United States Office of Air and Radiation November 2010 

Environmental Protection 

Agency 

_____________________________________________________________________________________________ 

PSD and Title V 

Permitting Guidance 

For Greenhouse Gases 

Prepared by the 

Office of Air Quality Planning and Standards 

U.S. Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 
November 2010 

Disclaimer 

This document explains the requirements of EPA regulations, describes EPA policies, and 

recommends procedures for permitting authorities to use to ensure that permitting decisions are 

consistent with applicable regulations. This document is not a rule or regulation, and the 

guidance it contains may not apply to a particular situation based upon the individual facts and 

circumstances. This guidance does not change or substitute for any law, regulation, or any other 

legally binding requirement and is not legally enforceable. The use of non-mandatory language 

such as “guidance,” “recommend,” “may,” “should,” and “can,” is intended to describe EPA 

policies and recommendations. Mandatory terminology such as “must” and “required” are 

intended to describe controlling requirements under the terms of the Clean Air Act and EPA 

regulations, but this document does not establish legally binding requirements in and of itself.
i 

Table of Contents 

I. INTRODUCTION ................................................................................................................. 1 

II. PSD APPLICABILITY ......................................................................................................... 5 

A. CALCULATING GHG MASS-BASED AND CO2E-BASED EMISSIONS ................................................................ 11

B. PSD APPLICABILITY FOR GHGS - NEW SOURCES .......................................................................................... 12

C. PSD APPLICABILITY FOR GHGS - MODIFIED SOURCES .................................................................................. 13

1. General Requirements .............................................................................................................................. 13

2. Contemporaneous Netting ........................................................................................................................ 16 

III. BACT ANALYSIS .............................................................................................................. 18 

A. DETERMINING THE SCOPE OF THE BACT ANALYSES ..................................................................................... 24

B. BACT STEP 1 – IDENTIFY ALL AVAILABLE CONTROL OPTIONS .................................................................... 25

C. BACT STEP 2 – ELIMINATE TECHNICALLY INFEASIBLE OPTIONS .................................................................. 34

D. BACT STEP 3 – RANKING OF CONTROLS ....................................................................................................... 38

E. BACT STEP 4 – ECONOMIC, ENERGY, AND ENVIRONMENTAL IMPACTS ........................................................ 39

F. BACT STEP 5 – SELECTING BACT ................................................................................................................ 45 

IV. OTHER PSD REQUIREMENTS ........................................................................................ 48 

V. TITLE V CONSIDERATIONS ........................................................................................... 51 

A. GENERAL CONCEPTS AND TITLE V REQUIREMENTS ...................................................................................... 51

B. TITLE V APPLICABILITY REQUIREMENTS AND GHGS .................................................................................... 52

C. PERMITTING REQUIREMENTS ......................................................................................................................... 53

D. TITLE V FEES ................................................................................................................................................. 56

E. FLEXIBLE PERMITS ......................................................................................................................................... 56 

VI. APPENDICES ..................................................................................................................... 58 
ii 

List of Appendices 

Appendix A. GHG Applicability Flow Chart – New Sources 

(January 2, 2011, through June 30, 2011) 

Appendix B. GHG Applicability Flow Chart – New Sources 

(On or after July 1, 2011) 

Appendix C. GHG Applicability Flow Chart – Existing Sources 

(January 2, 2011, through June 30, 2011) 

Appendix D. GHG Applicability Flow Chart – Existing Sources 

(On or after July 1, 2011) 

Appendix E. Example of PSD Applicability for a Modified Source 

Appendix F. BACT Example – Natural Gas Boiler 

Appendix G. BACT Example – Municipal Solid Waste Landfill 

Appendix H. BACT Example – Petroleum Refinery Hydrogen Plant 

Appendix I. Resources for GHG Emission Estimation 

Appendix J. Resources for GHG Control Measures 

Appendix K. Calculating Cost Effectiveness for BACT 

(Excerpt from Draft 1990 New Source Review Workshop Manual) 
1 

I. Introduction 

 EPA is issuing this guidance document to assist permit writers and permit applicants in 

addressing the prevention of significant deterioration (PSD) and title V permitting requirements1

for greenhouse gases (GHGs) that begin to apply on January 2, 2011. This document: (1) 

describes, in general terms and through examples, the requirements of the PSD and title V permit 

regulations; (2) reiterates and emphasizes relevant past EPA guidance on the PSD and title V 

review processes for other regulated air pollutants;2

 and (3) provides additional 

recommendations and suggested methods for meeting the permitting requirements for GHGs, 

which are illustrated in many cases by examples. We believe this guidance is necessary to 

respond to inquiries from permitting authorities and other stakeholders regarding how these 

permitting programs will apply to GHG emissions. 

 

This document is organized into sections with supporting appendices. Section I describes 

the purpose of this document, describes the actions that led to the permitting of sources of GHGs, 

and provides a general background for the permitting of major stationary sources. Section II 

describes PSD applicability criteria and how to determine if a proposed new or modified 

stationary source is required to obtain a PSD permit for GHGs. Section III discusses the process 

that EPA recommends following to determine best available control technology (BACT) for 

GHGs for new sources and modified emissions units. Section IV discusses how other PSD 

permitting requirements are generally inapplicable or have limited relevance to GHGs. Section V 

describes considerations for permitting of GHGs under title V of the CAA. The appendices 

located at the end of this document include PSD applicability flowcharts for new and modified 

sources of GHGs, an example PSD applicability analysis for a modified source, example BACT 

analyses, compilations of resources for estimating emissions of GHGs and for finding control 

measures for sources of GHGs, and cost effectiveness calculation methodology. 

Relevant Background

 New major stationary sources and major modifications at existing major stationary 

sources are required by the Clean Air Act (CAA or Act) to, among other things, obtain an air 

pollution permit before commencing construction. This permitting process for major stationary 

sources is called new source review (NSR) and is required whether the major source or major 

modification is planned for an area where the national ambient air quality standards (NAAQS) 

 

1

 Such requirements are reflected in provisions of the Clean Air Act, EPA rules, and approved State Implementation 

Plans. See 75 FR 17004 (Apr. 2, 2010). 

2

 Collections of past EPA guidance on the PSD and title V review processes include: 

• EPA websites listing some existing guidance documents for NSR (including PSD) 

(http://www.epa.gov/nsr/guidance.html) and title V (http://www.epa.gov/ttn/oarpg/t5pgm.html); 

• Environmental Appeals Board (EAB) decisions on PSD permitting 

(http://yosemite.epa.gov/oa/EAB_Web_Docket.nsf/PSD+Permit+Appeals+(CAA)?OpenView ) and title V 

permitting (http://yosemite.epa.gov/oa/EAB_Web_Docket.nsf/Title+V+Permit+Appeals?OpenView); and 

• EPA Region 7’s online searchable database of many PSD and title V guidance documents issued by EPA 

headquarters offices and EPA Regions (http://www.epa.gov/region07/air/policy/search.htm). 

Most of the EPA documents cited in this document can be found in one of these locations. To the extent this 

guidance relies on a document that is not located in one of the above collections, we have attempted to provide a 

website link or other relevant information to help locate the document. 
2 

are exceeded (nonattainment areas) or an area where the NAAQS have not been exceeded 

(attainment and unclassifiable areas). In general, permits for sources in attainment areas and for 

other pollutants regulated under the major source program are referred to as prevention of 

significant deterioration (PSD) permits, while permits for major sources emitting nonattainment 

pollutants and located in nonattainment areas are referred to as nonattainment NSR (NNSR) 

permits. The entire preconstruction permitting program, including both the PSD and NNSR 

permitting programs, is referred to as the NSR program. Since EPA has not established a 

NAAQS for GHGs, the nonattainment component of the NSR program does not apply. Thus, the 

NSR portions of this guidance focus on the PSD requirements that apply once GHGs become a 

regulated NSR pollutant. 

