U.S. Environmental Protection Agency

February 2013

Responses to Public Comments on the Proposed PSD Permit Major

Modification for Sierra Pacific Industries- Anderson Division
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Contents

I. INTRODUCTION ........................................................................................................................3

II. EPA’S RESPONSES TO THE PUBLIC’S COMMENTS........................................................................6

Comments Submitted by Mr. Russell Wade ........................................................................................ 6

Comments Submitted by Mr. C.T. Carden ........................................................................................... 6

Comments Submitted by Ms. Joy L. Newcom...................................................................................... 7

Comments Submitted by Mr. Marshall Knauss................................................................................... 7

Comments Submitted by Mr. Ken Archuleta....................................................................................... 8

Comments Submitted by Mr. Ed W. Coleman..................................................................................... 8

Comments Submitted by Ms. Mary Olswang...................................................................................... 8

Comments Submitted by Ms. Joan Coleman....................................................................................... 9

Comments Submitted by Ms. Heidi Strand of Citizens for Clean Air ................................................... 9

Comments Submitted by Mr. Rob Simpson of Helping Hand Tools .................................................. 10

Comments Submitted by Ms. Gretel Smith of Helping Hand Tools................................................... 19

Comments Submitted by Mr. Kevin Bundy of the Center for Biological Diversity (CBD)................... 22

Comments Submitted by Mrs. Scott and Ashley Wayman................................................................ 35

Comments Submitted by Ms. Patricia Lawrence............................................................................... 36

Comments Submitted by Mr. Dave Brown, Environmental Affairs and Compliance Manager of 

Sierra Pacific Industries- Anderson Division................................................................................... 38

APPENDIX........................................................................................................................................51

BACT FOR EMERGENCY ENGINE ....................................................................................................................51
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I. Introduction

The U.S. Environmental Protection Agency, Region 9 (EPA) proposed to issue a major

modification of the Prevention of Significant Deterioration (PSD) permit to Sierra Pacific 

Industries (SPI) for the SPI-Anderson Division facility (Facility) on September 14, 2012. The 

public comment period for the proposal (Proposed Permit)1began on September 13, 2012 and 

closed on October 17, 2012. During the public comment period EPA took comments on the 

proposed permit modification. 

The purpose of this document is to respond to every significant issue raised in the public 

comments received during the public comment period and explain what changes have been made 

in the final permit (Final Permit) as a result of those comments.

EPA announced the public comment period through a public notice published in the Record 

Searchlight (in English only) on September 14, 2012 and on Region 9’s website (in English) on 

September 13, 2012. EPA also distributed the public notice to the necessary parties in 

accordance with 40 CFR Part 124, including notices sent by mail on September 12, 2012 and 

email on September 13, 2012. Parties notified by EPA included agencies, organizations, and 

public members for whom contact information was obtained through a number of different 

methods, including requests made directly to EPA through Region 9’s website (or through other 

means) from parties seeking notification regarding permit actions in California, within the Shasta 

County Air Quality Management District (District), within Shasta County; and 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.

The Administrative Record for the Proposed Permit modification was made available at EPA 

Region 9’s office. EPA also made the Proposed Permit, the Fact Sheets and Ambient Air Quality 

Impact Report (AAQIR) and other supporting documents available on Region 9’s website.

During the public comment period, EPA received 15 comment letters and three requests for a 

public hearing. Responses to the public comments received are available in the following 

sections of this document.

EPA did not receive comments regarding the sufficiency of modeling for pollutants projected to 

have impacts below significant impact levels (SILs) for PM2.5. However, because of recent 

actions by EPA and a recent decision from the United States Court of Appeals for the District of 

Columbia Circuit, Sierra Club v. EPA, No. 10-1413, 2013 WL 216018 (Jan. 22, 2013), we are 

supplementing our analysis of the Project’s impacts on the annual PM2.5 National Ambient Air 

Quality Standards (NAAQS) and PSD increments for PM2.5. 

SILs are numeric values that may be used to evaluate whether a proposed major source or 

modification will cause or contribute to a violation of NAAQS or PSD increment. See 72 Fed. 

 

1 We note that EPA’s permitting regulations at 40 CFR Part 124 refer to proposed permits as “draft permits.” See 40 

CFR 124.6.
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Reg. 54112, 54138 (Sept. 21, 2007). The EPA has observed that if the source’s modeled impacts 

are below the level of the SIL for the relevant pollutant, this showing is often sufficient to 

demonstrate that the source will not cause or contribute to a violation of the NAAQS. 72 FR at 

54139. However, in the preamble of the final rule establishing SILs for PM2.5, EPA cautioned 

that there can be circumstances where a showing that the air quality impact of a proposed source 

is less than the PM2.5 SILs is not sufficient by itself to demonstrate that a source will not cause or 

contribute to a violation of the NAAQS or increment. 75 FR 64864, 64892-94 (October 20, 

2010); see also Sierra Club, 2013 WL 216018, at 5 (granting EPA request to vacate and remand 

regulatory text at 40 CFR 52.21(k)(2) because it does not allow permitting authorities the 

discretion to require a cumulative impact analysis, notwithstanding that the source’s impact is 

below the SIL, where there is information that shows the proposed source would lead to a 

violation of the NAAQS or increments). 

The AAQIR and further analysis included here show that the Project does not present the type of 

situation in which existing air quality in the affected area is already close to the NAAQS or PSD 

increment, such that a source with an impact below the PM2.5 SILs could nevertheless cause or 

contribute to a violation of the PM2.5 NAAQS or increment. As explained below, EPA’s 

conclusions that the Project will not cause or contribute to a violation of the NAAQS are 

supported by the background concentrations of PM2.5 in the area, modeling, and other factors. A 

cumulative impact analysis was not considered to be necessary to this conclusion.

Table 8.4-2 of the AAQIR shows that emissions from the Project are predicted to be below the 

SIL for PM2.5 (annual). See online docket #III.02, SPI-Anderson Ambient Air Quality Impact 

Report_12SEP12 at 33. Table 8.2-1 of the AAQIR provides the maximum background 

concentrations of PM2.5 that may be affected by the Project’s emissions. See AAQIR at 28. For 

PM2.5 (annual), where the Project’s modeled impact was below the SIL, the maximum 

background concentrations measured in the area are well below the NAAQS. The difference 

between the PM2.5 (annual) background concentration in the area and the NAAQS is 9.7 μg/m3

which is significantly greater than the PM2.5 annual SIL of 0.30 μg/m3. As noted in Section 

8.4.3.2 of the AAQIR, adding the Project’s predicted impact of 0.27 μg/m3to the existing 

background concentration yields a total concentration of 5.57 μg/m3 which is still less than one 

third of the NAAQS and leaves roughly 9.4 μg/m3remaining before the PM2.5 (annual) NAAQS 

is threatened. See AAQIR at 35.

In addition, other than SPI-Anderson’s projected emissions increases, there have been no actual 

emissions changes of PM2.5 from any new or modified major stationary source on which 

construction commenced after October 20, 2010, the major source baseline date for PM2.5

according to 40 CFR 52.21 (b)(14)(i)(c). See online docket #III.02, SPI-Anderson Ambient Air 

Quality Impact Report_12SEP12 at 34. Since the only source to consume PM2.5 increment in the 

area is SPI-Anderson, the applicant appropriately considered only the allowable emissions 

increase from the SPI-Anderson project in the annual PM2.5 increment analysis. Moreover, the 

predicted impact of the source for the PM2.5 (annual) NAAQS is well below the increment in the 

area. 

The applicant’s analysis also conservatively assumed that all PM emissions were comprised of 

PM2.5 emissions, and used PM emissions data as input to the modeling. As shown in Table 1.6-1 
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of EPA’s AP-42 Fifth Edition, Compilation of Air Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources, PM2.5 emissions from wood fired boilers equipped with 

electrostatic precipitators are expected to be roughly 65% of all filterable particulate emissions. 

Thus, actual PM2.5 impacts from the Project are expected to be considerably lower than those 

indicated in the modeled results and would not, therefore, be expected to cause or contribute to a 

violation of the PM2.5 (annual) ambient air quality standard or increment. 
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II. EPA’s Responses to the Public’s Comments

This section summarizes all significant public comments received by EPA and provides our 

responses to the comments. The full text of all public comments and many other documents 

relevant to the permit can be accessed online through EPA’s website at 

http://www.epa.gov/region09/air/permit/r9-permits-issued.html.

Comments Submitted by Mr. Russell Wade 

1. Comment: Our planet is heating as we put more and more carbon into the air trapping the 

infra-red rays of the sun and dehydrating our forests in the northen calif. 2011 set record 

temperatures in 15,000 areas in the U.S. we have had over a hundred square miles of 

forests burn, (this year) putting up even more carbon- just as Sierra Pacific clear cuts raise 

termperatures- a co-generation plant is a good idea for creating local energy- putting 

300,000 tons of CO2 in the air per year is stupid- this plant could be designed so the carbon 

output can be sequested. There is a big denial about the facts surrounding global warming 

we need to be reversing our carbon output-as presently designed the plant is only going to 

boost our carbon output. 

Response: The commenter has suggested that the new cogeneration unit should be 

required to sequester the carbon dioxide (CO2) emissions resulting from the combustion of 

various fuels. As noted in the Ambient Air Quality Impact Report (AAQIR), the 

modification was not subject to best available control technology (BACT) for the pollutant 

greenhouse gases (GHG) which is comprised of six gases, including CO2. Although the 

proposed modification identifies an increase in GHG emissions that exceeds the “subject to 

regulation” threshold of 75,000 tpy CO2e and GHG significance rate of 0 tpy, EPA’s 

Deferral for CO2 emissions from Bioenergy and Other Biogenic Sources under the 

Prevention of Significant Deterioration and Title V programs (76 FR 43490 July 20, 2011) 

applies to this project.

Comments Submitted by Mr. C.T. Carden

2. Comment: I have lived in N. Calif since 1964- in the forested areas. Our woods are 

crambed full of vegetation waiting for a forest fire. There is a great need to deforest (clean 

up) many of the chocked areas. S.P.I (Sierra Pac.) can help save (manage) these areas by 

burning (“hog fuel”) at their Anderson Co-Gen plant- Everybody wins with this plant for 

gen. electricity. We need electricity and cleaning up the forest at the same time. Please 

allow the And. Calif (Riverside Ave.) plant to build the co-gen. plant for the benefit of 

everybody. We need the jobs too. Thank you.

Response: The modification allows for the construction of a cogeneration unit at the 

existing SPI-Anderson facility. Fuels to be combusted in the new unit will be restricted to 

biomass and natural gas as detailed in the final permit.
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Comments Submitted by Ms. Joy L. Newcom

3. Comment: Please Please Please DO NOT PERMIT Sierra Pacific I. Please Please Please 

outlaw and shut them down. Their ATROCIUS Air Quality in this sink-bowl surrounded 

by 10,000+ foot mountain ranges, absolutely, cannot, handle any more particulate or 

chemical pollution!!! We’ve become way too populated with retired, disabled, infants, 

children and sensitive populations. S.P.I. need to build its plant in Nevada, or Sand, CA (by 

desalination plant.) 

Response: EPA’s permit action is for granting SPI the authority to construct new emission 

units at the existing SPI-Anderson location. Shasta County is in attainment or unclassifiable 

for all pollutants regulated under the PSD program. Moreover, The Clean Air Act identifies 

two types of NAAQS. Primary standards provide public health protection, including 

protecting the health of "sensitive" populations such as asthmatics, children, and the 

elderly. Secondary standards provide public welfare protection, including protection 

against decreased visibility and damage to animals, crops, vegetation, and buildings. In the 

AAQIR for this action, EPA demonstrated air pollution emissions from the new 

cogeneration unit will not cause or contribute to violations of any NAAQS or any 

applicable PSD increments for the pollutants regulated under the PSD program.

Comments Submitted by Mr. Marshall Knauss

4. Comment: I live across the highway from S. P. in Anderson and the last week or so I've 

noticed alot of brown smoke coming out of the generating facility they already have. My 

question is have they only started running it in the day time recently. I don't ever remember 

seeing the smoke. I figured they only ran at night .I would have to be against it if we will 

be increasing the amount of brown smoke--- SMOG-- IF YOU WILL INTO THE AIR.

Response: EPA‘s permit action is for granting SPI the authority to construct new emission 

units at the SPI- Anderson location. As stated in response to comment#3, this modification 

is not expected to cause or contribute to any NAAQS violation. EPA is not aware of 

increased air emissions at the SPI-Anderson facility at this time. However, after discussions 

with the District regarding this issue, EPA received the following information from the 

District on October 1, 2012: 

[T]here is a small 6 [megawatt] cogeneration plant located adjacent to SPI, near 

the northwest corner. This facility has undergone some retrofitting and is currently 

undergoing start-up testing. An Authority to Construct for Anderson Plant, LLC 

(Kiara Solar) was issued by the District on 10/1/10. This plant was included in the 

emission modeling during SPI’s application and EIR process.

The reason for this notification is to prevent any confusion... that could potentially 

arise from a passer by who might think that this is the SPI plant. This source is 

very visible from HWY 273 and people do confuse it with the SPI Anderson plant 

from time to time.
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Comments Submitted by Mr. Ken Archuleta

5. Comment: I am in favor of granting the permit modification to allow construction of a 31 

megawatt power plant.

Response: EPA’s permit action is for granting SPI the authority to construct a new 31 

MW emission unit at the SPI- Anderson location, an existing PSD major stationary source 

of air emissions. 

Comments Submitted by Mr. Ed W. Coleman 

6. Comment: Received your latest info on the “sierra Pacific Ind.” Anderson Calif. Division 

modification permit! They have been nothing short of a major polluter in the past, and have 

shown gross lack of compliance! We proved this with our own “Citizens for Cleaner Air”

contract with a private testing company! If the USEPA uses the proper pollution scale, we 

feel that environmental justice is served!

Response: It is unclear from the commenter’s statement what pollution scale should be 

considered in relation to this facility with regard to the PSD program. EPA requested public 

comment on its proposed action relating to the major modification of the PSD permit for 

SPI- Anderson. EPA’s proposed PSD permit would grant conditional approval, in 

accordance with the PSD regulations (40 CFR 52.21), to SPI to construct and operate a new 

cogeneration unit at its existing Anderson facility. The AAQIR that serves as the basis for 

this action which demonstrates that the facility as modified would not cause or contribute 

to a violation of the NAAQS. As discussed in response to comment# 3, the NAAQS were 

set to provide public health protection, including protecting the health of "sensitive" 

populations such as asthmatics, children, and the elderly.

Comments Submitted by Ms. Mary Olswang

7. Comment: I am writing with concerns about the SPI proposed cogeneration plant in 

Anderson, CA, Shasta County. I oppose the project.

It is estimated this plant will emit 330,000 tons of greenhouse gases annually. It is counter 

productive for the EPA to approve such projects while also supporting clean air policies. In 

this age, we cannot afford to dump more toxic waste into our atmosphere. 

Are there not alternative to disposing of their waste, like composting? Enriched soils can be 

used for growing new trees.

Response: As stated in the AAQIR, the proposed modification identifies an increase in 

GHG emissions that exceeds the “subject to regulation” threshold of 75,000 tpy CO2e and 

GHG significance rate of 0 tpy. However, EPA’s Deferral for CO2 emissions from 

Bioenergy and Other Biogenic Sources under the Prevention of Significant Deterioration 

and Title V programs (76 FR 43490 July 20, 2011) applies to this project. Since the nondeferred GHG emissions for this project are 38,252 tpy CO2e, the modification is not 

subject to BACT for GHG and a resulting control technology review for GHG was not 
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conducted. The deferral for CO2 emissions from bioenergy and biogenic sources under the 

PSD program was applied to those CO2 emissions that result from the combustion of 

biomass. 

Comments Submitted by Ms. Joan Coleman 

8. Comment: I wish to express my opposition to the permit before you to build a 31 

megawatt wood burning power plant north of Anderson. As you know this will be in 

addition to the 6 wood burning power plants in Shasta County. The plant will emit about 

330,000 tons of greenhouse gases annually. All 6 plants would then be generating about 

2.16million tons of greenhouse gases annually. The State says Shasta County already 

receives 26.5 TON of carbon monoxide released into the air DAILY. It is unreasonable to 

allow this plant to increase our air pollution The EPA should deny the permit.

Response: Please see response to comment #7 in regard to GHG emissions. 

The PSD program is intended to protect air quality in “attainment areas”, which are areas 

that meet the NAAQS. The District is currently in attainment of the NAAQS for CO. As 

stated in the AAQIR, air pollution emissions from the new cogeneration unit will not cause 

or contribute to violations of any NAAQS or any applicable PSD increments for the 

pollutants regulated under the PSD permit, including CO.

