time 

24/7. Remote testing and possibly even available third-party oversight, so we know that 

there’s no -- so the naysayers can say there’s no pollution between the EPA and 

corporation versus, you know, what’s in the public’s best interest. (David Craft)

Response: The comment does not clearly explain “remote testing” or “third-party 

oversight,” or how they may be evaluated as compliance options in the PSD permit. The 

PSD permit contains testing, monitoring, recordkeeping and reporting requirements to 

ensure that the facility is complying with the applicable BACT emissions and operational 

limits. If SPI fails to comply with any condition or term set forth in the PSD permit, the 

company may be subject to enforcement action pursuant to section 113 of the Clean Air 

Act. Our enforcement office ensures compliance with environmental requirements and, 

when warranted, will take civil or criminal enforcement action. We have not revised the 

permit based on this comment.

8.6 Comment: [The] 4 megawatt facility according to ECHO, EPA’s own website, was out 

of compliance for its entire existence, five-year existence, but it was there. How do you 

modify a permit that does not exist? And why is the best available control technology 

being looked at for a 4 megawatt facility that has never been in compliance? “Significant 

non-compliance” is what it says on the ECHO website. (Celeste Draisner) 

Response: See EPA’s response to comment 8.2 above. 

8.7 Comment: To not redo the environmental study on this project after such a monumental 

change is to totally disregard the Environmental Justice mandate. The mandate calls for 

early, prolonged and meaningful involvement of the effected community. The mandate 

calls for the federal agencies involved to go above and beyond their usual efforts to help 

and involve the effected community. EPA is the lead agency of this mandate. I 

understand it is a mandate and not a law. But for Region 9 to not even consider 

Environmental Justice and its role in this permitting process after the citizens won in the 

Appeals Court is disheartening to say the least. (Heidi Strand of Citizens for Clean Air / 

Marily Woodhouse of Battle Creek Alliance

Response: EPA does not understand the commenter’s reference to “not redo the 

environmental study on this project after such a monumental change.” EPA prepared a 

new AAQIR reviewing GHG impacts from the project and made the document available 

during the public comment period. See GHG AAQIR. 

The comment also raises questions about EPA Region 9’s efforts for addressing 

environmental justice in the process for proposing the PSD permit modification for the 

SPI-Anderson project. Executive Order 12898, entitled Federal Actions To Address 

Environmental Justice in Minority populations and Low-Income populations, states in 

relevant part that “each Federal agency shall make achieving environmental justice part 
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of its mission by identifying and addressing, as appropriate, disproportionately high and 

adverse human health or environmental effects of its programs, policies, and activities on 

minority populations and low-income populations.” (See section 1-101 of Exec. Order 

12898, 59 Fed. Reg. 7629 (Feb. 16, 1994).) EPA defines environmental justice as the fair 

treatment and meaningful involvement of all people regardless of race, color, national 

origin, or income with respect to the development, implementation, and enforcement of 

environmental laws, regulations, and policies.31 In September 2011, EPA issued Plan EJ 

2014 which was generally a strategy to help integrate environmental justice into EPA’s 

activities (e.g., permitting). EPA took a number of other actions to address EJ in 

permitting, including issuing a Federal Register notice titled EPA Activities to Promote 

Environmental Justice in the Permit Application Process which committed each EPA 

regional office to develop its own plan to address EJ in permitting with regard to 

enhanced outreach. (See 77 Federal Register 38051, June 26, 2012). In response to this, 

EPA Region 9 issued the EPA Region 9 Regional Implementation Plan to Promote 

Meaningful Engagement of Overburdened Communities in Permitting Activities (May 1, 

2013).32 

Prior to issuing the Proposed Permit and Revised Proposed Permit for public comment in 

September 2012 and November 2013, we reviewed demographic data for the community 

surrounding the immediate project area and nearby cities for the purpose of addressing 

environmental justice prior to proposing the permit and issuing public notification 

materials in accordance with 40 CFR Part 124. In accordance with the EPA Region 9 

Regional Implementation Plan to Promote Meaningful Engagement of Overburdened 

Communities in Permitting Activities (May 1, 2013), we considered socioeconomic, 

linguistic isolation, education and other relevant factors to help inform our public 

outreach activities. For our most recent permit proposal issued for public comment in 

November 2013, in addition to sending the public notice by U.S. postal mail and 

electronic mail to members of the public on our mailing and publishing the public notice 

in the Redding Record Searchlight as required by 40 CFR Part 124, we also performed 

the following outreach activities during the public comment period to assist us in 

meaningfully involve the affected community in the permitting process. 

EPA Region 9 granted a request to extend the public comment to provide the public 

more time to review and comment on EPA’s action. The public comment period was 

extended for an additional 28 days. 

EPA Region 9 held a public information meeting prior to the public hearing. The 

public information meeting was held at the same location as the public hearing in 

Anderson, CA which within the affect community and nearby the SPI-Anderson 

facility. During the public information meeting, EPA presented posters on the project 

 

31 See http://www.epa.gov/compliance/environmentaljustice/basics/ejbackground.html 32 See http://www.epa.gov/compliance/environmentaljustice/resources/policy/plan-ej-2014/permitting/2013-05-

region-09-plan.pdf 
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and the permitting process, as well as spoke to members of the public regarding the 

project and answered questions. 

EPA Region 9 made the permit documents available in local libraries in local libraries, 

at the local air permitting agency, and on the EPA Region 9 website. 

8.8 Comment: Anderson, located in Shasta County has been officially recognized as an 

Environmental Justice Community by the Environmental Appeals Board. The need for a 

reasonable time to review and comment on the complex proposed changes Region has 

initiated are especially acute in this case. (Heidi Strand of Citizens for Clean Air)

Response: The commenter requested an extension of the public comment period. EPA 

granted the commenter’s request and extended the public comment period for an 

additional 28 days. Regarding the commenter’s point regarding environmental justice, 

we would like to point out the following statement made in the EAB’s July 18, 2013 

decision regarding the SPI-Anderson PSD permit modification: 

In his Petition, however, Mr. Coleman asserts that Shasta County already has been 

identified as an environmental justice community by the Board in its decision in 

Knauf I. Coleman 1st Am. Pet. at 6. Mr. Coleman is mistaken; he has misread the 

Board’s decision in Knauf I. In that case, the Board remanded a PSD permit because 

there was not a sufficient response in the record to environmental justice concerns 

raised by a commenter. Knauf I, 8 E.A.D. 121, 175 (EAB 1999). The Board did not 

make a finding regarding whether an environmental justice community in Shasta 

County was affected by the permit in that case. When the case later returned to the 

Board, the Board again did not reach the factual issue of whether an environmental 

justice community was affected by the permit. See Knauf II, 9 E.A.D. 1 (EAB 

2000). Rather, the Board upheld the Region’s conclusion that no one in Shasta 

County, including anyone in any environmental justice communities, would be 

adversely affected by the permit because “the additional [particulate matter] from 

the proposed Knauf facility will not exceed the federal NAAQS [National Ambient 

Air Quality Standards] or PSD increment for [particulate matter].” Id. at 16. The 

Board expressly refused to consider the petitioners’ challenge to the Region’s 

demographic analysis of Shasta County. Id. at 17. 

In Re Sierra Pacific Industries (Anderson Processing Facility), PSD Appeal Nos. 13-01, 

13-02, 13-03 & 13-04, Order Remanding in Part and Denying Review in Part, Decided 

July 18, 2013. 

