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Adopted Regulation R145-13

ATTACHMENT A

June 5, 2014 SIP Revision

Nevada Division of Environmental Protection

ADOPTED REGULATION OF THE STATE

ENVIRONMENTAL COMMISSION

LCB File No. R145-13

May 2, 2014

EXPLANATION – Matter in italics is new; matter in brackets [omitted material] is material to be omitted.

AUTHORITY: §§1 and 2, NRS 445B.210.

A REGULATION relating to air pollution; revising provisions governing ambient air quality 

standards and certain environmental evaluations; and providing other matters properly 

relating thereto.

Section 1. NAC 445B.22097 is hereby amended to read as follows:

445B.22097 1. The table contained in this section lists the minimum standards of quality 

for ambient air.

NEVADA STANDARDS

A NATIONAL STANDARDSB

POLLUTANT AVERAGING TIME CONCENTRATIONC METHODD

PRIMARY

C, E

SECONDARY

C, F METHODD

Ozone 8 hours 0.075 ppm Chemiluminescence 0.075 ppm Same as primary Chemiluminescence

Ozone-Lake Tahoe

Basin, #90

1 hour

0.10 ppm

(195 μg/m

3

)

Ultraviolet absorption -- -- --

Carbon monoxide

less than 5,000′

above mean sea level

8 hours

9 ppm

(10,500 μg/m

3

)

Nondispersive 

infrared photometry

9 ppm

(10 mg/m

3

) None

Nondispersive 

At or greater infrared photometry

than 5,000′ above

mean sea level

6 ppm

(7,000 μg/m

3

)

Carbon monoxide at

any elevation

1 hour

35 ppm

(40,500 μg/m

3

)

35 ppm

(40 mg/m

3

)
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Adopted Regulation R145-13

NEVADA STANDARDS

A NATIONAL STANDARDSB

POLLUTANT AVERAGING TIME CONCENTRATIONC METHODDPRIMARY

C, E

SECONDARY

C, F METHODD

Nitrogen dioxide

Annual arithmetic 

mean

0.053 ppm

(100 μg/m

3

)

Gas phase 

chemiluminescence

53 ppb

G

Same as primary Gas phase 

chemiluminescence

1 hour [--] 100 ppb -- 100 ppb None

Sulfur dioxide

Annual arithmetic

mean

0.030 ppm

(80 μg/m

3

)

Ultraviolet 

fluorescence

0.03 ppm

H

(1971 standard)

None

Spectrophotometry 

(Pararosaniline 

method)

24 hours

0.14 ppm

(365 μg/m

3

)

0.14 ppm

H

(1971 standard)

3 hours

0.5 ppm

(1,300 μg/m

3

)

None 0.5 ppm

1 hour [--] 75 ppb -- 75 ppb None

Particulate matter 

as PM10

Annual arithmetic

mean

50 μg/m

3

High volume PM10

sampling

None None --

24 hours 150 μg/m

3

150 μg/m

3

Same as primary

High or low volume

PM10 sampling

Particulate matter 

as PM2.5

Annual arithmetic 

mean

[--] 15.0 μg/m

3

-- 15.0 μg/m

3

Same as primary Low volume PM2.5

sampling

24 hours [--] 35 μg/m

3

-- 35 μg/m

3

Same as primary

Lead (Pb) Rolling 3 mo. average 0.15 μg/m

3

High volume 

sampling, acid 

extraction and atomic 

absorption 

spectrometry

0.15 μg/m

3

Same as primary

High volume 

sampling, acid 

extraction and 

atomic absorption 

spectrometry

Hydrogen sulfide 1 hour

0.08 ppm

(112 μg/m

3

)

I

Ultraviolet 

fluorescence

-- -- --

Notes:

Note A: The Director shall use the Nevada standards in considering whether to issue a permit for 

a stationary source and shall ensure that the stationary source will not cause the Nevada

standards to be exceeded in areas where the general public has access. For the 2006 particulate
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Adopted Regulation R145-13

matter as PM2.5 24-hour and annual standards, the 2010 nitrogen dioxide 1-hour standard 

and the 2010 sulfur dioxide 1-hour standard, the Director shall use the form of the

standards set forth in 40 C.F.R. §§ 50.11, 50.13 and 50.17, as those provisions existed on

the effective date of this regulation, to ensure that the Nevada standard is no more stringent 

than the National standard in determining whether the stationary source will comply with

the Nevada standards in areas where the general public has access.

Note B: The National standards are used in determinations of attainment or nonattainment.

The form of a National standard is the criteria which must be satisfied for each respective 

concentration level of a standard for the purposes of attainment. The form for each National 

standard is set forth in 40 C.F.R. Part 50 and may be viewed at 

http://www.epa.gov/air/criteria.html.

Note C: Where applicable and except as otherwise described in Note G, concentration is 

expressed first in units in which it was adopted. [All measurements] Measurements of air 

quality that are expressed as mass per unit volume, such as micrograms per cubic meter, must be 

corrected to a reference temperature of 25 degrees Centigrade and a reference pressure of 760

mm of Hg (1,013.2 millibars [);] ), except measurements of particulate matter as PM2.5 and

lead (Pb), which are calculated in micrograms per cubic meter at local conditions; “ppb” in 

this table refers to parts per billion by volume, or nanomoles of regulated air pollutant per mole 

of gas; “ppm” refers to parts per million by volume, or micromoles of regulated air pollutant per 

mole of gas; “μg/m

3

” refers to micrograms per cubic meter.

Note D: Reference method as described by the EPA. Any reference method specified in 

accordance with 40 C.F.R. Part 50 or any reference method or equivalent method designated in 

accordance with 40 C.F.R. Part 53 may be substituted.

Note E: National primary standards are the levels of air quality necessary, with an 
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Adopted Regulation R145-13

adequate margin of safety, to protect the public health.

Note F: National secondary standards are the levels of air quality necessary to protect the

public welfare from any known or anticipated adverse effects of a regulated air pollutant.

Note G: The official National annual standard for nitrogen dioxide is 0.053 ppm. The National 

annual standard is identified in this table in equivalent units of parts per billion for the purpose

of simplifying its comparison with the National 1-hour standard which is also identified in parts 

per billion.

Note H: The 1971 National sulfur dioxide standards remain in effect for an area until 1 year 

after the area is designated for the 2010 National sulfur dioxide standard, except that in an area 

designated nonattainment for the 1971 National sulfur dioxide standards, the 1971 standards 

remain in effect until an implementation plan to attain or maintain the 2010 National sulfur 

dioxide standards is approved.

Note I: The ambient air quality standard for hydrogen sulfide does not include

naturally occurring background concentrations.

2. These standards of quality for ambient air are minimum goals, and it is the intent of 

the Commission in this section to protect the existing quality of Nevada’s air to the extent 

that it is economically and technically feasible.

Sec. 2. NAC 445B.311 is hereby amended to read as follows:

445B.311 1. An environmental evaluation which is required for a new or modified 

stationary source pursuant to NAC 445B.308 to 445B.314, inclusive, or as required by the 

Director must contain a careful and detailed assessment of the environmental aspects of 
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Adopted Regulation R145-13

the proposed stationary source and must also contain:

(a) The name and address of the applicant;

(b) The name, address and location of the stationary source;

(c) A description of the proposed stationary source, including the normal hours of

operation of the facility and the general types of activities to be performed;

(d) A map showing the location of the stationary source and the topography of the area, 

including existing principal streets, roads and highways within 3 miles of the stationary

source;

(e) A site plan showing the location and height of buildings on the site;

(f) Any additional information or documentation which the Director deems necessary to 

determine the effect of the stationary source on the quality of the ambient air, including 

measured data on the quality of the ambient air and meteorological conditions at the

proposed site before construction or modification; and

(g) [A] Except as otherwise provided in subsection 5, a dispersion analysis of each regulated

air pollutant.

2. Where approval is sought for stationary sources to be constructed in phases, the 

information required by subsection 1 must be submitted for each phase of the

construction project.

3. An environmental evaluation must also consider good engineering practice stack 

height. If the Director considers an analysis of a source based on a good engineering practice

stack height that exceeds the height specified in paragraph (a) or (b) of subsection 1 of NAC

445B.083, the Director shall:

(a) Notify the public of the availability of the demonstration study performed pursuant 

to paragraph (c) of subsection 1 of NAC 445B.083; and
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Adopted Regulation R145-13

(b) Provide an opportunity for a public hearing on the demonstration study in accordance 

with the requirements for a Class I operating permit set forth in subsections 7, 9 and 10 of

NAC 445B.3395.

4. A dispersion analysis used to determine the location and estimated value of the

highest concentration of each regulated air pollutant must include:

(a) A dispersion model based on the applicable models, bases and other requirements 

specified in the “Guideline on Air Quality Models,” which is Appendix W of 40 C.F.R. Part 

51, as adopted by reference in NAC 445B.221, except that the Director may authorize the 

modification of a model specified in the “Guideline on Air Quality Models” or the use of a 

model not included in the “Guideline on Air Quality Models” if the Director:

(1) Determines that the modification or use is appropriate;

(2) Obtains written approval of the modification or use from the Administrator; and

(3) Provides notice of and establishes a 30-day period for comment in accordance with 

the applicable provisions of NAC 445B.3364, 445B.3395, 445B.3447, 445B.3457 or

445B.3477;

(b) A narrative report describing:

(1) If applicable, assumptions and premises used in the analysis, including, without 

limitation:

(I) Model options chosen;

(II) Urban versus rural selection; 

(III) Background concentrations;

(IV) Characterization of emission sources as point, area or volume; 

(V) Emission discharge points; and
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Adopted Regulation R145-13

(VI) Rate of emission from each emission unit; and

(2) The geographic area considered in the analysis, including, without limitation, 

information concerning:

(I) The nearest significant terrain features; 

(II) The receptor grid or grids; and

(III) Restrictions on public access to the stationary source; and

(c) Valid meteorological information pursuant to the provisions of Appendix W of 40 C.F.R. 

Part 51, as adopted by reference in NAC 445B.221, which:

(1) For sources that are not subject to the permitting requirements of 40 C.F.R. § 52.21, 

as adopted by reference in NAC 445B.221:

(I) Is site specific, if the information exists pursuant to subsection 1 of this section 

or subsection 6 of NAC 445B.308, and which covers a period of not less than 1 year;

(II) Has been obtained from an off-site location representative of the proposed site 

and which covers a period of not less than 1 year;

(III) Represents the worst-case meteorological conditions, as approved by the Director 

for synthetic data; or

(IV) Has been obtained over the last 5 years at the nearest National Weather Service 

site; or

(2) For sources that are subject to the permitting requirements of 40 C.F.R. § 52.21, as 

adopted by reference in NAC 445B.221, is representative of the source site location and source 

emissions and which covers a period of not less than 1 year.