Comments Submitted by Ms. Heidi Strand of Citizens for Clean Air

9. Comment: The commenter states that the cogeneration unit must be issued a “new PSD 

permit.” EPA is clearly violating the intent of Executive Order #12898 with regard to 

Environmental Justice by circumventing the entire PSD permitting process. The commenter 

also requested a public hearing on a number of issues, ranging from how BACT is applied 

to information with regard to environmental violations at the facility and air pollution 

credits available in Shasta County. The commenter states that EPA disenfranchises 

members of the public from the public process by not holding a public a hearing. 

Response: SPI- Anderson is undergoing a physical change and or change in the method of 

operation that results in a significant emissions increase of several regulated NSR 

pollutants at the existing major stationary source. This corresponds to the definition of 

major modification as defined in 40 CFR 52.21(b)(2)(i). The new equipment at the site is 

being issued a PSD permit. See online docket #III.01, SPI-Anderson Proposed PSD Permit 

Modification_12SEP12. EPA is requiring the source to satisfy the requirements under 40 

CFR 52.21 as documented in the AAQIR, it is unclear why the commenter believes that 

EPA is circumventing the PSD permitting process. 

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 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.” Section 1-101 of Exec. Order 12898, 59 Fed. 
10

Reg. 7629 (Feb. 16, 1994). The AAQIR concluded that the proposed modification will not 

cause or contribute to air quality levels in excess of health standards for the pollutants 

regulated under EPA’s proposed PSD permit for the proposed modification, and that the 

project will not result in disproportionately high and adverse human health or 

environmental effects with respect to these air pollutants on populations residing near the 

SPI- Anderson site, or on the community as a whole.

EPA reviewed demographic data for the community surrounding the immediate project 

area prior to proposing the permit and issuing public notification materials in accordance 

with 40 CFR Part 124. In particular, EPA considered socioeconomic, linguistic isolation, 

education and other relevant factors to help inform our public outreach activities. Prior to 

noticing the proposed permit decision, EPA conducted a review of U.S. Census Data to 

determine whether outreach materials should be provided in a language other than English. 

EPA's review found that the cities of Anderson and Redding, along with Shasta County had 

less than 2.5%, 1.5% and 1.5% of all households listed respectively as linguistically 

isolated. Moreover EPA contacted the local air district to learn whether the district had 

received complaints, concerns, or requests regarding the publication of public notices in a 

language other than English for any prior permitting actions. District personnel stated that 

they had not received such complaints, concerns, or requests. Based on EPA's review and 

conversations with the local air district, EPA determined that outreach materials would not 

be translated into another language. EPA's public engagement activities included the 

mailing of roughly 800 public notices in the area surrounding the SPI- Anderson and in the 

state of California, emailing roughly 650 recipients and publishing a notification of the 

Project in the Record Searchlight on September 14, 2012. The Record Searchlight also 

published a separate article about the Project modification on September 22, 2012..

Pursuant to 40 CFR 124.12, EPA must hold a public hearing if it, on the basis of requests, 

determines there is a significant degree of public interest in a draft permit. After 

distributing the public notice to the necessary parties in accordance with 40 CFR Part 124

and additional members of the public, EPA received comments from 15 members of the 

public, including the applicant, and three requests for a public hearing. None of the requests 

for a public hearing demonstrated that there was significant public interest in the Project;

therefore EPA did not hold a public hearing. EPA reviewed and responded to all written 

comments from the public received during the public comment period. 

With respect to the comments regarding air pollution credits, the PSD program is intended 

to protect air quality in “attainment areas”, which are areas that meet the NAAQS. The 

District is currently in attainment or unclassifiable for all of the NAAQS. The PSD 

permitting program does not require emission offsets, commonly referred to as air pollution 

credits, to be surrendered prior to construction of an applicable source. 

Comments Submitted by Mr. Rob Simpson of Helping Hand Tools

10. Comment: On September 26, Mr. Simpson requested an extension of the public comment 

period because this is the first time he would provide comments on this type of facility and 

that the record contained numerous materials that could not be adequately reviewed within 

the allotted time. 
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Response: Our September 28, 2012 response is copied below:

Dear Mr. Simpson,

We received your questions regarding the proposed PSD permit modification for SPIAnderson. Let me first address your request for a public comment period extension. In 

order for EPA to extend the public comment period beyond the currently scheduled end 

date of October 17, 2012, a commenter must adequately justify why additional time is 

required in order to comment on the proposed action. While your request states that there 

are many documents to review, the number of documents for this project is no different 

than any other project, and you have not demonstrated why there would be a significantly 

greater burden to review the documents for this project. Thus, we do not plan to extend the 

public comment period at this time.

Finally, regarding the application materials, they can be found in the online Docket no. 

EPA-R09-OAR-2012-0634. The majority of the application information can be found in 

I.01, but additional important materials are also included in I.03, I.05, I.07, I.08, I.25, I.31, 

I.33, I.34. Document I.08 contains a Greenhouse Gas emissions estimate and discussion. 

The other items listed above contain additional emissions estimates, modeling information 

and other relevant material.

Thank you for your interest in EPA's proposed action. I hope you find this information 

useful.

11. Comment: On October 17, 2012, the commenter requested a public hearing and an 

extension of the public comment period. The commenter stated that the record is too 

extensive to review in the allotted time period.

Response: As we stated in our earlier reply to the commenter’s first request for an 

extension to the public comment period, the size of the record for this project is similar to 

that for other projects, and the commenter did not demonstrate a significantly greater 

burden to review the documents for this project. With regard to the commenter’s request 

for a public hearing, please see our response to comment #9 above. We note that none of 

the three requests for a public hearing demonstrated that there was significant public 

interest to warrant a public hearing.

12. Comment: The commenter stated that EPA only provided an English version of the public 

notice and that a public notice in Spanish should also have been provided. The commenter 

claims EPA failed to demonstrate that it notified participants in the State action(s) and the 

appropriate elected officials. Moreover, the commenter states that the public notice fails to 

disclose any effect on air quality and the Project’s effects in relationship to the NAAQS or 

at least in gross pollutant weights. 

Response: EPA distributed the public notice to the necessary parties in accordance with 

40 CFR Part 124, including notices sent by mail on September 12, 2012 and email on 
12

September 13, 2012 and publication in the Record Searchlight on September 14, 2012. 

Parties notified by EPA included agencies, organizations, and public members for whom 

contact information was obtained through a number of different methods, including 

requests made directly to EPA through Region 9’s website (or through other means) from 

parties seeking notification regarding permit actions in California, within the District, 

within Shasta County; and 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 CEC, the District, and other local neighboring 

air districts.

40 CFR Part 124 states that public notice of activities shall be given by mailing a copy of 

the notice to “the chief executives of the city and county where the major stationary source 

or major modification would be located” and EPA mailed the public notice to the city 

manager of Anderson, CA and the Chairman and Clerk of the Shasta County Board of 

Supervisors. It is unclear what the commenter means by “appropriate elected officials” as 

EPA mailed officials at the county and city level.

The translation of public notices is not required by 40 CFR Part 124, and EPA determined,

after discussing the public notification practices of the District that Spanish translation was 

not required. Prior to noticing the proposed permit decision, a review of U.S. Census Data 

in the area found that the cities of Anderson and Redding, along with Shasta County had 

less than 2.5%, 1.5% and 1.5% of all households listed respectively as linguistically 

isolated. Moreover, the District stated that it had not received complaints, concerns or 

requests regarding the publication of public notices in a language other than English for 

any prior permitting actions. 

EPA’s public notice included appropriate information as required by the public notice 

content requirements in 40 CFR 124.10(d). We note that the public notice did state that 

“[a]ir pollution emissions from the new cogeneration unit will not cause or contribute to 

violations of any National Ambient Air Quality Standards (NAAQS) or any applicable 

PSD increments for the pollutants regulated under the PSD permit.”

13. Comment: The commenter states that the facility apparently requires 7 of the 23 

megawatts electricity that it can generate. No state authority has, or is, required to make a 

determination if the electricity in this location is beneficial to the system. The project will 

interfere with the development of superior solar and wind alternatives. The commenter also 

states that a solar component should be considered in the BACT analysis.

Response: EPA, the permit issuer for this project, does not have an obligation to 

independently investigate all possible power generation alternatives, including a no-build 

alternative. Further, the Environmental Appeals Board has observed the importance of this 

limitation on the permit issuer's obligation, particularly where the evaluation of need for 

additional electrical generation capacity would require a rigorous and robust analysis and 

would be time-consuming and burdensome for the permit issuer. In such circumstances, the 

permit issuer is granted considerable latitude in exercising its discretion to determine how 

best to apply scarce administrative resources. 
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EPA has noted previously that in general, in California, in order to conduct a reasoned 

analysis to determine the need for new power plants in general, or a specific power plant in 

particular, either within the State as a whole, or in a particular geographic location within 

the State, EPA would need to consider a myriad of extremely complex factors and detailed 

information that EPA has neither the resources nor the expertise to analyze. This reasoning 

also applies in this case. The Region has the discretion, but is not required, to conduct an 

independent analysis of the need for all possible power generated by SPI in the context of 

this PSD permit proceeding. In this case, EPA does not believe that it is appropriate to 

conduct the type of rigorous and robust analysis that would be required to definitively 

determine the need for the Project. Even if EPA did have the expertise and resources to 

conduct such an analysis, the commenter has not provided any information on which to 

conduct such an analysis.

A solar component for this Project presents a significant departure from the existing 

facility’s operations and the Project’s purpose. In this instance, the existing lumber facility 

will add equipment within its existing physical footprint and utilize the excess biomass at 

this and other SPI sawmill or lumber operations.

14. Comment: The fuel mix should be considered in the BACT analysis for the project and 

the analysis fails to consider a different fuel mix. Increased gas use can raise the 

temperature and reduce emissions through more complete [combustion].

Response: The Project calls for a new cogeneration unit to be located at an existing 

lumber manufacturing facility. The cogeneration unit will consist of a biomass-fired boiler, 

a steam turbine, and a generator. According to SPI’s 2010 Application, SPI intends to use 

biomass from existing SPI facilities, as well as in-forest materials and various sources of 

agricultural and urban wood waste. Therefore, an inherent aspect of the project is that its 

fuel use be primarily biomass. The new boiler will also be capable of burning natural gas. 

The permit limits the amount of natural gas to be combusted to 10% of all heat input into 

the boiler. EPA believes that this limit is appropriate as the combustion within the boiler 

may need to be stabilized while burning biomass and to assist with the startup and 

shutdown of the boiler. While EPA recognizes that fuel mixtures affect the emissions of 

pollutants, it is unclear what mix the commenter is ultimately recommending and where 

this should be incorporated into the analysis. If the source changed its fuel mixture then 

numerous other considerations would need to be made, such as whether a boiler is an 

appropriate alternative and resulting control technologies. Moreover, alternative fuel mixes 

would change the profile of pollutants emitted in a myriad of ways where some pollutants 

would increase and others would decrease depending on the exact mixture. 

The commenter references different discussions related to the BACT analysis of GHG 

emissions where biomass could be considered, but the Project was not subject to the PSD 

program for GHGs because of the restriction to burn predominantly biomass and only up to 

10% of natural gas on a 12-month rolling basis. See AAQIR at 9.
14

15. Comment: The commenter states that the BACT analysis fails to adequately consider 

energy efficiency options. There should be no need for cooling towers and their associated 

emissions to dissipate heat. The heat should be used in the existing kiln or in a new kiln. 

The commenter also states that the permit should consider the existing kiln as permitted 

equipment and that the existing kiln should undergo a BACT analysis. 

Response: The BACT analysis in the AAQIR for the Project considers energy efficiency 

options where appropriate. As outlined in Section 4- Project Description of the AAQIR, the 

fuel combusted in the new cogeneration unit will produce steam that will be used in the 

existing lumber operations and for feeding a turbine that will drive a generator to produce 

electricity for use on site or for sale to the electrical grid. Utilization of the existing kilns at 

the facility does not negate the need for heat dissipation that may result from the 

combustion of additional biomass for electrical generation. 

The AAQIR analyzed contemporaneous emissions changes resulting from the Project. As 

stated in the application, “the installation of the boiler will not increase emissions from any 

existing emission units at the Anderson mill. There have been no contemporaneous 

modifications at the Anderson mill.” See online docket #I.01: SPI-Anderson PSD Permit 

Modification Application_25MAR10 at 3. As a result, the existing kilns are not expected to 

undergo a change in the method of operation that would result in an increase in emissions 

of NSR regulated pollutants. Therefore, the existing kilns were not subject to a BACT 

analysis. 

16. Comment: The commenter states that the permit should identify the existing equipment 

and require its retirement, and that the administrative record demonstrates that the permit 

should require that existing units should not operate concurrently with the new units.

Response: Table 4-2 of the AAQIR identifies existing equipment. See AAQIR at 7. As 

noted by the AAQIR, we did not include this existing equipment in EPA’s PSD permit 

because it is already permitted by SCAQMD. Both permits (SCAQMD’s permit and EPA’s 

permit) will be in effect and enforceable.

With regard to the commenter’s assertion that existing equipment should be retired, we 

note that many of the existing emissions units support the existing sawmill operations, and 

that retirement of these units could essentially result in a shutdown of the mill. Requiring 

retirement of existing units would be inconsistent with the application submitted to us. We 

note that SPI’s application analyzed emissions from the Project assuming that the existing 

boiler would continue to operate; in other words, SPI’s application did not claim any 

emission reduction credits from shut down of the existing boiler. Generally, if a company 

chooses to shut down existing equipment, EPA’s PSD regulations will allow the permitting 

authority to consider emission reductions from the shutdown equipment in projecting 

emissions increases from the new equipment. If the project’s net emissions remain below 

EPA’s PSD major modification thresholds, the project would not be subject to federal PSD 

requirements for BACT, ambient air quality impacts, etc. SPI’s application, however, did 

not present such a netting analysis, and we have processed it as an application for a major 

modification requiring a PSD permit. We also note that the commenter did not provide any 
15

legal or factual reasons to explain why he believes that EPA should require the retirement 

of existing units at the facility, and we are not aware of any in SPI’s application or 

elsewhere in the record.

With regard to the commenter’s assertion that the permit should require that existing units 

not operate concurrently with the new units, we understand the commenter to be referring 

to concurrent operation of the existing boiler and the new boiler. We note that SPI’s 2010 

application states that “the existing and proposed boiler would not operate concurrently 

other than some overlap during startup and shutdown.” See online docket #I.01: SPIAnderson PSD Permit Modification Application_25MAR10 at 9. Therefore, the application 

can be understood as stating that SPI will, at times, operate the boilers concurrently. The 

commenter did not provide legal or factual reasons that would support a permit condition 

prohibiting concurrent operation, and we are not aware of any in SPI’s application or 

elsewhere in the record.

17. Comment: The commenter states that EPA has no authority to modify the underlying 

State permit.

Response: As explained in our public notice, this permit modification is a modification to 

an existing PSD permit issued by Shasta County AQMD to SPI in 1994. The original PSD 

permit was issued by Shasta County APCD, pursuant to a delegation of EPA’s PSD 

permitting authority under 40 C.F.R. Part 52 to Shasta County AQMD. In 2003, EPA 

rescinded the PSD delegations for several California air districts, including Shasta County. 

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.

18. Comment: The commenter states that the analysis fails to consider the emissions 

associated with the collection, transport and handling of biomass. Also, the commenter 

states that a permit condition should require that all associated equipment operates on 

methane gas or biomass power. 

Response: Fuel handling equipment, as stated in the AAQIR, is currently permitted under 

the existing PSD permit issued by the District. Moreover, mobile tailpipe emissions from 

the facility are not regulated under the PSD program. The commenter provided no legal or 

factual basis for his assertion that the permit should include a permit condition requiring 

that all associated equipment operates on methane gas or biomass power. Such a condition 

would be technically infeasible. Although the permit limits natural gas heat input on an 

annual basis, natural gas may be needed during startup, shutdown and for combustion 

stabilization at multiple times during the facility’s operation. Requiring associated 

equipment to only operate on biomass power or inappropriately limiting the use of natural 

gas could be detrimental to the equipment used for the facility’s normal operation.

19. Comment: The commenter states that the analysis fails to consider increased kiln 

emissions and other operational emission increases. The commenter also states that the 

project should be based upon a comparison to the actual baseline instead of prior permit 

levels.
16

Response: Table 6-1 of AAQIR summarizes estimated emissions from the Project. 