 
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9. OTHER AIR QUALITY-RELATED COMMENTS

9.1 Comment: Currently, Shasta County has rated 2nd worst in California for filthy air 

quality, behind Los Angeles. What is EPA Region 9 doing to help solve our air quality 

problems? (Celeste Draisner)

Response: Please refer to our response to comment 3.1 for additional information 

regarding this comment, which was originally submitted to EPA in October 2012. 

This permit decision is for the approval to construct and operate equipment associated 

with the project. EPA is committed to protecting human health and the environment; 

however, this permitting action only addresses the approval to construct and operate 

emissions units at the SPI-Anderson facility. 

9.2 Comment: The effect of this new facility on the air quality in the valley areas has been 

grossly underestimated. (John Livingston of Sierra Club Shasta Group)

Response: It is unclear why the commenter believes the effect of the project on the air 

quality in the valley areas has been grossly underestimated. As part of the PSD 

permitting requirements, a thorough air quality analysis has been performed for this 

project. The results of this analysis and details of the appropriate and relevant inputs and 

the impacts of this project are contained in Section 8, especially Sections 8.4 and 8.5 of 

the 2012 AAQIR. The introduction to the 2013 RTC contains further discussion of the 

results presented in these two sections. Based on the information which is presented in 

the 2012 AAQIR, EPA concludes that the project will not cause or contribute to an 

exceedance of the applicable NAAQS or applicable PSD increments and that the air 

quality impacts in the vicinity of the facility have been adequately estimated. 

9.3 Comment: How can EPA say that the CO2 emissions from the plant will have a 

negligible effect when they are equivalent to 90,000 automobiles? This is approximately 

a doubling of the pollution from existing conditions. If there is not a comparable offset in 

the valley areas, this permit should not be allowed. If no offset is required, the air quality 

in Shasta County will be adversely affected by this facility. (John Livingston of Sierra 

Club Shasta Group)

Response: EPA determined that the permit modification does not require an ambient air 

quality impact analysis for GHG emissions because there is no NAAQS or PSD 

Increments for GHG pollutants and it is therefore not possible to compare the 

modification’s GHG emissions to a standard or increment. See PSD and Title V GHG 

Guidance at 47-48. Furthermore, although it is clear that GHG emissions contribute to 

global warming and other climate changes that result in impacts on the environment, 

climate change modeling and evaluations of risks and impacts of GHG emissions is 

typically conducted for changes in emissions orders of magnitude larger than the 

emissions from individual projects that might be analyzed in PSD permit reviews. 
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Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in 

specific places and points would not be possible with current climate change modeling. 

Given these considerations, GHG emissions would serve as the more appropriate and 

credible proxy for assessing the impact of a given facility. Thus, EPA believes that the 

most practical way to address the considerations reflected in the Class I area is to focus 

on reducing GHG emissions to the maximum extent. In light of these analytical 

challenges, compliance with the BACT analysis is the best technique that can be 

employed at present to satisfy the additional impacts analysis and Class I area 

requirements of the rules related to GHGs. See, PSD and Title V Guidance at 48. 

Neither EPA regulations nor guidance require pollutant mitigation or offset practices to 

be control technologies that must be considered in the PSD permitting process. 

Applicants are only required to evaluate inherently lower-emitting 

process/practices/designs (that result in reductions from equipment at the facility) and 

add-on control technologies, and a combination of these control alternatives. See, PSD 

and Title V Guidance at 25. While the practices identified by the commenter may be a 

part of an overall climate change plan, they are not applicable to the PSD permitting 

process for this specific facility. 

9.4 Comment: The air quality in Shasta County, especially in the Sacramento Valley, is 

slowly deteriorating due to pollution from agricultural burning, forest fires, and winds 

pushing Sacramento pollution north. The new cogeneration plant will significantly 

adversely affect the existing air quality in the county, especially near the plant. If the 

winds are from the south the poor air quality from the cogeneration plant will concentrate 

due to the northern mountains providing a barrier. The citizens of Shasta County will 

suffer the pollution from the facility and their health will be negatively impacted. Why 

should the citizens accept reductions in air quality when this facility is only designed to 

profit a privately held corporation? (John Livingston of Sierra Club Shasta Group)

Response: See EPA’s responses to comments 4.1 and 9.1. The air quality impacts portion of 

the 2012 AAQIR, Section 8, and especially Sections 8.2, 8.4 and 8.5, assessed the impacts of 

the project on ambient air quality, which includes impacts on PSD increments and the 

NAAQS. The NAAQS are set to protect public health and public welfare. Section 8.4 of the 

2012 AAQIR states that PSD increments are limits on cumulative air quality degradation. 

They are set to prevent air with pollutant concentrations lower than the NAAQS from being 

degraded to the level of the NAAQS. Table 8.4-3 shows that the project complies with the 

Class II PSD increments and the NAAQS. EPA concluded air pollution emissions from the 

project will not cause or contribute to violations of any NAAQS or any applicable PSD 

increments for the pollutants regulated under the PSD program. The new cogeneration plant 

is not predicted adversely affect existing air quality in the county, especially near the plant.

9.5 Comment: Due to the lack of information available from the regulatory agency, we 

found figures regarding biomass facility emissions from the Partnership for Policy 

Integrity. Using their figures for typical emissions from a 50 megawatt plant (based on 
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rates from biomass facility permits issued) we compared a 4 megawatt plant to a 31 

megawatt plant to determine its CO2 emissions, number of gallons of water used for 

cooling, number of tons of wood used, number of gallons of diesel fuel used to cut and 

transport the wood, and tons of waste ash produced per year: 

As can be seen above, there are huge increases in significant effects from a larger facility. 

Yet, your agency wants to modify the existing permit without any substantive analysis of 

these significant effects. (Marily Woodhouse of Battle Creek Alliance)

Response: EPA disagrees with the comment. EPA processed SPI’s PSD application in 

accordance with the PSD regulations in 40 CFR 52.21 and the public participation 

requirements in 40 CFR part 124. EPA conducted a BACT analysis for NOx, CO, PM, 

PM10, PM2.5 and GHGs, including CO2, because these pollutants result in emissions 

increases that are significant as defined in 40 CFR 52.21 (b)(23). EPA also conducted an 

air quality analysis for these pollutants (except for GHGs since no NAAQS has been 

established for this pollutant) based on our independent review of the SPI’s air quality 

modeling and monitoring data submitted as part of the PSD application and through 

discussions with the Federal Land Managers for nearby Class I areas (i.e., national parks 

and similar federal lands). EPA determined that the emissions increases from the 

proposed project will not cause or contribute to a violation of any NAAQS or applicable 

PSD increment. The comment does not include any specific information or facts 

demonstrating that EPA’s analysis or determinations were incorrect or flawed. 

Moreover, the commenter has not provided a legal or technical basis for EPA’s 

consideration of the impacts of number of gallons of water used for cooling, number of 

tons of wood used, number of gallons of diesel fuel used to cut and transport the wood, 

and tons of waste ash produced per year in its evaluation of BACT and impacts on air 

quality. The comment does not supply sufficient detail for EPA to respond further. 

 

9.6 Comment: The expansion of this plant would mean 356,400 more tons of CO2 would be 

added to the atmosphere each year, from just one point source at the biomass plant. As 

Miller points out, this does not include emissions from logging, transport, landfills, and 

soil carbon releases. Where is the EPA’s analysis regarding what impacts would occur to 

climate and air quality from an 87% increase at the point source, much less the other 
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uncalculated tons of CO2 released from the associated activities? (Marily Woodhouse of 

Battle Creek Alliance)

Response: EPA analyzed air quality impacts from the proposed project and determined 

that air pollution emissions from the project will not cause or contribute to violations of 

any NAAQS or any applicable PSD increments for the pollutants regulated under the 

PSD program. This analysis considered emissions from other nearby stationary sources. 

