UNrTED STATES ENVIRONMENTAL PROTECTION AGENCY 

RESEARCH TRIANGLE PARK, NC 27711 

Mr. David Isaacs 

Vice President, Government Policy 

Semiconductor Industry Association 

1101 K Street, NW, Suite 450 

Washington, D.C. 20005 

Dear Mr. Isaacs: 

AUG 2 f) ? iJ 1: 

OFFICE OF 

AIR OUAli'TY PLANNING 

AND STANDARDS 

The U.S. Environmental Protection Agency has received your letler dated July 29, 2011, in which you 

have articulated concerns about permitting for the semiconductor industry after the implementation of 

the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas (GHG) Tailoring Rule 

(the "Tailoring Rule"). In particular, your letter requested infonnation on the folJowing areas related to 

the application of PSD to semiconductor manufacturing facilities: 

l. Treatment of a semiconductor fabrication building (fab) as an "emissions unit" for purposes of 

dctennining PSD applicability. 

2. Addressing the day-to-day changes for PSD applicability determinations. 

3. Treatment of control measures when determining projected actual emissions (PAE). 

4. Use ofGHG Plontwide Applicability Limits (PALs). 

We understand from your letter that the regulation ofGHGs will trigger PSD permitting requirements 

tor some semiconductor manufacturing facilities for the first time. Your letter explained that fabs may 

make changes on a daily basis and that the ability to make those changes quickly is critical. Our 

responses to your questions are designed to help the semiconductor industry understand and comply 

with their PSD requirements. 

Background - The Semiconductor Industry 

On January 2, 2011, GHG emissions from stationary sources bccwne covered by the PSD permitting 

program for the first Lime. Additionally, GHO emissions first became subject to the title V operating 

permits program as of July I, 20 II. Semiconductor sources may now trigger permitting requirements 

under these two programs because of their GHG emissions. In the past, semiconductor sources have 

been able to avoid major source permitting requirements (i.e., PSD and title V) by implementing a series 

of control measures and accepting minor source emissions caps that kept them below major source 

thresholds. This approach has provided the semiconductor industry with needed operational flexibility. 

Over the past 15 years members of the semiconductor industry have achieved reductions in fluorinated 

GHG emissions, including pertluorocarbons (PFCs), bydronuorocarbons (HFCs), and sulfur 

hexafluoride (SF,), through process optimization, use of alternative chemistry, and emissions abatement 

(i.e., installation of air pollution control equipment). In large part. th~ reductions are attributable to a 

lntemet Address (URL) • http://www.epa.gov 

Recycled/Rocllcloble •Prtnled wllh Vegetablll Oil Based Inial on Aecydad Paper (Minlmum:ZS% Postconsumar) 
voluntary partnership 1 between the· Semiconductor Industry Association (SIA) and the EPA that 

pursuant to a memoranda of understanding. As part of the partnership, member companies committed to 

reduce emissions of fluorinated GHGs and to track and annually report those emissions. In most cases, 

voluntarily installed GltG emission controls were not incorporated into facility air permits because there 

were then no underlying applicable Clean Air Act requirements. SIA reports that GHG emission control 

devices were applied to etch and chamber clean processes primarily at newer fabrication plants. The 

most common technologies used are high temperature oxidizers followed by wet scrubbers to remove 

by-products. 

Spccitic SIA Questions 

I. Treatment of a Semiconductor Fab as an "Emissions Unit" for Purposes of Determining PSD 

Applicability 

In your letter you indicate that in minor source permitting of semiconductor manufacturing facilities, by 

local and state air pcnnitting agencies, each fab at a facility is normally treated as an individual 

emissions unit.2 You are now seeking confirmation that it is appropriate to treat each semiconductor fab 

at a manufacturing facility as a single emissions unit for the purposes of determining PSD applicability. 

This approach seems appropriate because of the interconnected nature of the "tools" in the fab. 

Similarly, the systems that deliver materials to those tools and manage their discharges have also 

generally been treated as part of the emissions unit. 

Often, an "emissions unit" is assumed to be a single piece of process equipment or activity. However, 

many pieces of related process equipment grouped together may also fit within the definition of 

"emissions unit" under the federal PSD regulations. ln order to determine how the "emissions unit" 

should be defined in this case we first look to the definition of"emissions unit" found at 40 CFR 

§52.21 (b)(7). 