 Major stationary sources and certain other sources are also required by the CAA to obtain 

title V operating permits. While title V permits generally do not establish new emissions limits, 

they consolidate requirements under the CAA, including applicable GHG requirements, into a 

comprehensive air permit. 

 Over the past year, EPA has taken several actions regarding GHGs under the CAA. The 

result of these EPA actions, explained in more detail below, is that certain PSD permits and 

certain title V permits issued on or after January 2, 2011, must address emissions of GHGs. 

These actions included new rules that established a common sense approach to phase in 

permitting requirements for greenhouse gas (GHG) emissions from stationary sources, beginning 

with large industrial sources that are already subject to PSD and title V permitting requirements. 

 On December 15, 2009, EPA found that elevated atmospheric concentrations of six wellmixed GHGs, taken in combination, endanger both public health and welfare (“the endangerment 

finding”), and that the combined emissions of these GHGs from new motor vehicles cause and 

contribute to the air pollution that endangers public health and welfare (“the cause and contribute 

finding”).3

 These findings did not themselves impose any requirements to control GHG 

emissions, but they were a prerequisite to finalizing GHG standards for vehicles under title II of 

the Act. Thereafter, on May 7, 2010, EPA issued a final rule – the Light-Duty Vehicle Rule 

(LDVR) – establishing national GHG emissions standards for vehicles under the CAA.4

 The 

new LDVR standards apply to new passenger cars, light-duty trucks, and medium-duty 

passenger vehicles, starting with model year 2012. 

 For stationary sources, on March 29, 2010, EPA made a final decision to continue 

applying (with one refinement) the Agency’s existing interpretation regarding when a pollutant 

becomes “subject to regulation” under the Act, and thus covered under the PSD and title V 

permitting programs applicable to such sources. EPA published notice of this decision on 

April 2, 2010.5

 Under EPA’s final interpretation, a pollutant becomes “subject to regulation” on 

the date that a requirement in the CAA or a rule adopted by EPA under the Act to actually 

control emissions of that pollutant “takes effect” or becomes applicable to the regulated activity 

 

3

 74 FR 66496 (Dec. 15, 2009). 

4

 75 FR 25324 (May 7, 2010). As part of this joint rulemaking, the Department of Transportation’s National 

Highway Traffic Safety Administration (NHTSA) issued Corporate Average Fuel Economy (CAFE) standards for 

these vehicles under the Energy Policy and Conservation Act, as amended. 

5

 75 FR 17004 (April 2, 2010). 
3 

(rather than upon promulgation or the legal effective date of the rule containing such a 

requirement). The EPA’s April 2, 2010 notice also explained that, based on the anticipated 

promulgation of the LDVR, the GHG requirements of the LDVR would take effect on January 2, 

2011, if the LDVR was finalized as proposed for model year 2012 vehicles. Thus, under EPA’s 

interpretation of the Act and applicable rules, construction permits issued6 under the PSD 

program on or after January 2, 2011, must contain conditions addressing GHG emissions. 

 With respect to title V operating permits, the April 2, 2010 notice reiterated EPA’s 

interpretation that the 100 tons per year (TPY) major source threshold for title V operating 

permits is triggered only by pollutants “subject to regulation” under the Act. EPA also explained 

that the Agency interprets “subject to regulation” for title V purposes in the same way it 

interprets that term for PSD purposes (i.e., a pollutant is subject to regulation when an actual 

control requirement under the Act takes effect). 

 On June 3, 2010, EPA issued a final rule that “tailors” the applicability provisions of the 

PSD and title V programs to enable EPA and states to phase in permitting requirements for 

GHGs in a common sense manner (“Tailoring Rule”).7

 The Tailoring Rule focuses on first 

applying the CAA permitting requirements for GHG emissions to the largest sources with the 

most CAA permitting experience. Under the Tailoring Rule, facilities responsible for nearly 70 

percent of the national GHG emissions from stationary sources are subject to permitting 

requirements beginning in 2011, including the nation’s largest GHG emitters (i.e., power plants, 

refineries, and cement production facilities). Emissions from small farms, churches, restaurants, 

and small commercial facilities are examples of source types that are not likely to be covered by 

these programs under the Tailoring Rule. The rule then expands to cover the largest sources of 

GHGs that may not have been previously covered by the CAA for other pollutants. 

 As discussed in detail below, under the Tailoring Rule, application of PSD to GHGs will 

be implemented in multiple steps, which we refer to in this document as “Tailoring Rule Steps” 

to avoid confusion with the five steps for implementing the “top down” best available control 

technology (BACT) analysis and the two steps of the applicability procedures for modifications. 

The first Tailoring Rule step begins on January 2, 2011, and ends on June 30, 2011, and this step 

 

6 Consistent with its regulations in 40 CFR Part 124, EPA uses the term “issued” to describe the time when a 

permitting authority issues a PSD permit after public comment on a draft permit or preliminary determination to 

issue a PSD permit. Depending on the applicable administrative procedures, the date a permit is issued is not 

necessarily the same as the date the permit becomes effective or final agency action for purposes of judicial review. 

Under EPA’s procedural regulations, a permit is “issued” when the Regional Office makes a final decision to grant 

the application, not when the permit becomes effective or final agency action. 40 CFR 124.15; 40 CFR 124.19(f). 

EPA generally applies the requirements in effect at the time a permit is issued by a Regional office unless the 

Agency has expressed an intent when adopting a new requirement that the requirement apply to permits that were 

issued earlier but not yet effective or final agency action by the time the new requirement takes effect. In re: 

Dominion Energy Brayton Point, L.L.C., 12 E.A.D. 490, 616 (EAB 2006). In its actions discussing the January 2, 

2011 date when GHGs will become a regulated NSR pollutant, EPA did not indicate that GHG requirements should 

apply to any permits issued before January 2, 2011. Thus, EPA does not intend to require PSD permits that are 

issued (as described in 40 CFR 124.15) prior to January 2, 2011 to address GHGs, even if the permit is not effective 

until after January 2, 2011 by virtue of a delayed effective date or an appeal to the Environmental Appeals Board. 

See, 40 CFR 124.15(b); 40 CFR 124.19(f). A similar approach may be appropriate in states with approved PSD 

programs that have analogous administrative procedures. 

7

 75 FR 31514 (June 3, 2010). 
4 

covers what EPA has called “anyway sources” and “anyway modifications” that would be 

subject to PSD “anyway” based on emissions of pollutants other than GHGs. The second step 

begins on July 1, 2011, and continues thereafter to cover both anyway sources and certain other 

large emitters of GHGs. EPA has committed to completing another rulemaking no later than 

July 1, 2012, to solicit comments on whether to take a third step of the implementation process to 

apply the permitting programs to additional sources. EPA has also committed to undertaking 

another rulemaking after 2012. Sources subject to the permitting programs under the first two 

steps will remain subject to these programs through any future steps. Future steps are not 

discussed further in this guidance document, since the outcomes of those rulemaking efforts are 

not yet known. Under the Tailoring Rule, in no event are sources with a potential to emit (PTE) 

less than 50,000 TPY of CO2 equivalent (CO2e) subject to PSD or title V permitting for GHG 

emissions before 2016. For additional information regarding the steps of the PSD and title V 

implementation processes for GHGs, please refer to the preamble of the Tailoring Rule.8

 

 This guidance does not reiterate all the provisions of the Tailoring Rule or other EPA 

rules; rather, it takes the applicable provisions and lays them out in a way designed to explain 

and simplify the procedures for applicants and other stakeholders going through the PSD and 

title V permitting processes. Should there be any inconsistency between this document and the 

rules, the rules shall govern. 

 The fundamental aspects of the PSD and title V permitting programs are generally not 

affected by the integration of GHGs into these programs. Therefore, this document does not 

elaborate on topics such as public notice requirements, aggregation of related physical or 

operational changes, the definition of a stationary source, debottlenecking, treatment of fugitive 

emissions, determining creditable emissions reductions, or routine maintenance, repair and 

replacement. Readers that are interested in understanding these aspects of the federal program 

should rely on current Agency rules and guidance when permitting GHGs. 