See e.g., 2012 AAQIR at 28. EPA also determined that the proposed project does not 

require an ambient air quality impact analysis for GHG emissions because there is no 

NAAQS or PSD Increments for GHG pollutants and it is therefore not possible to 

compare the modification’s GHG emissions to a standard or increment. We find no basis 

for considering emissions from activities from non-stationary facilities such as logging, 

transport, and soil carbon releases. The comment does not include any specific 

information or facts demonstrating that EPA’s analysis or determination was incorrect or 

flawed. The comment does not supply sufficient detail for EPA to respond further. 

9.7 Comment: Emissions from vehicles and wood burning are known to increase 

particulates in the air and cause respiratory problems. Biomass plants have been found to 

operate at ~ 24% efficiency. Enlarging this inefficient and polluting plant will combine 

with other increasing emissions to cause more cumulative effects to the health and wellbeing of the greater Shasta County area, and its surrounding counties. (Marily 

Woodhouse of Battle Creek Alliance)

Response: Tailpipe emissions from vehicles used at the facility are not regulated under 

the PSD program, which applies to stationary sources. EPA analyzed air quality impacts 

from the proposed project and determined that air pollution emissions from the project 

will not cause or contribute to violations of any NAAQS or any applicable PSD 

increments for the pollutants regulated under the PSD program. The NAAQS are 

protective of public health and welfare. EPA also determined that the proposed project 

does not require an ambient air quality impact analysis for GHG emissions because there 

is no NAAQS or PSD Increments for GHG pollutants and it is therefore not possible to 

compare the modification’s GHG emissions to a standard or increment. 

9.8 Comment: Jobs are good. Taxes enable government to perform critical services. 

Greenhouse gas emissions are problematic. Due to the closure of a Southern California 

nuclear power plant, greenhouse gas emissions have increased for the first time since 

2008. If greenhouse gases are indeed causing problems, all increases must be cautiously 

considered and the cumulative impacts of landscape changes taken into account. We, as 

in all of us, are totally dependent upon the systems the earth has designed. We have 

changed much of that landscape and cannot go back in time. But if we acknowledge our 

earth connection, we can maintain a sustainable world. (Virginia Phelps) 

Response: EPA evaluated BACT for GHGs. EPA determined that the proposed project 

does not require an ambient air quality impact analysis for GHG emissions because there 
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is no NAAQS or PSD Increments for GHG pollutants and it is therefore not possible to 

compare the modification’s GHG emissions to a standard or increment. 

9.9 Comment: I was just commenting on that the ambient air quality will be increased with 

the proposal. So I guess the drums are beating. It’s going to be roughly 85,000 cars 

sitting in one spot, emitting pollution for 24 hours a day, 365 days a year. It’s a lot of air 

pollution around here. We have the weather and everything. So I think that's quite a bit. 

I think the other kind of comparison we came up with was that it’s roughly 150,000, 

200,000 chimneys in the area that are -- would be going up. So, I guess, my proposal 

would be to Sierra Pacific, if any, they would be inclined to maybe buy wood stoves for 

everybody in the surrounding area within 10 miles or something like that to compensate 

for the pollution they're putting out. I mean, they're up there with that ambient air quality 

pretty high. I guess your standard is 188 and you are at 153. So that’s a lot of pollution 

that isn't here and will be here forever. I’m not sure how long this bio fuel thing is going. 

It’s probably going to go for 50 years, 60 years or so. So that’s 85,000 cars running 24/7, 

150,000, 200,000 wood burning stoves going 24/7 on this property. So there is air 

pollution. There is air pollution there. There’s the highway that's going down I-5 that 

also is polluting the air. And so I think maybe there should be some consideration, for 

possibly in the ten-mile radius, to supply EPA wood stoves for everyone at Sierra 

Pacific’s cost or half or something to compensate for the air pollution, because there is 

quite a bit and it will be here forever and they are self-monitored. I know that EPA 

monitors this from afar and our air pollution and air quality, and the Shasta County Air 

Quality Management District, will supervise it also. But I think it’s quite a bit of 

pollution in the area with their other unit, Wheelabrator, down the road. So I think a 

good enough proposal would be 10-mile radius where they compensate the surrounding 

areas with stoves or wood stoves or whatever it may be. I think it’s a lot of pollution and 

it should maybe be taken down a notch. (Antonio Damian, Jr.)

Response: EPA finds no legal basis for requiring SPI, as part of the PSD permitting 

process, to compensate surrounding areas with stoves or wood stoves within a 10-mile 

radius of the facility. 

9.10 Comment: I’m just taking this right out of the Record Searchlight. 330,000 tons of 

greenhouse gases. Is this being released into the valley? Why? Why can’t that be 

controlled? Cogeneration is a good idea. Polluting the air, using it as a garbage pit is 

not. Four hundred seventy-two tons of carbon monoxide should not be released in the 

air, and 272 tons of nitrous oxide, a major pollutant should not be released in the air. 

Why not create a technology that captures and uses these gases, instead of just using the 

air as a garbage pit. This valley is -- holds the air in, and when you have these kind of 

pollutants, it's going to affect two things, people with respiratory issues and we have a 

wonderful recreation industry up here. If we get the air too polluted, it’s going to affect 

that. I just want to be sure that these gases are captured. (Russ Wade)
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Response: EPA conducted a BACT analysis for NOx, CO, PM, PM10, PM2.5 and GHGs 

since these pollutants result in emissions increases that are significant as defined in 40 

CFR 52.21(b)(23) for the proposed project. This BACT determination, which is 

contained in the Final Permit, represents the maximum degree of reduction for each of 

these pollutants. EPA also conducted an air quality analysis for these pollutants (except 

for GHGs since no NAAQS has been established for this pollutant) based on our 

independent review of the SPI’s air quality modeling and monitoring data submitted as 

part of the PSD application and through discussions with the Federal Land Managers for 

nearby Class I areas (i.e., national parks and similar federal lands). EPA determined that 

the emissions increases from the proposed project will not cause or contribute to a 

violation of any NAAQS or applicable PSD increment. 

9.11 Comment: And I’d like to point out something. They should have the people out here in 

Whiskeytown National Forest and the Lassen National Forest provide the labor and the 

shredders and what have you. The Wheelabrator and this type of plant up here, Sierra 

Pacific, they should provide the trucking and haul that wood out of the woods up there to 

down here instead of setting it on fire and letting it burn. About 30 percent of their fires 

get out of control and burn everything, burn all kinds of stuff up, burn businesses up, 

burn homes, burn everything and they’re not held accountable. You cannot fire those 

people for doing something stupid. They’re protected by that. No, you cannot fire them. 

Anytime you get that, what you’re getting is an ego stretched out past their shoulders. I 

know people that are volunteer fire fighters and they’ve been called both of these fires, 

the one up there in Lassen Park that got away and cost $15 or $17, or I forget how many 

millions of dollars. They had that fire put out almost and go, and the wind was blowing 

like hell. The same thing happened up here in Whiskeytown National Forest. There was 

a fire up there. I forget the name of it, something Ridge. I don’t know. But anyway, 

they were on that fire and they had it almost out. And the guy made them let it go. It 

doesn’t make sense. The amount of emissions that they put in the air, in these forests, 

doing that type of burning is nothing compared to what a business puts out. We need 

these businesses and they do a good job and they burn them clean. You don’t see nothing 

but steam coming out of either one of these facilities. And the Environmental Protection 

Agency has already seen that, I notated, back in ‘09 and ‘12 and ‘13. That should have 

been good enough. That’s why I commended the Environmental Protection Agency for 

that. 