5. A dispersion analysis for:

(a) The 1-hour nitrogen dioxide standard established in NAC 445B.22097 is not required 

in an environmental evaluation for:
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Adopted Regulation R145-13

(1) A new stationary source if the new stationary source emits, or has the potential to 

emit, less than 40 tons of nitrogen dioxide per year; or

(2) A proposed modification to an existing stationary source if the proposed 

modification has the potential to emit less than 40 tons of nitrogen dioxide per year.

(b) The 1-hour sulfur dioxide standard established in NAC 445B.22097 is not required in 

an environmental evaluation for:

(1) A new stationary source if the new stationary source emits, or has the potential to 

emit, less than 40 tons of sulfur dioxide per year; or

(2) A proposed modification to an existing stationary source if the proposed 

modification has the potential to emit less than 40 tons of sulfur dioxide per year.
ATTACHMENT B

June 5, 2014 SIP Submittal TSD

Nevada Division of Environmental Protection

Technical Support Document for 

Nevada State Implementation Plan 

Revisions Addressing 

Minor Source Permitting Program
This page is intentionally blank.
B-1

I. Introduction

Section 110(a)(2)(C) of the Clean Air Act (Act) requires that each state implementation plan 

(SIP) include a program to provide for ‘‘regulation of the modification and construction of any 

stationary source within the areas covered by the plan as necessary to assure that national 

ambient air quality standards are achieved, including a permit program as required in parts C and 

D’’ of title I of the Act. The permit programs required in parts C and D of title I of the Act apply 

to new or modified ‘‘major’’ stationary sources of pollutants. Part C applies to certain new or 

modified sources in areas designated as attainment or unclassifiable and is designed to prevent 

significant deterioration of air quality. The requirements under Part C are commonly referred to 

as “PSD New Source Review.” Part D applies to sources in nonattainment areas and is 

commonly referred to as “Nonattainment New Source Review. Both of these programs apply to 

“major stationary sources” and “major modifications” as those terms are defined in 40 CFR Part 

51 Subpart I.

In addition to the PSD and Nonattainment New Source Review requirements, a state’s 

implementation plan must provide for the regulation of the construction and modification of any 

stationary source within the areas covered by the plan as necessary to assure that the national 

ambient air quality standards (NAAQS) are achieved. These general pre-construction 

requirements are commonly referred to as ‘‘minor NSR.’’ See 40 CFR 51.160-51.164. The 

requested revisions to the Nevada SIP set forth herein address deficiencies identified by the U.S. 

Environmental Protection Agency (USEPA) regarding Nevada’s minor NSR program. 

The Nevada Division of Environmental Protection (NDEP) Bureau of Air Quality Planning 

(BAQP) and Bureau of Air Pollution Control (BAPC) is the air pollution control authority for all 

areas of Nevada except for Clark and Washoe Counties, Nevada. The NDEP retains jurisdiction 

over sources that are fossil fuel-fired steam electrical generating units in Clark County.

II. Minor NSR Program SIP Revision Submittals 

Appendix V to 40 CFR Part 51 sets forth required technical support documentation to support a 

SIP submittal or revision. This Technical Support Document (TSD) identifies and responds to 

the requirements set forth in section 2.2 of that provision to support the State’s proposed SIP 

revisions.

(a) Identification of all regulated pollutants affected by the plan

The revisions that are the subject of this TSD concern three criteria pollutants: (1) the 2006 

PM2.5 standard; (2) the 2010 NO2 standard; and (3) the 2010 SO2 standard. The latter two 

standards are 1-hour standards, and are, at times, referred to as the 1-hour standards within this 
document. The new and revised rules allowing the State to implement those standards were 

adopted by the State Environmental Commission on May 2, 2014. The NDEP is the Governor’s 

designee for submitting official revisions of the Nevada SIP to the USEPA. The revisions to the 

Nevada Administrative Code (NAC) for which the NDEP is requesting approval as revisions to 

the Nevada SIP are as follows:

1. NAC 445B.22097:

a. Insertion of the 2006 PM2.5 24-hour and annual standards, the 2010 1-hour SO2

standard, and the 2010 1-hour NO2 standard into the State side of the table set forth in 

NAC 445B.22097.

b. Addition of language in Note A to clarify that the NDEP’s permitting decisions with 

respect to the 2006 PM2.5, 2010 SO2, and 2010 NO2 standards are no more stringent 

than under the federal standard.

c. Clarifying language in Note C as the conditions under which PM2.5 and Lead are to be 

measured.

2. NAC 445B.311:

a. Subsection 5 is created and adds new language providing an air dispersion modeling 

threshold for an application for the 1-hour standards if the proposed project or 

modification has the potential to emit less than 40 tons per year of NO2 or SO2.

(b) Identification of the locations of affected sources including the EPA attainment/ 

nonattainment designation of the locations and the status of the attainment plan for 

the affected areas(s).

The NDEP’s jurisdiction extends over all areas of the State of Nevada, with the exception of 

Clark County and Washoe County. Those two counties have their own air quality planning and 

control departments, with one exception. The NDEP retains jurisdiction over fossil fuel-fired 

steam electrical generating units in Clark County. Currently, that constitutes one facility: the 

Reid Gardner Generating Station (Reid Gardner). Reid Gardner is subject to state legislation 

calling for its retirement as a coal-fired power plant, but the legislation contemplates that the 

NDEP will retain jurisdiction over that facility if new electrical generation units are constructed. 

(Senate Bill 123 (June 2013)). 

The State is designated as follows for the NAAQS that are the subject of this TSD. 

1. PM2.5: The entire State of Nevada has been designated as attainment/unclassifiable for 

the 2006 PM2.5 National Ambient Air Quality Standards (NAAQS). 74 Fed. Reg. 58688, 

58747 (Nov. 13, 2009); see also State Designations, available at 

http://www.epa.gov/pmdesignations/2006standards/final/region9.htm (last viewed April 

11, 2014). 

2. NO2: The entire State of Nevada has been designated as attainment/unclassifiable for the 

2010 1-hour standard. 77 Fed. Reg. 9523, 9568 (Feb. 17, 2012); see also 2010 Nitrogen 
Dioxide Standards – Region 9 Recommendations and EPA Responses, available at 

http://www.epa.gov/airquality/nitrogenoxides/designations/region/region9.html (last 

viewed April 11, 2014). 

3. SO2: The State of Nevada made a recommendation to the U.S. EPA that the State be 

designated as attainment/unclassifiable. The U.S. EPA has not yet issued area 

designations for any part of the State for the 2010 1-hour SO2 standard. 

(c) Quantification of the changes in plan allowable emissions from the affected sources; 

estimates of changes in current actual emissions from affected sources or, where 

appropriate, quantification of changes in actual emissions from affected sources 

through calculations of the differences between certain baseline levels and allowable 

emissions anticipated as a result of the revision.

None of the areas under the NDEP’s jurisdiction are nonattainment, and, therefore, this 

requirement does not appear to apply to these proposed SIP revisions. Nonetheless, the NDEP 

does not anticipate increases in allowable emissions, current actual emissions from affected 

sources, or changes in actual emissions from the baseline levels and allowable emissions as a 

result of these revisions. The revisions instead will require affected sources to comply with three 

new, more stringent standards, which will likely result in emission reductions.

(d) The State's demonstration that the national ambient air quality standards, prevention 

of significant deterioration increments, reasonable further progress demonstration, 

and visibility, as applicable, are protected if the plan is approved and implemented. For 

all requests to redesignate an area to attainment for a national primary ambient air 

quality standard, under section 107 of the Act, a revision must be submitted to provide 

for the maintenance of the national primary ambient air quality standards for at least 

10 years as required by section 175A of the Act.

A. Nevada’s Current Regulatory Structure

1. Federal and State Ambient Air Quality Standards

Under Nevada’s current regulatory structure, Nevada implements both federal NAAQS and state 

ambient air quality standards. It accomplishes this dual function pursuant to NAC 445B.22097. 

That regulation lists the federal NAAQS and separately lists the Nevada ambient air quality 

standards. The federal standards are used for purposes of designating areas as being in 

attainment or nonattainment with the NAAQS. The Nevada list is used for making permitting 

decisions to “ensure that the stationary sources will not cause the Nevada standards to be 

exceeded in areas where the general public has access.” NAC 445B.22097, Note A.
2. Provisions That Protect the Ambient Air Quality Standards

Several other regulatory provisions set forth how the NDEP will ensure that a source will not 

cause the state or national ambient air quality standards to be violated. NAC 445B.308 

safeguards the standards by prohibiting the NDEP from issuing a permit if the applicant’s 

environmental evaluation shows that the facility will prevent the attainment or maintenance of a 

standard, will violate the SIP, or will violate an applicable requirement. NAC 445B.308(2). The 

NDEP may impose reasonable conditions upon a source, including monitoring requirements or 

the requirement to meet standards more stringent than those in the State air quality regulations. 

NAC 445B.308(6). 

NAC 445B.311 requires applicants of sources other than those subject to prevention of 

significant deterioration (PSD) requirements to submit an environmental evaluation with their 

applications pursuant to NAC 445B.308 to 445B.314. The environmental evaluation must 

include, among other things, an air dispersion model that complies with the requirements of 

Appendix W to 40 C.F.R. Part 51. NAC 445B.310 establishes an emission threshold above 

which the applicant must submit an air dispersion model as part of an environmental evaluation. 

Currently, new sources that emit 25 tons per year or more, or existing sources that have a 

potential to emit of 25 tons per year and which are seeking a modification of 10 tons per year or 

more, of any regulated air pollutant must perform an air dispersion model according to Appendix 

W. 

Before the NDEP may issue a permit, it must determine from all “relevant information that use 

of the stationary source will not result in any violation of the air quality regulations or the 

provisions of 40 C.F.R. § 52.21 or 40 C.F.R. Parts 60, 61 and 63, adopted by reference in NAC 

445B.221.” NAC 445B.318; see also NAC 445B.340. The NDEP may not issue a permit if the 

issuance would prevent attainment or maintenance of the air quality standards set forth in NAC 

445B.22097. NAC 445B.308(2). In order to make that determination, the NDEP utilizes air 

dispersion modeling analyses as necessary. 

3. Provisions Regarding Class I Sources

Under Nevada’s regulations, Class I sources are major sources and major stationary sources. 

They are, therefore, subject to Title V permitting and/or PSD permitting rather than minor new 

source review. The NDEP may issue an initial, revised or renewed Class I permit only if the 

permit provides for compliance with “the requirements of NAC 445B.001 to 445B.3689, 

inclusive, and any other applicable requirements” and U.S. EPA has had an opportunity to 

review the proposed permit and has no objections. NAC 445B.340.