 EPA Regional Offices should apply the policies and practices reflected in this document 

when issuing permits under the federal PSD and title V permitting programs, unless the facts and 

the record in an individual case demonstrate grounds to approach the subjects discussed in a 

different manner. State, local and tribal permitting authorities that issue permits under a 

delegation of federal authority from EPA Regional Offices should do likewise. EPA also 

recommends that permitting authorities with approved PSD or title V permit programs apply the 

guidance reflected in this document, but these permitting authorities have the discretion to apply 

alternative approaches that comply with state and/or local laws and the requirements of the CAA 

and approved state, local or tribal programs. As is always the case, permitting authorities have 

the discretion to establish requirements in their permits that are more stringent than those 

suggested in this guidance or prescribed by EPA regulations.9

 

 

 

8 75 FR at 31522-525.

9

 42 USC 7416. 
5 

II. PSD Applicability 

General Concepts

 Under the CAA, new major stationary sources of certain air pollutants, defined as 

“regulated NSR pollutants,” and major modifications to existing major sources are required to, 

among other things, obtain a PSD permit prior to construction or major modification. We refer 

to the set of requirements that determine which sources and modifications are subject to PSD as 

the “applicability” requirements. Once major sources become subject to PSD, these sources 

must, in order to obtain a PSD permit, meet the various PSD requirements. For example, they 

must apply BACT, demonstrate compliance with air quality related values and PSD increments, 

address impacts on special Class I areas (e.g., some national parks and wilderness areas), and 

assess impacts on soils, vegetation, and visibility. These PSD requirements are the subject of 

Sections III and IV of this document. 

 In this section, we discuss how the CAA and relevant EPA regulations describe 

the PSD applicability requirements. The CAA applies the PSD requirements to any 

“major emitting facility” that constructs (if the facility is new) or undertakes a 

modification (if the facility is an existing source).10 The term “major emitting facility” is 

defined as a stationary source that emits, or has a PTE of, at least 100 TPY, if the source 

is in one of 28 listed source categories, or, if the source is not, then at least 250 TPY, of 

“any air pollutant.”11 For existing facilities, the CAA adds a definition of modification, 

which, in general, is any physical or operational change that “increases the amount” of 

any air pollutant emitted by the source.12 

 EPA’s regulations implement these PSD applicability requirements through use of 

different terminology, and, in the case of GHGs, with additional limitations. Specifically, the 

regulations apply the PSD requirements to any major stationary source that begins actual 

construction (if the source is new) or that undertakes a major modification (if the source is 

existing).13 The term major stationary source is defined as a stationary source that emits, or has a 

PTE of, at least 100 TPY if the source is in one of 28 listed source categories, or, if the source is 

not, then at least 250 TPY, of regulated NSR pollutants.14 We refer to these 100- or 250-TPY 

amounts as the major source limits or thresholds. 

 A major modification is defined as “any physical change in or change in the method of 

operation of a major stationary source that would result in a significant emissions increase [] of a 

regulated NSR pollutant []; and a significant net emissions increase of that pollutant from the 

major stationary source.”15 EPA rules specify what amount of emissions increase is “significant” 

for listed regulated NSR pollutants (e.g., 40 TPY for sulfur dioxide, 100 TPY for carbon 

 

10 42 USC 7475(a), 7479(1). 

11 42 USC 7479(1). 

12 42 USC 7479(1), 7411(a)(4). 

13 40 CFR 52.21(a)(2). 

14 40 CFR 52.21(b)(1)(i). 

15 40 CFR 52.21(b)(2)(i) and the term “net emissions increase” as defined at 40 CFR 52.21(b)(3). 
6 

monoxide), but for any regulated NSR pollutant that is not listed in the regulations, any increase 

is significant. 16 

 

A pollutant is a “regulated NSR pollutant” if it meets at least one of four requirements, 

which are, in general, any pollutant for which EPA has promulgated a NAAQS or a new source 

performance standard (NSPS), certain ozone depleting substances, and “[a]ny pollutant that 

otherwise is subject to regulation under the Act.”17 PSD applies on a regulated-NSR-pollutantby-regulated-NSR-pollutant basis. The PSD requirements do not apply to regulated NSR 

pollutants for which the area is designated as nonattainment. Further, some modifications are 

exempt from PSD review (e.g., routine maintenance, repair and replacement).18 

For proposed modifications at existing major sources, PSD applies to each regulated NSR 

pollutant for which the proposed emissions increase resulting from the modification both is 

significant and results in a significant net emissions increase. This is true even if the increased 

pollutant is different than the pollutant for which the source is major. Thus, the regulations 

quoted above require a two-step applicability process for modifications. Step 1 involves 

determining if the modification by itself results in a significant increase. No emissions decreases 

are considered in Step 1. If there is no significant increase in Step 1, then PSD does not apply. 

If there is a significant increase in Step 1, then Step 2 applies, which involves determining if the 

modification results in a significant net emissions increase. The Step 2 calculation includes 

creditable emissions increases and decreases from the modification by itself and also includes 

creditable emissions increases and decreases at the existing source over a “contemporaneous 

period.” This period is defined in the federal regulations as the period that extends back 5 years 

prior to the date that construction commences on the modification and forward to the date that 

the increase from the modification occurs. 

In general, for PSD applicability the proposed emissions changes to new or existing 

emissions units are calculated, at the discretion of the owner or operator of the stationary source, 

based on either an “actual-to-projected-actual” emissions test or an “actual-to-potential” 

emissions test.19 Also, the “baseline actual emissions” for existing emissions units are generally 

the actual emissions in TPY from the unit for any consecutive 24-month period (selected by the 

applicant) in the prior 10 years, or 5 years if the source is an Electric Generating Unit (EGU).20

Assuming a source applies the actual-to-projected-actual applicability test for its modifications, it 

should be noted that many projects that sources undertake to improve the energy or process 

efficiency of their operations may not be subject to PSD review. This is because the increased 

efficiency of the project translates into less raw material and/or fuel consumption for the same 

amount of output of product. Consequently, as long as the output from the affected unit(s) is not 

projected to increase, the projected actual emissions for all of the pollutants emitted from the 

process is likely be less than its baseline actual emissions, resulting in a negative number for the 

change in emissions of the pollutants using the actual-to-projected-actual applicability test.21 Of 

 

16 40 CFR 52.21(b)(23)(i)-(ii). 

17 40 CFR 52.21(b)(50). 

18 40 CFR 52.21(b)(2)(iii). 

19 40 CFR 52.21(b)(41). 

20 40 CFR 52.21(b)(48). 

21 The source must be able to substantiate its projections, and if it fails to do so or if it fails to operate its unit in 

accordance with their projection, PSD may apply. 
7 

course, other factors must be considered as well when calculating the projected actual emissions 

resulting from a modification (e.g., whether the projected actual emissions increase could have 

been accommodated at the changed emissions unit(s) and is also unrelated to the particular 

project). These and other factors may influence whether a modification involving an energy or 

process efficiency improvement is subject to PSD. 

 

 Before beginning actual construction, a source may limit its PTE to avoid application of 

the PSD permitting program. To appropriately limit PTE, a source’s permit must contain a 

production or operational limitation in addition to the unit-specific emissions limitation in cases 

where the emissions limitation does not reflect the maximum emissions of the source operating 

at full design capacity. Restrictions on production or operation that limit a source’s PTE include 

limitations on quantities of raw materials consumed, fuel combusted, hours of operation, or 

conditions which specify that the source must install, operate, and maintain controls that reduce 

emissions to a specified emission rate or to a specified efficiency level. Production and 

operational limits must be stated as conditions that can be enforced independently of one 

another. For example, restrictions on fuel that relate to both type and amount of fuel combusted 

should state each as an independent condition in the permit. This is necessary to make the PTE 

restrictions enforceable as a practical matter.22

 As an alternative applicability procedure for modifications, applicants may secure an 

enforceable plantwide applicability limit (PAL) in TPY at existing major stationary sources for 

one or more regulated NSR pollutants.23 Once properly established in the source’s permit, 

subsequent modifications to existing emissions units, or the addition of new emissions units, are 

not subject to PSD for the PAL pollutant if the emissions of all emissions units under the PAL 

remain below the PAL limit and all other PAL requirements are met. 