Response: EPA finds no legal basis under the PSD regulations or the Clean Air Act for 

regulating forest resources in the PSD permit. 

9.12 Comment: The first thing I would like to bring up is the issue of atmospheric thermal 

decline. The temperatures in Redding have been a little bit warmer in the morning than 

Anderson actually is. So I really feel like Anderson kind of needs its own air monitoring 

device, so we know exactly what is going on in Anderson itself. Just because of the I-5 
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corridor, a relatively small air basin here, I don’t think Redding or Chico could be a really 

good representative of that. (David Craft)

Response: It is unclear what the commenter means by the “issue of atmospheric thermal 

decline.” The background concentrations from background monitors in Chico and 

Redding which were used in the air quality analyses for the project are appropriately 

representative for this source and consistent with EPA’s Guideline on Air Quality 

Modeling, in Appendix W to 40 CFR Part 51 (GAQM or Appendix W) and EPA 

guidance; thus, an additional ambient air monitor in Anderson is not required. 

Section 8.2 of the 2012 AAQIR discusses background ambient air quality. It explains 

that the basis for NO2 background values are ambient air concentrations recorded at a 

monitor located on Manzanita Avenue in Chico, California which EPA determined was 

the closest and most representative NO2 monitor to the site. CO (1-hour and 8-hour) 

background concentrations were also recorded from the monitor located on Manzanita 

Avenue in Chico. Section 8.2 also explains that the basis for PM2.5 and PM10 background 

values are ambient air concentrations recorded at monitors located at the Redding 

Department of Health and Anderson, respectively. Table 8.2-1 of the 2012 AAQIR 

shows the maximum background concentrations in the area and the corresponding 

NAAQS. 

Furthermore, Sections 8.4 and 8.5 of the 2012 AAQIR discuss air quality impacts and 

EPA’s conclusion that the Project will not cause or contribute to an exceedance of the 

applicable NAAQS or applicable PSD increments. 

9.13 Comment: The second thing has to do with particulates. There have been times in the 

past, I know, they got construction going on up there and there’s some old larger log 

decks. I remember one time the wind was blowing from the north and we looked up and 

thought there was a fire. It was not a fire just black particulates that were blowing off the 

property that looked like smoke. I’m sure there’s going to be mitigation measures to try 

and deal with dust and particulates. (David Craft)

Response: EPA’s Final Permit requires BACT emission limits for particulates for the 

proposed 468 MMBtu/hr biomass-fired boiler and its associated control equipment, 256 

HP natural gas-fired emergency engine, and three-cell cooling tower. The Final Permit 

requires installation and operation of multiclone collectors and an ESP for reducing 

particulate pollution at the boiler, and operation of the emergency engine restricted to 

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

minimal annual emissions. The Final Permit also requires SPI to conduct periodic testing 

of particulates for the boiler and emergency engine, and weekly tests of blow-down water 

quality for the cooling tower to determine particulate emissions. 

 
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10.OTHER GENERAL COMMENTS

10.1 Comment: Removing biomass from the forest is not sustainable given climate change 

and warming. The amount of biomass removed from the forest must be limited. (John 

Livingston of Sierra Club Shasta Group)

Response: EPA finds no legal basis for limiting the amount of biomass from forests in 

the PSD permit. Additionally, the comment is not clear on how this information should 

be analyzed within the context of EPA’s evaluation of BACT and impacts on air quality. 

The comment does not include any specific information or facts demonstrating that 

EPA’s analysis or determination was incorrect or flawed. The comment does not supply 

sufficient detail for EPA to respond further. 

10.2 Comment: Commenter presented methods for converting raw biomass to other forms of 

biomass which can be used energy or for co-firing with fossil fuels like coal or oil. (AfroAsian Energy Development Consortium Inc (AED))

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis. 

10.3 Comment: The commenter submitted a FOIA request to EPA Region 9 during the public 

comment period which requested “All communication inside and outside your agency 

from July 13th, 2013 to November 8th, 2013. Specifically all communication in any 

form with Sierra Pacific Industries regarding your agency’s intent to circulate a petition 

for the proposed permit ‘modification’ for Sierra Pacific Industries-Anderson released 

November 8th, 2013. (Heidi Strand of Citizens for Clean Air)

Response: According to our EPA Region 9 FOIA Office, EPA provided all responsive 

documents for this FOIA request to the commenter on January 9, 2014. Electronic 

versions of all responsive documents were made available online at the following 

webpage: 

https://foiaonline.regulations.gov/foia/action/public/view/request?objectId=090004d2801

57f21

10.4 Comment: Dear Shaheerah Kelly, per your Public Notice published on November 8th, it 

states “...construction of the modification may commence.” Could you define what 

‘Construction of a modification’ means? 

Per your public notice of the extension of public comment period on Permit Application 

No. SAC 12-01: 

The public notice states “On November 8th, 2013, we announced a new version of the 

permit...” Does this not trigger a 90 day recirculation process as required for all new 

draft permits? 
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It is our understanding that the public hearing follows this 90 day recirculation process. 

Will Region 9 be holding a public hearing after the 90 day recirculation of the draft 

permit? (Heidi Strand of Citizens for Clean Air)

Response: EPA responded in a December 6, 2013 email as follows. 

“Dear Ms. Strand, 

Thank you for your comments. We will include them and respond when we provide our 

response to comments document. Please be aware that the public comment period ends 

on January 10, 2014. 

Regarding your question about what is meant by “construction of the modification,” we 

assume you are referencing our public notice, which states, “If EPA issues a final 

decision granting the PSD permit modification, and there is no appeal, construction of the 

modification may commence, subject to the conditions of the PSD permit and other 

applicable permit and legal requirements.” This statement means that if EPA issues a 

final permit, SPI can begin the process of constructing and installing the new equipment 

authorized by the permit, including a new biomass-fired boiler, a new emergency engine 

and a new cooling tower. 

We would like to note that your reference to a 90-day recirculation process is unclear. 

On November 8, 2013, we announced a 30-day public comment period, which is required 

by EPA’s regulations at 40 CFR 124.10. We recently announced that we are extending 

the public comment period to January 10, 2014. Since we announced the public 

comment period, the draft permit has been available on our website at 

http://www.epa.gov/region9/air/permit/r9-permits-issued.html. It will help us to better 

respond to your question if you clarify why you believe there is a 90-day recirculation 

process. 

On Tuesday, December 10th, we will hold a public information meeting prior to the 

public hearing to provide the public with an opportunity to ask clarifying questions. 

More information about the public information meeting and public hearing can be found 

in the attached public notice.” 

10.5 Comment: Dear Shaheerah, thank you for your quick response. In answer to my 

question is this new construction or a modification, you responded: “This statement 

means that if EPA issues a final permit, SPI can begin the process of constructing and 

installing the new equipment authorized by the permit, including a new biomass-fired 

boiler, a new emergency engine and a new cooling tower.” 

Will this new equipment be placed in a new building? 
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According to the following document, there is a 90 day recirculation process. NEPA and 

CEQA: Integrating State and Federal Environmental Reviews, Draft for Public Review 

and Comment, March 2013. 

Finally, a Record of Decision (ROD) may only be issued 30 days after the Notice of 

Availability of a Final EIS and 90 days after the Notice of Availability for a Draft EIS 

have been published (40 CFR 1506.10(b)(1)-(2)). 

~ Office of the President and the Governor’s office of Planning and Research (State of 

California) 

Please explain why this does not apply. 

