OCT 1 1 2012

Mr. Omer Shalev (AIR-3) PenThts oitice Ar4 U.S. EPA Region 9 u.s. EPA RegIon

9 75 Hawthorne Street

San Francisco, CA 94105-390 1

Phone: (415) 972-3538

Re: Request for Public Comment

— PSD Application SAC 12-0 1

Sierra Pacific Industries, Anderson Division

Shasta County, California, Region IX

Dear Mr. Shalev

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 ofthe 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 ofthe EIR and Use Permit. The Notice of Determination was filed

following the BOS approval, which was not contested by any party within the 30-day 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 ofthe

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.
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grate system. Similarly, the boiler should only be defined as “Stoker” without the

additional definition for the grate type in other portions ofthe permit, including

but not limited to the following:

Page 6— Table 4-1: Proposed New Equipment — need to strikeout the term “withvibrating grate” next to Stoker Boiler.The NOx mass emission limit shown “Step 5 — Select BACT” on page 16 is60.8 lb/hr (3-hour block average). This value is based on the 0.13 lb/MMBtu (12-

month rolling average) BACT limit. It would be more appropriate to base themass 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).

2. Misreference — The first sentence ofthe first paragraph in Section 6

(Applicability ofthe Prevention of Significant Deterioration Regulations)

references Table 4. We believe the reference is actually to Table 6-1 and should

be corrected accordingly.

3. PSD non-applicability — Table 6.1 of Section 6 (Applicability ofthe Prevention

of Significant Deterioration Regulations) indicates that SO2,VOCs,H2S04and

Pb, are each less than the significant emission rate, and, therefore, PSD does notapply. This is reiterated in Section 8.4, which says “As shown in Table 8.4-1,

EPA does not expect SPI-Anderson to emit Pb, VOC, and SO2in significant

amounts.” In each ofthese determinations, the facility and its permit are notsubject to BACT, Air Impact Analysis requirements, or conditions for each of

these pollutants.

As explained above and in the ER for this project, SO2emissions are not

expected to exceed the PSD significant emission rate threshold, and, therefore,

this pollutant is not subject to PSD regulations. As such, the SO2limit in Table

7.1-7 should be removed.

4. Typographical Error — Table 6-1 and footnote 3 do not match with respect to

C0 2e. We do not contest either quantity, simply that the final permit should havesimilar 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.
technical studies supporting the PSD permit considers 1 hour and 8 hour

concentrations for modeling purposes. SPI respectfully requests that for startupand shutdown the averaging limits may remain unchanged in Table 7.1-7, but theaveraging times should be changed to hourly concentrations (8-hour average) forCO and NOx.

6. 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 ofsource testing, compliance may be achieved by providing performancespecifications from the manufacturer to meet or exceed the g/kW-hr (on a 3-hour

max rolling average) as specified in Table 7.2-3.In the first sentence of Section 7.2.1 (NOx, CO, PM, PM10 PM2.5Emissions),

Step 1 — 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 ofthat control would not be appropriate. Similarly,

the last sentence ofthat same paragraph should be removed.

The NSPS limits provided in Table 7.2-1 (NSPS Limits for Engines) and Table7.2-3 are from Subpart 1111, which covers compression-ignition engines. Limits

from Supart 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

NOx CO PM

Engine Type (glhp-hr) (g/hp-hr) (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

NOx CO PM

Engine Type (gfhp-hr) (gfhp-hr) (gfhp-hr)

Emergency engine 2.0 4.0 1.0

Similarly, Table 7.2-2, which reflects the limits from Subpart 1111 instead of Subpart JJJJ,

should appear as follows:
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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 NO2annual NAAQS entry in Table 8.4-3 (SPI-Anderson

Compliance with Class II PSD Increments and NAAQS) should read: “100 (53

ppb).”

Prevention of Significant Deterioration Permit Conditions (PSD Permit)

8. As stated in #6 above, the description ofthe cooling tower in the second

paragraph under Project Description, and of ID U2 in Table 1, should be changedto read “three-cell,” instead of “two-cell.”