Emissions unit means any part of a stationary source that emits or would have the potential to 

emit any regulated NSR pollutant and includes an electric utility steam generating unit as defined 

in paragraph (b)(31) of this section. For purposes of this section, there are two types of emissions 

units as described in paragraphs (b)(7)(i) and (ii) ofthis section: 

(i) A new emissions unit is any emissions unit that is (or will be) newly constructed and that 

has existed for Jess than 2 years from the date such emissions unit first operated. 

{ii) An existing emissions unit is any emissions unit that does not meet the requirements in 

paragraph (b)(7)(i) of this section. A replacement unit, as defined in paragraph (b)(33) of 

this section, is an existing emissions unit. 

Additionally, although not determinative, New Source Performance Standards (NSPS) and National 

Emission Standards for Hazardous Air Pollutants (NESJ lAP) can be sources of information that may be 

1 PFC Reduction/Climate Partnership for the Semiconductor Industry; see http://www.epa.gov/semiconductor-pfc. 

2 Some examples where this approach has been used arc: IBM Ea:st Fishkill Facility in Hopewell Junction, NY title V pennit; 

V itesse Corp in Colorado Springs, CO state operating permit; Renesas Electronics in Roseville, CA operating penn it; and 

Micron Technology in Boise ID construction and operating pcnnit. 

2 
helpful in defining an emission unit. In this case NESHAP Subpart BBBBB- National Emission 

Standards for Hazardous Air Pollutants for Semiconductor Manufacturing provides relevant information 

on what a semiconductor manufacturing process unit might be. NESHAP Subpart BBBBB states that: 

A semiconductor manufacturing process unit includes the equipment assembled and connected 

by ductwork or hard-piping including furnaces and associated unit operations; associated wet and 

dry work benches; associated recovery devices; feed, intermediate, and product storage tanks; 

product transfer racks and connected ducts and piping; pumps, compressors, agitators, pressurerelief devices, sampling connecting systems, open-ended valves or lines, valves, connectors, and 

instrumentation systems; and control devices. 

Our past guidance on the treatment of"emissions units" in other industries is consistent with this 

approach. In a letter issued by the EPA Region III on November 30, 2000, the EPA provided guidance 

regarding a proposed PSD modification at a DuPont faciJity. 3 The guidance indicated that DuPont's 

proposed project could be considered a modification to a single emissions unit. The emissions unit was 

defined as the entire solvent-spun synthetic fiber process that included the spinning, wash/draw, and 

solvent recovery operations. Similarly, in guidance issued by the EPA Region VIII dated February 6) 

1990, regarding a determination of Lowest Achievable Emission Rate (LAER) for Coors Container,4 the 

EPA determined that an emissions unit consisted of the entire coating operation (topcoat, basecoat, etc). 

In both determinations the NSPS definition of emissions unit was relied upon; the rule provided a 

rationale for grouping the processes together to create a single emission limitation covering all of the 

equipment. This was the most technically-achievable and cost-effective way to evaluate control for these 

operations. 

Given the flexibility provided for in the PSD definition of emission unit, considering the treatment of 

semiconductor facilities under the NESHAP, and considering our previous guidance on this matter we 

believe that the treatment of a fab as an emissions unit for PSD applicability purposes is appropriate. We 

believe it would usually be consistent with the federal definition of"emissions unit" to include in the fab 

"emissions unit" the integrated contiguous clean room space, including all the tools, and systems that 

support the activities in the clean room. The fab emissions unit could be located in a single building or 

adjoining buildings as long as it is physically connected, integrated, and operated as a continuous clean 

room space. However, if a building or facility were to contain more than one physically separated and 

independent clean room, we believe it would generally be appropriate to treat those fabs as separate 

emissions units. Air pollutant control equipment that serves more than one fab may need to be treated as 

a separate emissions unit under the relevant regulatory definition of "emissions unit," for example a 

regenerative thermal oxidizer (RTO) that serves multiple fabs to control volatile organic compounds 

(VOC) emissions will emit GHGs and should be treated as a separate emissions unit. Not all contro] 

equipment will have additional emissions beyond that which they control. this needs to be considered 

when determining how fabs and their control equipment are treated as emissions units. We believe that it 

would generally be consistent with the federal definitions of"emissions unit" to treat equipment serving 

3 U.S. EPA, Region UI, to John Daniel, Director, Air Program Coordination, Commonwealth of Virginia, Department of 

Environmental Quality, 30 November 2000. 4 U.S. EPA, Region VHI, to Brad Beckham, Director, Air Pollution Control Division, Colorado Department of Health, 6 

February 1990. 