[P]er EPA guidelines, a public hearing is to gather comments from the public during the 

scoping/beginning of the permitting process. If Region 9 skips this process, and does not 

recirculate the revised/draft permit then the purpose of a public hearing is defeated. The 

intent of the Environmental Appeals Board ruling has not been respected. The Region's 

December 10th public hearing on the permit is only valid as a scoping meeting before 

recirculating the draft permit for review. 

While EPA regulations require a 45 day minimum for recirculating a draft permit, I feel 

due to the complexity and controversy, a 90 day recirculation is appropriate. (Heidi 

Strand of Citizens for Clean Air)

Response: EPA responded to this comment in a December 9, 2013 email as follows. 

“Dear Ms. Strand, 

Thank you again for your comments. As mentioned previously, we will include them and 

respond when we provide our response to comments document. 

You asked “will this new equipment be placed in a new building?” The new equipment 

will be installed in a new building within the existing property of the Sierra Pacific 

Industries facility. 

The PSD permit is not part of the NEPA or CEQA processes. Therefore, the regulations 

governing the NEPA and CEQA processes do not apply to the PSD permit. EPA’s 

regulations governing the PSD permitting process are at 40 CFR 52.21, and EPA’s public 

participation regulations for the PSD permit are at 40 CFR part 124. These regulations 

require EPA to provide at least 30 days for public comment period, and require EPA to 

provide notice of a public hearing at least 30 days prior to the hearing. As mentioned in 

the previous e-mail message, EPA did this. Additionally, we recently announced that we 

are extending the public comment period to January 10, 2014. 
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In accordance with our regulations, EPA will be accepting oral and written comments 

during the public hearing scheduled for December 10.” 

10.6 Comment: I contacted Ross Bell, the Shasta Quality Air District Manager, in December 

2013 to determine what the emissions are currently from the 4 megawatt plant. He didn’t 

know. When asked if there were any monitoring documents he said there might be some 

in the files somewhere. This lack of knowledge on the part of a regulating agency is 

troubling, particularly in light of the large increase in emissions and other effects that will 

occur if the biomass plant is enlarged to a 31 megawatt plant. If one of the main 

regulatory agencies is unable to monitor the effects of a 4 megawatt plant, how will they 

be able to monitor and analyze the additional direct and indirect effects of a plant that has 

increased its size, effects, and emissions by 87%? (Marily Woodhouse of Battle Creek 

Alliance)

Response: As explained in our September 2012 and November 2013 public notices, and 

the 2013 RTC, EPA’s action is a modification to an existing PSD permit originally issued 

by Shasta County AQMD in 1995 for the 4 MW biomass stoker boiler cogeneration unit 

and associated equipment.33 The original PSD permit was issued pursuant to a delegation 

of EPA’s PSD permitting authority under 40 CFR part 52 to Shasta County AQMD. In 

2003, EPA rescinded the PSD delegations for several California air districts, including 

Shasta County. See 68 FR 19371 (April 21, 2003).) We have not re-delegated PSD 

permitting authority to Shasta County; therefore, EPA is the PSD permitting authority for 

this action. However, the PSD permit issued by the District (Permit No. 94-PO-18) for 

the existing equipment at the SPI-Anderson facility is still in effect. 

The EPA’s action is to modify this PSD permit to authorize construction of a new 31 

MW biomass stoker boiler cogeneration unit and ancillary equipment at the SPIAnderson facility. The PSD permit contains several BACT emissions and operational 

limits. The permit also contains monitoring, testing, recordkeeping and reporting 

requirements for assuring compliance with these emissions and operational limits. If SPI 

fails to comply with any condition or term set forth in the PSD permit, the may be subject 

to enforcement action pursuant to section 113 of the Clean Air Act. 

10.7 Comment: The expansion of this plant could require approximately 177,390,000 more 

gallons of water per year to be used for cooling than are currently being used. Is it not 

the EPA’s responsibility to safeguard the public trust resource of water? Does it fulfill 

the EPA’s mandate to protect the public, and the environment that sustains them, to 

modify a permit that allows over 177 million more gallons of water per year to be used 

for a privately owned, for-profit biomass plant? (Marily Woodhouse of Battle Creek 

Alliance)

 

33 Id. at 28 
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Response: The comment is beyond the scope of EPA’s action. The PSD permit is a 

Clean Air Act permitting program for regulating major sources of air pollution. EPA 

processed SPI’s PSD application in accordance with the PSD regulations in 40 CFR 

52.21 and the public participation requirements in 40 CFR part 124. EPA conducted a 

BACT analysis for NOx, CO, PM, PM10, PM2.5 and GHGs since these pollutants result in 

emissions increases that are significant as defined in 40 CFR 52.21(b)(23). EPA also 

conducted an air quality analysis for these pollutants (except for GHGs since no NAAQS 

has been established for this pollutant) based on our independent review of the SPI’s air 

quality modeling and monitoring data submitted as part of the PSD application and 

through discussions with the Federal Land Managers for nearby Class I areas (i.e., 

national parks and similar federal lands). EPA determined that the emissions increases 

from the proposed project will not cause or contribute to a violation of any NAAQS or 

applicable PSD increment. EPA’s permitting action does not include evaluating water 

discharges from the facility. Furthermore, the comment is not clear regarding how the 

information provided regarding water use at the facility should be analyzed within the 

context of EPA’s evaluation of BACT and impacts on air quality. 

10.8 Comment: Biomass plants use huge amounts of water for cooling also: 14,000-18,000 

gallons per day for each megawatt. This means that the current daily usage for the 4 

megawatt plant is up to 72,000 gallons a day; at 31 megawatts that could increase to 

558,000 gallons a day. According to the Partnership for Policy Integrity (www.pfpi.net) 

about 85% of that is evaporated and the balance is returned to the river (the Sacramento 

in this case) as a heated solution containing concentrated pollutants such as aluminum 

and phosphorus. (Heidi Strand of Citizens for Clean Air / Marily Woodhouse of Battle 

Creek Alliance)

Response: See EPA’s response to comment 10.7 above. 

10.9 Comment: Marily wanted to attend the meeting. She wanted clarification from Region 9 

if the waste water from the plant was going to be cleaned before going into the 

Sacramento River. (Heidi Strand of Citizens for Clean Air / Marily Woodhouse of Battle 

Creek Alliance)

Response: See EPA’s response to comment 10.7 above. 

10.10 Comment: The expansion of this plant will require 351,000 more tons of wood per year 

on an ongoing basis, year after year. The land has finite limits of what it can produce, 

even in more optimal conditions than are occurring presently. Where is all of the fuel for 

an 87% larger single biomass plant supposed to come from year after year? (Marily 

Woodhouse of Battle Creek Alliance)

Response: According to SPI’s PSD permit application, the SPI-Anderson lumber 

operation produces approximately 160,000 bone dry tons (BDT) of wood waste per year, 

which approximately 60,000 BDT are consumed by the existing cogeneration unit, 
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20,000 BDT are trucked to other biomass power plants, and the roughly 80,000 BDT 

balance is trucked to other markets (e.g. wood chips to pulp mills). The new proposed 

boiler will have the capacity to consume a maximum of 219,000 BDT per year, in which 

roughly 80,000 BDT will be generated by the facility’s existing lumber operations at its 

current output, and additional wood fuel will be transported by truck to the facility from 

SPI’s other lumber operations in California. SPI PSD Permit Application, March 2010 at 

3-4. According to SPI’s application, the additional wood fuel will come from lumber 

operations at Arcata, Shasta Lake, and Red Bluff, as well as in-forest materials from SPIowned or controlled timberlands, and various sources of agricultural and urban wood 

wastes. Id. 