4. Provisions Regarding Class II Sources

For Class II sources, which, by definition set forth in the Nevada Administrate Code, are minor 

sources as defined by U.S. EPA, the NDEP may issue a permit only after taking into account 

“the effect of such a facility on the maintenance of the state and national ambient air quality 
standards contained in NAC 445B.22097 and the applicable state implementation plan.” NAC 

445B.3457(4)(c)(3). If the modeling thresholds in NAC 445B.310 are met, the applicant for a 

Class II permit must submit an environmental evaluation, which includes an air dispersion 

model. NRS 445B.308 prevents the NDEP from issuing a permit if the agency determines that 

the new or modified source will prevent attainment and maintenance of the state or national 

standards set forth in NAC 445B.22097 or will cause a violation of the SIP or any applicable 

requirement. NAC 445B.308(2). The NDEP makes that determination by evaluating modeling 

analyses of the new or modified source as necessary. 

5. The Proposed Revisions to Nevada’s Applicable State Implementation Plan

These regulatory revisions submitted for approval into Nevada’s SIP seek to (1) add the revised 

federal standards to the Nevada list so that those standards are implemented in Nevada’s 

permitting decisions; and (2) clarify that Nevada’s implementation of those standards will not be 

more strenuous than the federal standards. The existing language in Note A prohibits a source 

from exceeding, in any given year, any Nevada standard where the general public has access. 

This is equivalent to adopting an annual 100th percentile (or first-high) threshold for the pollutant 

averaged (i.e., hourly, daily, or annual) concentrations. The revised federal standards are 

promulgated with a statistical “form,” which is the 3-year average of either the 98th percentile 

(24-hour PM2.5), 99th percentile (1-hour NO2, SO2), or annual mean (annual PM2.5). Thus, under 

the revised federal standards, the level of the standard may be exceeded on occasion over the 

three years without causing a violation of the standard. The revision to Note A seeks to make 

clear that any environmental analyses required of the facility or performed by the NDEP will not 

be more stringent than the federal standard. In other words, currently, sources must perform 

their modeling analyses to demonstrate that there will not be a single annual exceedance of the 

standard in areas where the public has access (i.e., annual 100th percentile or first high). The 

NDEP is clarifying that, for the three new standards being adopted into the Nevada list, modeling 

performed by the sources or by the NDEP for proposed new facilities or modifications of 

existing facilities will not be more stringent than the federal standard.

The proposed revisions to NAC 445B.22097 and to 445B.311 would require new sources to

provide an air dispersion model in the environmental evaluation with their permit application for 

the 2006 PM2.5 standard if those sources had a potential to emit that is 25 tons per year or more

of PM2.5. For modifications, the revisions require that an applicant submit an air dispersion 

analysis with the environmental evaluation if the facility emits 25 tons or more per year and the 

modification would result in at least 10 tons per year increase. The threshold for requiring the 

applicant to submit a modeling analysis with the environmental evaluation for a modification, if 

the facility emits 25 or more tons per year of PM2.5, is consistent with the significant emission 

rate of 10 tons per year set forth in the PSD rule at 40 C.F.R. 51.166(b)(23)(i). As the U.S. EPA 

has stated: 

The determination of what should be classified as a modification 

subject to major NSR is based, in part, on a ‘‘significant emissions 
rate.’’ The major NSR regulations define this term as a rate above 

which a net emissions increase will trigger major NSR permitting 

requirements, if the increase results from a major modification.

Sources are exempt from major NSR requirements if the emissions 

increase resulting from a modification is below this rate because 

EPA considers such lower emissions increases to be de minimis for 

purposes of the major NSR program.

73 Fed. Reg. 28321, 28332 (May 16, 2008). While the threshold for requiring the applicant to 

submit an environmental evaluation for a new project is above the significant emission rate, it is 

one-fourth of the emissions that would trigger PSD review. 

The proposed revisions would also establish the air dispersion modeling assignment threshold for 

the 2010 1-hour SO2 and NO2 standards. For those two standards, the applicant would not be 

required to submit an air dispersion model with the environmental evaluation if the new or 

modified source were to result in less than 40 tons per year increase of the subject pollutant. The 

40 tons per year is based on the significant emission rate set forth in 40 C.F.R. 51.166(b)(23)(i). 

Pursuant to that regulation, an emissions increase less than 40 tons per year of SO2 or NO2 is not 

deemed significant for the purposes of PSD permitting. An increase less than that is deemed by 

U.S. EPA to be insignificant for PSD applicability determinations. Id. Requiring an applicant to 

submit an air dispersion model only if the new project or modification exceeds those levels is

protective of the NAAQS because such an increase is less than a quarter of the 250 tons per year 

threshold that would trigger PSD permitting under 40 C.F.R. 52.21(b)(1)(i)(b). It is also less 

than half of the 100 tons per year PSD permitting threshold for certain types of sources. 40 

C.F.R. 52.21(b)(1)(i)(a). It is also consistent with the significant emission rates for precursors 

for PM2.5 formation. 40 C.F.R. 52.21(b)(23)(i). Ala. Power Co. v. Costle, 636 F.2d 323, at 360-

361 (D.C.Cir. 1979) (recognizing U.S. EPA’s authority to make a de minimis exception when 

circumstances so merit). Because it is already deemed to be insignificant, it is protective of the 

NAAQS. 

Although the modeling assignment threshold of 25 tons per year of PM2.5 emissions for new 

sources is greater than the 10 tons per year significant emission rate set forth in 40 C.F.R. 

51.166(b)(23), the higher threshold is protective of the state and national ambient air quality 

standards for several reasons, as set forth in more detail below. First, the threshold is protective 

because it is merely one-fourth of the applicable major source threshold and incorporates the 

significant emission rates for PM2.5 precursors. Major sources would be subject to PSD 

permitting if they emit either 100 tons per year or 250 tons per year of PM2.5, depending on the 

type of the facility. A threshold that is one-fourth of that is protective. Second, most minor 

sources with PM2.5 emissions would trigger PSD permitting requirements for other pollutants 

before PM2.5 emissions even approach the level of the state or federal NAAQS. Third, stationary 
source emissions of PM2.5 contribute a de minimis portion of the PM2.5 emission inventory for 

the State. 

B. The Proposed Thresholds Requiring the Permit Applicant to Submit Air 

Dispersion Models with an Environmental Evaluation are a Small 

percentage of the Major Source Thresholds, and are, Therefore, Protective.

First, the existing modeling assignment threshold that would apply to the 2006 PM2.5 standard is 

protective because it is merely one-fourth of the applicable major source threshold. Major 

sources are subject to PSD permitting if they emit either 100 tons per year or 250 tons per year of 

PM2.5, depending on the type of the facility. If a source’s emissions reach 100 tons per year or 

250 tons per year, depending on the type of the source, for any criteria pollutant, it must undergo 

PSD permitting review for all criteria pollutants. Requiring the applicant to submit an air 

dispersion model for PM2.5 with its environmental evaluation only if the potential to emit for a 

new source is 25 tons or more per year is protective because it is merely one-fourth of the 

applicable major source threshold, and even less than one-fourth for sources that are not subject 

to PSD permitting unless they emit 250 tons per year or more. Furthermore, applicants are 

required to submit an air dispersion model for existing sources if the source has a potential to 

emit at least 25 tons per year and the applicant seeks a modification with the potential to emit 10 

tons per year or more. The significant emission rate for PM2.5 under the federal PSD provisions 

is 10 tons per year. Thus, for modifications of a facility that potentially emits 25 tons per year, 

the modeling requirement meets the PSD significant emission rate and is therefore protective of 

the NAAQS. 

The proposed SIP revisions incorporate the significant emission rates for PM2.5 precursors. The 

proposed revisions would require applicants to submit air dispersion models for the new 1-hour 

standards if their sources’ potential to emit meets or exceeds 40 tons per year of NO2 or SO2. 

Those rates are equal to the significant emission rates for NO2 and SO2 as precursors of PM2.5. 

40 CFR 52.21(2)(b)(23)(i). Thus, the proposed revisions comport with the levels of direct PM2.5

emissions and PM2.5 precursor emissions that the USEPA has deemed to be insignificant. 

Similarly, the proposed new threshold for applicants to submit an air dispersion model for the 

new 1-hour standards is 40 tons per year, which is the PSD significant emission rate. Emissions 

below those levels are deemed to be insignificant. 

C. PM2.5 Sources Would Trigger PSD Permitting for Other Criteria 

Pollutants Before PM2.5 Emissions Would Interfere with Attainment or 

Maintenance of the NAAQS.

Second, the existing 25 tons per year threshold is protective because high-emitting PM2.5 minor 

sources would trigger PSD permitting requirements for other criteria pollutants before PM2.5 

emissions would trigger PSD permitting. Such facilities would then be subject to PSD review. 

PM2.5 emissions will not approach any level that could interfere with attainment or maintenance 
of the state or federal ambient air quality standards. To make this determination, the NDEP 

researched whether the existing 25 tons per year emission level is protective of the NAAQS.

The NDEP examined three types of high-emitting stationary combustion sources in this analysis. 

Those stationary combustion sources are deemed to be the ‘worst case scenarios’ for the State, 

based on the emissions inventory and review of published emission factors. The three 

combustion sources reviewed are: a) an industrial wood-fired boiler; b) an industrial boiler 

combusting residual oil; and c) an industrial reciprocal internal combustion engine combusting 

natural gas.

For each one of these sources, multiple emissions scenarios were created based on permit data, 

published AP-42 emission factors1, uncontrolled operations, and various controlled operating 

scenarios. AERMOD modeling pursuant to the requirements of Appendix W and statistical 

approaches were used to determine emission rates and the resulting atmospheric concentrations. 

1. Material and Methods

a) Emission rates

Emission rates for each scenario were estimated using the emission factors established in the 5th 

Edition of the EPA-AP 42 (‘Compilation of Air Pollutant Emission Factors’). Besides the actual 

(i.e. from the permit) control scenarios and production rates, different theoretical scenarios were 

tested to verify how close the resulting atmospheric concentrations would be to the 24-hour 

NAAQS.

b) Pollutant concentrations

Atmospheric pollutant concentrations were estimated using AERMOD v.12345 and 

meteorological data processed with AerMet v.12345 pursuant to Appendix W. Five years of 

representative meteorological data were used, pursuant to Appendix W. The form of the 

standard was calculated for each scenario by using the rolling-average of the five annual 98th 

percentiles (or the 8th highest values of the annual 24-hour distribution). Finally, the average 

design value was used within each source type to create statistical relations between the emission 

scenario and resulting air quality. These relations were used to interpolate and/or extrapolate the 

effects of non-simulated emission scenarios on air quality.