3 
multiple fabs (such as boilers, emergency generators, and similar auxiliary equipment), that are operated 

separately and are often located in a separate building, as separate emissions units. 

When conducting a PSD applicability determination, all emissions increases from emission units 

associated with, or affected by a project must be included in the calculations. Applied to the fab, this 

means that the PSD applicability determination would look at the overall increase across the entire fab 

emissions unit from a project, not the specific changes at each particular tool or other system within the 

fab. Implementing state and local agencies may adopt different and potentially more stringent or less 

flexible requirements under their STP-approved minor or major New Source Review (NSR) programs. 

We encourage you to work with your reviewing agencies to confirm the specific requirements applicable 

to individual semiconductor manufacturing facilities. 

II. Addressing the "day~to~day changes" for PSD applicability determination 

In your letter you indicated that a number of semiconductor fabs undergo dozens of small changes each 

year as the production methods and operations are maintained, updated, adjusted and refined. You 

proposed three approaches or methods for practical and efficient PSD applicability detennination for 

such changes described in your letter as "day-to-day changes" and requested whether each of the 

proposed methods would provide an adequate record ofPSD non-applicability. 

rirst, we would like to clarify that our response to this request on "day-to-day changes" assumes that the 

subject facilities are potentially major PSD sources only due to GHG emissions (i.e., potential emissions 

of all non-GHG regulated NSR pollutants are assun1ed to be below major source thresholds both before 

and after the project at issue). Accordingly, we are limiting our response to PSD applicability procedures 

and requirements applicable to GHGs, more specifically to the established "subject to regulation" 

thresholds for GHGs, based on carbon dioxide (C02) equivalent (C02e) emissions.5 This is consistent 

with the context of the SIA's proposed applicability determination methods and our understanding that 

many semiconductor manufacturing facilities are potentially major sources under PSD only due to 

GHGs. 

We summarized the three S[A proposed PSD applicability determination methods below with our 

corresponding responses. 

SJA 's Proposed Method 1 -This method would apply when the Projected Actual Emissions of the 

fab are well below 75,000 tpy C02e. In such a case, if it is determined that the change does not 

increase the Projected Actual Emissions, this determination will serve as a record that the change 

cannol trigger PSD. Under this method, the fab owner would create and record an assessment of 

the Projected Actual Emissions and the review of each change would be a simple determination 

that the project will not increase the Projected Actual Emissions. 

Under 40 CFR 52.2l(b)(49)(v)(b) GHGs arc subject to regulation for an existing stationary source that 

emits or has the potential to emit 100,000 tpy C02e, when the source undertakes a physical change or 

~ 40 CFR 52.2 I (bX49). As a result of the Tailoring Rule, GHGs are treated differently ftom non-01-10 regulated NSR 

pollutants under the PSO program. EPA has published detailed guidance on PSD applicability determinations and other 

permitting requirements for GHGs. See hnp://www.cpa.gov/nsr/ghgpcrmilting.html. 

4 
change in the method of operation that will result in an emissions increase of75,000 tpy C02c or more. 

The temt "emissions increase" in this context means both a significant emissions increase as calculated 

under 52.21(a)(2)(iv) and a significant net emissions increase as defined in 52.21(b)(3) and (b)(23).6 

Under 52.21(a)(2)(iv) whether an emissions increase occurs for a project involving only existing 

emissions units (e.g., an existing fab) is detennined using the actual-to-projected-actual emissions test. 