GHG-Specific Considerations

 Beginning on January 2, 2011, GHGs are a regulated NSR pollutant under the PSD major 

source permitting program when they are emitted by new sources or modifications in amounts 

that meet the Tailoring Rule’s set of applicability thresholds, which phase in over time. For PSD 

purposes, GHGs are a single air pollutant defined24 as the aggregate group of the following six 

gases: 

- carbon dioxide (CO2) 

- nitrous oxide (N2O) 

- methane (CH4) 

- hydrofluorocarbons (HFCs) 

- perfluorocarbons (PFCs) 

- sulfur hexafluoride (SF6) 

 

22 See, generally, EPA Guidance on Limiting Potential to Emit (PTE) in New Source Permitting (June 13, 1989), 

available at http://www.epa.gov/reg3artd/permitting/t5_epa_guidance.htm. 

23 40 CFR 52.21(a)(2)(v), (b)(2)(iv) and (aa)(1)(ii). 

24 40 CFR 52.21(b)(49)(i). 
8 

Specifically, in Tailoring Rule Step 1, beginning on January 2, 2011, and continuing 

through June 30, 2011, GHGs that are emitted in at least specified threshold amounts from a new 

source that is subject to PSD anyway, due to emissions of another regulated NSR pollutant, are 

subject to regulation and therefore a regulated NSR pollutant from that source. By the same 

token, when an existing major source undertakes a physical or operational change that would be 

subject to PSD anyway due to emissions of another regulated NSR pollutant and increases its 

emissions of GHGs by at least the specified threshold amounts, the GHGs are treated as subject 

to regulation and therefore as a regulated NSR pollutant from that source. (We call such a 

modification an “anyway modification.”) In Tailoring Rule Step 2, beginning on July 1, 2011, 

and continuing thereafter, GHGs emitted by anyway sources and anyway modifications remain a 

regulated NSR pollutant in the same manner as under Step 1. In addition, for new sources that 

are not anyway sources and for modifications that are not anyway modifications, emissions of 

GHGs in at least specified threshold amounts are also treated as subject to regulation and 

therefore as a regulated NSR pollutant. 

 For GHGs, the Tailoring Rule does not change the basic PSD applicability process for 

evaluating whether there is a new major source or modification. However, due to the nature of 

GHGs and their incorporation into the definition of regulated NSR pollutant, the process for 

determining whether a source is emitting GHGs in an amount that would make the GHGs a 

regulated NSR pollutant, includes a calculation of, and applicability threshold for, the source 

based on CO2 equivalent (CO2e) emissions as well as its GHG mass emissions. Consequently, 

when determining the applicability of PSD to GHGs, there is a two-part applicability process that 

evaluates both:25

• the sum of the CO2e emissions in TPY of the six GHGs, in order to determine whether 

the source’s emissions are a regulated NSR pollutant; and, if so 

• the sum of the mass emissions in TPY of the six GHGs, in order to determine if there is a 

major source or major modification of such emissions. 

This applicability process is laid out in more detail in Sections II.B through D of this 

guidance, as well as in flowcharts in Appendices A through D. 

CO2e emissions are defined as the sum of the mass emissions of each individual GHG 

adjusted for its global warming potential (GWP). Since GWP values may vary, applicants 

should use the GWP values in Table A-1 of the Greenhouse Gas Reporting Program (GHGRP) 

(40 CFR Part 98, Subpart A, Table A-1). Note that the GHGRP does not require reporting of all 

emissions and emission sources that may be subject to a PSD applicability analysis. 

In the annual US inventory of GHG emissions and sinks, EPA has reported that the LandUse, Land-Use Change and Forestry (LULUCF) sector (including those stationary sources using 

biomass for energy) in the United States is a net carbon sink, taking into account the carbon 

 

25 As we explained in the Tailoring Rule preamble, while evaluation of the mass-based thresholds is technically the 

second step in the PSD applicability analysis, we understand that most sources are likely to treat this mass-based 

evaluation as an initial screen from a practical standpoint, since they would not proceed to calculate emissions on a 

CO2e basis if they do not trigger PSD or title V on a mass basis. See 75 FR at 31522. 
9 

gains (e.g., terrestrial sequestration) and losses (e.g., emissions or harvesting) from that sector.26

On the basis of the Inventory results and other considerations, numerous stakeholders requested 

that EPA exclude, either partially or wholly, emissions of GHG from bioenergy and other 

biogenic sources for the purposes of the BACT analysis and the PSD program based on the view 

that the biomass used to produce bioenergy feedstocks can also be a carbon sink and therefore 

management of that biomass can play a role in reducing GHGs.27 EPA plans to provide further 

guidance on the how to consider the unique GHG attributes of biomass as fuel. 

Even before EPA takes further action, however, permitting authorities may consider, 

when carrying out their BACT analyses for GHG, the environmental, energy and economic 

benefits that may accrue from the use of certain types of biomass and other biogenic sources 

(e.g., biogas from landfills) for energy generation, consistent with existing air quality standards. 

In particular, a variety of federal and state policies have recognized that some types of biomass 

can be part of a national strategy to reduce dependence on fossil fuels and to reduce emissions of 

GHGs. Federal and state policies, along with a number of state and regional efforts, are 

currently under way to foster the expansion of renewable resources and promote biomass as a 

way of addressing climate change and enhancing forest-management. EPA believes that it is 

appropriate for permitting authorities to account for both existing federal and state policies and 

their underlying objectives in evaluating the environmental, energy and economic benefits of 

biomass fuel. Based on these considerations, permitting authorities might determine that, with 

respect to the biomass component of a facility’s fuel stream, certain types of biomass by 

themselves are BACT for GHGs. 

To assist permitting authorities further in considering these factors, as well as to provide 

a measure of national consistency and certainty, EPA intends to issue guidance in January 2011 

that will provide a suggested framework for undertaking an analysis of the environmental, 

energy and economic benefits of biomass in Step 4 of the top-down BACT process, that, as a 

result, may enable permitting authorities to simplify and streamline BACT determinations with 

respect to certain types of biomass. 

The guidance will include qualitative information on useful issues to consider with 

respect to biomass combustion, such as specific feedstock types and trends in carbon stocks at 

different spatial scales (national, regional, state). The aim of the information will be to assist 

permitting authorities in evaluating “carbon neutrality” in the assessment of environmental, 

energy and economic impacts of control strategies under Step 4 of the BACT process, which, 

again, may enable the streamlining of BACT determinations with respect to certain types of 

biomass. The agency is currently reviewing the comments received in response to the July 15, 

2010 Call for Information (CFI) that solicited feedback from stakeholders on approaches to 

accounting for GHG emissions from bioenergy and other biogenic sources.28 These comments, 

among other things, suggest that certain biomass feedstocks (e.g., biogas) may be considered 

 

26 2010 US Inventory Report at http://epa.gov/climatechange/emissions/usinventoryreport.html. 

27 GHG emissions from bioenergy and other biogenic sources are generated during combustion or decomposition of 

biologically-based material, and include sources such as utilization of forest or agricultural products for energy, 

wastewater treatment and livestock management facilities, and fermentation processes for ethanol production. 

28 The Call for Information was published on July 15, 2010. (75 FR 41173 and 75 FR 45112). EPA received over 

7,000 comments and is still assessing them. 
10 

carbon neutral with minor additional analysis. Such a carbon benefit may further inform the 

BACT process, especially where a permitting authority considers the net carbon impact or 

carbon-neutrality of certain feedstocks in accounting for the broader environmental implications 

of using particular biomass feedstocks. 