 

1 These emissions factors are published in the 5th Edition of the EPA-AP 42 (‘Compilation of Air Pollutant Emission 

Factors’).
Figure 1: Schematic of the analysis approach adopted in this work. This diagram was repeated for each activity scenario 

and type of source. The definition of a specific activity scenario within the same source type and 5 years of meteorological 

data are the ’starting points’ of this approach. A relation describing the air quality change (e.g., the hypothetical design 

value, expressed in terms of NAAQs percentage) vs. the emission scenarios is the final result.

c) Relation between PM2.5 emission scenario and other criteria pollutant 

emissions

This part of the analysis relates the PM2.5 emissions and effects on air quality with the emissions 

of other regulated criteria pollutants under the same activity scenarios. The main objective was 

to examine whether the activities under the following three scenarios that cause substantial 

deterioration of the PM2.5 air quality standard would be already regulated under the PSD 

program. PSD permits are issued for sources that emit more than 250 tons/year of any regulated 

criteria pollutant (SO2, CO, NOx, and PM10). For this analysis, we also considered the case of 

sources emitting more than 100,000 tons/year of CO2. For the purposes of this analysis, the 

NDEP did not consider whether the facilities would be subject to PSD permitting as one of the 

enumerated stationary sources emitting 100 tons per year or more of a regulated NSR pollutant 

under 40 C.F.R. 52.21(b)(1)(i)(a). Assumptions were made about the operating scenarios to 

reflect reasonable operating parameters based on facilities that actually exist or previously 

existed in Nevada. The EPA’s AP- 42 was used to determine the emission factors for each 

pollutant and each type of source considered.

d) Background concentration

Determination of PM2.5 background concentration was performed using two monitor stations. 

The Jarbidge station (ID 32-007-9000), located in northern Nevada, is considered the 

‘background’ station by the NDEP air quality program. As the station relies on manual samples, 

design values for the period 2007-2011 were calculated based on the reported 3-day 

concentrations. The Jean station located in Clark County (ID 32-0031-019) is managed by the 

Clark County Department of Air Quality and was deemed to be representative of PM2.5 
background concentrations for that area. However, recent analysis showed that this station is 

affected by pollutant transport from California, possibly from the Los Angeles area. The NDEP 

nevertheless used this station as representative of PM2.5 background in southern Nevada and 

used the design values as reported by the EPA for the 2007-2011 period.

Table 1: PM2.5 design values as calculated/reported for the Jarbidge and Jean monitoring stations.

Period Jarbidge (μg/m3) Jean (μg/m3)

2007-2009 10.60 11

2008-2010 8.02 11

2009-2011 8.27 10

Considering that both stations reported similar values, we adopted the overall average of the 

design values (i.e., 9.81 μg/m3) as a PM2.5 background. 

2. Synopsis of results

This section briefly describes the main results obtained from this work. 

A chart is shown for each of the three source types (i.e., wood-fired boiler, industrial oil boiler, 

and IC engine burning natural gas). Each chart displays the relation between simulated PM2.5

design values (i.e., the 5-year average, and expressed in terms of NAAQS percentage) and 

corresponding emission scenarios. Also, each chart displays the relation between the PM2.5

emission scenario and the corresponding emissions of other criteria pollutants (see chart label for 

more details).
a) Wood-Fired boiler

Figure 2: Average estimated percentage of the 24-hour PM2.5 NAAQS as a function of the PM2.5 emissions caused by the 

different operating scenarios. Each empty circle represents the emission and resulting average percentage of the NAAQS 

from a specific activity scenario. The dashed yellow line is the 24-hour PM2.5 NAAQS (i.e., 100%). Based on the 

established linear relation between PM2.5 emissions and percentage of the NAAQS (solid line) and using the emission 

factors from the AP-42, it is possible to estimate for each criteria pollutant the resulting PM2.5 concentration (and hence 

percentage of the NAAQS) caused by an emission of 250 tons/year (100,000 tons/year for CO2). These percentages are 

shown as red bars. Some criteria pollutants are not shown in the chart because the corresponding percentages of PM2.5 

NAAQS are too high to be included. They are, however, reported in the table below. This chart helps determine what 

level of activity (and hence PM2.5 emissions) would already fall under PSD permit conditions because of other criteria 

pollutants. For instance, a system with a wood-fired boiler operating at 38 MMBtu/hour (scenario 1) would not trigger 

any PSD conditions. However, a system with the same boiler operating at 152 MMBtu/hour (scenario 3) would trigger 

PSD conditions because of CO and NOx emissions (and emitting more than 100,000 tons/year of CO2). See Section 3.3 

below for further explanation.

Activity levels for the scenarios reported in the chart. Scenario 1 is the actual permitted case.

1 37.95 MMBtu/hour – actual permit 3 151.8 MMBtu/hour

2 75.9 MMBtu/hour

Codes used for other criteria pollutants used in the chart. The estimated percentage of the 24-hour PM2.5 NAAQS 

that a criteria pollutant emission of 250 tons/year (or 100,000 tons/year for CO2) would cause is given between 

parentheses.

a SO2 (1442%) c CO (60%)

b NOx (74%) d CO2 (74%)

e PM10 (139%)

As Figure 2 shows, a wood fired boiler operating under reasonable conditions (37.95 

MMBtu/hour, which was the rate actually permitted), would be just over twenty percent of the 

NAAQS and less than 25 tons/year. If we were to double that emission rate to 75.9 

MMBtu/hour, its emissions would be approximately 30 tons/year, which would still be less than 

fifty percent of the NAAQS. It would also be above the threshold requiring the applicant to 

model the facility or any modifications to the facility. Only if we were to double the emission 

rate again, from 75.9 MMBtu/hour to 151.8 MMBtu/hour would the NAAQS be potentially 

threatened. But even before reaching that point, the applicant would have to undergo a PSD 

permitting analysis for carbon monoxide, nitrogen oxides, and carbon dioxide. In fact, the 

1

2

3

d

c

b

0 5 10 15 20

0

20

40

60

80

100

120

0 20 40 60 80 100

PM2.5 Emission (lb/hr)

Percentage of NAAQS

PM2.5 Emission (tons/year)
facility would only reach sixty percent of the PM2.5 NAAQS before having to undergo a PSD 

analysis for carbon monoxide. The current 25 tons/year threshold for the applicant to provide a 

modeling analysis for a new facility is protective because PM2.5 emissions would be well below 

the NAAQS at that level. Higher PM2.5 emissions would result in the applicant being subject to a 

PSD analysis for other criteria pollutants before the PM2.5 NAAQS were threatened. 

Additionally, for sources that have a potential to emit 25 tonsperyear, future modifications are 

subject to modeling at 10 tons per year, which is the level that the U.S. EPA deems significant 

pursuant to 40 CFR 52.21(2)(b)(23)(i). 

b) Industrial boiler combusting residual oil

Figure 3: Average estimated percentage of the 24-hour PM2.5 NAAQS as a function of the PM2.5 emissions caused by the 

different activity scenarios. Each empty circle represents the emission and resulting average percentage of the NAAQS 

from a specific activity scenario. The dashed yellow line is the 24-hour PM2.5 NAAQS (i.e., 100%). Based on the 

established linear relation between PM2.5 emissions and percentage of the NAAQS (solid line) and using the emission 

factors from the AP-42, it is possible to estimate for each criteria pollutant the resulting PM2.5 concentration (and hence 

percentage of the NAAQS) caused by an emission of 250 tons/year (100,000 tons/year for CO2). These percentages are 

shown as red bars. Some criteria pollutants are not shown in the chart because the corresponding percentages of PM2.5 

NAAQS are too high to be included. They are, however, reported in the table below. This chart helps determine what 

level of activity (and hence PM2.5 emissions) would already fall under PSD permit conditions because of other criteria 

pollutants. For instance, a system with a 0.5% sulfur content residual oil boiler operating at 467 gal/hour and no PM2.5 

control (scenario 1) would not trigger any PSD condition. However, a system with the same boiler using 1% sulfur 

content (scenario 2) would trigger PSD conditions because of SO2. See Section 3.4 below for further explanation.

Codes for scenarios and activity levels reported in the chart. Scenario 1 is the actual permit

Sulfur Content = 0.5% Sulfur Content = 1%

1 467 gal/hour – no control (actual permitted 

limit)

2 467 gal/hour – no control

3 934 gal/hour – no control 4 934 gal/hour – no control

6 467 gal/hour - Multiple Cyclone Controller 5 934 gal/hour – MCC

1

2

3

4

5

6

a

e

f

g

h

j

0 2 4 6 8 10

0

20

40

60

80

100

120

0 10 20 30 40 50

PM2.5 Emission (lb/hr)

Percentage of NAAQS

PM2.5 Emission (tons/year)
(MCC)

Codes used for other criteria pollutants used in the chart. The estimated percentage of the 24-hour PM2.5 NAAQS 

that a criteria pollutant emission of 250 tons/year (or 100,000 tons/year for CO2) would cause is given between 

parentheses

Sulfur Content = 1% Sulfur Content = 0.5%

a SO2 (37%) f SO2 (46%)

b NOx standard NO burner (124%) g NOx standard NO burner (77%)

c NOx low NO burner (145%) h NOx low NO burner (91%)

d CO (1163%) i CO (725%)

e CO2 (high sulfur) (95%) j CO2 (high sulfur) (59%)

As Figure 3 shows, an industrial boiler running residual oil with 0.5% sulfur content would 

trigger PSD permitting requirements for SO2 well before the PM2.5 NAAQS would be in 

jeopardy. If we were to double the fuel consumption rate to 934 gal/hour, and conservatively 

assume that no air pollution controls are installed, the facility would still trigger PSD permitting 

for SO2 at less than half of the PM2.5 NAAQS, no matter the sulfur content of the fuel. 

Conversely, if the facility were to emit no more than 25 tons per year of PM2.5, it would already 

be subject to PSD permitting because it would be above the PSD threshold for SO2. If burning 

high sulfur fuel, it would also be subject to PSD permitting for carbon dioxide. Again, the 

current 25 tons per year threshold for the applicant to provide a modeling analysis for a new 

facility is protective because PM2.5 emissions would be well below the NAAQS at that level. 

Higher PM2.5 emissions would result in the applicant being subject to a PSD analysis for other 

criteria pollutants before the PM2.5 NAAQS were threatened. Additionally, modifications of 

sources with a potential to emit of 25 tons per year are subject to modeling if the modification is 

at least 10 tons per year, which is the level that the USEPA deems significant pursuant to 40 

CFR 52.21(2)(b)(23)(i).
c) Reciprocating Internal Combustion Engine combusting natural gas

Figure 4: Average estimated percentage of the 24-hour PM2.5 NAAQS as a function of the PM2.5 emissions caused by the 

different activity scenarios. Each empty circle represents the emission and resulting average percentage of the NAAQS 

from a specific activity scenario. The dashed yellow line is the 24-hour PM2.5 NAAQS (100%). Based on the established 

linear relation between PM2.5 emissions and percentage of the NAAQS (solid line) and using the emission factors from 

the AP-42, it is possible to estimate for each criteria pollutant the resulting PM2.5 concentration (and hence percentage of 

the NAAQS) caused by an emission of 250 tons/year (100,000 tons/year for CO2). These percentages are shown as red 

bars. Some criteria pollutants are not shown in the chart because the corresponding percentages of PM2.5 NAAQS are 

too high to be included. They are, however, reported in the table below. This chart helps determine what level of activity 

(and hence PM2.5 emissions) would already fall under PSD permit conditions because of other criteria pollutants. For 

instance, with this type of system, all the emission scenarios considered would already fall under PSD conditions, caused 

by NOx and CO emissions. See Section 3.5 below for further explanation.