Contrary to the commenter’s assertion, we did not evaluate the Project using a baseline of 

prior permit levels. SPI stated that the Project will not increase emissions from any existing 

units. See online docket # I.01: SPI-Anderson PSD Permit Modification 

Application_25MAR10 at 4. Moreover, the applicant also stated that emissions increases 

from fuel handling operations were not projected to increase. See online docket #I.05: SPIAnderson_response_to_2nd_EPA_incomplete_letter-final_07SEP10. Therefore, projected 

actual emissions from existing units at the SPI- Anderson facility were assumed to be equal 

to baseline actual emissions. 

The Project consists of three new emission units and, consistent with EPA’s regulations at 

40 CFR §52.21(a)(2)(iv)(c), (d) and (f), we evaluated the Project using an actual emissions 

baseline of zero for the new emission units. See online docket # I.01: SPI-Anderson PSD 

Permit Modification Application_25MAR10, at Tables 2-1 and 2-2; #I.41: SPI-Anderson 

Annual Emissions MEMO_05SEP12. Tables 2-1 and 2-2 of SPI’s 2010 Application and 

Table 6-1 of EPA’s AAQIR summarize the estimated emissions increases from the Project 

and our conclusions that the Project would exceed the significance levels for CO, NOx, PM, 

PM10, and PM2.5. We note that use of the baseline suggested by the commenter would not 

necessarily lead to additional procedural or substantive requirements for this Project 

because EPA and SPI analyzed the Project with a baseline of zero – as such, all emissions 

increases from new equipment were considered in our analysis.

20. Comment: The air quality monitoring station 50 miles away.

Response: As was stated in Section 8.4.3.3 of the AAQIR: "Despite its distance from the 

project site, the monitor from Chico is conservative based on its proximity to a more 

industrial area at the north end of the Sacramento Valley." In addition, EPA has looked at 

the traffic counts near SPI- Anderson and near the Chico monitor and observed that they 

both have similar traffic counts and major highways nearby, I-5 and Highway 99 

respectively. Thus, the Chico monitor is not only representative of the background 

concentrations in the Project area, but also more conservative given its proximity to a more 

industrialized area and the similar number of traffic counts.

21. Comment: The commenter states that EPA failed to identify the environmental justice

community in the vicinity of the proposed project. It is inadequate for the EPA to skip this 

and simply claim no harm to any potential community without notification. 

Response: Please see the response to comment #9.

22. Comment: The commenter states that the analysis is misleading because it does not 

disclose that the project intends to burn urban wood or post consumer wood which would 

be more appropriately burned with a DLN burner. 

Response: EPA does not agree that our analysis is misleading. The new boiler will 

generate electricity from the combustion of biomass and not be permitted to burn waste that 
17

is not considered a traditional fuel. See response to the comment #86 for more detail. In 

particular, Condition X.G.1. in the PSD permit restricts fuel to natural gas and the 

following:

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

wood debris from urban areas;

b. All agricultural crops or residues;

c. Wood and wood wastes identified to follow all of the following practices; 

i. 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

ii. Harvested for the purpose of forest fire fuel reduction or forest stand improvement.

To the extent the commenter is stating that the new boiler should be equipped with a DLN 

burner, we note that, as stated in the AAQIR, estimated emissions from a boiler with DLN 

boilers are higher than the limits we have proposed for SPI’s new stoker boiler. See 

AAQIR at 13.

23. Comment: The commenter states the permit fails to require appropriate ash bunker waste 

disposal.

Response: We disagree. This PSD permit is intended to protect public health and welfare 

from actual or potential adverse effects that may reasonably be anticipated to occur from 

air pollution or from exposures to pollutants in other media that originate as emissions to 

the ambient air. The commenter did not specify any appropriate additional waste disposal 

requirements that he believes should be included in the PSD permit. We note, however, that 

the proposed and final permits include conditions for the wood waste and ash waste storage 

and transportation. In particular the following conditions in Section X.F. contain storage bin 

and ash transport requirements: 

5. Wood waste collection and storage bin leaks shall be minimized at all times. All 

indentified wood waste collection and storage bin leaks, spills and upsets of any kind 

shall be corrected or cleaned immediately, within 4 hours, as practicable, to correct the 

leak, spill or upset.

6. Wood waste collection and storage bins shall be emptied on a schedule that ensures that 

the cyclone-separator system does not become plugged.

7. Wood waste collection and storage bins, not including the fuel shed, shall remain 

enclosed to mitigate the fugitive emissions from the unloading process.

8. All ash shall be transported in a wet condition in covered containers or stored in closed 

containers at all times.

24. Comment: The commenter states, “EMx, SCR and Urea should be required.”

Response: The BACT analysis in AAQIR for the Project details why EPA is not requiring 

installation of an EMx or SCR. The commenter did not provide further legal or factual 

bases for his comment; therefore, it is unclear why the commenter believes this alternative 

control technologies should be required. 
18

25. Comment: The commenter states that consideration of the McNeil facility is entirely 

speculative and that additional analysis is required to distinguish the SPI project from the 

McNeil facility.

Response: We disagree. Our BACT analysis considered the State of Vermont’s permit for 

the McNeil Generating Station (McNeil), which has a stoker boiler controlled by 

regenerative selective catalytic reduction (RSCR) technology. The permit for the McNeil 

facility imposes several NOx limits, including Condition 11(g), which limits NOx emissions 

to 0.075 lb/MMBtu, averaged over a calendar quarter. See online docket #I.38: McNeil 

Generating Station Title V Permit, at 15. Condition F(c) of the permit, however, states that 

Condition 11(g) is enforceable only by state authorities and is not federally enforceable, 

whereas all other limits in the permit are federally enforceable. See online docket #I.38:

McNeil Generating Station Title V Permit, at 8-9. As stated in our AAQIR for the Project, 

we do not believe that this limit is the result of a BACT analysis or that it constitutes a 

BACT determination. See AAQIR at 15-16. We also note that, as shown in Table 7.1-1 of 

our AAQIR, the McNeil NOx emissions limit of 0.075 lb/MMBtu, is averaged over a 

calendar quarter, whereas the limit we have proposed for the Project is 0.15 lb/MMBtu, 

averaged over 3 hours, a much shorter, and therefore more stringent time period. We note 

further that Condition 11(a) in the McNeil permit imposes a limit of 0.23 lb/MMBtu (no 

averaging period specified) for NOx, which is higher than our short-term BACT 

determination for SPI of 0.15 lb/MMBtu (3-hour average). Thus, our BACT determination 

for NOx for SPI is as stringent, if not more stringent, than the McNeil emissions limit for 

NOx issued by the State of Vermont. The commenter has not made any demonstration as to 

why any further analysis needs to be performed or to what end.

26. Comment: The commenter states that the PSD increment trigger date for PM2.5 should 

have been when the original permit was issued 

Response: EPA disagrees. As noted in Section 8.4.3. of the AAQIR, the applicable trigger 

date for PM2.5 is October 20, 2011. 40 CFR 52.21(b)(14)(ii)(c). EPA correctly applied the 

appropriate trigger date and it is unclear why the commenter believes that a different PSD 

increment trigger date should have been used.

27. Comment: The commenter states that the analysis must demonstrate the nitrogen 

deposition on the adjacent elderberry plants.

Response: As stated in the AAQIR for the Project, EPA is required to ensure that any 

action authorized, funded, or carried out by EPA is not likely to jeopardize the continued 

existence of any endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. EPA concludes that the project 

will have no likely adverse effect on any endangered or threatened species or designated 

critical habitat. Discussions with the United States Fish and Wildlife Service (USFWS) 

support EPA’s conclusion.

The commenter did not provide a legal or factual basis for his assertion that EPA must 

demonstrate the nitrogen deposition on the elderberry plants. In particular, page 3 of the
19

July 9, 1999 Conservation Guidelines for the Valley Elderberry Longhorn Beetle from the 

USFWS states that “complete avoidance (i.e., no adverse effects) may be assumed when a 

100-foot (or wider) buffer is established and maintained around elderberry plants 

containing stems measuring 1.0 inch or greater in diameter at ground level.” See online 

docket #II.03: USFWS Conservation Guidelines of Elderberry Longhorn Beetle. As stated 

in our AAQIR, SPI has confirmed that construction activities will not occur within 100 feet 

of the elderberry shrubs that are in the Pacific Gas and Electric power line right of way and 

that the nearest construction activity to the existing elderberry plants will be the erection of 

the electrical power poles at the existing electrical sub-station which are 137 feet away 

from the nearest elderberry shrub. See AAQIR at 45.

Comments Submitted by Ms. Gretel Smith of Helping Hand Tools

28. Comment: The commenter requests an extension of the public comment period for the 

reasons stated in comment #11. 

Response: Please see response to comment #11.

29. Comment: The commenter states that the AAQIR fails to show any analysis to support its 

conclusion that no Environmental Justice issues exist. The AAQIR should contain a 

complete Environmental Justice evaluation to support the conclusion stated.

Response: Please see response to comment #9.

30. Comment: The commenter states that measurements of background ambient air quality 

from an air quality monitoring station 55.5 miles from the proposed site should not be used 

because measurements at or near the actual site must be used to obtain accurate data that 

represents the actual air quality at the proposed site.

Response: Please see response to comment #20.

31. Comment: The commenter states that the permit fails to calculate the cumulative effect of 

secondary emissions. The cogeneration plant will receive its fuel from onsite and from 

offsite facilities via truck. The AQIA fails to analyze the cumulative impact on GHG and 

other emissions the trucks contribute to the overall emissions of the plant. The secondary 

environmental impact from transportation of the bio fuel and the removal of waste from the 

facility should be analyzed. Further, the AQIA does not analyze the cumulative impact of 

the secondary emissions from the kilns. The AQIA should analyze secondary emissions, 

BACT on the secondary emissions should be imposed, and the permit should include an 

emissions limit on the secondary emissions.

Response: The permit modification required BACT on all applicable emission units in the 

Project. In particular, truck emissions were not considered in a discussion of secondary 

emissions because secondary emissions do not include any emissions which come directly 

from a mobile source, such as emissions from the tailpipe of a motor vehicle, from a train, 

or from a vessel. 40 CFR 52.21(b)(18). As discussed in the response to comment #19, 
20

emissions from the kilns were not projected to increase and were not subject to a BACT 

analysis.

32. Comment: The comment claims that the permit should require the technology that 

achieves the lowest possible emissions rate, including EMx or DLN burners.

Response: Our BACT analysis included evaluations of both EMx and DLN burner 

systems. AAQIR at 13. EPA concluded that the EMx was technologically infeasible for a 

biomass boiler. DLN burners, while technologically feasible, would not result in lower 

emissions of NOx than what was proposed. The commenter provides no legal basis for its 

statement that the permit should require the technology that achieves the “lowest possible 

emissions rate.” As stated in section 169(3) of the Clean Air Act, BACT means an emission 

limitation based on the maximum reduction of each pollutant subject to regulation under 

the Clean Air Act while taking into account energy, environmental, and economic impacts. 

42 U.S.C. §7479(3).

33. Comment: The BACT analysis fails to establish the type of ammonia the SNCR or SCR 

will use. This is important because the transportation and storage of certain types of 

ammonia poses a public health risk. Additionally, ammonia slips vary from the types of 

ammonia utilized by the plant. 

Response: Ammonia is not a pollutant subject to regulation under the PSD program. See

40 CFR 52.21(b)(50). Therefore, our BACT analysis did not include a detailed review of 

possible ammonia emission reductions. As part of Step 4 of our NOx BACT analysis, 

however, our AAQIR identified various types of ammonia that could be used as a reagent 

in the SNCR system, and explained that compared to anhydrous ammonia, aqueous 

ammonia and urea require more fuel to evaporate the additional water in those types of 

reagents. AAQIR at 16. Our analysis also noted that all types of ammonia reagents require 

energy to inject the reagent into the exhaust and that the exhaust will contain some small 

quantity of ammonia regardless of what type of reagent is used. Thus, our review of 

environmental and economic impacts in our BACT analysis for NOx did not result in a 

clear indication that one type of reagent should be specified. EPA notes that in addition to 

the NOx emissions limitation required by the PSD permit, the source is subject to District 

Rule 3-26 which limits ammonia emissions to 20 ppm.

SPI’s 2010 Application states that SPI intends to use anhydrous ammonia. See online 

docket #I.01: SPI-Anderson PSD Permit Modification Application_25MAR10 at 3.

Although EPA did not evaluate the relative effectiveness of various ammonia reagents in 

our BACT analysis, SPI observed in discussions with EPA that anhydrous ammonia is 

more effective at its other biomass and sawmill facilities at reducing NOx emissions and 

maintaining compliance with ammonia slip requirements compared to other types of 

reagent ammonia, such as urea and aqueous ammonia. The applicant also noted that it does 

not store more than 10,000 lbs of anhydrous ammonia on any of its other sites at one time.

See online docket #V.03: Ammonia Discussion with SPI_13NOV12.
21

In response to the commenter’s concern for public safety related to the storage of certain 

types of ammonia, we note that the Shasta County Department of Resource Management 

considered risks associated with the storage of ammonia and ultimately recommended the 

approval of Use Permit 07-021 for the Project. See online docket #V.04: Report to Shasta 

County Planning Commission_14JUN12 at 1. The County’s report states that SPI would be 

required to update its existing Hazardous Materials Business Plan/Spill Prevention Control 

and Countermeasure Plan and an Emergency Response Plan. “These plans shall provide for 

specific Best Management Practices to be employed during construction and operation ...

policies and procedures to be implemented in the storage and handling of hazards and 

hazardous materials and emergencies, and dissemination of information included in the 

plans to contractors and employees. Implementation of the plans would reduce potential 

impacts related to hazards and hazardous material and in the event of an emergency to a 

less-than-significant level.” See online docket #V.04: Report to Shasta County Planning 

Commission_14JUN12 at 5.

The transportation of anhydrous ammonia is regulated under the Federal Motor Carrier 

Safety Administration (FMCSA) of the U.S. Department of Transportation (DOT). However, 

in response to the commenter’s concern regarding the transportation of anhydrous 

ammonia, EPA has also considered the risk of an accident resulting from the truck 

shipments resulting from the Project. The Project is estimated to require 183,960 pounds 

per year of ammonia. See online docket #I.01: SPI-Anderson PSD Permit Modification 

Application_25MAR10 at TableA-1 of Appendix A at 41. As noted above, the applicant 

stated that it does not store more than 10,000 lbs of ammonia, the threshold quantity of 

ammonia according to 40 CFR 68.130, on site at any one time. Assuming one truck can 

replenish 10,000 lbs of ammonia, the Project will require approximately 19 shipments of 

ammonia per year. With several suppliers of anhydrous ammonia within 200 miles of the 

SPI- Anderson location, EPA estimates that this would result in 8,000 miles of truck miles 

travelled, including roundtrips. However, tank shipments carrying ammonia would be in 

only one direction, therefore 4,000 miles of ammonia transport for the Project would result 

each year. In a report sponsored by the FMCSA, the average hazardous material accident 

rate was 0.32 estimated per million miles travelled. See online docket #V.05: FMCSA Risks 

of Hazardous Material Truck Shipment_March 2001 at ES-4. Therefore, 4,000 miles of 

ammonia transport per year would result in an estimated single truck accident for the

Project in 800 years. However, only 28% of all accidents in the FMCSA study were 

characterized as spill accidents. See online docket #V.05: FMCSA Risks of Hazardous 

Material Truck Shipment_March 2001 at 10-2 This further reduces the estimated accident 

frequency related to the ammonia transport from the Project to 1 spill in 3,000 years from a 

truck carrying 10,000 lbs or less of ammonia to the Project site. 

A report prepared by EC/R for another EPA action, states that a national database operated 

by the National Toxic Substance Incidents Program of the U.S. Agency for Toxic 

Substances and Disease Registry reports that between 2005 – 2010, there were 45 incidents 

involving anhydrous ammonia; that all incidents were associated with agricultural use of 

the chemical; and that the vast majority of those incidents were associated with loading 

operations or soil applications, rather than transport on highways or public areas. There 

were no incidents involving anhydrous ammonia use at a power plant or transportation to a 
22

power plant between 2005 and 2010. See online docket #V.06: ECR Mobile Source Risk 

Estimate Report_30JUL12 at 12.

34. Comment: Step 4 of the BACT analysis comparing SCR and SNCR fails to analyze 

comparative costs of facilities. The analysis should include a comparative cost to other 

facilities.

Response: The commenter provided no legal or technical basis for consideration of 

comparative costs to other facilities. We received a similar comment from another 

commenter that suggested that we should analyze comparative costs. Our response to that 

comment is at #44, below.