9. As stated in #1 above, the term “with Vibrating Grate” should be removed from

Table 1.

10. Malfunction Reporting — Section IV ofthe PSD permit includes provisions for

the Permittee to notify EPA for malfunctions. This is atypical ofsimilar operating

permits and usually reported directly to the designated Air District and otherwise

copied to EPA as part ofregular 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.

11. 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).

12. Air Pollution Control Equipment and Operations — Section X.B specifies for

control equipment to operate continuously, but does not restrict this to operation

ofthe boiler itself. It is impractical, and with respect to the electrostatic

precipitator (ESP), can severely damage control equipment to operate without theboiler. As such, the sentence should be rephrased to indicate “During Boiler

operations, Permittee shall continuously operate...”.

The last sentence in this paragraph 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 minimizeemissions potentially less than permitted. This creates subjectivity to the term
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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 isnot warranted by this PSD permit for SO2and should be deleted. If not deleted,

the requirement should be limited to providing PUC-quality natural gas and norequirements 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/dscfthroughout most ofthe state, including the Shasta County area.

The current wording would potentially prohibit the facility from operating and asindicated 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.

14. PSD Non-Applicability and Startup Averaging Periods — As stated in #3 and

#5 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 orpermit conditions associated with these pollutants as in Table 5, item D.8, and

Section H. All conditions associated with VOC, SO2and Pb should be deleted

from the permit. Averaging periods in Table 5 should be changed as indicated in

#3 above.

15. Auxiliary Equipment Emissions Limitations — In Table 6 of Section X.E.l, the

PM/PM 10emission limit on U2 (the cooling tower) should be 0.272 lb/hr (hourly

average), instead of 0.26 lb/hr. Also in Item 1, Table 6, the NOx, CO, and

PM/PM 10emission limits shown for U3 (the emergency boiler recirculation pumpengine) are taken from NSPS Subpart 1111 for compression ignition engines, where

they should have been taken from NSPS Subpart JJJJ, as indicated in #6 above.

In Section X.E.2, the reference to fire safety testing should be removed, as U2 is

not used for fire safety.

16. 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 notinclude any upset that may occur related to Ui, U2, or U3 and that “with” was
17. 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

“Fuel for the cogeneration unit will come from the existing SPI facilities inCalifornia at Arcata,Anderson, Shasta Lake, and Red Bluff, as well as in-forest

materials from SPI-owned or controlled timberlands, and various sources of

agricultural and urban wood wastes”. This description has remain unchangedduring 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 ERand Special Use Permit. This wording is slightly more restrictive althought 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 ofthe 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 ofthe following practices;

a. Harvested pursuant to an approved timber management plan prepared

in accordance with the Z’berg-Nejedly Forest practice Act of 1973 orother locally or nationally approved plan; and

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

improvement.

18. Performance Tests — As indicated earlier in item 14 above, no performance

testing is warranted by this PSD permit for items H. i.e (Pb emissions), H. 1 .b

(SOx emissions), and Item 2.a (both for SO2and 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
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deleted in its entirety in consideration ofthe 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 tofacilities. As such, the requirement for the Permittee to ensure that the fuel tested

is representative ofthe 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.

19. Recordkeeping and Reporting — Item 1.9 ofthe PSD permit indicates “for Ui,

daily records offuel received other than natural gas shall be maintained. These

records shall include a detailed description offuel supplier, fuel type and tons

received.” Ui receives fuels from the facility itselfthat 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 ofthis comment,

these are facility received or inbound fuels. Item 1.9 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 ofthe fuel (onsite or offsite) to determine an overall

usage.

SPI respectfully requests that these corrections and clarifications be incorporated into the

fmal AAQIR and PSD permit for the Anderson cogeneration facility. Please let us knowif you have any questions about these comments.

Sincerely,

;)

David C. Brown, PEEnvironmental Affairs and Compliance Manager.