In summary, that test involves calculating baseline actual emissions and projected actual emissions for 

each emissions unit affected by a project and calculating the project emissions increase as the sum of the 

differences between projected actual emissions and baseline actual emissions for each unit.7 The 

definition of projected actual emissions provides that the owner or operator may exclude, in calculating 

the increase from a particular emissions unit, that portion of the unit's emissions following the project 

that the unit could have accommodated in the selected baseline actual emissions period and that are also 

unrelated to the project. 8 

SIA's proposed Method I relies on a simplified version of the actual-to-projected-actual emissions test 

as an initial screen for purposes of determining whether there is a significant emissions increase in 

evaluating whether GHGs are subject to regulation for a project that, under certain circumstances, may 

provide a streamlined approach to these calculations. Because the proposed approach ignores baseline 

actual emissions, thereby assuming baseline actual emissions equal zero, and because it does not exclude 

any of the fab emissions following the project in determining the increase, it represents a conservative 

estimate of the increase in emissions occurring from the fab as a result of the project. Moreover, if the 

projected actual emissions alone from a fab do not exceed 75,000 tpy C02e, the calculation of 

significant emissions increase under the actual-to-projected-actual test for that fab would also not exceed 

75,000 tpy C02e, such that GHGs would not be subject to regulation for that project, assuming the fab 

was the only affected emissions unit. 

In general, we fmd Method 1 acceptable as an initial screen for purposes of determining that there is not 

a significant emissions increase in GHGs from a project in order to determine whether GHGs are subject 

to regulation for that project. If GHGs are not subject to regulation for a project, PSD would not be 

triggered due to GHG emissions increases resulting from the project at a fab. However, we would like to 

clarify certain additional requirements. First, our aggregation policy, discussed in further detail in our 

response to SIA proposed Method 3, requires that nominally separate changes that are sufficiently 

related based on established criteria be aggregated into a single common project for the purpose of 

determining PSD applicability.9 Accordingly, owners or operators should evaluate "day to day changes" 

to determine the proper aggregation of such changes prior to evaluating PSD applicability. Second, our 

interpretation ofthe Clean Air Act and long standing policy requires that calculations ofprojeet 

emissions increases include not only those increases occurring from new or modified emissions units but 

also affected non-modified units. 10 For example, a modification to an existing semiconductor facility fab 

6 40 CFR 52.2l(b)(49Xiii). 7 40 CFR 52.21 (a)(2Xiv)(c). 8 40 CFR 52.21(b)(41Xii)(c). 9 For a collection of prior EPA memoranda relevant in detennining whether projects should be aggregated, please see 75 FR 

19570-71 (April 15, 2010). While the policy discussion in this reconsideration notice does not represent a final agency 

position without further action by the agency, the numerous memoranda cited in this notice stand for themselves as examples 

of our historic approach to aggregation. 10 The regulations define a "major modification'' as one in which a physical change or a change in the method of operation 

of a major stationary source results in a significant emissions increase of a regulated NSR pollutant and a significant net 

5 
may result in increased steam demand from facility boiler(s). In that case, the boiler(s) could realize 

increased utilization on an annual basis (and a corresponding increase in GHG emissions) as a result of 

the changes in the fab and emissions from the boiler(s) must be evaluated using the actual-to-projectedactual emissions test to resolve the total emissions increase from the source that is related to the project. 

17inally, your letter noted that the fab owner would create and record an as..~essment of projected actual 

emissions and requested whal record is adequate to demonstrate PSD non-applicability. We believe that 

a record that is consistent with the recordkeeping, monitoring, and reporting provisions of 40 CFR 

52.21 (r)(6) would be adequate to document a detennination of PSD non-applicability in this situation. 

SIA 's Proposed Method 2 - A simple variation on Method 1 can be used to deal with day-to-day 

changes at fahs that have Projected Actual Emissions over 75,000 tpy C02e. In this instance, the 

fab owner will also determine the Baseline Actual Emissions for a 24 month period in the prior ten 

years. If the difference between the Projected Actual Emissions and the Baseline Actual Emissions 

is well below 75,000 tpy C02e, one applies the same approach as Method 1. 