10.11 Comment: If the EPA approves a modification of this permit to enlarge the biomass 

plant, it will increase the amount of logging of grown forests to replace them with tree 

plantations that lack diversity. Replacing grown, existing forests with tree plantations 

simplifies plant and animal communities because it reduces habitat. A forest is made up 

of different kinds and sizes of trees that provide what is termed “structure” by ecologists, 

and has an “understory” of many kinds of shrubs and other plants. In turn, the structure 

and understory provide food, resting and denning habitat for all the other forms of 

wildlife, from microorganisms to bugs to birds to mammals. “Large-scale clear-cutting 

of forests should be avoided because it reduces biomass and biological diversity. Further, 

the loss of vegetation results in the rapid loss of nutrients from the soil, which eventually 

reduces the productivity of the entire ecosystem. Both biomass production and biological 

diversity decline as a result.” (Pimentel et al. 1992) (Marily Woodhouse of Battle Creek 

Alliance)

Response: The comment is not clear on how the information provided regarding logging 

and forest diversity should be analyzed within the context of EPA’s evaluation of BACT 

and impacts on air quality. The comment does not include any specific information or 

facts demonstrating that EPA’s analysis or determination was incorrect or flawed. The 

comment does not supply sufficient detail for EPA to respond further. 

10.12 Comment: An increase in ash production from the amount of 525,600 pounds per year to 

16,293,600 pounds per year will require a great deal more transportation (increasing fuel 

usage and coincident air quality impacts) and more landfill space. The ash is mixed with 

water for disposal. Some ash may also have high concentrations of heavy metals, 

depending on what is being burned. (Marily Woodhouse of Battle Creek Alliance)

Response: The comment is not clear regarding how ash production at the facility should 

be analyzed within the context of EPA’s evaluation of BACT and impacts on air quality. 

EPA processed SPI’s PSD application in accordance with the PSD regulations in 40 CFR 

52.21 and the public participation requirements in 40 CFR part 124. EPA conducted a 

BACT analysis for NOx, CO, PM, PM10, PM2.5 and GHGs since these pollutants result in 

emissions increases that are significant as defined in 40 CFR 52.21 (b)(23). EPA also 

conducted an air quality analysis for these pollutants (except for GHGs since no NAAQS 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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has been established for this pollutant) based on our independent review of the SPI’s air 

quality modeling and monitoring data submitted as part of the PSD application and 

through discussions with the Federal Land Managers for nearby Class I areas (i.e., 

national parks and similar federal lands). EPA determined that the emissions increases 

from the proposed project will not cause or contribute to a violation of any NAAQS or 

applicable PSD increment. The comment does not include any specific information or 

facts demonstrating that EPA’s analysis or determination was incorrect or flawed. The 

comment does not supply sufficient detail for EPA to respond further. 

10.13 Comment: Fueling this plant will cause an increase in fuel consumption for 

transportation that will use many more hundreds of thousands of gallons of diesel. This 

is another cumulative impact that is being ignored. (Marily Woodhouse of Battle Creek 

Alliance)

Response: Tailpipe emissions from vehicles used at the facility are not regulated under 

the PSD program. The PSD program applies to stationary sources. EPA addressed a 

similar comment in our response to comment #18 in our 2013 RTC. 

10.14 Comment: SPI, and their proponents, have made a point of talking about the handful of 

jobs that the expanded plant could provide. Shasta County has a population of 177,223 

people; Tehama County has 63,463 people. The other surrounding counties number 

additional tens of thousands more people. All of these people will be impacted by 

reduced air quality, water loss, and loss of forest cover. The EPA is a public agency that 

should be acting in the best interests of the majority of the population. This permit must 

not be modified to allow huge increases in cumulative impacts. (Marily Woodhouse of 

Battle Creek Alliance)

Response: EPA’s 2012 AAQIR analyzed air quality impacts and concluded that the 

proposed project will not cause or contribute to a violation of the NAAQS or PSD 

increments. See also, 2013 RTC at 3-5. 

10.15 Comment: Barnosky et al. published a scientific paper in 2012 that examined the 

potential of biological systems to change suddenly at all scales, from local to global. 

They wrote: “Localized ecological systems are known to shift abruptly and irreversibly 

from one state to another when they are forced across critical thresholds. It is now well 

documented that biological systems on many scales can shift rapidly from an existing 

state to a radically different state. Biological states are neither steady nor in equilibrium. 

The shift from one state to another can be caused by either a ‘threshold’ or a 

‘sledgehammer’ effect. State shifts resulting from threshold effects can be difficult to 

anticipate, because the critical threshold is reached as incremental changes accumulate 

and the threshold value generally is not known in advance. By contrast, a state shift 

caused by a sledgehammer effect--for example the clearing of a forest using a bulldozer-- 

comes as no surprise. In both cases, the state shift is relatively abrupt and leads to new 

mean conditions outside the range of fluctuation evident in the previous state. Humans 
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have already changed the biosphere substantially. The biological resources we take for 

granted at present may be subject to rapid and unpredictable transformations within a few 

human generations.” We call upon the EPA to act with foresight and knowledge to 

protect the future. The corollary significant effects that enlarging this biomass plant 

would contribute to must be acknowledged, not ignored. (Marily Woodhouse of Battle 

Creek Alliance)

Response: The comment is not clear how the information provided should be analyzed 

within the context of EPA’s evaluation of BACT and impacts on air quality. The 

comment does not include any specific information or facts demonstrating that EPA’s 

analysis or determination was incorrect or flawed. The comment does not supply 

sufficient detail for EPA to respond further. 

10.16 Comment: I would like to show my support of this project. As a lifetime resident of 

Anderson and business owner in Anderson, SPI has always been such a good neighbor 

and community supporter. My facility is across the street from SPI, and SPI is a good 

neighbor. They are a good company with good business ethics. I see no reason this 

project should not move forward. We need the quality jobs this project will provide. 

(Tom Water of Harvest Printing)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis. 

10.17 Comment: I'm the Superintendent of the high schools located in the south of Shasta 

County. I’d like to say that Sierra Pacific is not in our community. They are part of our 

community. They support a multitude of projects around here that benefit our kids at the 

high school level, whether it's grant programs or educational programs that without their 

assistance we would not be able to duplicate. They have been supportive for many, many 

years and they’re a part of the fiber that exists down here, and they’ve always been 

responsive and responsible to our community. I would say that down the road if there is 

an issue, that there are plenty of government agencies, because I deal with a bunch of 

them, I'm sure they would step in and advise them on how to correct them and stuff. Like 

I said, they've always been responsive. They’re a part of what exists here. It would 

create jobs and jobs are an important part of a community. Jobs that support families and 

families generate kids and schools, it’s just a domino effect. We have an excellent 

relationship with Sierra Pacific even as a school district. They have no need to help us, 

and they always have. And they’ve always been responsible about the manner in which 

they do it. So we would ask also that this project be approved and to support the 

community. (Tim Azevedo)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.
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10.18 Comment: I’m speaking from two perspectives tonight. The first is as a member of the 

Board of Directors of the Economic Development Corporation in Shasta County. I’ve 

been asked by Chairman, Wayne Pohlmeyer, and Executive Director, Mark Lascelles, to 

provide full support on behalf of the Board of the EDC, for Sierra Pacific’s request. It 

not only offers a number of jobs in the construction phase, but also for the long haul, and 

we think it’s a very viable project and a good project. Secondly, I’m speaking as a 

Certified Public Accountant. My firm represents a number of contractors, log truckers, 

timber fallers, who represent literally thousands of employees who are employed 

indirectly by Sierra Pacific Industries. These people work hard in the woods to literally 

remove every component of the harvested timber and bring it to the mill, including now 

slash that had previously been burned in the forest, now will be brought in to support this 

cogeneration plant. It’s a good project, a clean project and I sincerely hope EPA will 

respond favorably on Sierra Pacific's request. (Dave Scott)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.