Codes for scenarios and activity levels reported in the chart. Scenario 5 is the actual permitted case (with the 

assumption that all PM10 is PM2.5). The actual permit is considered in scenario 1

1 77 MMBtu/hour – no control – actual permit 4 385 MMBtu/hour – no control

2 154 MMBtu/hour – no control 5 77 MMBtu/hour – Factory-guaranteed (all PM10 is 

PM2.5)

3 231 MMBtu/hour – no control

Codes used for other criteria pollutants used in the chart. The estimated percentage of the 24-hour PM2.5 NAAQS 

that a criteria pollutant emission of 250 tons/year (or 100,000 tons/year for CO2) would cause is given between 

parentheses

a SO2 (6788%) d CO 90-105% load (17%)

b NOx 90-105% load (6%) e CO <90% load (12%)

c NOx <90% load (10%) f CO2 (41%)

As Figure 4 shows, a reciprocal internal combustion engine running natural gas would trigger 

PSD permitting requirements for NOx and carbon monoxide well before reaching a level of 

PM2.5 emissions that would interfere with maintenance or attainment of the PM2.5 NAAQS. In 

fact, PM2.5 emissions would be subject to PSD permitting before reaching a level that would 

threaten the PM2.5 standard, even assuming a worst case scenario of an IC engine running at 385 

1 2

3

4

5

b

c

d

e

f

0 10 20 30 40 50

0

20

40

60

80

100

120

0 50 100 150 200 250

PM2.5 Emission (lb/hr)

Percentage of NAAQS

PM2.5 Emission (tons/year)
MMBtu/hour without controls. Furthermore, even at 77MMBtu/hour, the IC engine would emit 

more than 25 tons/year, and, thus would be subject to the modeling requirement. Additionally, 

future modifications are subject to modeling at 10 tons per year, which is the level that the U.S. 

EPA deems significant pursuant to 40 CFR 52.21(2)(b)(23)(i). An internal combustion engine 

in this scenario would have to be operated under severely restricted hours in order for the 

applicant to avoid modeling a modification. Hence, the 25 tons/year modeling threshold for new 

internal combustion engines and 10 tons/year for modifications is protective of the NAAQS. 

A quick glance at all sources confirms the above analyses. In the figure below, the average of all 

three combustion sources combined is represented by the dashed black line. In this case, to have 

(on average) 80% of the NAAQS, the PM2.5 emission threshold should be set to 50 tons/year.

d) All source types

Figure 5: Results from all source types. Symbols and labels are the same as the previous three figures

IC Engine running natural gas: codes for scenarios and activity levels reported in the chart. 

1 77 MMBtu/hour – no control – actual permit 4 385 MMBtu/hour – no control

2 154 MMBtu/hour – no control 5 77 MMBtu/hour – Factory-guaranteed (all PM10 is 

PM2.5)

3 231 MMBtu/hour – no control

IC Engine running natural gas: codes used for other criteria pollutants used in the chart. The estimated percentage of the 

24-hour PM2.5 NAAQS that a criteria pollutant emission of 250 tons/year (or 100,000 tons/year for CO2) would cause is 

given between parentheses

a SO2 (6788%) d CO 90-105% load (17%)

b NOx 90-105% load (6%) e CO <90% load (12%)

c NOx <90% load (10%) f CO2 (41%)

Boiler running residual oil: codes for scenarios and activity levels reported in the chart. Scenario 1 is the actual permit

Sulfur Content = 0.5% Sulfur Content = 1%
1 467 gal/hour – no control (actual permit) 2 467 gal/hour – no control

3 934 gal/hour – no control 4 934 gal/hour – no control

6 467 gal/hour - MCC 5 934 gal/hour – MCC

Boiler running residual oil: codes used for other criteria pollutants used in the chart. The estimated percentage of the 24-

hour PM2.5 NAAQS that a criteria pollutant emission of 250 tons/year (or 100,000 tons/year for CO2) would cause is given 

between parentheses

Sulfur Content = 1% Sulfur Content = 0.5%

a SO2 (37%) f SO2 (46%)

b NOx standard NO burner (124%) g NOx standard NO burner (77%)

c NOx low NO burner (145%) h NOx low NO burner (91%)

d CO (1163%) i CO (725%)

e CO2 (high sulfur) (95%) j CO2 (high sulfur) (59%)

Wood-fired boiler: activity levels for the scenarios reported in the chart. Scenario 1 is the actual permitted case.

1 37.95 MMBtu/hour – actual permit 3 151.8 MMBtu/hour

2 75.9 MMBtu/hour

Wood-fired boiler: codes used for other criteria pollutants used in the chart. The estimated percentage of the 24-hour 

PM2.5 NAAQS that a criteria pollutant emission of 250 tons/year (or 100,000 tons/year for CO2) would cause is givent 

between parentheses.

a SO2 (1442%) c CO (60%)

b NOx (74%) d CO2 (74%)

e PM10 (139%)

Figure 5 also demonstrates that for each of the scenarios, even if operated in a best case manner 

with low sulfur content fuel and controls, PSD permitting requirements would be triggered for 

other pollutants well before PM2.5 emissions would threaten to interfere with attainment or 

maintenance of the NAAQS.

3. Scenario 1 – Wood-Fired Boiler

As a test source, the wood-fire boiler used at the NV Dept. of Corrections in Carson City was 

used (Facility ID A0670). The wood boiler is no longer in operation. The permit number is 

AP9223-2093 (2008). The wood fired boiler is described as a 900 HP Hurst Boiler & Welding 

Company, mfd 2006, 37.95 MMBTU/hr max heat input, steam turbine 1.0 MW output.

a) Meteorological Data

AERMOD v. 12345 was used to estimate atmospheric concentration, employing only regulatory 

options. AerMet for v. 12345 was used to pre-process meteorological data. Even though there is 

a meteorological station managed by NDEP-BAQP in Carson City, preliminary analysis using 

AerMet revealed some issue with the 2008 data. The use of the National Weather Service 

(NWS) station in Reno (for hourly surface, 1-minute ASOS, and upper air data) was less 

problematic while providing very similar results. For this reason, meteorological data from the 

Reno NWS (hourly surface, 1-minute ASOS, and upper air) and from the period 2008-2012 were 

used to perform this analysis. 

A preliminary analysis on the total annual precipitation from 1981 to 2011 was used to identify 

which years in the analysis period had average (30th-70th percentile, 2008), above average (over 
70th percentile, 2009 and 2010) and below average (below 30th percentile, 2011 and 2012) annual 

precipitation. The station in Reno was considered located in an arid region and at the airport site.

b) Emissions and scenarios

An emission limit of 0.10 pound per million Btu’s of heat input was used in all operating 

scenarios as required by the New Source Performance Standards set forth in 40 CFR Part 60, 

Subpart Dc, §60.40c(b)(1).

The mass fraction of PM2.5 is highly dependent on the control system in place (AP 42 Table 1.6-

5). Adopting the worst-case scenario, we assumed that all the PM is less than or equal to 2.5 μm, 

i.e., all emitted PM is PM2.5. Under this condition, emissions of PM2.5 is only a function of the 

system heat input. Therefore, three scenarios with different MMBtu were used for this modeling 

exercise. Emissions in each scenario were estimated as 0.1 lb/MMBtu * MMBtu/hour.

Table 2: Scenarios and associated activity rates and PM2.5 emissions

Scenario # Heat input (MMBtu/hour) Emission (g/s)

1 37.95 (the actual permitted) 0.478

2 75.9 0.956

3 151.8 1.913

c) Modeling and results

AERMOD v12345 was used to model PM2.5 emissions. Receptors were placed across a grid 250

m-spaced and a nested 100 m-spaced grid. Also, discrete receptors were placed along the plant 

fence line, but no receptors were placed within the plant area. Only regulatory options were 

selected for running AERMOD.

Maps of annual 98th percentile values of the 24-hour average distribution (i.e., the 8th highest) 

were produced for each year considered (2008 to 2012). PM2.5 standards were calculated as the 

3-year average of the maximum annual 98th percentile.
Figure 6:Example of PM2.5 concentrations (8th highest max of 24-hour average over 1 year, μg m-3). The scenario 

represented is #3 for year 2012. The red cross is the location of the source, and the white region is the plant area. 

Topography is shown in meters asl.

Table 3: Emissions (g/s) and max 8th highest of 24-hour average PM2.5 for each scenario and year (μg m-3)

Scenario Emissions 2008 2009 2010 2011 2012

1 0.478 6.11 6.19 5.84 6.08 6.16

2 0.956 12.22 12.39 11.68 12.16 12.32

3 1.913 24.44 24.79 23.37 24.33 24.65

Table 4: Emissions (g/s) and estimated 24-hour design values (3-year rolling-average of values in Table 3) for each 

scenario and year (μg m-3)

Scenario Emissions 2008-2010 2009-2011 2010-2012

1 0.478 6.05 6.04 6.03

2 0.956 12.10 12.08 12.05

3 1.913 24.20 24.16 24.12
Figure 7: Time-series of annual max 8th-highest 24-hour average for all the scenarios and years considered in this 

analysis. The red dashed line is the 24-hour EPA-NAAQS. The yellow dashed line is the 24-hour EPA NAAQS minus the 

estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3).

Figure 8: Average estimated design values (Table 4) as a function of PM2.5 emissions. Numbers identify the scenarios 

(Table 4). The red dashed line is the 24-hour EPA-NAAQS. The yellow dashed line is the 24-hour EPA NAAQS minus the 

estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3). The equation for the linear fit is 

shown as well.

Codes for scenarios reported in the figure 

1 37.95 MMBtu/hour 3 151.8 MMBtu/hour

2 75.9 MMBtu/hour

From the above equation, an emission of 2.77 g/s (22.0 lb/hour, or 96.4 tons/year) would be 

required to produce PM2.5 concentrations above the 24-hour NAAQS, assuming no background. 
If a background of 9.81 μg/m3

is assumed, the required emission would be 1.99 g/s (15.79 

lb/hour, or 69.16 tons/year).

d) Other Criteria Pollutant Emissions

In this section, we estimated the emissions of other criteria pollutants based on the scenario(s) 

that would cause a violation of the PM2.5 hourly NAAQS. In particular, a PM2.5 emission of 1.99 

g/s (15.79 lb/hour, or 69.16 tons/year) is required to cause an exceedance of the 24-hour NAAQS 

(averaged over three 3-year periods, see previous section). With a PM emission cap set to 0.1 

lb/MMBtu and assuming that all PM is PM2.5, the heat input required to produce PM2.5 emissions 

that would violate the hourly NAAQS is 158 MMBtu/hour. Using this heat input, we estimated 

the emissions of the other criteria pollutants and CO2 (using EPA AP-42, 1.6-2 and 1.6-3 tables). 