35. Comment: The temporary deferment of requiring BACT on Greenhouse gas emissions 

(GHG) for biofuels does not apply to plants that use natural gas. (76 FR No. 139, July 20, 

2011; 40 CFR 52.21 (b)(49)(ii)(a); 40 CFR 41.166(b)(48)(ii)(a). The EPA does not state 

what percentage of natural gas will contribute to the GHG emissions of the plant. 

Response: The deferral for CO2 emissions from bioenergy and biogenic sources under the 

PSD program was applied to those CO2 emissions that result from the combustion of 

biomass. Condition X.G.2. of the final permit limits natural gas usage to 10% of the annual 

heat input to U1. We included CO2 emissions from natural gas in our analysis of whether 

the Project was subject to BACT for GHG. See AAQIR at 49-50. However, the GHG 

emissions from natural gas, as measured in CO2e, were below the subject to regulation 

threshold and the Project was not subject to BACT for GHG. See AAQIR at 9.

36. Comment: EPA should consider the kilns in the analysis of emissions and operations 

process of this plant. There should be an analysis of the effects of not using a cooling 

tower.

Response: Please see the response to comment #15. 

37. Comment: The BACT analysis does not analyze the use of a solar component to offset 

some or all of the emissions resulting from the use of natural gas. 

Response: Please see the response to comment #13.

38. Comment: The commenter states that the AAQIR does not fully analyze the nitrogen 

deposition impact of the surrounding area. The commenter states that the AAQIR should 

analyze the nitrogen deposition impacts and the effect the emissions impacts may have on the 

surrounding flora and fauna including the elderberry shrubs in the immediate vicinity of the 

plant. 

Response: Please see the response to comment #27.

Comments Submitted by Mr. Kevin Bundy of the Center for Biological Diversity (CBD)

Technical Feasibility of Fluidized-bed Boiler Designs
23

39. Comment: The commenter disagrees with EPA’s statement in the AAQIR that SPI has 

not entered a binding power purchase agreement (PPA) with consistent base load electricity 

demand. The commenter states that although final state regulatory approval is still pending, 

SPI has entered into a power purchase agreement with Pacific Gas & Electric Company 

(PG&E).

Response: The commenter’s submittal includes an “Attachment A,” which is an “Advice 

Letter,” dated September 7, 2012, and submitted by PG&E to the California Public Utilities 

Commission (CPUC). PG&E’s Advice Letter describes a purchase power agreement (PPA) 

between PG&E and SPI and identifies a PPA as Appendix F. (The commenter did not 

submit Appendix F to the Advice Letter, apparently because the PPA itself is confidential).

Based on the Advice Letter, EPA acknowledges that a PPA between PG&E and SPI does 

in fact appear to exist. We appreciate the commenter’s bringing this information to our 

attention. We note that the public comment period for this permit began on September 12, 

2012, just three business days after the date of the Advice Letter. We also note that the 

Advice Letter indicates that the PPA is not yet final because it appears to be currently 

pending before the California Public Utilities Commission (CPUC) and PG&E has 

requested the CPUC’s approval of the PPA by March 2013. Finally, we note that the 

Advice Letter is signed by PG&E, not SPI; therefore, it is problematic to ascribe 

significance to it without qualification. 

40. Comment: The commenter states that to the extent there is a feasibility problem, it results 

from contractual terms that SPI negotiated, as opposed to technical limitations. The 

commenter argues that the Advice Letter states that PG&E’s obligation to purchase power 

from SPI is limited to the amounts specified under current contracts, which will expire in 

2016 and 2017. The commenter continues that SPI intends to commence operation of the 

new boiler in 2014 and ramp up to full power production in 2017. The commenter 

concludes that the operational flexibility SPI seeks will be necessary for only three years 

and only because of contractual terms that SPI negotiated. The commenter states that even 

if SPI has negotiated a PPA that restricts it from selling the facility’s full output for the first 

three years of operation, that business decision does not make fluidized-bed boiler 

alternatives technologically infeasible under Step 2 of the BACT analysis and that this 

business decision should not be the basis of a permit that would allow SPI to install and 

operate equipment that will emit higher rates of pollutants for decades after 2017.

Response: SPI submitted to EPA a letter dated January 23, 2012 explaining its need for a 

stoker boiler, as opposed to a fluidized bed boiler. In short, SPI’s letter states that the new 

boiler will be used for two purposes: (i) to produce steam to operate lumber-drying kilns 

for SPI’s saw mill operation; and (ii) to produce steam to power a turbine and electrical 

generator that will produce electricity for sale to the power grid. SPI’s letter states that the 

new boiler must be able to operate at loads between 20 percent and 100 percent because the 

boiler must continue to provide steam for its saw mill operation even if demand for grid 

power was not present and the steam turbine and generator are taken offline. SPI’s letter 

explains that it anticipates that there may be low demand for grid power in the near term, 

which will require it to operate the new boiler at low loads because PG&E, the purchaser of 
24

the power to be generated by the new boiler / turbine / generator, has projected that 

“between 2014 and 2017, and perhaps beyond,” it will have more renewable energy 

available to it than it will need to meet California renewable energy standard requirements.

SPI’s January 2012 letter also refers to operations at its facility in Lincoln, California, 

which includes a stoker boiler, lumber-drying kilns, and a steam turbine and generator.

SPI’s letter explains that the Lincoln facility’s stoker boiler has been capable of operating 

at low load and maintaining operation of the lumber drying kilns when the steam turbine 

and generator were offline for unscheduled repairs. SPI’s letter thus describes another 

scenario in which a boiler capable of operating at low load is able to accomplish its 

business purposes.

In addition, SPI’s January 2012 letter states that a boiler that cannot operate at lower loads 

would have to be shut down, which would result in shutdown of the saw mill’s lumberdrying kilns and possibly a complete shutdown of the mill. According to SPI’s letter, which 

included a supporting reference to a fluidized bed boiler manufacturer, fluidized bed boilers 

are unable to operate at lower load rates (i.e., a turndown mode). SPI stated that a fluidized 

bed boiler was therefore incompatible with its planned use of the new boiler to produce 

process steam as well as steam to generate electricity for sale to the power grid. 

Based on SPI’s January 2012 letter, as well as SPI’s other submittals, SPI’s business 

purpose in constructing the new boiler is two-fold: to process steam for its mill operations 

and to provide a renewable energy source of grid power. To meet these dual purposes, SPI 

requires a boiler type that can operate under varying loads: at low load when steam is 

required only for mill operations; and at high load when steam is required for both mill 

operations and grid power. SPI has provided technical support for a determination that a 

fluidized bed boiler is not capable of meeting both purposes, and the commenter did not 

provide technical evidence to the contrary. Moreover, it is of little relevance that SPI may 

have negotiated a contract for the sale of electricity that does not require full steam 

production at all times – BACT does not require that the permit applicant enter into 

business contracts that will maximize the use of permitted emissions units. SPI’s business 

purpose for selection of a stoker boiler is that is fulfills two purposes and SPI has provided 

a technical justification that a fluidized bed boiler cannot adequately fulfill both purposes.

41. Comment: The commenter states that it is not clear that the operational flexibility SPI 

seeks is necessary at all. According to the commenter, deliveries in excess of PG&E’s 

renewable energy obligations will be bankable; therefore, it appears unlikely that PG&E 

would require SPI simply not to generate excess power that PG&E could easily bank in 

order to meet an acknowledged future compliance deficit.

Response: The comment questions SPI’s justification for operating in a turndown mode, 

and thus SPI’s need for a stoker boiler. We note that although the Advice Letter states that 

excess power would be bankable and available for future compliance periods, it does not

“acknowledge” a future compliance deficit. Advice Letter at 17-18. In addition, the 

motivations of PG&E, which is not the permit applicant, are outside the scope of our 

authority to consider when reviewing a PSD permit application. Furthermore, the comment 
25

does not address SPI’s stated need for a boiler that can operate in turndown mode as a 

result of maintenance or repair on the steam turbine and generator.

42. Comment: The commenter states that EPA must consider alternatives to the facility as 

proposed. For example, EPA could deny the permit outright and allow the applicant to 

renew the application once the need for the facility arises. Another alternative would be to 

prohibit operation of the new boiler and allow SPI to continue to operate the existing boiler 

for power and process steam until 2017 or whenever the PPA requires full base load power 

deliveries. These alternatives are consistent with the PPA, SPI’s submittals, and EPA’s 

statement of basis and demonstrate that fluidized-bed boiler designs should not have been 

rejected as technically infeasible.

Response: EPA, the permit issuer for the Project, does not have an obligation to 

independently investigate all possible alternatives. The Environmental Appeals Board has 

observed the importance of this limitation on the permit issuer's obligation, particularly 

where the evaluation of need for additional electrical generation capacity would require a 

rigorous and robust analysis and would be time-consuming and burdensome for the permit 

issuer. In such circumstances, the permit issuer is granted considerable latitude in 

exercising its discretion to determine how best to apply scarce administrative resources. 

EPA has evaluated the Project for all of the of the appropriate applicable PSD 

requirements. Moreover, we note that the comment does not address SPI’s stated need for a 

boiler that can operate in turndown mode in the event of maintenance or repair on the 

steam turbine and generator.

EPA’s Rejection of Catalytic Control Technologies as BACT for NOx

43. Comment: The commenter stated that EPA’s BACT analysis is inconsistent because it 

concludes that SCR is technically feasible but rejects SCR on the lack of demonstrated 

effectiveness. SCR should have been ranked as the top control option at Step 3.

Response: Step 3 of our BACT analysis ranked SCR as the top control option. See 

AAQIR at 15, Table 7.1-2. The fact that there is little operational data for SCR on stoker 

boilers is a factor that we considered in Step 4, as part of our analysis of economic impacts.

Please see our response to comment #44 below. After a thorough review, EPA determined 

that BACT for NOx for the Project is 0.13 lb/MMBtu on a 12-month rolling basis and 0.15 

lb/MMBtu on a 3-hour block average.

44. Comment: Citing the Draft NSR Manual at B.31-B.32, the commenter states that the 

BACT analysis fails to consider the cost effectiveness of the proposed control relative to 

other similar sources that have employed that control. The commenter states that neither 

the Statement of Basis nor SPI’s application contains comparative information about 

average and incremental costs of SCR at other biomass facilities that have employed SCR 

or RSCR as BACT. Evaluation of economic impact on the proposed facility alone is 

insufficient to support rejection of a proposed control measure as BACT.
26

Response: The portion of the Draft NSR Manual cited by the commenter recommends that 

an applicant document significant cost differences between control technologies “where a 

control technology has been successfully applied to similar sources in a source category. . 

.” Draft NSR Manual at B.31 (emphasis added). We were unable to find significant support 

for a finding that either SCR or RSCR has been successfully applied to biomass stoker 

boilers, nor did the commenter provide any such examples. As shown in our AAQIR at 

Table 7.1-1, our BACT analysis included information regarding a number of recent BACT 

determinations for stoker boilers. Table 7.1-1 shows that, although seven facilities have 

received permits that would require use of SCR or RSCR, five of those facilities have not 

been constructed; thus, those five BACT determinations do not represent an “achieved in 

practice” standard. Our review found only one source, Lufkin Generating Plant (Lufkin), 

constructed with SCR. Since completing construction in late 2011, Lufkin has operated 

sporadically; as a result, the facility has not generated a significant quantity of emissions 

data, making it difficult to verify that the NOx emission rate of 0.075 lb/MMBtu on a 30-

day rolling basis has been achieved in practice. In addition, our review found only one 

source constructed with RSCR, McNeil Generating Station (McNeil). The limit identified 

in Table 7.1-1 for this source, 0.075 lb/MMBtu, is averaged over 150 days and has been 

verified; however, the short-term limit for the McNeil boiler is 0.23 lb/MMBtu (no 

averaging period specified), which is higher than our short-term BACT determination for 

SPI of 0.15 lb/MMBtu (3-hour average).

In making our BACT determination for SPI, we considered the lack of operational data for 

SCR for similar sources as well as the $9,000 per ton of NOx removed incremental cost for 

SCR (compared to SNCR) at SPI. Our determination is consistent with the Draft NSR 

Manual, which recommends documentation of significant cost differences between control 

technologies when the permitting authority is eliminating a control technology that has 

been successfully applied to similar sources. In this case, we were unable to find that SCR 

has been successfully applied to similar sources, and in the limited instance of RSCR at 

McNeil, we found that our BACT determination for SPI was at least as stringent, if not 

more stringent, than the limit for McNeil.

45. Comment: The commenter states that EPA did not clearly explain why it selected SPI’s 

proposed NOx emission limits as BACT. Other facilities with SNCR have been permitted at 

lower emission rates and “demonstrated in practice” should not be the controlling factor.

The commenter also argued that if EPA is adopting an emission limit with a margin of 

safety, then EPA must explain its choice and support it in the record.

Response: Our AAQIR did not reference “compliance margin” as a basis for our BACT 

determination; the commenter is apparently assuming that we were relying on this concept 

as a basis for our NOx BACT determination. Our AAQIR, however, explained that the 

basis for our determination is that the limit is the most stringent NOx emissions limit for 

stoker boilers with SNCR demonstrated in practice and that the incremental costs of SCR 

above the costs of SNCR made SCR cost prohibitive. See AAQIR at 15-16.

Our NOx BACT determination was based in part on the information provided in Table 7.1-

1 of the AAQIR, which lists recent NOx BACT determinations for biomass stoker boilers.
27

Two determinations include the use of SNCR and lower NOx emissions limits than the 

limit proposed for SPI; however, neither facility has been constructed, and, therefore, those 

limits have not been demonstrated in practice. In addition, we note that Table 7.1-1 of the 

AAQIR shows that the lower NOx limits using SNCR are subject to longer averaging 

periods (0.1 lb/MMBtu (30-day rolling average) and 0.12 lb/MMBtu (24-hour block)) than 

the short term limit we have proposed for SPI (0.15 lb/MMBtu (3-hour block)).

In addition, SPI presented information that although another of its facilities received a NOx

limit of 0.1 lb/MMBtu, SPI was unable to achieve this lower limit without using excessive 

amounts of ammonia. Specifically, SPI’s 2010 application states that SPI received a permit 

in 2006 for a 450 MMBtu/hr boiler at its facility near Burlington, Washington with NOx

limits of 0.13 lb/MMBtu (24-hour average) and 0.1 lb/MMBtu (12-month rolling average).

SPI stated that the 0.1 lb/MMBtu (12 month rolling average) limit was removed from the 

permit because excessive ammonia use in the SNCR system resulted in a secondary plume.

See online Docket #1.01: SPI-Anderson PSD Permit Modification Application 25 MAR10, 

App. B at 7, n.3. We also note that SPI’s Anderson facility is subject to District Rule 3-26, 

which limits ammonia slip emissions which can result from excessive ammonia use.

EPA’s BACT determination for CO

46. Comment: The commenter states that the BACT analysis for CO contains the same flaws 

as the BACT analysis for NOx. According to the commenter, these flaws are the rejection 

of fluidized-bed boiler design alternatives as technically infeasible and the failure to 

compare average and incremental cost of catalytic CO controls with equivalent costs at 

other comparable facilities.

Response: Because the commenter is not raising new concerns with respect to our BACT 

analysis for CO separate and apart from the issues the commenter raised regarding our 

BACT analysis for NOx, our response to this comment is largely by reference to the 

responses regarding the NOx BACT comments. In addition, we have a few other points to 

make that are specific to our CO BACT analysis.

With regard to the BACT determination for CO and the corresponding installation of addon control technology alternatives to the stoker boiler, EPA believes its BACT 

determination was appropriate. Of those facilities identified in the BACT analysis with 

lower permitted CO emissions limitations, three other permitted sources in Table 7.1-3 

have lower CO emissions limitations through the implementation of an oxidation catalyst 

and three employ good combustion. None of the six facilities identified has constructed. 

The AAQIR for the Project describes an oxidation catalyst as a technically feasible control 

alternative and provides context that verifiable data with biomass stoker boilers 

implementing an oxidation catalyst remains limited. In its review of add-on control 

alternatives, EPA not only considered the cost of an oxidation catalyst, but also what has 

been achieved in practice with stoker biomass boilers. EPA also reviewed a number of 

facilities and permit determinations that were not provided by the applicant in its BACT 

analysis materials.
28

Some proposed facilities have lower permitted emission limits for CO through the 

implementation of good combustion and others have higher permitted emission limits. 