Proposed Method 2 is a variation of Method 1 that incorporates baseline actual emissions into the 

calculation of whether a physical change or change in the method of operation ut a stationary source that 

emits or has the potential to emit I 00,000 tpy C02c will result in an significant emissions increase of 

75,000 tpy C02e or more for purposes of determining whether GHGs are subject to regulation for the 

project. As long as the calculation of baseline actual emissions and projected actual emissions comports 

with the regulatory definitions of those terms, we believe this approach is acceptable for determining 

that no significant increase of emissions for GHGs occurred for the project and that GHGs are 

accordingly not subject to regulation for a project. 11 Our response to proposed Method I related to 

project aggregation, the consideration of all affected emissions units in the analysis, and appropriate 

recordkccping also applies to proposed Method 2. 

SIA's Proposed Method 3- Under this method, the fab owner starts each calendar year with an 

assessment of the range of changes that may occur in the upcoming year and then determines the 

nature of their C01e impacts. At the start of the year, the fab owner completes the actual-to· 

projected-actual emissions calculation to determine the maximum emissions increase that could 

result from the full range of changes. That assessment can then be relied upon to address 

applicability for all the day-to-day changes for that year so long as the changes are consistent with 

and within the scope of changes laid out at the start of the year. A reassessment is triggered 

annually or with any mid-year departure from the plan of action that was assessed at the start of 

the year. 

Proposed Method 3 involves a project aggregation approach designed to reduce the burden of PSD 

applicability analyses for frequent, relatively minor physical and operational changes wilhin a fab. EPA 

has addressed project aggregation in several letters, memoranda, and rulemaking preambles that 

emissions increase of that pollutant at the source. See 40 CFR 52.21 (b)(2). Based on this, the total increase in emissions 

includes: ( 1) Increases occurring at all new or modified units, and (2) 11ny other increases at existing emissions units not 

being modified that experience emissions increases as a result or the change. Increases occurring from units as a result of 

"debottlenecking" or "increased utilization'' caused by a project must be included in determining NSR applicability for the 

project. 

11 Baseline actual emissions and projected actual emissions are defined in 40 CFR 52.21 (b)(48) and (b)(41 ), respectively. 

6 
establish our interpretation ofthe Clean Air Act provisions related to "modification" and policy on 

project aggregation.9 In brief, we look for indicia of relatedness among the individual actions at a source 

in order to determine whether the activities, in the aggregate, are one physical or operational change as 

those terms are used in the statute and regulations. We have made clear in past policy documents that the 

EPA may enforce the major source permitting requirements in cases when a source "circumvents" major 

NSR by dividing one change and its emissions increase into nominally-separate physical or operational 

changes. Our policy on aggregation outlines an approach relying upon case-specific factors (e.g., timing, 

funding, and the company's own records) and the relationship between nominally-separate changes. 

Our policy does not preclude the aggregation of multiple physical or operational changes when such 

changes taken together can be reasonably viewed as sufficiently related to be a single project even if 

individually or smaller groupings also could be viewed as physical or operational changes. So long as 

the grouping of changes aggregated together is consistent with our aggregation policies, does not result 

in circumvention of major modification permitting requirements, and does not create project netting 

opportunities that are inconsistent with the regulatory provisions and our policy, the group of changes 

may be assessed as one. The aggregation of multiple small changes that serve a common general 

purpose over the course of a reasonable planning or funding time period (such as one year) as described 

in your letter could qualify as a single project if the company's own records and representations support 

that conclusion, again consistent with our policy-based project aggregation criteria. In such 

circumstances we find it acceptable and appropriate to consider the aggregate changes a single project 

within the fab. 

Beyond the above relatively straight-forward context however, application of proposed Method 3 must 

take into consideration several additional factors to ensure compliance with applicable regulatory 

provisions and policy. First, where individual changes are aggregated for the purpose of applicability 

analysis and streamlining, and individual changes or smaller groupings of changes within the proposed 

aggregate 'project' appropriately could also be viewed as physical or operational changes, the owner or 

operator should consider only those changes that result in emissions increases in the projection in the 

first step of an applicability analysis and not any changes that result in emissions decreases when 

applying this method. 12 This is to ensure that project aggregation is not used as a mechanism to provide 

for "project netting", which as indicated above is not allowed by the regulations. 