Table 5: Emissions of other criteria pollutants and CO2 under the scenario that would cause an exceedance of the PM2.5 

NAAQS. All annual emissions are expressed in short tons per year and assume a constant hourly emission for 24 hours a 

day, 365 days per year.

Pollutant Annual Emission (short 

tons/year)

SO2 17.3

NOx 338.9

CO 415.0

PM10 134,862.4

CO2 179.8

The previous table shows the annual emissions for other criteria pollutants when PM2.5 emission 

levels cause exceedances of the PM2.5 NAAQS. Using a similar approach, it is also possible to 

estimate the PM2.5. emissions when the other criteria pollutants reach a level of emission equal to 

250 tons/year (which triggers a PSD permit type, or 100,000 tons/year for CO2). The assumption 

behind this calculation is that emissions are constant and continuous for the entire year (i.e., for 

8760 hours per year).
Figure 9: Same as Figure 8. In addition, the PM2.5 emissions and concentrations caused when other criteria pollutants 

are emitted at 250 tons/year (10,000 tons/year for CO2) are shown with red bars. Some criteria pollutants are not shown 

because the corresponding PM2.5 emissions and concentrations are too high to be represented in this graphic. The related 

PM2.5 concentrations (μg/m3) are, however, reported in the table below. The yellow dashed line is the 24-hour EPA 

NAAQS minus the estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3).

Codes for scenarios reported in the figure 

1 37.95 MMBtu/hour 3 151.8 MMBtu/hour

2 75.9 MMBtu/hour

Codes and pollutants for each of the scenarios considered. The PM2.5 emission (g/s) when the other criteria pollutant 

emission is 250 tons/year (or 100,000 tons/year for CO2) is reported between parentheses.

a SO2 (363.3) c CO (15.1)

b NOx (18.5) d CO2 (18.6)

e PM10 (34.93)

4. Scenario 2 - Industrial Boiler combusting residual oil2

The model exercise was built upon the permit case for the Idahoans Foods LLC (formerly known 

as Winnemucca Farms). The facility was stripped of all sources but the main industrial boiler. In 

the original permit, the boiler was set to run oil #6 with 0.5% sulfur content at 467 gallons/hour 

for only a portion of the year (about 5346 hours) and run natural gas for the remaining part. In 

all the scenarios presented in this work, we have assumed that the boiler burns residual oil for the 

entire year.

a) Meteorological Data

The facility did not have on-site met data. AerMet v12345 was used to process the met data. 

Only regulatory options were used, and a 0.5 m/s threshold was used to determine calms with 1-

min automated surface observing systems (ASOS). The years from 2008 to 2012 were used for 

 

2 Residual oil is defined as “crude oil, fuel oil that does not comply with the specifications under the definition of 

distillate oil, and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and Materials in 

ASTM D396 (incorporated by reference, see § 60.17).” 40 CFR § 60.41c. 
the modeling. Daily total precipitation (from NOAA Integrated Surface Database, 

http://www.ncdc.noaa.gov/oa/climate/isd/index.php) from 1981 to 2011 was used to define the 

30-year norm for annual precipitation in Winnemucca. The 30th and 70th percentiles of this 

distribution were used to classify the years between 2008 and 2012 as dry, wet, or average with 

respect to precipitation.

Table 6: Type and source of meteorological data used for this scenario.

Type of met Source Note

Surface Winnemucca Municipal Airport

ASOS-1min Winnemucca Municipal Airport 0.5 m/s threshold

Upper Air Elko 

b) Emissions and scenarios

AP-42 table 1.3-5 was used to estimate PM2.5 emissions for the industrial boiler under different 

working scenarios. 

Table 7: Working scenarios used for the industrial boiler scenario.

Scenario # Sulfur 

content

Oil consumption 

(gallons/hour)

Control Emissions (g/s)

1 0.5% 467 None 0.256 g/s

2 1.0% 467 None 0.409 g/s

3 0.5% 934 None 0.511 g/s

4 1% 934 None 0.819 g/s

5 1% 934 Multiple Cyclone Controller 0.06 g/s

6 0.5% 467 Multiple Cyclone Controller 0.02g/s

c) Modeling and results

Aermod v12345 was used to model PM2.5 emissions. Receptors were placed using a nested grid, 

with high receptor density in proximity of high PM2.5 concentrations. Also, discrete receptors 

were placed along the plant fence line, but no receptors were placed within the plant area. Only 

regulatory options were selected for running Aermod.

Maps of annual 98th percentile values of the 24-hour average distribution (i.e., the 8th highest) 

were produced for each year considered (2008 to 2012). PM2.5 standards were calculated as the 

3-year average of the max annual 98th percentile.
Figure 10: Example of PM2.5 concentrations (8th highest max of 24-hour average over 1 year, μg m-3). The scenario 

represented is #1 for year 2011. The red cross is the location of the source, and the white region is the plant area. 

Topography is shown in meters asl.

Table 8: Emissions (g/s) and max 8th highest of 24-hour average PM2.5 for each scenario and year (μg m-3)

Scenario Emissions 2008 2009 2010 2011 2012

1 0.26 7.86 7.84 7.55 7.28 6.57

2 0.41 12.57 12.54 12.09 11.65 10.51

3 0.51 15.71 15.67 15.10 14.56 13.13

4 0.82 25.17 25.10 24.20 23.33 21.04

5 0.06 1.78 1.71 1.71 1.65 1.49

6 0.02 0.55 0.55 0.53 0.51 0.46

Table 9: Emissions (g/s) and estimated 24-hour design values for each scenario and year (μg m-3)

Scenario Emissions DV 2008-2010 DV 2009-2011 DV 2010-2012

1 0.26 7.75 7.56 7.13

2 0.41 12.40 12.09 11.42

3 0.51 15.49 15.11 14.26

4 0.82 24.82 24.21 22.86

5 0.06 1.73 1.69 1.62

6 0.02 0.55 0.53 0.50
Figure 11: Time-series of annual max 8th

-highest 24-hour average for all the scenarios and years considered in this 

analysis. The red dashed line is the 24-hour EPA-NAAQS. The yellow dashed line is the 24-hour EPA NAAQS minus the 

estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3).

Figure 12: Average estimated NAAQS as a function of PM2.5 emissions. Circles identify the scenarios. The red dashed line 

is the 24-hour EPA-NAAQS. The yellow dashed line is the 24-hour EPA NAAQS minus the estimated background 

concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3). The equation for the linear fit is shown as well.

Codes for scenarios reported in the figure (same for Figure 11) (MMC: Multiple Cyclone Controller)

Solfur Content = 0.5% Solfur Content = 1%

1 467 gal/hour – no control 2 467 gal/hour – no control

3 934 gal/hour – no control 4 934 gal/hour – no control

6 467 gal/hour - MCC 5 934 gal/hour - MCC
From the above equation, an emission of 1.195 g/s (9.5 lb/hour, or 41.62 tons/year) would be 

required to produce PM2.5 concentrations above the 24-hour NAAQS, assuming no background. 

If a background of 9.81 μg/m3is assumed, the required emission would be 0.8603 g/s (6.83 

lb/hour, or 29.92 tons/year), which is still above the modeling threshold of 25 tons per year for a 

new facility and 10 tons per year for a modification of an existing facility with a total potential to 

emit of 25 tons per year or more.

d) Other Criteria Pollutant Emissions

In this section, we estimated the emissions of other criteria pollutants based on the scenario(s) 

that would cause a violation of the PM2.5 hourly NAAQS. From the previous section, a PM2.5

emission of 0.8603 g/s (6.83 lb/hour) would cause a violation of the hourly NAAQS (averaged 

over three 3-year periods, see previous sections). Using this threshold and the associated heat 

input, we estimated the concurrent emissions of the other criteria pollutants and CO2 (using EPA 

AP-42 1.3). Only the scenarios with no controls were considered for this simulation, as they 

likely produce the worst conditions. Two options in each scenario were considered: sulfur 

content at 1% and 0.5%. The following table shows the results of this calculation.

Table 10: Emissions of other criteria pollutants and CO2 under the conditions that would cause a violation of the PM2.5

NAAQS. Two options for each scenario were considered: 1% and 0.5% sulfur content for oil#6. Table AP 42 1.3-2 

(boilers >100 MMBtu/hours) was used for SO2, NOx, and CO. Table AP 42 1.3.12 was used for CO2. All annual emissions 

are expressed in short tons per year and assume a constant hourly emission for 24 hour a day, 365 days per year. NOx

emissions are estimated using both standard and low NO burners (i.e., standard/low NO).

Sulfur 

Content

PM2.5

emission 

factor 

(lb/103gal)

Energy 

Input

(gal/hour)

SO2

emissions 

(tons/year)

NOx

emissions 

(tons/year)

CO 

emissions 

(tons/year)

CO2

emissions 

(tons/year)

1.0% 6.96 982 675 202/173 22 104,949

0.5% 4.34 1573 540 324/276 34 168,064

The previous table shows the resulting annual emissions for other criteria pollutants when PM2.5 

emission levels would cause a violation of the PM2.5 NAAQS. By using a similar approach, it is 

also possible to estimate the PM2.5 emissions when the other criteria pollutants reach a level of 

emission equal to 250 tons/year (which triggers a PSD permit type, or 100,000 tons/year for 

CO2). This calculation assumes that emissions are constant and continuous for the entire year 

(i.e., for 8760 hour per year).
Figure 13: Same as Figure 12. In addition, the PM2.5 emissions and concentrations caused when other criteria pollutants 

are emitted at 250 tons/year (10,000 tons/year for CO2) are shown with red bars. Some criteria pollutants are not shown 

because the corresponding PM2.5 emissions and concentrations are too high to be represented in this graphic. The related 

PM2.5 concentrations (μg/m3) are, however, reported in the table below. The 1% and 0.5% sulfur fuel content scenarios 

are considered here as well. Some criteria pollutants and scenarios are not shown because the corresponding PM2.5 

emissions are too high to be represented in this graphic. They are, however, reported in the table below. The yellow 

dashed line is the 24-hour EPA NAAQS minus the estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 

9.81 μg/m3).

Codes for scenarios reported in the figure (same as Figure 11)

Sulfur Content = 0.5% Sulfur Content = 1%

1 467 gal/hour – no control 2 467 gal/hour – no control

3 934 gal/hour – no control 4 934 gal/hour – no control

6 467 gal/hour - MCC 5 934 gal/hour - MCC

Codes, pollutants, and descriptions for each all the scenarios considered. The PM2.5 emission (g/s) when the other 

criteria pollutant emission is 250 tons/year (or 100,000 tons/year for CO2) is reported between parentheses.