Finally, EPA also plans to determine by May 2011, well before the start of the second 

phase of PSD implementation pursuant to the Tailoring Rule, whether the issuance of a 

supplemental rule is appropriate to address whether the Clean Air Act would allow the Agency 

and permitting authorities or permitted sources, when determining the applicability of PSD 

permitting requirements to sources of biogenic emissions, to quantify carbon emissions from 

bioenergy or biogenic sources by applying separate accounting rules for different types of 

feedstocks that reflect the net impact of their carbon emissions. This determination will take into 

consideration both the LULUCF inventory and the full record of responses to the CFI. 
11 

A. Calculating GHG Mass-Based and CO2e-Based Emissions 

 For any source, since GHG emissions may be a mixture of up to six compounds, the 

amount of GHG emissions calculated for the PSD applicability analysis is a sum of the 

compounds emitted at the emissions unit. The following example illustrates the method to 

calculate GHG emissions on both a mass basis and CO2e basis. 

A proposed emissions unit emits five of the six GHG compounds in the following 

amounts: 

 50,000 TPY of CO2 

 60 TPY of methane 

 1 TPY of nitrous oxide 

 5 TPY of HFC-32 (a hydrofluorocarbon) 

 3 TPY of PFC-14 (a perfluorocarbon) 

The GWP for each of the GHGs used in this example are: 

GHG GWP*

Carbon Dioxide 1 

Nitrous Oxide 310 

Methane 21 

HFC-32 650 

PFC-14 6,500 

* as of the date of this document (see 40 CFR Part 98, Subpart A, Table A-1)

The GHGs mass-based emissions of the unit are calculated as follows: 

50,000 TPY + 60 TPY + 1 TPY + 5 TPY + 3TPY = 50,069 TPY of GHGs 

The CO2e-based emissions of the unit are calculated as follows: 

(50,000 TPY x 1) + (60 TPY x 21) + (1 TPY x 310) + (5 TPY x 650) + (3 TPY x 6,500) 

= 50,000 + 1,260 + 310 + 3,250 + 19,500 = 74,320 TPY CO2e 

Note: Short tons (2,000 lbs), not long or metric tons, are used in PSD applicability 

calculations.29

 

29 Metric tonnes (i.e., 1,000 kg) are used in the GHG Mandatory Reporting rule. 
12 

B. PSD Applicability for GHGs - New Sources 

1. Tailoring Rule Step 1 - PSD Applicability Test for GHGs in PSD Permits Issued from 

January 2, 2011, to June 30, 2011

 PSD applies to the GHG emissions from a proposed new source if both of the following 

are true:30

• Not considering its emissions of GHGs, the new source is considered a major source for 

PSD applicability and is required to obtain a PSD permit (called an “anyway source”),

and

• The potential emissions of GHGs from the new source would be equal to or greater than 

75,000 TPY on a CO2e basis. 

2. Tailoring Rule Step 2 - PSD Applicability Test for GHGs in PSD Permits Issued on or 

after July 1, 2011 

 PSD applies to the GHG emissions from a proposed new source if either of the following 

is true: 

• PSD for GHGs would be required under Tailoring Rule Step 1, or

• The potential emissions of GHGs from the new source would be equal to or greater than 

100,000 TPY CO2e basis and equal to or greater than the applicable major source 

threshold (i.e., 100 or 250 TPY, depending on the source category31) on a mass basis for 

GHGs. 

 The PSD applicability criteria discussed above for new sources are summarized in Table 

II-A below. Flowcharts for applicability determinations for new sources in each of the two 

Tailoring Rule steps are presented in Appendices A and B, respectively. 

 

30 While the Tailoring Rule specified that potential emissions calculations for GHG applicability determinations 

would also involve a finding that potential emissions would be equal to or greater than the applicable significant 

emission rate on a mass basis, in the interest of clarity and simplicity, this guidance does not discuss this 

requirement with regard to new sources, because the lack of a netting analysis in a new source determination means 

that any new source that meets the 75,000 TPY CO2e requirements would automatically exceed the applicable 

significant emissions rate for GHGs, which is 0 TPY on a mass basis. 

31 42 USC 7479(1) (providing list of 100 TPY sources). 
13 

Table II-A. Summary of PSD Applicability Criteria for New Sources of GHGs 

Permits issued from 

January 2, 2011, to June 30, 2011 

Permits issued 

on or after July 1, 2011 

PSD applies to GHGs, if all of these conditions 

are met: 

• The source is otherwise subject to PSD (for 

another regulated NSR pollutant) 

• The source has a GHG PTE equal to or 

greater than: 

o 75,000 TPY CO2e 

PSD applies to GHGs, if all of these conditions 

are met: 

• The source is otherwise subject to PSD (for 

another regulated NSR pollutant) 

• The source has a GHG PTE equal to or 

greater than: 

o 75,000 TPY CO2e 

OR 

• Source has a GHG PTE equal to or greater 

than: 

o 100,000 TPY CO2e, and

o 100/250 TPY mass basis 

C. PSD Applicability for GHGs - Modified Sources 

1. General Requirements 

a. Tailoring Rule Step 1 - PSD Applicability Test for GHGs in PSD Permits Issued from 

January 2, 2011, to June 30, 2011

 PSD applies to the GHG emissions from a proposed modification to an existing major 

source if both of the following are true: 

• Not considering its emissions of GHGs, the modification would be considered a major 

modification anyway and therefore would be required to obtain a PSD permit (called an 

“anyway modification”), and

• The emissions increase and the net emissions increase of GHGs from the modification 

would be equal to or greater than 75,000 TPY on a CO2e basis and greater than zero TPY 

on a mass basis. 

b. Tailoring Rule Step 2 - PSD Applicability Test for GHG in PSD Permits Issued on or after 

July 1, 2011 

 PSD applies to the GHG emissions from a proposed modification to an existing source if 

any of the following is true: 

• PSD for GHGs would be required under Tailoring Rule Step 1. 

OR BOTH: 
14 

o The existing source’s PTE for GHGs is equal to or greater than 100,000 TPY on a 

CO2e basis and is equal to or greater than 100/250 TPY (depending on the source 

category) on a mass basis32 and 

 

o The emissions increase and the net emissions increase of GHGs from the 

modification would be equal to or greater than 75,000 TPY on a CO2e basis and

greater than zero TPY on a mass basis. 

OR BOTH:

o The existing source is minor33 for PSD (including GHGs) before the modification, 

and

o The actual or potential emissions of GHGs from the modification alone would be 

equal to or greater than 100,000 TPY on a CO2e basis and equal to or greater than the 

applicable major source threshold of 100/250 TPY on a mass basis. Note that minor 

PSD sources cannot “net” out of PSD review. 

 The PSD applicability criteria for modified existing sources discussed above are 

summarized in Table II-B below. Flowcharts for applicability determinations for existing 

sources in each of the two Tailoring Rule steps are presented in Appendices C and D, 

respectively. 

 

32 The mass basis calculation for the amount of GHGs determines whether the GHGs are emitted at the major source 

level, so that GHGs are considered to be emitted at the major source level if they are emitted in an amount that is 

equals to or greater than 100/250 TPY (depending on the source category) on a mass basis. In contrast, the CO2e 

basis calculation for the amount of GHGs is relevant for determining whether the GHGs are subject to regulation as 

a regulated NSR pollutant, but not for determining whether GHGs are emitted at the major source level. 