However, as noted in SPI’s application, “emissions resulting from incomplete combustion 

(CO and VOC) are balanced with emissions related to high furnace temperatures (NOx) to 

achieve optimally low emissions of all pollutants. However, in order to achieve the 

proposed NOx emission limit (0.13 lb/MMBtu) while not exceeding 20 parts per million 

(ppm) ammonia slip, as required by Shasta County (Shasta County AQMD Rule 3:26.c.4), 

boiler operation will favor reduced NOx creation over reduced CO creation.” See online 

docket I.01: SPI-Anderson PSD Permit Modification Application 25MAR10, App.B at 16.

As a result of all these considerations, EPA determined that BACT for CO for the Project is

0.23 lb/MMBtu (3 hour block average) and 108 lb/hour (3-hour block average).

EPA’s BACT determination for PM, PM10 and PM2.5

47. Comment: The commenter states that the BACT analysis improperly concludes the 

emission limitations for particulate matter. Lower emission limits have been permitted at 

other facilities, both with the ESP and multiclone technology proposed by SPI and with the 

baghouse technology which was not selected. EPA does not explain why it chose only a 

“demonstrated in practice” emissions limit rather than the most effective technically 

feasible control.

Response: As detailed in the BACT analysis for PM in the AAQIR, EPA identified three 

biomass stoker boilers with lower permitted emissions limits for PM, none of which has 

constructed. See AAQIR at 19-22, and Table 7.1-5. One of those projects appears to have 

been canceled, and as noted in our AAQIR, was permitted for filterable particulate only, 

whereas the SPI limit is for total PM. Beaver Wood Power Biomass Technical Support 

Document, February 10, 2012, p. 22. The other two proposed facilities listed in Table 7.1-5 

have slightly lower emission rates of PM, utilizing different add-on control technologies: 

Warren County Biomass is permitted with an emission limit of 0.018 lb/MMBtu employing 

a baghouse, and Beaver Wood Energy is permitted with an emission limit 0.019 lb/MMBtu 

employing an ESP. Our BACT determination for SPI- Anderson is 0.02 lb/MMBtu.

Our AAQIR for the Project describes both a baghouse and ESP as technically feasible 

control alternatives. At Steps 1 and 4, we noted that baghouses may present a fire concern 

and generally require more energy than ESPs. Moreover, our AAQIR explains that SPI 

estimated the same level of control from both add-on control alternatives at 0.02 lb/MMBtu 

for PM. See AAQIR at 21 and online docket #I.01: SPI-Anderson PSD Permit Modification 

Application 25 MAR10, App. B at 21. We also reviewed a number of facilities and permit 

determinations that were not provided by the applicant in its BACT analysis materials and 

what has been achieved in practice. In our review of add-on control alternatives, we 

considered not only energy and environmental impacts associated with the add-on control 

alternatives, but also what controls have been achieved in practice with biomass stoker 

boilers. As a result, EPA has determined that BACT for total particulate matter for the 

Project is 0.02 lb/MMBtu.

EPA’s BACT determination for Emergency Engine Emissions
29

48. Comment: EPA improperly rejected the most stringent emissions control option of NSPScompliant non-emergency engine for use as an emergency engine without identifying 

average or incremental cost of controls, providing comparative cost information from other 

facilities, or reviewing other BACT determinations. EPA’s statement that “economic 

impacts and limited environmental benefit” would not justify use of a more stringent 

control technology is inadequate.

Response: We received comments from SPI during the public comment period clarifying

its intention to install a spark ignition natural gas fired engine rather than a compression 

ignition engine as stated in the AAQIR. This revision does not affect the lb/hour emissions 

limits of 0.78 lb/hr NOx, 6.11 lb/hr of CO, and 0.0216 lb/hr of PM/PM10. In addition, the 

emergency engine will also be required to comply with the NSPS emergency engine 

emissions limits provided in 40 CFR 60 Subpart JJJJ, which applies to spark-ignition 

engines. As stated in the AAQIR, operation of the emergency engine will be restricted to 

no more than 100 hours per year 

We have revised the Emergency Engine BACT Analysis for a spark ignition emergency 

engine rather than a compression ignition emergency engine. As for the original BACT 

analysis for the compression ignition engine, we note that the proposed emissions and 

operational limits will result in extremely low mass emissions on an annual basis.

Moreover, we also note that the commenter did not supply additional information that more 

stringent limits could be consistently achieved in practice for the 191kW engine.

We have concluded that an NSPS-compliant spark ignition emergency engine that is 

subject to the proposed hourly emission limits and an operational restriction of 100 hours 

per year represents an adequate balance of the impacts associated with the Project’s 

emergency recirculating pump requirements. In the final permit the spark ignition 

emergency engine will result in low emissions of approximately 226 lbs/year of CO, 78 

lbs/year of NOx and 3 lbs/year of PM. As such, the spark ignition natural gas emergency 

engine for the Project is appropriate and meets BACT. For further information, please see

our revised Emergency Engine BACT Analysis in the Appendix to this document.

EPA’s BACT determination for Cooling Tower Emissions

49. Comment: The commenter stated that the BACT analysis does not properly evaluate 

particulate control for cooling towers. According to the commenter, EPA relies solely on a 

conclusory and internally contradictory statement to make its final determination and the 

AAQIR does not identify anything that provides authority for what amounts to an ad hoc de 

minimis exemption from rigorous application of BACT requirements.

Response: We disagree with the commenter that our analysis of cooling tower controls 

was conclusory or de minimis. As set forth in the AAQIR, we conducted a top-down 

BACT analysis that considered three types of cooling towers technologies: dry cooling, 

wet-dry hybrid, and wet cooling with 0.0005% drift eliminators. EPA did not find any saw 

mill facilities or biomass boilers that use dry cooling or wet-dry hybrid cooling as an 
30

alternative to wet cooling. We note that the commenter did not provide any examples of 

dry or wet-dry cooling tower applications for saw mills or biomass boilers (or any 

examples at all). Of wet cooling tower options, the applicant’s proposal to use DRU-1.5 

high-efficiency mist eliminators represents the lowest proposed amount of drift that EPA 

found in its review of similar facilities. As we noted in the AAQIR, the difference between

the various cooling tower control options is approximately 1.10 tons of total PM per year.

In response to the commenter’s reference to an internal contradiction in our statement that a 

reduction in overall efficiency would result from the use of a dry or hybrid wet-dry 

systems, we acknowledge that we inadvertently included a mis-statement. We should have 

stated that this efficiency reduction would result from the additional energy requirements 

for dry (not wet, as stated in the AAQIR) and hybrid systems. Although we believe that our 

intent could be discerned from the overall context of our analysis, we appreciate the 

commenter bringing this mis-statement to our attention.

Without any supporting information available to us, either from our own review or from the 

commenter, it is difficult to consider an additional sufficient basis on which to establish 

BACT limits that could be consistently achieved in practice by the Project for the cooling 

tower. We find that the applicant’s proposed control of wet cooling with high efficiency 

mist eliminators adequately balances the collateral impacts associated with the Project’s 

cooling requirements and has resulted in low potential emissions from the cooling system –

1.1 tons per year of PM/PM10/PM2.5. As such, the proposed cooling system for the Project 

is appropriate, consistent with other PSD permits for similar sources as stated in SPI’s 2010 

application. See online docket #1.01, SPI-Anderson PSD Permit Modification Application 

25 MAR10, App. B at 29 and meets BACT.

EPA’s Air Quality Analysis

50. Comment: The commenter argues that EPA’s air quality analysis was deficient because it 

did not adequately explain why it assumes startup/shutdown NOx emission rates (when the 

SNCR system will not be working) are the same as normal operational emission rates. The 

analysis should explain why NOx emissions with and without SNCR would be the same.

The commenter also stated that there is a discrepancy between the descriptions of the 

startup process in the AAQIR and a letter submitted by SPI to EPA dated May 30, 2012.

Response: EPA requested that SPI provide a modeling analysis that reflects worst-case 

conditions during startup. See online docket #I.33: SPI- Anderson to EPA email re SUSD 

emissions clarification 27JUN12and # I.11: SPIAnderson_updated_modeling_and_SUSD_analysis-final_30MAY12 at Table 5. To the 

extent that the commenter is questioning why “NOx emissions with and without the SNCR 

system would be exactly the same,” we emphasize the distinction between, on the one 

hand, a worst case assumption that NOx emissions during startup are equivalent to NOx

emissions during normal operations and, on the other hand, a conclusion that such 

emissions are equivalent. Equivalency between the two scenarios, startup and normal 

operations, is an assumption being made for modeling purposes in order to capture worst 

case conditions. To the extent the commenter is questioning the validity of this assumption, 
31

we believe the assumption is valid because startup includes firing natural gas, which results 

in lower NOx emissions than biomass. In addition, startup involves lower flow rates and 

reduced exhaust temperatures. Therefore, as a general matter, it is reasonable to assume 

that emissions during the firing of natural gas will be less than emissions during firing of 

biomass.

In addition, the applicant supplied comments during the public comment period regarding 

emissions during periods of startup and shutdown. In its comments, the applicant reiterated 

that the appropriate mass emission limits were included in the AAQIR and permit; 

however, the applicant requested that the averaging period for emissions limits for NOx and 

CO during startup and shutdown be increased from an hourly average to an 8-hour average.

See response to comment #70 in this document. EPA has granted this request and revised 

the permitted averaging times for NOx and CO emissions during periods of startup and 

shutdown.

We also note that the modeling that used this assumption showed that emissions for annual 

and 1-hour NO2 and 24-hour PM2.5 would exceed SILs; therefore a cumulative impacts 

analysis was required and conducted. In other words, because SPI had to do the cumulative 

impacts modeling anyway, the assumption that NOx during startup was equivalent to NOx

during normal operations did not result in less analysis.

51. Comment: The air quality analysis does not quantify secondary PM2.5 formation despite 

high emissions of NOx, a PM2.5 precursor, and does not support its assertion that emissions 

of secondary PM2.5 will be less than direct, primary emissions.

Response: We maintain that our discussion of secondary impacts in Section 8.4.3.2 of the 

AAQIR is sufficient for characterizing the potential impacts on secondary PM2.5 resulting 

from 270 tpy of NOx. In addition, most of these chemical transformations in the 

atmosphere occur slowly (over hours or even days, depending on atmospheric conditions 

and other variables), causing secondary PM2.5 impacts to occur generally at some distance 

from the source of its gaseous emissions precursors, and are unlikely to overlap with 

nearby maximum primary PM2.5 impacts in space or time.

EPA’s Additional Impacts Analysis 

52. Comment: EPA’s additional impact analysis is inadequate because EPA cannot rely on 

the fact that air modeling shows no violation of the secondary NAAQS as a proxy for 

analysis of depositional effects on soil and vegetation.

Response: While the commenter noted concerns about characterizing depositional effects 

based on a comparison to the secondary NAAQS, our determination that the Project would 

not generally result in adverse impacts to soils or vegetation was based on several 

considerations as noted in the AAQIR, including air quality related values (AQRVs), soils 

survey, biological review, and screening procedures guidance. In addition, the AAQIR also 

outlines our approach for comparing the Project’s modeled impacts to EPA’s screening 

concentrations. See AAQIR at 41-42. Based on our consideration of the various sources of 

information, we determined that emissions associated with the project will not result in 
32

adverse impacts to soils or vegetation. The following further clarifies our consideration of 

the AQRVs, soils survey information, and biological review. 

SPI’s 2007 PSD application included a summary of the results associated with the AQRVs; 

this summary used CALPUFF to evaluate impacts to AQRVs in Class I areas. Class I Area 

deposition fluxes for nitrogen and sulfur deposition were calculated from CALPUFF 

results. Although there are no specific standards for incremental impacts to soils and 

vegetation, the National Park Service (NPS) has set deposition analysis thresholds (DATs) 

of 0.005 kg/ha/yr for nitrogen deposition and for sulfur deposition. See online docket 

#V.01: Guidance on Nitrogen and Sulfur Deposition Analysis Thresholds at 4. A DAT is 

the additional amount of nitrogen or sulfur deposition within a Class I area below which 

estimated impacts from a project are considered insignificant. Nine Class I areas were 

evaluated, ranging from distances of 57 km to 192 km; the maximum nitrogen and sulfur 

deposition flux results were 0.0007 and 0.0002, respectively, and therefore not greater than 

the DATs of 0.005. As a result, the predicted nitrogen and sulfur deposition fluxes 

containing primary and secondary aerosols attributable to the Project are not expected to 

significantly impact soils and vegetation within Class I areas.

The DATs, also referenced as concern thresholds, are intended to serve as a quantitative, 

conservative screening criteria for Federal Land Managers (FLMs) to identify whether 

there are potential deposition fluxes requiring further consideration on a case-by-case basis. 

Since the year 2000, the FLMs have provided guidance regarding the AQRVs, which 

includes discussions regarding deposition. As stated in the most recent FLMs’ guidance on 

nitrogen and sulfur deposition analyses, the information and procedures are generally 

applicable to both Class I and Class II areas for evaluating the effect of nitrogen or sulfur

increases. See online docket #V02: FLM Interagency Guidance for Nitrogen and Sulfur 

Deposition Analyses_November 2011 at 2.

In subsequent updates and clarifications to SPI’s 2010 PSD application, the applicant 

provided further characterization for soil and vegetation impacts, including soils survey 

information and a biological review. See online docket #I.03: SPIAnderson_response_to_EPA_incomplete_letter-final_01JUL10, #II.01: SPI-Anderson to 

EPA re Biological Assessment 01APR10 and #II.02: Biol Rpt for EPA review_Complete 

pkg-R 15APR10. As part of its biological review, SPI did not identify any refuges or 

preserves containing sensitive soils or vegetation that could potentially be impacted by the 

proposed project. Section 9.2 of the AAQIR evaluates potential visibility impacts on two 

Class II areas, the Sacramento River National Wildlife Refuge (38.8 km) and Whiskeytown 

National Recreation Area (18.3 km). See AAQIR at 43-44. SPI’s DAT analysis concluded 

that the Project would result in relatively low deposition fluxes on nearby Class I areas, 

which we considered as an indicator that adverse impacts on nearby soils or vegetation in 

these two Class II areas would be unlikely.

With regards to the nearby soils, we considered the soils survey review SPI conducted 

using the Web Soil Survey (WSS). See AAQIR at 41.The WSS is a web-based tool that 

provides soil maps, data and information produced by the National Cooperative Soil 

Survey operated by the USDA Natural Resources Conservation Services (NRCS) Based on 

the applicant’s review, we considered the Project’s potential nitrogen and sulfur deposition 
33

unlikely to further influence the pH of soils (5.3 to 6.5) in the area. Based on discussions 

with and/or review of information from the USFWS, BLM, and NRCS, we considered this 

information in determining that the Project’s impact would not result in adverse impacts to 

soils or vegetation.

Finally, we note that the commenter did not suggest any specific additional analysis that we 

could have or should have conducted. Moreover, we note that, as presented in Table 9.1-2 

of the AAQIR, the maximum modeled concentrations of NOx and SOx are several orders of 

magnitude below EPA’s secondary NAAQS standards. For all the reasons stated above, we 

believe our determination that the Project will not generally result in adverse impacts to 

soils or vegetation was appropriate.

Other Applicable Legal Requirements 

53. Comment: The Clean Air Act and EPA’s implementing regulations clearly require that 

SPI demonstrate compliance with other applicable standards, including SIP provisions, 

NSPS and NESHAP, in conjunction with its PSD application. See 42 U.S.C. §7475(c)(3); 

40 C.F.R. §52.21(j)(1), but SPI’s application and EPA’s statement of basis do not discuss 

compliance with these provisions.

Response: EPA has determined that the emissions limits in the proposed permit are more 

stringent than, and therefore will assure compliance with, applicable SIP and NSPS 

requirements. We note that Shasta County has maintained its designations as attainment for 

all criteria pollutants for many years; therefore, consistent with the Act, Shasta County’s 

SIP does not contain the more stringent emission standards that are typically found in SIPs 

applicable to nonattainment areas. We have also determined that the Project is subject to 

the standards of performance of NSPS Subpart Db, and that the proposed permit will assure 

compliance with those obligations. NSPS Subpart Db states that an affected facility that 

commences construction after February 28, 2005, and that combusts over 30 percent wood 

(by heat input) on an annual basis and has a maximum heat input capacity greater than 250 

MMBtu/hr shall not cause to be discharged into the atmosphere from that affected facility 

any gases that contain PM in excess of 0.030 lb/MMBtu heat input. 40 CFR Part 

60.43b(h)(1). The PM emissions limit for the boiler in the Project is 0.02 MMBtu/hr. These 

requirements were discussed in SPI’s 2007 and 2010 applications.