10.19 Comment: I’m a lifetime resident of Shasta County pretty much. I grew up watching a 

number of lumber mills that functioned in our county. We watched those dry up and go 

away. Now we have an opportunity to make things a little bit better for our community 

by having a project like this. This is a good thing economically, job creating and 

supporting the community, which we desperately need. These people have worked and 

been good neighbors to all of us, whether it’s the county or this city. They’ve done an 

excellent job and being involved in our community. I think if they have done everything 

required of them when they received that permit some time ago, and then we come back 

again because we have to have more public hearings, which sometimes cause more 

delays and more delays and we get nowhere. I strongly encourage that the EPA get 

behind this project and support what Sierra Pacific is trying to do and help keep our 

community strong. (Butch Schaefer)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.

10.20 Comment: I am a former City Council member of Anderson. I also owned an insurance 

agency where I insured the trucks for the loggers and the logging operations, and many of 

these people were employed by Sierra Pacific in their mills. We have a cogeneration 

plant in Anderson. It’s never been a problem and Sierra Pacific has never been a problem 

to us. Although, they are not in the City Anderson, they are our best neighbor outside the 

city. They provide a lot of services here for the people that work for them. They live 

here. They trade here. They bring money into our community. Sierra Pacific has been a 

big supporter of our kids in this town and the schools. They support our fireworks that 

we have here and they support a lot of other things that we have. So if they have 

complied with it, I don’t know what the problem is, other than somebody just thinks, I 

guess, we should just keep going and keep having these hearings and whatever. They’ve 
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got their permit already. I don’t know why we have to keep doing this, but it’s taking up 

time. It’s preventing them from finishing their plan. But that will provide a lot of jobs in 

the city and county, and we need these jobs. We need this plant, and I wish it would get 

done now and give them their permit and let us go. (Norma Comnick)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.

10.21 Comment: I’m the Principal at the Anderson New Technology High School located 

about a few blocks from here, and we have many students who have benefited from 

scholarships that SPI has provided almost every year. SPI has always been a good 

neighbor to us. They participate on panels and judge our students’ projects as well as our 

senior boards each year. And we do need jobs in this community. I grew up here and 

watched the community change over time. We have students that are graduating, and 

many of them have to leave the area because they can't find jobs here, so jobs are very, 

very important to this community. (Pat Allison)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.

10.22 Comment: I have no connection to Sierra Pacific Industries. I’m a licensed civil 

engineer, structural engineer. I’ve lived in this community, had a business here for a lot 

of years. The Environmental Protect Act says that mitigation measures are to be 

examined. I think one that’s not examined nearly enough was spoken about from another 

speaker that we have control burns here every year. I think the mitigation measures 

should include the fact that that material could be carried down here, processed in the 

plants such as the one that SPI has proposed expanding as opposed to burning it in place. 

It’s certainly viable. It releases a lot more into the air than their plant. I looked it up 

again tonight, just to be sure I had the number correct. I got it from the U.S. Geological 

Survey site. One mature oak tree puts 165 tons of water emission into the air every year, 

one tree. Now, I’m not going to compare emissions from burning fires to oak tree 

emissions, but it’s astounding to find out the volume of water provided by one oak tree. 

So let’s talk about the volumes rather than the quality of the emissions. Guess how many 

oak trees there are between here and Redding. A thousand? Two thousand? Three 

thousand? Each one of them putting somewhere, conservatively, around 100 tons of 

water per year. Now, if somebody wants to multiply that out and come back, you could 

build a case that would be a flood plain. We’d drown with that much water. So when 

you start talking about emissions and you come up with 472 tons, 272 tons, it sounds 

huge, until you put it into comparison about what one oak tree has. Now again, I want to 

make it clear I’m not comparing water vapor to emissions from burning trees up at 

Whiskeytown Lake. I will add that my family has been in this area for over 140 years. I 

have now retired from my business and this area is extremely important to me. I am in 

the outdoors a lot. I do not want to see a degradation of the area any worse than it is. I 

think this is not going to affect it. It would be minuscule. Regarding SPI, I just finished 
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a long term on the Mosquito Board of Shasta County. We have had mild virus here, a lot 

of other things, and the SPI mill could have been a major contributor to this. They’re 

excellent. They work with us in every way keeping the mosquito populations down. It 

doesn’t get a lot of publicity, but they are a very good neighbor. They went out and 

worked with our people, used their cranes, along with other things. So as somebody else 

said, they are not just in this area. They are a part of this area. Secondly, this is my 14 

year of retirement, but I had an engineering planning business in town for a long time. 

When I sold that business ten or 12 years ago, I had 43 employees. I would say that firm 

now is down to 11 employees. We are in vital need of leadership-type jobs in this 

community. SPI, everywhere you look on the boards of community activities, they 

provide those kind of people. I don't have the number now, but it's been published how 

many hours SPI employees put in at public service. Now, I realize you can be a great 

neighbor and still be a terrible polluter. I hope I made the point to begin with that this 

pollution can be mitigated. It’s nowhere near the degree that’s been inferred by others 

and they are a wonderful neighbor. So I urge that their permit be approved. (John 

Dunlap)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.

10.23 Comment: Good evening and thank you for this opportunity to speak in favor of Sierra 

Pacific Industries’ application for a permit modification to allow for the construction and 

operation of an additional new cogeneration unit at their current site in Anderson. My 

name is Trish Clark. I served Shasta County as an elected official from 1986 to 2006, 

including terms as Mayor, City Councilman, Chairman of the Board of Supervisors, and 

have also served during that period on the Shasta County Air Quality Control Board. It 

was my privilege during that period to work closely with Sierra Pacific Industries on 

many projects, some of theirs and some of mine. They have for many years proven 

themselves to be good and responsible stewards of the land and the environment. In 

striving constantly to ensure a healthy future for their lands and their company, they also 

provide for the future of our community. They are totally involved in supporting a 

community where their facilities are located. They provide hundreds of good jobs, 

support for their employees and their families and they provide local scholarships for 

students and have financially supported projects throughout Shasta County. I and 

currently the President of the Frontier Senior Center in Anderson. Sierra Pacific has from 

the beginning been a willing partner in providing support for that ongoing operation, fully 

and dependent senior-owned non-government supported senior center. I am confident 

that this new cogeneration plant will in no way negatively impact this community and the 

city that has been my home since 1977. I thank you for your consideration and ask for 

swift approval of this project. (Trish Clark)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.
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10.24 Comment: First of all, I would like to thank everybody that came here, and I would like 

to thank Sierra Pacific for helping to bring people from the community here. I would like 

to thank Trish Clark who spoke. I would like to thank Shane Young and Dave Brown for 

being kind to me when I met with them at the corporate offices. And I would like to 

thank Curtis Brown for disagreeing with me. I'll try to answer a few questions from the 

audience and will put my very brief comments on the record. In terms of why are we 

doing this, we the Citizens For Clean Air decided to ask the EPA for a public hearing 

because they are the permitting agency and we were hoping that we could get the factory 

built cleaner using best available control technology, which according to [Omer Shalev] 

of the EPA, is not being used because of invention. So we would like to see the factory 

built cleaner. That's why we asked for the community to come and why we asked for the 

EPA to come here, so that we would have the factory built as clean as possible with the 

least amount of environmental impact to Shasta County, especially to the children who 

live here. 