33 A source is considered minor for PSD if it does not emit any regulated NSR pollutants in amounts that equal or 

exceed 100/250 TPY (depending on the source category). 
15 

Table II-B. Summary PSD Applicability Criteria for Modified Sources of GHGs 

Permits issued from 

January 2, 2011, to June 30, 2011 

Permits issued 

on or after July 1, 2011 

PSD Applies to GHGs, if: 

• Modification is otherwise subject to PSD 

(for another regulated NSR pollutant), and 

has a GHG emissions increase and net 

emissions increase: 

o Equal to or greater than 75,000 TPY 

CO2e, and

o Greater than -0- TPY mass basis, 

PSD Applies to GHGs, if: 

• Modification is otherwise subject to PSD (for another 

regulated NSR pollutant), and has a GHG emissions increase 

and net emissions increase: 

o Equal to or greater than 75,000 TPY CO2e, and

o Greater than -0- TPY mass basis 

OR BOTH: 

• The existing source has a PTE equal to or greater than: 

o 100,000 TPY CO2e and 

o 100/250 TPY mass basis

• Modification has a GHG emissions increase and net 

emissions increase: 

o Equal to or greater than 75,000 TPY CO2e, and

o Greater than -0- TPY mass basis 

OR BOTH: 

• The source is an existing minor source for PSD, and 

• Modification alone has actual or potential GHG emissions 

equal to or greater than: 

o 100,000 TPY CO2e, and

o 100/250 TPY mass basis 
16 

2. Contemporaneous Netting

 As noted above, assessing PSD applicability for a modification at an existing major 

stationary source against the GHG emissions thresholds is a two-step process. Step 1 of the 

applicability analysis considers only the creditable increases from the proposed modification 

itself. Step 2 of the applicability analysis, which is often referred to as “contemporaneous 

netting,” considers all creditable increases and decreases (including increases and decreases 

resulting from the proposed modification) occurring at the source during the “contemporaneous 

period.” The federal “contemporaneous period” for GHG emissions is no different than the 

federal contemporaneous period for other regulated NSR pollutants, which covers the period 

beginning 5 years before construction of the proposed modification through the date that the 

increase from the modification occurs. 

It should be noted that both the contemporaneous period and the baseline period will, at 

least for a while, require reference to emissions prior to the January 2, 2011 date that PSD 

applies to GHG-emitting sources. That is, because the contemporaneous period includes a fiveyear “look back,” for several years after January 2, 2011, the contemporaneous period for netting 

of GHG emissions includes periods before January 2, 2011. By the same token, when 

calculating the “baseline actual emissions” for existing units included in PSD applicability 

calculations, the selected 24-month time period for determining actual emissions may include 

time periods that begin before January 2, 2011. 

Because PSD applicability for modifications at existing sources requires a two-step 

analysis, and because, for GHGs, each step requires a mass-based calculation and a CO2e-based 

calculation, a total of four applicability conditions must be met in order for modifications 

involving GHG emissions at existing major sources to be subject to PSD. These four conditions 

are summarized below.34

1) The CO2e emissions increase resulting from the modification, calculated as the sum of 

the six GHGs on a CO2e basis (i.e., with GWPs applied) is equal to or greater than 

75,000 TPY CO2e. No emissions decreases are considered in this calculation (i.e., if the 

sum of the change in the six GHGs on a CO2e basis from an emissions unit included in 

the modification results in a negative number, that negative sum is not included in this 

calculation to offset increases at other emissions units). 

2) The “net emissions increase” of CO2e over the contemporaneous period is equal to or 

greater than 75,000 TPY. 

3) The GHG emissions increase resulting from the modification, calculated as the sum of 

the six GHGs on a mass basis (i.e., with no GWPs applied) is greater than zero TPY. No 

emissions decreases are considered in this calculation (i.e., if the sum of the change in the 

six GHGs on a mass basis from an emissions unit included in the modification results in a 

 

34 In addition, as discussed above, either the modification must be an “anyway” modification or the source must 

emit, prior to the modification, GHGs in the amount of 100,000 TPY CO2e and 100/250 TPY mass basis. 
17 

negative number, that negative sum is not included in this calculation to offset increases 

at other emissions units). 

4) The “net emissions increase” of GHGs (on a mass basis) over the contemporaneous 

period is greater than zero TPY. 

Flowcharts of the above four-part PSD applicability test for modified sources of GHGs 

are presented in Appendices C and D. Appendix E provides a detailed example of the 

application of the test to a modified existing major source. 
18 

III. BACT Analysis 

Under the CAA and applicable regulations, a PSD permit must contain emissions 

limitations based on application of BACT for each regulated NSR pollutant. A determination of 

BACT for GHGs should be conducted in the same manner as it is done for any other PSD 

regulated pollutant. 

The BACT requirement is set forth in section 165(a)(4) of the CAA, in federal 

regulations at 40 CFR 52.21(j), in rules setting forth the requirements for approval of a state 

implementation plan (SIP) for a State PSD program at 40 CFR 51.166(j), and in the specific SIPs 

of the various states at 40 CFR Part 52, Subpart A - Subpart FFF. CAA § 169(3) defines BACT 

as: 

an emissions limitation (including a visible emission standard) based on the maximum 

degree of reduction for each pollutant subject to regulation under the Clean Air Act 

which would be emitted from any proposed major stationary source or major 

modification which the Administrator, on a case-by-case basis, taking into account 

energy, environmental, and economic impacts and other costs, determines is achievable 

for such facility through application of production processes and available methods, 

systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative 

fuel combustion techniques for control of each such pollutant.... 

Each new source or modified emission unit subject to PSD is required to undergo a BACT 

review. 

 The CAA and corresponding implementing regulations require that a permitting authority 

conduct a BACT analysis on a case-by-case basis, and the permitting authority must evaluate the 

amount of emissions reductions that each available emissions-reducing technology or technique 

would achieve, as well as the energy, environmental, economic and other costs associated with 

each technology or technique. Based on this assessment, the permitting authority must establish 

a numeric emissions limitation that reflects the maximum degree of reduction achievable for 

each pollutant subject to BACT through the application of the selected technology or technique. 

However, if the permitting authority determines that technical or economic limitations on the 

application of a measurement methodology would make a numerical emissions standard 

infeasible for one or more pollutants, it may establish design, equipment, work practices or 

operational standards to satisfy the BACT requirement.35

Top-Down BACT Process

 EPA recommends that permitting authorities continue to use the Agency’s five-step “topdown” BACT process to determine BACT for GHGs.36 In brief, the top-down process calls for 

 

35 40 CFR 51.166(b)(12); 40 CFR 52.21(b)(12). 

36 The Clean Air Act Advisory Committee (CAAAC) recognized that the top-down framework is the “predominant 

method for determining BACT” and recommended that permitting authorities continue to use their existing BACT 

determinations process, such as the top-down framework, in conducting BACT analyses for GHGs. CAAAC, 

Interim Phase I Report of the Climate Change Work Group of the Permits, New Source Review and Toxics 
19 

all available control technologies for a given pollutant to be identified and ranked in descending 

order of control effectiveness. The permit applicant should first examine the highest-ranked 

(“top”) option. The top-ranked options should be established as BACT unless the permit 

applicant demonstrates to the satisfaction of the permitting authority that technical 

considerations, or energy, environmental, or economic impacts justify a conclusion that the topranked technology is not “achievable” in that case. If the most effective control strategy is 

eliminated in this fashion, then the next most effective alternative should be evaluated, and so on, 

until an option is selected as BACT.37 

EPA has broken down this analytical process into the following five steps, which are 

each discussed in detail later in this section. 

Step 1: Identify all available control technologies. 

Step 2: Eliminate technically infeasible options. 

Step 3: Rank remaining control technologies. 

Step 4: Evaluate most effective controls and document results. 

Step 5: Select the BACT. 

To illustrate how the analysis proceeds through these steps, assume at Step 1 that the 

permit applicant and permitting authority identify four control strategies that may be applicable 

to the particular source under review. At the second step of the process, assume that one of these 

four options is demonstrated to be technically infeasible for the source and is eliminated from 

further consideration. The remaining three pollution control options should then be ranked from 

the most to the least effective at the third step of the process. In the fourth step, the permit 

applicant and permitting authority should begin by evaluating the energy, environmental, and 

economic impacts of the top-ranked option. If these considerations do not justify eliminating the 

top-ranked option, it should be selected as BACT at the fifth step. However, if the energy, 

environmental, or economic impacts of the top-ranked option demonstrate that this option is not 

achievable, then the evaluation remains in Step 4 of the process and continues with an 

examination of the energy, environmental, and economic impacts of the second-ranked option. 