On December 20, 2012, the EPA Administrator signed the final National Emission 

Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters (Boiler MACT) which will be effective 60 days 

from the date of publication in the Federal Register. The emission limits for CO and PM in 

the Boiler MACT for a new biomass stoker boiler are 390 ppm (~0.345 lb/MMBtu) with 

CEMS and 0.030 lb/MMBtu respectively. The BACT limits for the Project at 0.23 

lb/MMBtu for CO and 0.02 lb/MMBtu for PM are more stringent than those in the Boiler 

MACT. The Project will also be subject to other requirements from the Boiler MACT, such 

as other non criteria pollutant emission limits, monitoring, recordkeeping and reporting

requirements.
34

54. Comment: EPA has not adequately explained why or how it is processing this permit as a 

major modification. The statement of basis contains no discussion of any contemporaneous 

emissions changes resulting from the modification or baselines used to evaluate emission 

increases. The draft permit and statement of basis focus only on the new boiler as if it were 

the only emissions source at the facility, which makes it impossible to determine how EPA 

arrived at significance determinations.

Response: SPI’s 2007 and 2010 applications state that the Project will not increase 

emissions from any existing units. See online docket #I.13: SPI-Anderson PSD 2007 

Permit Modification Application at 7, #I.01: SPI-Anderson PSD Permit Modification 

Application_25MAR10, at 4. SPI also stated that emissions increases from fuel handling 

operations are not projected to increase. See online docket #I.05: SPIAnderson_response_to 2nd_EPA_incomplete_letter-final_07SEP10. In addition, SPI and 

EPA evaluated the Project using an actual emissions baseline of zero for all new 

equipment. See online docket # I.01: SPI-Anderson PSD Permit Modification 

Application_25MAR10 at Tables 2-1 and 2-2, #I.41: SPI-Anderson Annual Emissions 

MEMO_05SEP12. Tables 2-1 and 2-2 of SPI’s 2010 Application and Table 6-1 of EPA’s 

AAQIR summarize the estimated emissions increases from the Project and our conclusions 

that the Project would exceed the significance levels for CO, NOx, PM, PM10, and PM2.5.

In addition, we disagree with the commenter’s suggestion that the draft permit and 

statement of basis place an inappropriate emphasis on the new boiler. The “Project 

Description” section of both the draft permit and the AAQIR contain the following 

statement: “The site currently contains a wood-fired boiler cogeneration unit with 

associated air pollution control equipment and conveyance systems that produce steam to 

dry lumber in existing kilns.” Draft Permit, at 1; AAQIR at 3. The AAQIR also includes 

separate tables for new and existing equipment: Table 4-1, Proposed New Equipment List, 

and Table 4-2, Existing Equipment List. EPA clearly described the Project as a 

modification of the Facility’s existing configuration.

EPA’s Deferral of PSD for Biogenic CO2 and Grandfathering PM

55. Comment: The commenter states that EPA’s deferral of PSD requirements for biogenic 

CO2 emissions is unlawful and that EPA’s treatment of biogenic CO2 emissions in the draft 

permit would violate the Clean Air Act if EPA’s deferral is vacated. The commenter also 

states that 42 U.S.C. §7465(a)(2) imposes an independent obligation to consider lesspolluting alternatives; therefore, EPA must evaluate alternatives that reduce dangerous 

carbon pollution. The commenter cites several scientific studies to support its argument that 

combustion of biomass fuels, including green wood and forest thinnings as well as harvest 

residuals and other wastes, can increase greenhouse pollution for many years. 

Response: As noted by the commenter, there is pending litigation in the D.C. Circuit 

Court of Appeals regarding our rule, Deferral for CO2 Emissions from Bioenergy and 

Other Biogenic Sources under the Prevention of Significant Deterioration and Title V 

Programs, 76 Fed. Reg. 43490 (July 20, 2011). EPA’s position is that the Deferral is a 

proper exercise of our authority under the Clean Air Act in light of the need for further 
35

scientific review of CO2 emissions from biogenic sources. Consistent with our rule and the 

Agency’s position, our PSD analysis for the Project does not include an evaluation for CO2

emissions.

With regard to alternatives to the Project, we do not agree that our obligations under 

section 165(a)(2) are as broad as the commenter suggests. EPA does not have an obligation 

to independently investigate all possible power generation alternatives. Further, the 

Environmental Appeals Board has observed the importance of this limitation on the permit 

issuer's obligation, particularly where the evaluation of need for additional electrical 

generation capacity would require a rigorous and robust analysis and would be timeconsuming and burdensome for the permit issuer. In such circumstances, the permit issuer 

is granted considerable latitude in exercising its discretion to determine how best to apply 

scarce administrative resources. In re Prairie State Generating Company, 13 E.A.D. 1, 32 

(EAB 2006) at 33.

In this case, EPA does not believe that it is appropriate to conduct the type of analysis that 

would be required to “fully evaluate possible permit conditions that would reduce of avoid 

greenhouse gas pollution” from the Project. Even if EPA did have the expertise and 

resources to conduct such an analysis, the commenter has not provided any criteria on 

which such an analysis could be measured against so as to meet the commenter’s demand 

for a “full” evaluation.

56. Comment: The commenter states that the grandfathering provisions in EPA’s proposed

rule revising the PM NAAQS are unlawful.

Response: As stated in the public notice for the Project, EPA has requested public 

comment on its proposed action relating to the Project. The commenter states that the 

Center for Biological Diversity has submitted comments to EPA with regard to the specific 

issue of grandfathering PSD actions in the context of our recently proposed PM NAAQS. 

EPA will address those comments as part of our rulemaking action on the PM NAAQS.

Comments Submitted by Mrs. Scott and Ashley Wayman

57. Comment: The commenter states that the biological resources, parks and neighborhoods, 

including Verde Vale Elementary school, surrounding the proposed plant would be greatly 

affected in adverse ways. The commenter would like a larger area started within the 

forthcoming Environmental Impact Report.

Response: The AAQIR supporting the proposed action describes the legal and factual basis 

for the proposed permit, including requirements under the PSD regulations at 40 CFR §52.21. 

The AAQIR examines the potential impacts to air quality and biological resources as required 

under the PSD program. It is unclear from the comment above what larger area needs to be 

considered under this action. 

58. Comment: The commenter has inquired as to how the new cogeneration unit will not 

continually violate air standards. What will the facility do about odor?
36

Response: The PSD permit with this action requires the facility to comply with applicable 

requirements under the PSD program. The permit requires BACT for NOx, CO, PM, PM10

and PM2.5. The emission limits in the permit will protect the NAAQS for NO2, CO, PM10

and PM2.5. Moreover, the permit contains monitoring, recordkeeping and reporting 

requirements to ensure that the facility complies with emission limits contained in the 

permit.

The PSD permit does not contain requirements directly regarding odor because odor is not 

a regulated NSR pollutant. Separately, odor is listed as an air contaminant in Shasta County 

District Rule 1:2. Moreover, District Rule 3:16 states that the Air Pollution Control Officer 

may place reasonable conditions upon any source that will mitigate the emissions of air

contaminants or other material which cause injury, detriment, nuisance, or annoyance to

any considerable number of persons or to the public, or which endanger the comfort,

repose, health, or safety of any such persons or to the public, or which cause, or have the 

natural tendency to cause, injury or damage to business or property.

59. Comment: We ask that considerations be made to the cultural and historical sites within 

the proposed project site. 

Response: The location for the modification at SPI- Anderson will be within the physical 

footprint of the current facility location. The facility is located at 19758 Riverside Avenue in 

Anderson, California 96007 (Assessor’s parcel No. 050-110-025). The site is approximately 

0.5 mile west of Interstate 5, and approximately 2 miles north of the city of Anderson. It is 

unclear what cultural or historical sites within the boundary of the current facility location need 

to be considered given that the Project will be located on SPI- Anderson’s existing site. 

Comments Submitted by Ms. Patricia Lawrence

60. Comment: Cumulative impacts of total air pollution in California's upper central valley 

have not been completely evaluated to include pollution from wildfires, increased vehicle 

and stationary sources of pollution, and air traffic pollution including chemtrails from jets 

in the federal weather modification program.

Response: The AAQIR, which describes the legal and factual basis for the permit, including 

requirements under the PSD regulations at 40 CFR §52.21, analyzed air quality impacts from 

the Project. The air quality impacts portion of the AAQIR assessed the impacts of the Project 

on ambient air quality. EPA concluded that the emission limits will protect the NAAQS. It is 

unclear from the commenter’s statement why the background ambient air quality monitoring 

data does not include these incidents or how they will affect Project’s ability to protect the 

NAAQS.

61. Comment: There is only so much clean air in the upper central valley where inversion 

layers are prevalent. Who gets the clean air and for what purpose? Why should a biomass 

plant be first over a solar panel manufacturer?
37

Response: As stated in the response to comment #60, the AAQIR assessed the impacts of 

the Project on ambient air quality and EPA concluded that the emission limits will protect 

the NAAQS. 

Regarding the solar panel comment, please see the response to comment #13.

62. Comment: There may or may not be a steady or long lasting supply of biomass from the 

forests and wildlands. The applicant states that wood and 'other' biomass is proposed to be 

burned that will include household and industrial waste such as car tires. Even best 

available technology will not scrub all the dioxins from waste and tire burning.

Response: The new boiler will only be allowed to burn biomass, traditional non-waste fuel 

and not be permitted to burn waste that is not considered a traditional fuel. See response to 

comment #86. In particular, Condition X.G.1. in the PSD permit restricts fuel to natural gas 

and the following:

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

debris from urban areas;

b. All agricultural crops or residues;

c. Wood and wood wastes identified to follow all of the following practices; 

i. 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

ii. Harvested for the purpose of forest fire fuel reduction or forest stand improvement.

The fuel restrictions in the PSD permit do not allow for the combustion of industrial waste 

or of car tires, and therefore the combustion characteristics from the burning industrial 

waste or of tires was not analyzed in the AAQIR for the Project.

63. Comment: Loss of California's natural forests due to clearcutting and conversion to tree 

farms and previous wildfires is releasing a huge carbon sink in these forests that needs to 

be protected to help reduce carbon in the atmosphere. What to do with accumulated 

biomass is a big problem in this state. Burning is not the only option. Chipping it and 

putting it back on the forest floor is another. 

Response: The treatment of accumulated biomass within the state of California is beyond 

the scope of this PSD permitting action. To the extent that the Project should be subject to a 

BACT analysis for GHGs, EPA concluded that the PSD program did not apply to the 

Project for GHGs. The AAQIR identified an increase in GHG emissions that exceeds the 

“subject to regulation” threshold of 75,000 tpy CO2e and the GHG significance rate of 0 

tpy, however EPA’s Deferral for CO2 emissions from Bioenergy and Other Biogenic 

Sources under the Prevention of Significant Deterioration and Title V programs (76 FR 

43490 July 20, 2011) applies to the Project. Since the non-deferred GHG emissions for this 

project are 38,252 tpy CO2e, as calculated in Appendix A of the AAQIR, the modification 

is not subject to BACT for GHG. 
38

64. Comment: The commenter requests a public hearing in order to address the issues raised 

in Comments #60-63 and all issues that this proposal evokes.

Response: Pursuant to 40 CFR 124.12, EPA must hold a public hearing if it, on the basis 

of requests, determines there is a significant degree of public interest in a draft permit. 

After distributing the public notice to the necessary parties in accordance with 40 CFR Part 

124 and additional members of the public, EPA received comments from 15 members of 

the public, including the applicant, and three requests for a public hearing. None of the 

requests for a public hearing demonstrated that there was significant public interest in the 

Project; therefore EPA did not hold a public hearing. EPA reviewed and responded to all 

written comments from the public received during the public comment period.

Comments Submitted by Mr. Dave Brown, Environmental Affairs and Compliance Manager 

of Sierra Pacific Industries- Anderson Division

Sierra Pacific Industries (SPI) appreciates the opportunity to comment on the proposed PSD 

permit and supporting Ambient Air Quality Impact Report (AAQIR) for the SPI Anderson 

facility. While not specifically addressed in the PSD or AAQIR documents, it is noted that the 

overall facility permitting process for this project has included an Environmental Impact Report

(EIR) to fulfill the requirements of the California Environmental Quality Act (CEQA) and 

approval of a Special Use Permit as required by Shasta County. That EIR similarly addressed 

Air Quality (including reference to the PSD permit and process), Climate Change, Soils, 

Traffic, Noise, Water Resources and other considerations. A public hearing was held for the 

initial scoping meeting, a second hearing at the Planning Commission for the EIR certification 

and Use Permit approval, and a third public hearing on appeal to the County Board of 

Supervisors (BOS), which upheld approval of the EIR and Use Permit. The Notice of 

Determination was filed following the BOS approval, which was not contested by any party

within the 30-clay statute of limitations period following its issuance.

The comments below are first shown relative to the AAQIR document, followed by comments 

specific to the proposed PSD permit (and indicated in earlier comments of the AAQIR as 

applicable). It is understood that the AAQIR is the technical analysis that the actual PSD relies

upon. While these comments are intended to correct minor inaccuracies and inconsistencies in 

the draft documents, the changes we have proposed do not affect the substantive analysis and 

would not require significant revisions to the AAQIR or the proposed PSD permit.

AAQIR

65. Comment: Boiler Design -Section 7.1.1 of the AAQIR indicates two general boiler 

technology designs, including stoker and fluidized bed. The stoker example (top of page 

12, further defines Stoker to include "vibrating, traveling grate, etc." For purposes of clarity 

and relevance to the proposed boiler, the term 'step-grate' should be added to this 

description as the proposed boiler utilizes a mechanical step-grate for fuel distribution and 

neither a vibrating nor traditional traveling grate system. Similarly, the boiler should only 

be defined as "Stoker" without the additional definition for the grate type in other portions 

of the permit, including but not limited to the following:
39

Page 6- Table 4-1: Proposed New Equipment- need to strikeout the term "with vibrating 

grate" next to Stoker Boiler.

Response: EPA acknowledges the comments. Although we do not produce a revised 

AAQIR as part of our final permit decision, we reviewed these comments and determined 

that they do not require a change in our final permit decision or additional analysis of the 

basis for our determinations.

66. Comment: The NOx mass emission limit shown "Step 5 -Select BACT" on page 16 is

60.8lb/hr (3-hour block average). This value is based on the 0.13lb/MMBtu (12- month 

rolling average) BACT limit. It would be more appropriate to base the mass emission limit 

based on the 0.15 lb/MMBtu (3-hour block average) BACT limit, in which case, the value 

would be 70.2 lb/hr (3-hour block average).

Response: EPA agrees that the 60.8 lb/hr mass emission limit should correspond to the 

12-month rolling average and that 70.2 lb/hr mass emissions should correspond to the 3-

hour block average as the applicant has appropriately noted. As the boiler for the project 

will have a rating of 468 MMBtu/hr, it can be readily verified that the product of 468 

MMBtu/hr multiplied by 0.13 lb/MMBtu is 60.8 lb/hr, and that the product of 468 

MMBtu/hr multiplied by 0.15 lb/MMBtu is 70.2 lb/hr. Therefore the mass emission limit 

on a 3-hour block average corresponding to the 0.15 lb/MMBtu BACT determination for 

NOx should, in fact, be 70.2 lb/hr. Our proposed permit limit of 60.8 lb/hr (3-hour block 

average) was therefore erroneous. The final permit contains the correct limit of 70.2 lb/hr 

(3-hour block average).

The permit has been revised to incorporate the correct NOx lb/hr mass emission limit for 

U1. 

67. Comment: Misreference- The first sentence of the first paragraph in Section 6 

(Applicability of the Prevention of Significant Deterioration Regulations) references Table 

4. We believe the reference is actually to Table 6-1 and should be corrected accordingly.

Response: EPA acknowledges the comment. Although we do not produce a revised 

AAQIR as part of our final permit decision, we reviewed the comment and determined that 

it does not require a change in our final permit decision or additional analysis of the basis 

for our determinations.

68. Comment: PSD non-applicability- Table 6.1 of Section 6 (Applicability of the Prevention 

of Significant Deterioration Regulations) indicates that SO2, VOCs, H2SO4, and Pb are 

each less than the significant emission rate, and, therefore, PSD does not apply. This is 

reiterated in Section 8.4, which says "As shown in Table 8.4-1, EPA does not expect SPIAnderson to emit Pb, VOC, and SO2 in significant amounts." In each of these 

determinations, the facility and its permit are not subject to BACT, Air Impact Analysis 

requirements, or conditions for each of these pollutants.
40

As explained above and in the EIR for this project, SO2 emissions are not expected to 

exceed the PSD significant emission rate threshold, and, therefore, this pollutant is not 

subject to PSD regulations. As such, the SO2 limit in Table 7.1-7 should be removed.