Second, we would like to make clear that there is no presumption that a one year aggregation period is 

appropriate or justified for the purposes of determining major modification applicability. Owners or 

operators must carefully review all proposed physical or operational changes occurring at a source to 

ensure that they are appropriately aggregated in accordance with our policy-based criteria. Separating 

components of a project using proposed Method 3, for example- by accounting for some in one annual 

aggregation period and others in the next, could be considered circumvention of PSD permitting 

requirements if the increase calculated using proper project aggregation is significant. 

12 We have made clear that only increases in emissions are accounted for under 'Step I' of the major modification 

applicability procedures (the determination ofthe project emissions increase). In order to credit decreases in the applicability 

analysis, the owner or operator must perform a contemporaneous netting analysis (i.e., 'Step 2' of the applicability 

procedures). See, e.g., letter from Barbara A. Finazzo, U.S. EPA Region 2 to Kathleen Antoine, HOVENSA, L.L.C., "Re: 

HOVENSA Gas Turbine Nitrogen Oxides (GT NOx) Prevention of Significant Deterioration (PSD) Pennit ApplicationEmission Calculation Clarification;" March 30, 2010. 

7 
Third, as described in our responses to proposed Methods 1 and 2 the applicability analysis is not limited 

to modified emissions units (e.g., an existing fab in this scenario) but rather must include all units at the 

source that could be affected by the project. This includes non-modified emissions units that are 

debottlenecked or could realize increased utilization as a result of the changes in the fab. Lastly, with 

respect to what would constitute an adequate record to document a PSD non-applicability determination, 

we believe that a record that is consistent with provisions of 40 CFR 52.21(r)(6) would be sufficient to 

document a determination ofPSD non-applicability in this situation. 

Ill. Treatment of unenforceable controls when determining projected actual emissions 

To determine PSD applicability (both for determining if GHGs are subject to regulation and when 

evaluating whether there is a major modification at an existing major stationary source), an owner or 

operator. may use one of two tests to determine the emissions increase from an existing emissions unit: 

the "actual-to-projected-actual" emissions test or the "actual-to-potential" emissions test. 13 If the 

emissions unit at an existing source is new the owner or operator must use the "actual-to-potential" 

emissions test to calculate emissions increases at that unit. "Baseline actual emissions" are used to 

establish pre-project emissions for applicability purposes under both tests. 

For an existing emissions unit that is not an electric utility steam generating unit, "baseline actual 

emissions" are generally the average rate in tons-per-year at which the unit actuaHy emitted a regulated 

pollutant during any consecutive 24 month period (selected by the applicant) in the prior 10 years.

14 

"Projected actual emissions" are the maximum annual rate, in tons-per-year that an existing unit is 

projected to emit a regulated pollutant in any one of the 5 or 10 years following the date the unit resumes 

regular operation after the project depending on whether certain regulatory criteria are met. 15 In 

calculating an increase using the "actual-to-projected-actual" emissions test the owner or operator may 

exclude the portion of the unit's emissions following the project that an existing unit could have 

accommodated during the baseline actual emissions period and that are also unrelated to the particular 

project including any increased utilization due to product demand growth. 16 "Potential to emit" is the 

maximwn capacity of a unit to emit a pollutant under its physical and operational design. Any physical 

or operational limitation on the capacity to emit, including air pollution control equipment and 

restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, 

shall be treated as part of the unit's design if the limitation or the effect it would have on emissions is 

enforceable as a practical matter. 11 

For the purpose oflimiting potential to emit, air pollution control equipment or the effect it has on 

emissions must be enforceable as a practical matter. In general, this means that applicable permit 

13 40 CFR 52.2I(b)(2)(iv) and (b)(41 ). 14 40 CFR 52.2I(b)(48)(ii). 

IS 40 CFR 52.2I(b)(41). 16 40 CFR 52.2I(b)(4I)(ii)(c). 17 52.2l(b)(4). While the definition of"potential to emit" in the PSD regulations contains the tenn "federally enforceable," 

this aspect ofthat decision was vacated in Chemical Manufacturers Association v. EPA, 70 F.3d 637 (D.C. Cir. 1995). See 

also National Mining Association v. EPA, 59 F.3d 1351, 1362-63 (D.C. Cir. 1995). We thus interpret this tenn to mean 

"federally enforceable or legally and practicably enforceable by a state or local air pollution control agency." See, e.g., 

Interim Policy of Federal Enforceability Requirements for Limitations on Potential to Emit at 3-4 (Jan. 22, 1996). For 

simplification, we here use the term "enforceable as a practical matter" to encompass "federally enforceable or legally and 

practicably enforceable by a state or local air pollution control agency." 