Sulfur Content = 1% Sulfur Content = 0.5%

a SO2 (9.3) f SO2 (11.6)

b NOx standard NO burner (31.2) g NOx standard NO burner (19.4)

c NOx low NO burner (36.6) h NOx low NO burner (22.8)

d CO (293.0) i CO (182.7)

e CO2 (high sulfur) (24.0) j CO2 (high sulfur) (15.0)

5. Scenario 3 – Internal Combustion Engine combusting natural gas

The model exercise for this type of source was built upon the permit case for the Western102 

power plant owned by Barrick Goldstrike Mines, Inc. The power plant has 14 natural gas 

Wartsilla 4-stroked lean-burn IC engines (77 MMBtu/hour) using natural gas and an emergency 

generator using natural gas. All of them were modeled.
a) Meteorological Data

The facility does not have an on-site met station. However, the Tracy Power Plant owned and 

operated by NVEnergy is very closely located to the Western102 power plant and has on-site 

data. Therefore, when available, the Tracy on-site data were used as the on-site data for 

Western102. 

In particular, met time-series for years 2011 and 2012 were re-processed using AerMet v12345 

and Tracy on-site data, Reno Airport surface data (1-min ASOS) and Reno upper-air data. Timeseries for 2009 and 2010 were not readily accessible and pre-existing surface and profile AerMet 

files (v.11059) were used. These files were processed using the same Tracy on-site and Reno 

surface and upper-air data. For the year 2008, no on-site data were used, but only surface (1-min 

ASOS) and upper-air data from Reno. Only regulatory options were used to process met data. 

The option to estimate scale temperature using the bulk Richardson number was used for the 

years 2011 and 2012.

b) Emissions and scenarios

AP-42 table 3.2-2 was used to estimate the primary (i.e., sum of filterable and condensable) 

PM2.5 emission rates. The energy input (MMBtu/hour) was increased from the original 77 

MMBtu/hour to 154 MMBtu/hour , 231MMBtu/hour, and 385 MMBtu/hour. Also, a scenario 

was constructed by assuming that all the PM10 factory-guaranteed emissions were PM2.5.

Table 11: Energy use, control and emissions for the different scenarios used for the natural gas IC.

Scenario # Energy use 

(MMBtu/hour)

Control Emissions (g/s) for 

each IC Engine

1 77 None 0.0969

2 154 None 0.1938

3 231 None 0.291

4 385 None 0.4844

5 77 Factory-guaranteed 

(all PM10 is PM2.5)

0.3263

c) Modeling and results

Aermod v12345 was used to model PM2.5 emissions. Receptors were placed using a nested grid, 

with high receptor density in proximity of high PM2.5 concentrations. Also, discrete receptors 

were placed along the plant fence line, but no receptors were placed within the plant area. Only 

regulatory options were selected for running Aermod.

Maps of annual 98th percentile values of the 24-hour average distribution (i.e., the 8th highest) 

were produced for each year considered (2008 to 2012). PM2.5 standards were calculated as the 

3-year average of the max annual 98th percentile.
Figure 14: Example of PM2.5 concentrations (8th highest max of 24-hour average over 1 year, μg m-3

). The scenario 

represented is #4 for year 2012. The red cross is the location of the source, and the white region is the plant area. 

Topography is shown in meters asl.

Table 12: Total emissions for the entire facility (g/s) and max 8th highest of 24-hour average PM2.5 for each scenario and 

year (μg m-3)

Scenario Emissions 2008 2009 2010 2011 2012

1 1.42 5.42 4.08 4.12 6.67 6.17

2 2.77 10.55 8.15 4.23 10.30 9.19

3 4.13 15.69 12.24 6.29 14.69 13.62

4 6.84 25.93 20.38 10.44 23.13 22.67

5 4.63 17.56 13.73 7.05 16.05 15.27

Table 13: Total emissions for the entire facility (g/s) and estimated 24-hour design values for each scenario and year (μg 

m

-3

)

Scenario Emissions NAAQS 2008-

2010

NAAQS 2009-

2011

NAAQS 2010-

2012

1 1.42 4.54 4.96 5.65

2 2.77 7.64 7.56 7.91

3 4.13 11.41 11.07 11.53

4 6.84 18.92 17.98 18.74

5 4.63 12.78 12.28 12.79
Figure 15: Time-series of annual max 8th

-highest 24-hour average for all the scenarios and years considered in this 

analysis. The red dashed line is the 24-hour EPA-NAAQS. The yellow dashed line is the 24-hour EPA NAAQS minus the 

estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3).

Figure 16: Average estimated design values as a function of PM2.5 emissions (for the entire facility) and linear fit. Empty 

circles identify the scenarios. The red dashed line is the 24-hour EPA-NAAQS. The yellow dashed line is the 24-hour EPA 

NAAQS minus the estimated background concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3). The equation for 

the linear fit is shown as well.

Codes for scenarios reported in the figure (same for Figure 15)

1 77 MMBtu/hour – no control 4 385 MMBtu/hour – no control

2 154 MMBtu/hour – no control 5 77 MMBtu/hour – Factory-guaranteed (all PM10 is PM2.5)

3 231 MMBtu/hour – no control

From the above equation, an emission rate of 9.6 g/s from each IC engine (76 lb/hour, or 332 

tons/year) would be required to produce PM2.5 concentrations above the 24-hour NAAQS, 
assuming no background. If a background of 9.81 μg/m3

is assumed, the required emission 

would be 0.68 g/s (5.39 lb/hour, or 23.61 tons/year). 

d) Other Criteria Pollutant Emissions

In this section, we estimated the emission of other criteria pollutants based on the scenario(s) that 

would cause a violation of the PM2.5 hourly NAAQS. From the previous section, a PM2.5

emission of 0.68 g/s (5.39 lb/hour) from each IC engine would cause a violation of the hourly 

NAAQS (averaged over three 3-year periods, see previous sections). Using this threshold, we 

estimated the concurrent emissions of the other criteria pollutants and CO2 (using EPA AP-42 

3.2-2) from each engine. Only the scenarios with no controls were considered for this simulation.

Table 14: Concurrent emissions of other criteria pollutants and CO2from each IC engine under the conditions that would 

cause a violation of the PM2.5 NAAQS. Table AP 42 3.2-2 was used for SO2, NOx, CO, and CO2. All annual emissions are 

expressed in short tons per year and assume a constant hourly emission for 24 hour a day, 365 days per year. NOx and 

CO emissions are estimated using both a 90-105% and a <90% load (i.e., 90-105%/<90%).

PM2.5

emission 

factor 

(lb/MMBtu)

Energy Input

(MMBtu/hour)

SO2

emissions 

(tons/year)

NOx

emissions 

(tons/year)

CO 

emissions 

(tons/year)

CO2

emissions 

(tons/year)

9.91E10-3

544 1.4 9721/2018 775/1327 262,099

The previous table shows the resulting annual emissions for other criteria pollutants when PM2.5 

emission levels would cause an exceedance of the PM2.5 NAAQS. By using a similar approach, 

it is also possible to estimate the PM2.5. emissions when the other criteria pollutants reach a level 

of emission equal to 250 tons/year (which triggers a PSD permit type, or 100,000 tons/year for 

CO2). The assumption behind this calculation is that emissions are constant and continuous for 

the entire year (i.e., for 8760 hour per year).
Figure 17: Same as Figure 16. In addition, the PM2.5 emissions and concentrations caused when other criteria pollutants 

are emitted at 250 tons/year (10,000 tons/year for CO2) are shown with red bars. Some criteria pollutants are not shown 

because the corresponding PM2.5 emissions and concentrations are too high to be represented in this graphic. The related 

PM2.5 concentrations (μg/m3) are, however, reported in the table below. Some criteria pollutants and scenarios are not 

shown because the corresponding PM2.5 emissions are too high to be represented in this graphic. They are, however, 

reported in the table below. The yellow dashed line is the 24-hour EPA NAAQS minus the estimated background 

concentration for 24-hour PM2.5 (i.e., 35 minus 9.81 μg/m3).

Codes for scenarios reported in the figure (same for Figure 15)

1 77 MMBtu/hour – no control 4 385 MMBtu/hour – no control

2 154 MMBtu/hour – no control 5 77 MMBtu/hour – Factory-guaranteed (all PM10 is PM2.5)

3 231 MMBtu/hour – no control

Codes and pollutants for each all the scenarios considered. The estimated PM2.5 emission (g/s) that causes the pollutant 

emission to be 250 tons/year (or 100,000 tons/year for CO2) is reported between parentheses.

a SO2 (1709.8) d CO 90-105% load (4.4)

b NOx 90-105% load (1.5) e CO <90% load (3.0)

c NOx <90% load (2.4) f CO2 (10.4)

D. STATIONARY SOURCE EMISSIONS OF PM2.5, NO2, and SO2 HAVE A DE 

MINIMIS CONTRIBUTION TO THE PM2.5 EMISSION INVENTORY FOR THE 

STATE.

CONTRIBUTION TO THE PM2.5EMISSION INVENTORY FOR THE STATE.

Third, the portion of PM2.5 that stationary sources contribute to Nevada’s emission inventory is 

de minimis. The NDEP first quantified the contribution of minor PM2.5 sources to the overall 

emissions inventory in Nevada using the National Emissions Inventory (NEI) database. The 

emissions inventory reflects both quality-assured monitoring data and emissions estimates that 

have been vetted through the public participation process. The NDEP evaluated the PM2.5

emissions, as calculated by the U.S. EPA, in the 2008 and 2011 NEI databases. The 2008 and 

2011 NEI datasets were used because they were complete datasets for all sources. As set forth in 

Table 15 and Table 16, the 2008 and 2011 NEI data demonstrate that in 2008, the minor source 
contribution to the total PM2.5 emission inventory was a scant 1.3%. In 2011, the minor source 

contribution was slightly more at 2.8%. The difference is largely due to wildfire emissions. 

There was significant wildfire activity in 2008 as compared to 2011: 55,493 tons emitted in 

2008 compared to 6,718 tons in 2011. Importantly, minor source emissions decreased by nearly 

one-third in that timeframe, from 912 tons in 2008 to 648 tons in 2011. Because the minor 

source contribution to the PM2.5 emission inventory is so small, the modeling threshold of 25 

tons per year is protective of the 2006 PM2.5 ambient air quality standard.

CONTRIBUTION TO THE NO2 AND SO2 EMISSION INVENTORY FOR THE STATE.