This Step 4 assessment should continue until an achievable option is identified for each source. 

The highest-ranked option that cannot be eliminated is selected as BACT at Step 5, which 

includes the development of an emissions limitation that is achievable by the particular source 

using the selected control strategy. Thus, the inclusion and evaluation of an option as part of a 

top-down BACT analysis for a particular source does not necessarily mean that option will 

ultimately be required as BACT for that source. 

 Subcommittee (Feb. 3, 2010) at 16 and 18, available at

http://www.epa.gov/oar/caaac/climate/2010_02_InterimPhaseIReport.pdf. 37 1990 Workshop Manual at B.2. 
20 

 EPA developed the top-down process in order to improve the application of the BACT 

selection criteria and provide consistency.38 For over 20 years, EPA has applied and 

recommended that permitting authorities apply the top-down approach to ensure compliance 

with the BACT criteria in the CAA and applicable regulations. EPA Regional Offices that 

implement the federal PSD program (through Federal Implementation Plans (FIPs)) and state 

permitting authorities that implement the federal program through a delegation of federal 

authority from an EPA Regional Office should apply the top-down BACT process in accordance 

with EPA policies and interpretations articulated in this document and others that are referenced. 

However, EPA has not established the top-down BACT process as a binding requirement 

through rule.39 Thus, permitting authorities that implement an EPA-approved PSD permitting 

program contained in their State Implementation Plans (SIPs) may use another process for 

determining BACT in permits they issue, including BACT for GHGs, so long as that process 

(and each BACT determination made through that process) complies with the relevant statutory 

and regulatory requirements.40 EPA does not require states to apply the top-down process in 

order to obtain EPA approval of a PSD program, but EPA regulations do require that each state 

program apply the applicable criteria in the definition of BACT.41 Furthermore, EPA has certain 

oversight responsibilities with respect to the issuance of PSD permits under state permitting 

programs. In that capacity, EPA does not seek to substitute its judgment for state permitting 

authorities in BACT determinations, but EPA does seek to ensure that individual BACT 

determinations by states with approved programs are reasoned and faithful to the requirements of 

the CAA and the approved state program regulations.42 

The discussion that follows in Section III provides an overview of the top-down BACT 

process, with discussion of how each step may apply to the aspects that are unique to GHGs. In 

addition, Appendices F, G, and H to this document provide illustrative examples of the 

application of the top-down BACT process to emissions of GHGs. These examples provide only 

basic illustrations of the concepts discussed in this document. A successful BACT analysis 

requires a more detailed record (that is, case- and fact-specific) to justify the conclusions reached 

by the permitting authority than can be provided in this guidance. 

 The most comprehensive discussion of the five-step top-down BACT process can be 

found in EPA’s 1990 Draft New Source Review Workshop Manual (“1990 Workshop 

Manual”),43 and the method has been progressively refined through federal permitting decisions 

by EPA, orders on title V permitting decisions, and opinions of the EPA Environmental Appeals 

Board (EAB) that have adopted many of the principles from the 1990 Workshop Manual and 

 

38 Memorandum from Craig Potter, EPA Assistant Administrator for Air and Radiation, to Regional Administrators, 

Improving New Source Review Implementation (Dec. 1, 1987); Memorandum from John Calcagni, EPA Air Quality 

Management Division, Transmittal of Background Statement on “Top-Down” Best Available Control Technology 

(BACT) (June 13, 1989). 

39 Alaska Department of Environmental Conservation v. EPA, 124 S.Ct. 983, 995 n. 7 (2004). 40 In re Cardinal FG Company, 12 E.A.D. 153, 162 (EAB 2005) and cases cited therein. 41 40 CFR 51.166(b)(12); 40 CFR 51.166(j). 

42 Alaska Department of Environmental Conservation v. EPA, 124 S.Ct. 983 (2004); In the Matter of Cash Creek 

Generation, LLC, Petition Nos. IV-2008-1 & IV-2008-2 (Order on Petition) (December 15, 2009). 43 A copy of the 1990 Workshop Manual is available at http://www.epa.gov/ttn/nsr/gen/wkshpman.pdf. There is 

another draft version of the 1990 Workshop Manual that has jigsaw puzzle pieces on the cover, is not available 

online, and has some minor differences from the online version. For ease of reference, any citations to the 1990 

Workshop Manual in this document refer to the version that is available at the link provided above. 
21 

expanded upon them. Thus, EPA recommends that permitting authorities seeking more detailed 

guidance on particular aspects of the top-down BACT process take care to consider more recent 

EPA actions (many of which are referenced in this document) in addition to the discussions in 

the 1990 Workshop Manual.44 

 Since the BACT provisions in the CAA and EPA’s rules provide discretion to permitting 

authorities, a critical and essential component of a successful BACT analysis (whether it follows 

the top-down process or another approach) is the record supporting the decisions reached by the 

permitting authority. Permitting authorities should ensure that the BACT requirements contained 

in the final PSD permit are supported and justified by the information and analysis presented in a 

thorough and complete permit record. The record should clearly explain the reasons for 

selection or rejection of possible control and emissions reductions options and include 

appropriate supporting analysis.45 In accordance with relevant statutory and regulatory 

requirements, the permitting authority must also provide notice of its preliminary decision on a 

source’s application for a PSD permit and an opportunity for the public to comment on that 

preliminary decision. Thus, the record must also reflect careful consideration and response to 

each significant consideration raised in public comments. Each BACT analysis must be 

supported by a complete permitting record that shows consideration of all the relevant factors. 

 This guidance (including the appendices) provides some preliminary EPA views on 

some key issues that may arise in a BACT analysis for GHGs. It is important to recognize that 

this document does not provide any final determination of BACT for a particular source, since 

such determinations can only be made by individual permitting authorities on a case-by-case 

basis after consideration of the record in each case. Upon considering the record in an individual 

case, if a permitting authority has a reasoned basis to address particular issues discussed in this 

document in a different manner than EPA recommends here, permitting authorities (including 

EPA) have the discretion to do so in decisions on individual permit applications consistent with 

the relevant requirements in the CAA and regulations. Thus, depending on the relevant facts and 

circumstances, permitting authorities have the discretion to establish BACT limitations that are 

more or less stringent than levels that might appear to result if one were to follow the 

recommendations in this guidance. 

Relationship of BACT and New Source Performance Standards (NSPS)

The CAA specifies that BACT cannot be less stringent than any applicable standard of 

performance under the New Source Performance Standards (NSPS).46 As of the date of this 

guidance, EPA has not promulgated any NSPS that contain emissions limits for GHGs. EPA has 

developed this permitting guidance and associated technical “white papers”47 to support initial 

 

44 See the collections of PSD guidance provided in footnote 2, supra. 45 In re Knauf Fiber Glass, GmbH, 8 E.A.D. 121, 131 (EAB 1999) (“The BACT analysis is one of the most critical 

elements of the PSD permitting process. As such, it should be well documented in the administrative record.”); In re 

Steel Dynamics, Inc., 9 E.A.D. 165, 224-25 (EAB 2000) (remanding BACT limitation where permit issuer failed to 

provide adequate explanation for why limits deviated from those of other facilities). 

46 42 USC 7479(3). 

47 These technical “white papers”, targeting specific industrial sectors, provide basic information on GHG control 

options to assist states and local air pollution control agencies, tribal authorities and regulated entities implementing 

measures to reduce GHG, particularly in the assessment of best available control technology (BACT) under the PSD 
22 

BACT determinations for GHGs that will need to be made without the benefit of having an 

NSPS and supporting technical documents to inform the evaluation of the performance of 

available control systems and techniques. 

To the extent EPA completes an NSPS for a relevant source category, BACT 

determinations that follow will need to consider the levels of the GHG standards and the 

supporting rationale for the NSPS. The process of developing NSPS and considering public 

input on proposed standards will advance the technical record on GHG control strategies and 

may reflect advances in control technology or reductions in the costs or other impacts of using 

particular control strategies. Thus, the guidance in this document should be viewed taking into 

consideration the potential development of an NSPS for a particular source category. In 

addition, the fact that a NSPS for a source category does not require a more stringent level of 

control does not preclude its consideration in a top-down BACT analysis. 