Response: The applicant correctly notes that BACT for SO2 does not apply for the project, 

as noted in Table 6-1 of AAQIR. Therefore, EPA should not have included an emission 

limit for SO2 corresponding to BACT emissions limits during startup and shutdown. EPA 

has removed the emissions limitation erroneously attributed to BACT for SO2 during and 

startup and shutdown.

EPA does not produce a revised AAQIR as part of our final permit decision; however, we 

revised the final permit issued for the project in accordance with this comment. 

69. Comment: Typographical Error- Table 6-1 and footnote 3 do not match with respect to 

CO2e. We do not contest either quantity, simply that the final permit should have similar 

values. Similarly, the VOC emissions from Table 6-1 (34.9) do not match Table 8.4-1 

(34.8).

The stack temperature associated with startup/shutdown operation shown in Table 8.3-1 

should be 250 °F, not 294 °F.

Response: EPA acknowledges the comments. Although we do not produce a revised 

AAQIR as part of our final permit decision, we reviewed these comments and determined 

that they do not require a change in our final permit decision or additional analysis of the 

basis for our determinations.

70. Comment: Startup and Shutdown BACT limits- Section 7.1.3 provides a general 

description of startup and shutdown procedures relative to the boiler operations and 

otherwise excludes actual pollutant concentration operations during this period. Section 

8.4.2 includes Analysis of startup and shutdown for emissions and indicates that "Startup 

CO emissions are expected to exceed those experienced during normal operating 

conditions." As such, startup and shutdown averaging periods longer than normal 

operations (3-hour) are warranted. The technical studies supporting the PSD permit 

considers 1 hour and 8 hour concentrations for modeling purposes. SPI respectfully

requests that for startup and shutdown the averaging limits may remain unchanged in Table 

7.1-7, but the averaging times should be changed to hourly concentrations (8-hour average) 

for CO and NOx.

Response: The final permit has been revised to show that the averaging times for the NOx

and CO emission limits during startup and shutdown are based on an 8-hour average. The 

mass limits remain unchanged. EPA has also added Condition X.C.2. which states that

“CO emissions at all times from U1, including startup and shutdown events as defined 

Conditions X.D.3. and X.D.4., shall not exceed 432 lbs/hr (hourly average).” Condition 

X.C.2., in conjunction with the other CO emission limits for U1 in the final permit, 

constitute EPA’s BACT determination for CO from U1. 
41

As noted in the AAQIR for the Project, SPI-Anderson expects periods of startup and 

shutdown to be infrequent in nature. In its March 2010 application, the applicant stated that 

it typically shuts down its boilers at least twice per year for maintenance. Conditions 

X.D.3.and X.D.4 in the PSD permit for the Project define startup and shutdown periods for 

the boiler and state that the generator shall be separated from the electrical grid during 

these periods. By separating the generator and consequently disallowing sale of electricity 

to the grid during periods of startup and shutdown, SPI does not have a financial incentive 

to operate the boiler in states of startup or shutdown. Therefore, EPA believes that the 

emissions experienced during periods of startup and shutdown will occur on an infrequent 

basis.

Although EPA has increased the averaging period of NOx during startup and shutdown, an 

updated modeling analysis for the 1-hour NO2 NAAQS was not conducted. As noted in 

EPA’s guidance memorandum dated March 1, 2011, EPA believes that it is inappropriate 

to implement the 1-hour NO2 standard, which is expressed in a statistical form, in a manner 

that compliance demonstrations be based on emission scenarios that can logically be 

assumed to be relatively intermittent. When EPA is the reviewing authority for a permit, 

we will consider it acceptable to limit the emission scenarios included in the modeling 

compliance demonstration for the 1-hour NO2 NAAQS to those emissions that are 

continuous enough or frequent enough to contribute significantly to the annual distribution 

of daily maximum 1-hour concentrations, rather than for startup and shutdown events that 

may occur on a relatively infrequent basis. See online docket I.40: Additional Clarification 

1hr NO2 Modeling-Fox_01MAR11 at 9-10 in online docket.

In addition, although EPA has increased the averaging period for CO during startup and 

shutdown, an updated modeling analysis for the 1-hour CO NAAQS was not necessary 

because this modeling analysis has already been conducted. Table 7.1-7 of the AAQIR, 

which contains BACT emission rates during startup and shutdown, relied on values 

presented in Table 5 of SPI’s May 30, 2012 submission. The values presented in SPI’s 

Table 5, however, are somewhat inaccurate. See online docket #I.11: SPIAnderson_updated_modeling_and_SUSD_analysis-final_30MAY12. This flaw, however, is 

minor since the footnote to SPI’s Table 5 clearly states that modeled impacts for the CO 

were estimated using a mass emission rate of 432 lbs/hr (1-hour average). As shown in 

Table 8.3-1 of the AAQIR, Project-only modeled impacts reflect that modeling based on 

values of 432 lbs/hr (1-hour average) and 108 lbs/hr (8-hour average) was conducted. For 

this reason, EPA has also added Condition X.C.2. to the final permit to limit CO emissions 

to 432 lb/hr (1-hour average) in addition to the startup and shutdown mass emissions limit 

for CO of 108 lbs/hr (8-hour average). 

For further discussion, please see the response to comment #50. Permit Condition X.D.5

has also been changed to reflect the 8-hour averaging period. 

71. Comment: Determination of Compliance- Section 7.2, Step 5 (page 24) selects BACT for 

the Emergency Engine. An emergency engine is typically not subject to annual source 

testing to determine compliance. Rather, to avoid the impracticality of source testing, 

compliance may be achieved by providing performance specifications from the 
42

manufacturer to meet or exceed the g/kW-hr (on a 3-hour max rolling average) as specified 

in Table 7.2-3.

Response: EPA has determined that the following is BACT for the Emergency Engine: 

BACT for 191 kW Emergency Engine

Pollutant Limit Averaging 

Time

NOx 0.78 (lb/hr) Hourly

CO 4.0(g/hp-hr) 3- Hour

PM, PM10, PM2.5 0.0216 (lb/hr) Hourly

These limits are set forth in Table 6 of the final permit. Condition X.I.4. of the final permit 

requires an initial performance test as set forth in 40 CFR §60.4244, and at least every five 

years beginning ten years after the initial performance test. See the Appendix to this 

document for more information on the BACT determination for the emergency engine.

EPA has updated the equipment description for this emissions unit in the final permit to be 

a spark-ignition (SI) internal combustion, natural gas-fired emergency engine. As stated in 

the BACT analysis and the final permit, the emergency engine shall comply with 40 CFR 

Part 60 Subpart JJJJ. Moreover, Condition X.G.3. has been added to the final permit which 

states that “the heat input to U3 shall only be PUC-quality pipeline natural gas.”

EPA has removed the testing requirement for PM10 from the emergency engine from 

Condition X.H.4. in the proposed permit. EPA acknowledges that emissions from SI 

emergency engines combusting pipeline natural gas have low PM10 emissions and that 40 

CFR Part 60 Subpart JJJJ does not contain PM10 emission limits or require monitoring or 

performance tests for PM10 emissions, In order to demonstrate compliance with the 

PM/PM10 emissions limit in Condition X.E.1, the permittee shall comply with Conditions

X.G.3. and X. J.10. in the final permit. Condition X.J.10. states that “[f]or U3, the permittee 

shall maintain records of the following: hours of operation, purpose of operation, fuel usage 

on hourly basis and calculated PM/PM10 emissions base on manufacturer emissions 

specifications and fuel usage data.” 

72. Comment: In the first sentence of Section 7.2.1 (NOx, CO, PM, PM10, PM2.5 Emissions), 

Step I-Identify all control technologies, "catalyzed diesel particulate filter" should be 

removed from the list. The proposed engine is a natural gas-fired, spark-ignition engine, 

and use of that control would not be appropriate. Similarly, the last sentence of that same 

paragraph should be removed.

Response: The Appendix to this document contains an updated BACT analysis for the 

natural gas-fired spark ignition emergency engine. The revised BACT analysis does not 

identify the diesel particulate filter or a particulate filter trap as appropriate control 

technologies for this unit. 

73. Comment: The NSPS limits provided in Table 7.2-1 (NSPS Limits for Engines) and Table

7.2-3 are from Subpart IIII, which covers compression-ignition engines. Limits from 
43

Subpart JJJJ, which covers spark-ignition engines should be used instead. We suggest that 

Table 7.2-1 and Table 7.2-3 should appear as follows:

Table 7.2-1: NSPS Limits for 191 kW, Natural Gas-Fired, Spark-Ignition Engines

Engine Type NOx (g/hp-hr) CO (g/hp-hr) PM (g/hp-hr)

Non-emergency engine 1.0 2.0 0.7

Emergency Engine 2.0 4.0 1.0

Table 7.2-3: Summary of BACT for 191 kW, Natural Gas-Fired, Spark-Ignition 

Emergency Engine

Engine Type NOx (g/hp-hr) CO (g/hp-hr) PM (g/hp-hr)

Emergency Engine 2.0 4.0 1.0

Similarly, Table 7.2-2, which reflects the limits from Subpart IIII instead of Subpart JJJJ,

should appear as follows:

Table 7.2-2: Summary of PTE for 191 kW, Natural Gas-Fired, Spark-Ignition

Emergency Engine

Pollutant Emergency Engine (tpy)

NOx 0.056

CO 0.11

PM 0.028

Response: The Appendix to this document contains an updated BACT analysis for the 

natural gas-fired spark ignition emergency engine. The revised BACT analysis incorporates 

the appropriate emissions limits from 40 CFR Subpart IIII; however, the PTE summary for 

NOx and PM have not changed from the proposal as the PTE limits for those pollutants 

were based on more stringent emissions limits supplied by the applicant’s consultant in an 

April 26, 2012 email. See the Appendix for more detail.

74. Comment: Typographical Error- Section 7.3 under "Wet Cooling" (bottom of page 24) 

should indicate a three-cell cooling tower, not a two-cell cooling tower. This was reflected 

in the May 30, 2012 Updated Air Dispersion Analysis prepared by Environ and identified 

in the PSD permit.

To be consistent, the NO2 annual NAAQS entry in Table 8.4-3 (SPI-Anderson Compliance 

with Class II PSD Increments and NAAQS) should read: "100 (53 ppb)."

Response: EPA acknowledges the comment. Although we do not produce a revised 

AAQIR as part of our final permit decision, we reviewed this comment and determined that 

it does not require a change in our final permit decision or additional analysis of the basis 

for our determinations.

Prevention of Significant Deterioration Permit Conditions (PSD Permit)
44

75. Comment: As stated in #6 above, the description of the cooling tower in the second 

paragraph under Project Description, and of ID U2 in Table 1, should be changed to read 

"three-cell," instead of “two-cell."

Response: The permit has been revised to incorporate the suggested language. EPA notes 

that this revision is descriptive in nature and does not have any substantive effect on the 

permit or EPA’s analysis of the Project. 

76. Comment: As stated in #1 above, the term "with Vibrating Grate" should be removed 

from Table 1.

Response: This term has been deleted from PSD Permit SAC 12-01. EPA notes that this 

revision is descriptive in nature and does not have any substantive effect on the permit or 

EPA’s analysis of the Project.

77. Comment: Malfunction Reporting- Section IV of the PSD permit includes provisions for 

the Permittee to notify EPA for malfunctions. This is atypical of similar operating permits 

and usually reported directly to the designated Air District and otherwise copied to EPA as 

part of regular reporting. It may be desirable to add an item "D." to this section that allows 

for items IV.A thru C to be waived if notification is submitted to the Air District.

Response: Section IV will remain unchanged. EPA is currently the PSD permitting 

authority in the District. As a result, the permittee must report malfunctions to EPA Region 

9. The PSD permit authorizes the construction and operation of emissions units associated 

with the Project; however it is not an Operating Permit under title V of the Clean Air Act. 

If the District adopts the PSD permitting program, then the permittee may request a permit 

revision that removes reporting requirements to EPA.

78. Comment: Typographical Error: Section X- Table 3 -the values for PM, PM10, and PM2.5

(each at 41) do not match the AAQIR values (each at 42.1 respectively).

Response: This is not a typographical error. The values in Section 6 of the AAQIR reflect 

the changes in emissions resulting from the project, including estimates from the 

emergency engine and the cooling tower. Table 3 limits emissions only from the new 

boiler. The increase in emissions from the AAQIR, particularly for PM, is attributable to 

the PM emissions from the cooling tower and the emergency engine. 

79. Comment: Air Pollution Control Equipment and Operations- Section X.B specifies for 

control equipment to operate continuously, but does not restrict this to operation of the 

boiler itself. It is impractical, and with respect to the electrostatic precipitator (ESP), can 

severely damage control equipment to operate without the boiler. As such, the sentence 

should be rephrased to indicate "During Boiler operations, Permittee shall continuously 

operate...".

Response: The permit has been revised to incorporate the suggested language regarding 

the air pollution control technologies during boiler operations. EPA notes that this revision 
45

is descriptive in nature and does not have any substantive effect on the permit or EPA’s 

analysis of the Project.

80. Comment: The last sentence in this paragraph [Paragraph X.B.] is similarly concerning 

and indicates "Permittee shall also perform any necessary operations to minimize emissions 

so that emissions are at or below the emission limits specific in this permit." This implies

that if conditions warrant, that the Permittee is required to minimize emissions potentially

less than permitted. This creates subjectivity to the term “emission limits" and reduces the 

ability of the Permittee to perform adjustments to fine-tune, utilize approved fuels, or 

similar measures would otherwise be allowed at or below emission limits. As emission 

limits are already defined, this sentence is unnecessary and should be deleted in its entirety.

Response: EPA has replaced this language with the following: Permittee shall also to the 

extent practicable, maintain and operate equipment in a manner consistent with good air 

pollution control practice for minimizing emissions. This requirement imposes an 

obligation substantially similar to 40 CFR. §60.11(d) and encourages SPI to follow 

industry standards for reducing air emissions. 

81. Comment: Natural Gas Usage- As stated in #3 above, SO2 emissions from the proposed 

project are not subject to PSD review. Section X.D.I of the PSD (page 7 of 17) indicates 

requirements for PUC-quality pipeline natural gas and limits of 0.20 grains per 100 dry 

standard cubic feet (dscf) on a 12-month rolling average basis and not to exceed 1.0 grains 

per 100 dscf at any time. This requirement is not warranted by this PSD permit for SO2 and 

should be deleted. If not deleted, the requirement should be limited to providing PUCquality natural gas and no requirements for sulfur content. SPI has spoken with PGE on 

available natural gas. While it is PUC grade, the sulfur content appears to periodically 

exceed the 0.20 grains/dscf throughout most of the state, including the Shasta County area. 

The current wording would potentially prohibit the facility from operating and as indicated 

above should not be restricted or limited by this permit. While we recognize that Sulfur in 

natural gas can contribute to PM emissions, the BACT determination including the ESP 

does not rely upon this for its determination and we respectfully request the change 

incorporated above.

Response: EPA considered pipeline natural gas in the BACT analysis for particulate 

matter as a means to reduce emissions of particulate from the Project due to its low sulfur 

content. In order to verify that the Project is utilizing low sulfur fuels, especially during 

startup and shutdown, the permit will continue to contain requirements that restrict the 

natural gas being combusted in U1 and U3 to Public Utility Commission (PUC)-quality 

pipeline natural gas. EPA agrees that specific sulfur content requirements may be difficult 

to achieve at the facility given the infrequent use of natural gas, As a result, sulfur content 

requirements on a grain per dry standard cubic foot basis have been removed from 

Condition X.D.1. Although Condition X.D.1. has been revised, PM, PM10, PM2.5 emissions 

limits for U1 have not changed from the proposed permit. 

EPA notes that particulate emissions from the combustion of PUC- quality pipeline natural 

gas are expected to be lower than particulate emissions resulting from the combustion of 
46

biomass. In addition, Condition X.G.2. in the final permit restricts the heat input to U1 on a 

12-month rolling basis and, as noted in the response to comment #70, startup and shutdown 

events are expected to be infrequent in nature. 

82. Comment: PSD Non-Applicability and Startup Averaging Periods- As stated in #4 and #6

above, SO2, VOC, and Pb emissions from the proposed project are not subject to PSD 

review. Therefore, the PSD permit should not include emission limits or permit conditions 

associated with these pollutants as in Table 5, item D.8, and Section H. All conditions 

associated with VOC, SO2 and Pb should be deleted from the permit. Averaging periods in 

Table 5 should be changed as indicated in #6 above.