The results are similar for minor sources of NO2 and SO2. As set forth in Table 17, Table 18, 

Table 19, and Table 20 below, the minor source contribution to NO2 based on the 2008 NEI v.2 

data was a mere 5.4% of statewide emissions. The minor source contribution of SO2 based on 

the 2008 NEI data was even less, at 4.3%. Even if the minor source contributions of NO2 and 

SO2 cannot be considered de minimis, they are certainly slight. The contribution by minor 

sources to the SO2 and NO2 emission inventories in Nevada is so small that extinguishing those 

sources would make little, if any, difference to Nevada’s emission inventories for those two 

criteria pollutants. Because the minor source contribution is so small, the proposed modeling 

assignment threshold of 40 tons per year is protective of the 1-hour standards. Forty tons per 

year is the level at which the U.S. EPA deems a new source or modification to be significant 

under PSD permitting. 40 CFR 52.21(2)(b)(23)(i). It is also less than one-fifth of the 250-ton 

threshold that triggers PSD permitting and less than one-half of 100-ton threshold for certain 

types of sources. As such, it is protective of the NAAQS.

Table 15: Minor source contribution to PM2.5 in 2008

2008 Minor Source Inventory Contribution to PM2.5

Using GPR v.3 data instead GPR of v.2 and county totals by data category report.

Summary PM 2.5 - Primary (Tons)

Total Emissions (NDEP Only) 70,402

Event 55,643

Prescribed Fires 150

Wildfires 55,493

Nonpoint 11,270

Nonroad 291

Onroad 482

Point - Total 2,716

Point - Major 1,783

Point - Minor1912

Minor Source PM 2.5 Contribution 1.3%

1 Does not include airport or rail yard data categories.
It should be noted that the Hawthorne Army Depot (AP97110863) appears to have reported 

artificially inflated PM10 emissions for the 2008 NEI. For this analysis, the PM2.5 value from the 

2008 GPR v.1 was replaced with the facility wide PTE for PM10 (with the conservative 

assumption that 100% of the PM10 is PM2.5).

Table 16: Minor source contribution to PM2.5 in 2011

2011 Minor Source Inventory Contribution to PM2.5

Using 2011 NEI v.1 data and county totals by data category report.

Summary PM 2.5 - Primary (Tons)

Total Emissions (NDEP Only) 23,253

Event 7,283

Prescribed Fires 565

Wildfires 6,718

Nonpoint 13,358

Nonroad 257

Onroad 501

Point - Total 1,855

Point - Major 1,185

Point - Minor1648

Minor Source PM 2.5 Contribution 2.8%

1 Does not include airport or rail yard data categories.

Table 17 Minor source contribution to NO2in 2008

2008 Minor Source Inventory Contribution to NO2

Using GPR v.3 data instead GPR of v.2 and county totals by data category report

Summary NO2 (Tons)

Total Emissions (NDEP Only) 58700

Event 5573

Prescribed Fires 24

Wildfires 5549

Nonpoint 15204

Nonroad 2539

Onroad 13841

Point - Total 21543

Point - Major 19764

Point - Minor11196

 

Minor Source NO2 Contribution 2.0%

1 Does not include airport or rail yard data categories.
Note: The 2008 GPR v. 3 does not include corrections submitted by NDEP in March of 2014.

Table 18: Minor source contribution to NO2in 2011

2011 Minor Source Inventory Contribution to NO2

Using 2011 NEI v.1 data and county totals by data category report.

Summary NO2 (Tons)

Total Emissions (NDEP Only) 46766

Event 1792

Prescribed Fires 102

Wildfires 1690

Nonpoint 14307

Nonroad 2298

Onroad 17148

Point - Total 11220

Point - Major 9310

Point - Minor11238

 

Minor Source NO2 Contribution 2.6%

1 Does not include airport or rail yard data categories.

Note: The 2011 NEI v. 1 does not include corrections submitted by NDEP in March of 2014.

Table 19: Minor source contribution to SO2in 2008

2008 Minor Source Inventory Contribution to SO2

Using GPR v.3 data instead GPR of v.2 and county totals by data category report.

Summary SO2 (Tons)

Total Emissions (NDEP Only) 14620

Event 3969

Prescribed Fires 13

Wildfires 3956

Nonpoint 118

Nonroad 17

Onroad 98

Point - Total 10417

Point - Major 9848

Point - Minor1560

 

Minor Source SO2 Contribution 3.8%

1 Does not include airport or rail yard data categories.
Note: The 2008 GPR v. 3 does not include corrections submitted by NDEP in March of 2014.

Table 20: Minor source contribution to SO2in 2011

2011 Minor Source Inventory Contribution to SO2

Using 2011 NEI v.1 data and county totals by data category report.

Summary SO2 (Tons)

Total Emissions (NDEP Only) 6902

Event 809

Prescribed Fires 53

Wildfires 756

Nonpoint 145

Nonroad 6

Onroad 68

Point - Total 5873

Point - Major 5474

Point - Minor1389

 

Minor Source SO2 Contribution 5.6%

1 Does not include airport or rail yard data categories.

Note: The 2011 NEI v. 1 does not include corrections submitted by NDEP in March of 2014.

E. THE STATE MAY PERFORM THE MODELING ANALYSES FOR FACILITIES 

WITH EMISSIONS LESS THAN 25 TONS PER YEAR, OR 40 TONS PER YEAR 

FOR THE 1-HOUR STANDARDS

Fourth, the State must be able to determine, as required by NAC 445B.308(2), that the new or 

modified source will not prevent attainment and maintenance of the state or national standards 

set forth in NAC 445B.22097 or cause a violation of the SIP or any applicable requirement. 

Toward that end, the State may require an applicant to submit “any other information the 

Director determines is necessary to make an independent air quality impact assessment.” NAC 

445B.308(1). The State may perform the modeling for applications even if the emissions are 

below the threshold in NAC 445B.310 requiring the applicant to submit an air dispersion model 

with the environmental evaluation. Such practice enables the NDEP to ensure that the ambient 

air quality standards are protected. 

(e) Modeling information required to support the proposed revision, including input data, 

output data, models used, justification of model selections, ambient monitoring data 

used, meteorological data used, justification for use of offsite data (where used), modes 

of models used, assumptions, and other information relevant to the determination of 

adequacy of the modeling analysis.
See above. Also, the NDEP continues to use models as approved in Appendix W. 

(f) Evidence, where necessary, that emission limitations are based on continuous emission 

reduction technology.

This element is not applicable, as these rule revisions are for minor new source review. 

(g) Evidence that the plan contains emission limitations, work practice standards and 

recordkeeping/reporting requirements, where necessary, to ensure emission levels.

For the standards at issue in this TSD, the areas under the NDEP’s jurisdiction are 

attainment/unclassifiable or the USEPA has not yet promulgated a designation. The items set 

forth in this section are more appropriately addressed toward ameliorating an area designated as 

nonattainment. Nonetheless, these elements are addressed in the NDEP’s relevant infrastructure 

SIPs. 

(h) Compliance/ enforcement strategies, including how compliance will be determined in 

practice.

Nevada’s approved applicable SIP demonstrates that the NDEP has statutory authority to 

implement and enforce its air quality regulations through site and record inspections, compliance 

orders, stop orders, notices of alleged violation, and penalties. The proposed revisions included 

in this SIP submittal do not abrogate the NDEP’s compliance and enforcement authority. The 

NDEP’s compliance and enforcement strategies will be expanded in practice to encompass the 

new standards being adopted here. 

(i) Special economic and technological justifications required by any applicable EPA policies, 

or an explanation of why such justifications are not necessary.

No special economic and technical justifications are required for the NDEP’s implementation of 

USEPA’s 2006 PM2.5, 2010 1-hour SO2, and 2010 1-hour NO2 standards. The State is 

adopting those new standards into the State side of the table set forth in NAC 445B.22097 so that 

it may incorporate those standards in its permitting decisions and compliance and enforcement 

strategies. It is noteworthy that these revisions apply to the minor sources (i.e. sources not 

subject to PSD permitting) under the NDEP’s jurisdiction. Minor sources make a de minimis 

contribution to the PM2.5, and NO2 and SO2 inventories in the State, and, therefore, should 

enjoy some flexibility in terms of permitting. For the reasons set forth above, the revisions 

proposed are protective of the ambient air quality standards. 

III. Conclusions

The revisions to the Nevada Administrative Code, and incorporation of those revisions into the 

SIP, provide more protection for the state and national ambient air quality standards than 

currently exists. The proposed regulations insert the 2006 PM2.5 standard, and the 1-hour 
standards for NO2 and SO2, into the state side of the table in NAC 445B.22097, which requires 

the State to incorporate those standards into its permitting analyses and issuance. 

The modeling threshold of 25 tons per year of PM2.5 emissions for new sources, which exists in 

Nevada’s current regulations, is greater than the 10 tons per year significant emission rate set 

forth in 40 C.F.R. 51.166(b)(23). Nonetheless, the higher threshold is protective of the state and 

national ambient air quality standards for several reasons. First, that threshold is merely onefourth of the applicable major source threshold and incorporates the significant emission rates for 

PM2.5 precursors. Major sources would be subject to PSD permitting if they emit either 100 tons 

per year or 250 tons per year of PM2.5, depending on the type of the facility. A threshold that is 

one-fourth of that is protective. Importantly, the modeling threshold for modifications is 10 tons 

per year, which is the same as the PSD significant emission rate for PM2.5. Also, the State is 

proposing to revise its modeling threshold for the 1-hour standards so that it matches the PSD 

significant emission rates as well as the PM2.5 precursor significant emission rates for NO2 and 

SO2. Thus, these revisions address not only direct PM2.5 emissions but precursor emissions as 

well. Second, the Nevada-specific analyses included herein demonstrate that minor source 

combustion processes with the highest rates of PM2.5 emissions (worst case scenarios), as found 

in AP-42 and Nevada’s NEI submittal, would trigger PSD permitting requirements for other 

pollutants first, and subject the facility to PSD review before PM2.5 (alone) reached the PSD 

permitting threshold. Third, stationary source emissions of PM2.5 are a de minimis contribution

to the PM2.5 emission inventory for the State. Fourth, the State may only issue a minor source 

permit if it determines that the source will not prevent attainment and maintenance of the state or 

national standards set forth in NAC 445B.22097 or cause a violation of the SIP or any applicable 

requirement. The NDEP may require more information and conduct modeling analyses even for 

sources below the significant emission rate levels, or, in the case of new sources emitting PM2.5, 

below 25 tons per year in order to make such a determination. 

For the 1-hour standards, the revisions incorporate the PSD significant emission rates of 40 tons 

per year of NO2 and 40 tons per year of SO2. Because emissions less than 40 tons per year are 

deemed by EPA to be insignificant, setting a modeling assignment threshold at this level is 

protective of the NAAQS. 

In sum, the revisions strengthen the NDEP’s minor new source review program. For that reason, 

the NDEP requests that these revisions be incorporated into the applicable SIP. 
ATTACHMENT C

June 5, 2014 SIP Submittal Support

Nevada Division of Environmental Protection

Evidence of Public Participation

and Adoption
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C-1

C.1 State Environmental Commission Public Hearing Notice
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C.2 Affidavits of Publication
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C.3 State Environmental Commission Hearing Agenda, May 2, 2014
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