8 
conditions establish a legal obligation to install and operate the equipment and that compliance with the 

relevant permit limits can be verified. However, for calculating projected actual emissions, it is not 

required that air pollution control equipment or the effect such equipment has on emissions be 

enforceable to be considered, nor is it required that the projected emissions themselves be made 

enforceable. As such, when calculating projected actual emissions, in addition to considering legally 

enforceable restrictions, owners or operators may consider the effect on emissions of design or 

operational parameters, including air pollution control equipment, that are not enforceable. 

Projected actual emissions should be calculated consistent with the criteria contained in the definition of 

that term. 18 Generally, projected actual emissions are based on the design and operational parameters 

that determine the emission rate per unit of production or time and projected annual production or 

utilization rate. For the purposes of projected actual emissions, the design and operational parameters 

can include air pollution control equipment installed and operated on a unit regardless of whether such 

equipment is legally enforceable. This approach provides consistency between the way voluntary 

controls are considered in calculating projected actual emissions and baseline actual emissions, thereby 

more accurately resolving increases in emissions resulting from physical or operational changes. 

Notwithstanding the above conclusion, the burden is on the source owner or operator to ensure that 

projected actual emissions, including the effect of air pollution control equipment, are based on sound 

scientific information, are reasonable, and that air pollution controls are designed and operated 

consistent with representations made in the applicability calculations or else an emissions increase that 

could trigger PSD may occur. Capture and control efficiencies, outlet concentrations, or other metrics 

used to estimate controlled emissions should be supported by source test data, vendor design 

specifications, guarantees, or engineering calculations as appropriate. In circumstances where air 

pollution control equipment has been considered in detcnnining projected actual emissions for one or 

more pollutants from an existing emissions unit, it is incumbent on the owner or operator to maintain 

and operate the equipment in accordance with good air pollution control practices, regardless of whether 

or not such equipment is legally enforceable. At a minimum this means that any manufacturer 

recommended operating and maintenance procedures are followed and that a record of any parameter 

monitoring performed, maintenance activities, and periods of control equipment downtime be 

maintained. It is important to stress that the EPA is authorized to take enforcement action for a violation 

ofPSD if the projection is not consistent with the regulatory requirements. 

IV. Use ofGHG Plantwide Appiieability Limits 

We acknowledge your request for information as it relates to the use of PALs for the semiconductor 

industry. We are in the process of analyzing your request and the applicable regulations and will be 

responding to this aspect of your request in a subsequent letter to be issued in the coming weeks. 

18 The definition of projected actual emissions specifies that owners or operators shall consider all relevant information, 

including but not limited to, historical operating data and the company's representations and highest projections of business 

activity. The definition also specifies that fugitive emissions, to the extent quantifiable, and emissions associated with 

startups, shutdowns, and malfunctions shall be included. See 40 CFR 52.21 (b)( 41)(ii). 

9 
Conclusion 

The responses to your questions provided in this Jetter and associated interpretations pertain to the 

Federal PSD regulations. Implementing state and local agencies may adopt different and potentially 

more stringent or less flexible requirements under their SIP-approved minor or major New Source 

Review (NSR) programs. We encourage you to work with your reviewing agencies to confirm the 

specific requirements applicable to individual semiconductor manufacturing facilities. 

I appreciate this opportunity to respond to your questions, and I hope this response answers your 

questions. If you have additional questions, please contact Juan Santiago at (919) 541-1084. 

Again, thank you for your letter. T appreciate the opportunity to be of service and trust the information 

provided is helpful. 

cc: Janet McCabe, OAR 

Anna Marie Wood, OAQPS 

Phil Brooks, OECA 

Elliott Zenick, OGC 

Juan Santiago, OAQPS 

Raj Rao, OAQPS 

Sincerely, 

?~!l.W~ /A Stephen D. Page f""' Director 

Office of Air Quality Planning 

and Standards 

10