Response: EPA has removed the SO2 emission limits from Table 5 and on Condition 

X.D.8. However, EPA has retained the initial source test requirements for VOC, SO2 and 

Pb. EPA agrees that the source is not subject to PSD for SO2, Pb, or VOC as outlined in the 

AAQIR. As outlined in SPI’s 2010 application, SPI used AP-42 emission factors with fuel 

input throughput figures to estimate the potential to emit of the source. These estimates, 

however, are not based on specific fuel characteristics used on site. While the permit 

contains adequate fuel conditions that justify the technical assumptions in the AAQIR, EPA 

also recognizes that biomass may have a variable emissions profile depending on the 

cellulosic material that is combusted. Therefore, EPA believes the initial source test 

conditions for SO2, VOC, and Pb are not excessively burdensome and are appropriate in 

this case.

EPA has revised the averaging times for emissions limits during periods of startup and 

shutdown in the final permit. See response to comment #70 for more discussion.

83. Comment: Auxiliary Equipment Emissions Limitations- In Table 6 of Section X.E.1, the 

PM/PM10 emission limit on U2 (the cooling tower) should be 0.272 lb/hr (hourly average), 

instead of 0.26 lb/hr.

Response: EPA acknowledges that the proposed permit included the improper hourly 

average emissions limit for PM/PM10 for U2. In a May 2012 submission, the applicant 

revised the PM/PM10 hourly emissions rate of 0.272 lb /hr from the cooling tower and 

included a revised modeling analysis for the Project’s modeled impacts in the AAQIR

reflected an hourly PM/PM10 emissions rate of 0.272 lb/hr from the cooling tower. See

online docket #I.11: SPI-Anderson_updated_modeling_and_SUSD_analysisfinal_30MAY12 at Table 5. EPA has revised Table 6 in Condition X.E.1. in the final permit 

to show that emissions of PM/PM10 from U2 shall not exceed 0.272 lbs/hr. EPA’s BACT 

determination for PM/PM10 emissions for U2 (cooling tower) on a lb/hr basis is Condition 

X.E.1. in the final permit.

84. Comment: Auxiliary Equipment Emissions Limitations-In Item I, Table 6, the NOx, CO, 

and PM/PM10 emission limits shown for U3 (the emergency boiler recirculation pump 

engine) are taken from NSPS Subpart IIII for compression ignition engines, where they 

should have been taken from NSPS Subpart JJJJ, as indicated in #6 above. In Section 
47

X.E.2, the reference to fire safety testing should be removed, as U2 is not used for fire 

safety.

Response: The permit has been revised to incorporate the appropriate emission limits 

following a revised BACT analysis for the emissions unit. For more detail, see the response 

to comment #9 and the Appendix to this document. 

EPA acknowledges the commenter’s clarification that the emergency engine is used for the 

water recirculation pump as needed, and not for fire safety purposes. Therefore, the 

reference to fire safety testing has been removed from Condition X.E.2.

85. Comment: Operating Conditions and Work Practices-Section F. Item 7 refers to wood 

waste and storage bins and the requirement that these remain enclosed. The (wood) fuel 

shed, is by design, an open sidewall system and is not part of any pressurized or temporary 

bin. The phrase "not including the fuel shed" will clarify how this item is interpreted for 

compliance purposes.

Item 14 indicates "All leaks, spills and upsets of any kind shall be corrected or cleaned with 

4 hours." It is assumed and needs clarification that this does not include any upset that may 

occur related to U1, U2, or U3 and that "with" was intended to be "within" 4 hours. Certain 

upset conditions may require timeframes longer than 4 hours, daylight hours, business 

hours, or other conditions that would otherwise prohibit compliance with this item. Please 

clarify the intent of this requirement and add the terms "as practicable".

Item 16 and 17- VOCs were indicated below SERs for this permit and conditions for VOCs 

should not apply.

Response: The permit has been revised to incorporate the language regarding the fuel 

shed.

Regarding Condition X.F.14, EPA incorrectly incorporated a wood waste and collection 

storage condition and has corrected the permit. This condition has been combined with 

Condition X.F.5. Condition X.F.5. now states, in entirety, “Wood waste collection and 

storage bin leaks shall be minimized at all times. All identified wood waste collection and 

storage bin leaks, spills and upsets of any kind shall be corrected or cleaned immediately, 

within 4 hours, as practicable, to correct the leak, spill or upset.”

The permit will retain the work practice standards relating to volatile organic waste and 

containers possibly holding VOCs or volatile organic waste. As demonstrated in the 

AAQIR the Project was below the significant emission rate for VOCs, however these 

conditions represent reasonable work practice standards that may prevent or reduce the 

incidence of fire and other possible sources of additional air pollution. 

86. Comment: Fuel Restrictions- Section F.2 specifies fuels different than those applied for in 

the PSD application by the Permitee, which included:

(from the PSD Application, Section 2.2 Fuel Supply)
48

"Fuel for the cogeneration unit will come from the existing SPI facilities in California at 

Arcata, Anderson, 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". This description has remain unchanged during the PSD process with EPA and 

would request that it either remain for the PSD permit, or be modified to reflect the 

wording below, as approved by the EIR and Special Use Permit. This wording is slightly 

more restrictive although not substantively different than originally proposed to EPA in the 

PSD application and is supported by the modeling and technical analysis for the proposed

PSD.

The fuel description in the draft PSD is not consistent with the PSD application or the 

technical analysis and modeling supporting this project and would be inconsistent with the 

proposed operation of the facility.

(from the approved EIR and Special Use Permit, Shasta County- Use Permit 07-021, 

Condition 91 respectively)

Fuels burned in the cogeneration boiler shall be limited to the following:

a. Waste pallets, crates, dunnage, manufacturing and construction wood wastes, tree 

trimmings, mill residues, and range land maintenance resides;

b. All agricultural crops or waste;

c. Wood and wood wastes identified to follow all of the following practices; 

a. 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

b. Harvested for the purpose of forest fire fuel reduction or forest stand improvement.

Response: EPA is familiar with the fuel terminology proposed in the application. 

However, the facility will only be allowed to burn biomass, traditional non-waste fuel and 

not be permitted to burn waste that is not considered a traditional fuel. The source is not 

considered a solid waste incinerator and has not satisfied the appropriate performance 

standards requirements associated with commercial and industrial solid waste incinerators. 

EPA understands the source’s interest in streamlining its fuel definitions with other 

regulatory agencies. However, the source will not be able to burn waste that is not 

considered a traditional fuel. Therefore, Condition X.G.1. in the PSD permit restricts fuel to 

natural gas and the following:

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

debris from urban areas;

b. All agricultural crops or residues;

c. Wood and wood wastes identified to follow all of the following practices; 
49

i. 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

ii. Harvested for the purpose of forest fire fuel reduction or forest stand improvement.

87. Comment: Performance Tests- As indicated earlier in item 14 above, no performance 

testing is warranted by this PSD permit for items H.1.e (Pb emissions), H.1.b (SOx

emissions), and Item 2.a (both for SO2 and Pb emissions) and these should be respectfully 

removed from the proposed PSD permit. Similarly item 2.c does not provide any flexibility 

from the facility's maximum steam production rate for PM testing. In practical application, 

a percentage of the maximum steam rate is applied to allow operational flexibility while 

maintaining permit limits. To this extent, we request that the PSD permit allow for a 90% 

of the maximum steam rate for performance testing.

Item H.3.d (cooling tower) requires establishment of procedures to ensure TDS limits are 

not exceeded. With a 0.0005% drift rate, TDS is not measurable in practice and 

unnecessary at that performance standard. This item should be deleted in its entirety in 

consideration of the drift rate imposed.

Item H.6 for sulfur gas content-similar to item 13 above. This item is unnecessary and not 

warranted as a condition for this permit and appears unachievable based on review of 

available natural gas supplies (PGE). Similarly, PGE performs testing on entire service

areas, not specific distributions to facilities. As such, the requirement for the Permittee to 

ensure that the fuel tested is representative of the fuel delivered to the site is impractical to 

achieve. Instead, we request that the PSD permit request that the permittee provide sulfur 

content reports (from the PUC Quality Natural Gas distributor- PGE in this instance) with 

no numerically defined requirement on the sulfur content.

Response: EPA has retained the initial source test requirements for VOC, SO2 and Pb 

because EPA believes the initial source test conditions for SO2, VOC, and Pb are not 

excessively burdensome and are appropriate in this case. See response to comment #82 for 

further discussion.

EPA disagrees with applicant’s comment regarding PM testing in Condition X.I.2.c. PM 

testing shall be performed at the maximum steam rate with the appropriate fuel according 

the manufacturer’s specifications. As stated in Condition X.I.5. “Upon written request from 

the Permittee, and adequate justification, EPA may waive a specific annual test and/or 

allow for testing to be done at less than maximum operating capacity.” The applicant has 

not provided sufficient information for the maximum steam rate requirement to be 

permanently waived. 

EPA acknowledges that the permit does not establish limits for total dissolved solids 

(TDS). However, the permittee will still be required to establish maintenance procedures 

that ensure the integrity of the drift eliminators and compliance with recirculation rates. 

Moreover, the permittee will still be required to comply with PM/PM10 emission limits 
50

from U2 as specified in X.E.1. rates and calculated according to Condition X.I.3.b.

Condition X.I.3.d. in the final permit states that the permittee shall do the following. :

“Establish a maintenance procedure that states how often and what procedures will be used 

to ensure the integrity of the drift eliminators and to ensure compliance with recirculation 

rates. This procedure is to be kept onsite and made available to EPA and District personnel 

upon request. The permittee shall promptly report any deviations from this procedure.”

The permit has been revised (See Condition X.J.1) to incorporate the suggested language 

regarding the record of sulfur content reports for natural gas used on site.

88. Comment: Recordkeeping and Reporting – Item I.9 of the PSD permit indicates "for U1, 

daily records of fuel received other than natural gas shall be maintained. These records 

shall include a detailed description of fuel supplier, fuel type and tons received." U1 

receives fuels from the facility itself that are directly conveyed to the fuel delivery and 

handling system. The facility similarly receives fuels from outside sources that are weighed

and tracked - for purposes of this comment, these are facility received or inbound fuels.

Item I.9 should clarify that on-site derived fuels are exempt from recordkeeping regarding

tonnage. For purposes of determining compliance, estimates of fuels may be derived from

the boiler rating, steam flow, and heat value of the fuel (onsite or offsite) to determine an 

overall usage.

Response: Condition X.J.9 (Condition X.I.9 in the proposed permit) will remain 

unchanged. The BACT determinations for the Project and the emissions limits for U1in the 

final permit are on a lb/hr and lb/MMBTU heat input basis. In its application SPI stated that 

the boiler will be rated at 468.0 MMBTU/hr based on heat input. See online docket #I.01:

SPI-Anderson PSD Permit Modification Application_25MAR10 at 3. In order to readily 

verify compliance with the emission limits and fuel conditions in the permit, the permittee 

must be able demonstrate that all fuel combusted in U1 is appropriately monitored and 

recorded. All fuels, including those derived on-site, must comply with fuel conditions in 

Section X.G. of Permit SAC 12-01. Without appropriately accounting for all fuel received 

the permittee would seemingly be able to inappropriately back-date, potentially mislabel

and assume that all unaccounted materials combusted in U1 were compliant fuels generated 

onsite.
51

Appendix

BACT for Emergency Engine

The project includes a 256hp (191kW) natural gas-fired spark ignition emergency engine 

to run a water recirculation pump for the boiler. The limited operation of this unit results

in minimal annual emission rates. This equipment is subject to BACT for NOx, CO, PM,

PM10, PM2.5. 

In the AAQIR and draft permit, EPA incorrectly identified the proposed emergency 

engine as a compression ignition natural gas engine. During the public comment period, 

the applicant noted that the proposed unit was, in fact, a spark ignition natural gas fired 

emergency engine. Taking this information into account, EPA has revised its BACT 

analysis for the emergency engine. 

A top-down BACT analysis has been performed for the spark ignition emergency engine 

and is summarized below.

7.2.1 NOx, CO, PM, PM10, PM2.5 Emissions

Step 1 -- Identify all control technologies

The control options for NOx emissions from engines include SCR, NOx reducing catalyst, 

NOx adsorber, catalytic converter, and oxidation catalyst. A catalytic converter and 

oxidation catalyst are also control options for CO emissions. 

The emergency engine will be required by the final permit to be in compliance with 

NSPS requirements, including emission limits. The emergency engine will also be 

subject to operational restrictions. Different types of engines have different emission 

requirements based on the type of engine being purchased. Engine manufacturers may 

need to employ some of the control technologies identified above in order to comply with 

the NSPS emission limits, depending on the type of engine and the applicable limits. The 

applicant is proposing to install an emergency engine for infrequent recirculation pump 

needs. At a minimum, SPI must purchase an engine that complies with the NSPS and 

meets the emission requirements for emergency engines. However, we note that the

applicant could purchase an engine that meets the NSPS standards for non-emergency 

engines, which have more stringent limits, and operate it as an emergency engine. As a 

result, this review identifies the control technologies to be:

 NSPS-compliant emergency engine 

 NSPS-compliant non-emergency engine

 Operational restrictions (e.g., limits on the hours of operation)

Step 2 – Eliminate technically infeasible control options

All of the control technologies identified are assumed to be technically feasible.

Step 3 – Rank remaining control technologies
52

The available control technologies are ranked according to control effectiveness in Table 

7.2-1.

Engine Type (191kW) NOx

(g/hp-hr)

CO

(g/hp-hr)

Non-emergency engine 1.0 2.0

Emergency engine 2.0 4.0

The NSPS for spark ignition internal combustion engines does not contain emissions 

limits for PM, PM10 or PM2.5. However, the applicant submitted emissions estimates for 

the emergency engine that are more stringent than the NSPS standards for a natural gas 

spark engine for NOx and PM, PM10 and PM2.5 in an email on April 26, 2012. See online 

docket I.31: SPI-Anderson to EPA re Emergency Engine Emissions 26APR12. 

Step 4 – Economic, Energy and Environmental Impacts

Due to economic impacts and limited environmental benefit, requiring add-on controls or 

compliance with the NSPS for non-emergency engines would be impractical in this case. 

The additional emission reductions would have very little environmental benefit and not 

justify any additional cost. We note that the expected emissions from the emergency 

engine are 226 lbs/year of CO, 78 lbs/year of NOx and 3 lbs/year of PM.

The draft permit contained an hourly NOx emission limit for the emergency engine that is 

more stringent than those found in 40 CFR Part 60 Subpart JJJJ for spark ignition 

emergency engines. This hourly limit was used to assess annual PTE of the emergency 

engine in the AAQIR and has not changed.

In addition, the draft permit contained hourly emissions limits for PM, PM10 and PM2.5. 

The current NSPS for spark ignition natural gas fired engines does not have limits for 

PM, PM10 and PM2.5. The hourly limit in the draft permit was used to asses annual PTE 

of the emergency engine in the AAQIR and has not changed. 

The draft permit also contained an hourly CO emissions limit that is less stringent than 

the 40 CFR Part 60 Subpart JJJJ limits for emergency spark ignition engines; in the final 

permit, EPA will include the more stringent Subpart JJJJ emergency engine emissions 

limit. Our revised calculation of annual PTE for the emergency engine reflects this NSPS 

limit.

As illustrated in Table 7.2-2 the potential emissions from the emergency engine (based on 

100 hours of operation per year and complying with permitted and NSPS for natural gas 

spark ignition emergency engines) has not changed for NOx and PM, PM10 and PM2.5 and 

revised lower for CO. A thorough review of other BACT determinations was not 

performed because it is very unlikely that a more detailed review would change the final 

determination due to the annual emission rates associated with the proposed limits and 

the operational restriction of 100 hours annually.
53

Table 7.2-2: Summary of PTE for 191 kW Emergency Engine

Pollutant Emergency Engine (tpy)

NOx 0.039

CO 0.11

PM, PM10, PM2.5 0.0011

Step 5 – Select BACT

Based on a review of the available control technologies, we have concluded that BACT is 

limiting the hours of operation to 100 hours and the permitted emission limits listed in 

Table 7.2-3. It is assumed that newly purchased engines would be the most energy 

efficient available and that operating in compliance with NSPS requirements will ensure 

that each engine is properly maintained and as efficient as possible. Again, we note that 

the expected emissions from the emergency engine are 226 lbs/year of CO, 78 lbs/year of 

NOx and 3 lbs/year of PM.

Table 7.2-3: Summary of BACT for 191 kW Emergency 

Engine

Pollutant Limit Averaging 

Time

Source

NOx 0.78 (lb/hr) Hourly Permit

CO 4.0(g/hp-hr) 3- Hour NSPS

PM, PM10, PM2.5 0.0216 (lb/hr) Hourly Permit