In terms of what Curtis Brown said of the forest mismanagement, I am not going to 

disagree that the forests -- I mean, they’re in trouble. There’s a lot of fires, people 

operating on red burn days, cutting the trees down or operating lawn mowers or heavy 

equipment. That’s bad. Fires can start very easily in Redding, California. It’s a big 

problem. But that’s a separate issue from the building of a factory that relies entirely on 

biofuels to operate. I would only point out that the most impact that it has had on the 

Forest Service and USDA and the policy, the biggest lobbyist, is the timber. So there is 

some culpability of big timber in terms of how they lobby the USDA. I would encourage 

Sierra Pacific and all of the logging companies to use the power of logging to help protect 

our forests and help protect our community. (Celeste Draisner)

Response: The comment does not include any specific information or facts 

demonstrating that EPA’s analysis or determination was incorrect or flawed. The 

comment does not supply sufficient detail for EPA to respond further. 

10.25 Comment: My question to EPA – I’m trying to be brief here. My question to EPA is do 

factories require permits to operate? Because there are a lot of factories that Sierra 

Pacific owns and is operating that do not have permits to operate. Knauf fiberglass 

operated for at least three years without a permit to operate, while in violation of 

emission limits for particulate matter. And, you know, particulate matter you can’t see it, 

but it's dangerous. You can’t see radon, but it will kill you. So my question is -- is the 

current facility in Anderson, the 4 megawatt facility, doesn’t have a permit to operate. It 

expired on its two-year extension last January 19. So we’re modifying a permit that 

doesn’t exist. How do you do that? How do you modify a permit to build a much larger 

facility next door on a permit that doesn’t exist? (Celeste Draisner)

Response: EPA prepared the Proposed Permit and Revised Proposed Permit for this 

project in accordance with the implementing PSD regulations at 40 CFR 52.21, and 

issued the proposed decisions in accordance with EPA’s public participation regulations 
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at 40 CFR Part 124. The PSD program applies to the proposed construction of a new 

major facility or the major modification of an existing facility that is located in an area 

that is classified as attainment or unclassifiable with the National Ambient Air Quality 

Standards (NAAQS). EPA Region 9 is currently the permitting authority for issuing PSD 

permits in Shasta County, California, which is classified as attainment or unclassifiable 

with the National Ambient Air Quality Standards (NAAQS). EPA’s PSD action does not 

involve issuing a “permit to operate.” 

In addition to EPA’s PSD preconstruction permitting program, SPI’s facility is subject to 

the CAA’s title V operating permit program. Shasta County AQMD is currently the title 

V permitting authority for Shasta County. 40 CFR Part 70, App. A. Shasta County 

AQMD issued SPI’s initial title V operating permit in July 2000, renewed the title V 

operating permit in September 2006, and renewed the title V operating permit again on 

September 27, 2013. See also, In re Sierra Pacific Industries, Anderson Division, PSD 

Appeal No. 14-01 (EAB April 10, 2014) (Order Dismissing Appeal for Lack of 

Jurisdiction). 

10.26 Comment: On behalf of Sierra Pacific, I would like to thank you guys for taking your 

time and being here tonight. A little history about the project. This cogeneration project 

has been through proper permitting procedures in preparation of the draft Impact Report 

on July 9, 2009, in this very room. A scoping meeting was held July 21, 2009. The first 

draft Environmental Impact Report was published for 45 days, from August 6, 2010, to 

September 20, 2010. A recirculated draft Environmental Impact Report was published 

for 45 days, from September 2, 2011, to October 17, 2011, to address global climate 

change. A second recirculated draft of the Environmental Impact Report was published 

for another 45 days, from February 15, 2012, to April 2, 2012, addressing global climate 

change again. On June 14, 2012, the Environmental Impact Report was completed and in 

compliance with the California Environmental Compliance Act and CEQA guidelines 

and passed by the Shasta County Planning Commission. The Environmental Impact 

Report was appealed to the Shasta County Board of Supervisors on June 18, 2012. The 

Shasta County Board of Supervisors conducted a duly-noticed public hearing and 

considered the appeal on July 17, 2012. The Board of Supervisors passed and adopted 

the Environmental Impact Report on that day. The PSD application was determined to be 

administratively complete on October 4, 2010. EPA Region 9 received public comment 

from September 14, 2012, to October 17, 2012. The previous PSD was signed on 

February 19, 2013, and this PSD permit was appealed. That brings us to today, four 

years and five months later. This project has been under the most environmental scrutiny 

possible. Sierra Pacific Industries believes that this is a good project in every aspect. 

The plant and the state-of-the-art technology will be among the most efficient and most 

emission compliant of its type in the nation. The construction process will employ over 

50 workers from various local contractors. The new plant will employ 8 to 10 new 

permanent jobs, in addition to approximately 300 indirect jobs will be created in 

transportation, forestry and related fields. The new facility will create green power and 

renewable wood fiber sources. This will assist the state in obtaining 33 percent its power 
Responses to Public Comments on the Proposed PSD Permit Major Modification for SPI-Anderson 

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from renewable sources by 2020. Shasta County will benefit from the project with new 

tax revenue and continue job stability. The new facility will also prepare Sierra Pacific 

for growth for the future. SPI invests in new and better technology and continues to keep 

its plants modern. This commitment will keep SPI strong and demanding in a 

competitive industry for years to come. Sierra Pacific is a family-owned company and 

employs over 3,000 employees in California. We supply good paying stable jobs in the 

communities where we operate our facilities. Tonight we ask the EPA to approve this 

project so we can get people to work and start getting ready for the future. Thank you for 

your consideration. (Shane Young of SPI-Anderson)

Response: The comment does not include any specific information or facts 

demonstrating that EPA’s analysis or determination was incorrect or flawed. The 

comment does not supply sufficient detail for EPA to respond further. 

10.27 Comment: I’m here for myself. I’m a resident of Anderson. My kids go to Anderson 

schools. I really want to talk about two bullets on the display over here on the right. It’s 

talking about the best available control technology, determinations and also effects on 

ambient air. I look at ambient air in two different ways. One is looking at it literally on a 

facility on a postage stamp or in your car. I also look at ambient air as what’s happening 

in the county. There’s been a lot of speakers tonight talking about control burns, fires, 

things of that nature. That’s exactly what I look at when I look at ambient air. When I 

think of the effect of the proposed facility on ambient air, we need 20 of these facilities. 

It’s ridiculous to still have as many controlled burns that’s happened that put out so much 

more pollution that is uncontrolled. These facilities are first class. They reduce VOCs, 

CO and NOx emissions. CO2 stays the same, but it’s an incredible reduction. It’s by not 

having this facility having been approved earlier years ago, you know what, the effect 

today is there’s more pollution in the air today because this wasn’t approved years ago. 

(Dave Brown)

Response: The comment is not requesting in any changes to the PSD permit or EPA’s 

analysis.

10.28 Comment: [H]ow will this affect the community of people who rely on wood heat, when 

[SPI] uses all or most of the available pollutants? (Elray Kleis)

Response: The comment is not clear. EPA prepared the 2012 Proposed Permit and 

Revised Proposed Permit for this project in accordance with the implementing PSD 

regulations at 40 CFR 52.21, and issued the proposed decisions in accordance with 

EPA’s public participation regulations at 40 CFR Part 124. In accordance 40 CFR 52.21, 

EPA conducted a top-down BACT analysis; an air quality analysis to show that the 

proposed project will not cause or contribute to a violation of any NAAQS or applicable 

PSD increment, as well as an assessment of impacts on visibility and other conditions in 

nearby national parks and federal lands; and an additional impacts analysis. The 

comment does not supply sufficient detail for EPA to respond further.