Importance of Energy Efficiency

As discussed in greater detail below, EPA believes that it is important in BACT reviews 

for permitting authorities to consider options that improve the overall energy efficiency of the 

source or modification – through technologies, processes and practices at the emitting unit. In 

general, a more energy efficient technology burns less fuel than a less energy efficient 

technology on a per unit of output basis. For example, coal-fired boilers operating at 

supercritical steam conditions consume approximately 5 percent less fuel per megawatt hour 

produced than boilers operating at subcritical steam conditions.48 Thus, considering the most 

energy efficient technologies in the BACT analysis helps reduce the products of combustion, 

which includes not only GHGs but other regulated NSR pollutants (e.g., NOX, SO2, 

PM/PM10/PM2.5, CO, etc.). Thus, it is also important to emphasize that energy efficiency should 

be considered in BACT determinations for all regulated NSR pollutants (not just GHGs). 

Additional considerations concerning energy efficiency in the determination of BACT for GHGs 

are discussed in more detail below. 

An available tool that is particularly useful when assessing energy efficiency 

opportunities and options is performance benchmarking. Performance benchmarking 

information, to the extent it is specific and relevant to the source in question, may provide useful 

information regarding energy efficient technologies and processes for consideration in the BACT 

assessment. Comparison of the unit’s or source’s energy performance with a benchmark may 

highlight the need to assess additional energy efficiency possibilities. To the extent that 

benchmarking an emissions unit or source shows it to be a poor-to-average performer, the 

permitting authority may need to document and evaluate whether greater efficiencies are 

achievable. To ensure that the source is constructed and operated in a manner consistent with 

achieving the energy efficiency goals determined to be BACT, consideration should be given to 

 permitting program. These papers provide basic technical information that may be useful in a BACT analysis but 

they do not define BACT for each sector. 48 U.S. Department of Energy, Cost and Performance Baseline for Fossil Energy Plants - Volume 1: Bituminous 

Coal and Natural Gas to Electricity, DOE/NETL-2007/1281, Final Report, Revision 1 (August 2007) at 6 (finding 

that the absolute efficiency difference between supercritical and subcritical boilers is 2.3% (39.1% compared to 

36.8%), which is equivalent to a 5.9% reduction in fuel use), available at http://www.netl.doe.gov/energyanalyses/pubs/Bituminous%20Baseline_Final%20Report.pdf. 
23 

the individual and overall impact of the various measures under consideration. For example, in 

the case of numerous small energy saving measures, the intended effect of such measures could 

be reflected in projecting the GHG emissions limit or output-based standard for the emissions 

unit. On the other hand, it may be appropriate to include specific energy efficiency measures or 

techniques in the permit (as well as reflected in the GHG emissions limit) where such measures 

would clearly have a noticeable effect on energy savings.  

There are a number of resources available for benchmarking facilities. For example, 

EPA’s ENERGY STAR program for industrial sources offers several resources that can assist 

with performance benchmarking. To evaluate the energy performance of an entire facility, 49

ENERGY STAR developed sector-specific benchmarking tools called plant Energy Performance 

Indicators (EPIs).50 For sectors where an EPI has been developed, these tools may be used to 

assess a plant’s performance compared to the industry. At a unit and process level, ENERGY 

STAR has developed sector-specific Energy Guides for a number of industries. These Energy 

Guides discuss in detail processes and technologies that a permit applicant or permitting 

authority may wish to consider. This type of information may be particularly useful at the initial 

stages of the GHG BACT permitting process as the RACT/BACT/LAER clearinghouse (RBLC) 

is populated and updated with case-specific information.51 Additional resources can be found in 

Appendix J of this document. 

 

 

49 For PSD applicability, the scope of the “major stationary source” is determined by the definition in 40 CFR 

52.21(b)(1), and the title V “major source” is defined in 40 CFR 70.2. The PSD and title V regulations distinguish 

between a “facility” and a “stationary source”; in fact, the regulations include a facility as type of stationary source. 

40 CFR 52.21(b)(5)-(6), 40 CFR 71.2. However, in this guidance, source and facility are used interchangeably to 

generally designate pollutant emitting structures and do not designate official positions regarding applicability 

unless otherwise noted. 

50 Current ENERGY STAR industrial sector EPIs can be found at http://www.energystar.gov/EPIS. 51 The RBLC provides access to information and decisions about pollution control measures required by air 

pollution emission permits issued by state and local permitting agencies so that the information is accessible to all 

permitting authorities working on similar projects. The expanded RBLC includes GHG control and test data, and a 

GHG message board for permitting authorities. 
24 

A. Determining the Scope of the BACT Analyses 

General Concepts

An initial consideration that is not directly covered in the five steps of the top-down 

BACT process is the scope of the entity or equipment to which a top-down BACT analysis is 

applied. EPA has generally recommended that permit applicants and permitting authorities 

conduct a separate BACT analysis for each emissions unit52 at a facility and has also encouraged 

applicants and permitting authorities to consider logical groupings of emissions units as 

appropriate on a case-by-case basis.53 

 For new sources triggering PSD review, the CAA and EPA rules provide discretion for 

permitting authorities to evaluate BACT on a facility-wide basis by taking into account 

operations and equipment which affect the environmental performance of the overall facility. 

The term “facility” and “source” used in applicable provisions of the CAA and EPA rules 

encompass the entire facility and are not limited to individual emissions units.54

For existing sources triggering PSD review, EPA rules are more explicit that BACT 

applies to those emission units at which a net emissions increase would occur at the source55 as a 

result of a physical change or change in the method of operation.56 EPA has interpreted these 

provisions to mean that BACT applies in the context of a modification to only an emissions unit 

that has been modified or added to an existing facility.57 

 

52 40 CFR 52.21(b)(7). 

53 1990 Workshop Manual at B.10; In re General Motors, Inc., 10 E.A.D. 360, 382 (EAB 2002). EPA has also 

supported grouping emissions units in the similar context of evaluating options for meeting the technology-based 

LAER standards under the nonattainment NSR program. Memorandum from John Calcagni, Air Quality 

Management Division to David Kee, Region V, Transfer of Technology in Determining Lowest Achievable 

Emissions Rate (LAER) (Aug. 29, 1988). 54 42 USC 7479(1) and (3); 40 CFR 52.21(b)(1) and (5). 

55 For the purposes of determining whether a PSD permit is required (applicability of PSD), EPA requires a 

permitting authority to look beyond the emissions unit that is modified (across the entire source) to determine the 

extent of emissions increases that result from the modification. Thus, EPA has considered downstream and 

upstream emissions increases and decreases from emissions units that are not physically or operationally changed 

when determining the level of emissions increase that results from a modification. This concept is frequently 

described as “debottlenecking” because the upstream or downstream emission increases that are accounted for in the 

analysis are often the result of increased throughput across the source resulting from the removal of a bottleneck in 

the equipment that is physically changed. 1990 Workshop Manual at A.46; Letter from Kathleen Henry, Region III 

to John M. Daniel, Virginia DEQ (Oct. 23, 1998) (Intermet Archer Creek Facility). In 2006, EPA proposed

potential changes to its approach to debottlenecking based on an analysis that the agency had flexibility to define the 

causation of an increase. 71 FR 54235 (Sept. 14, 2006) However, that proposal was not adopted by the Agency and 

explicitly withdrawn. The discussion of this concept in this note is intended solely to provide context for the BACT 

requirement. This note is in no way intended to modify the Agency’s approach to this aspect of PSD applicability, 

as applied prior the 2006 proposal referenced above and continuing to this day. 

56 40 CFR 52.21(j)(3). 

57 In the preamble for the 1980 rule that established the current version of section 52.21(j)(3), EPA explained that 

“BACT applies only to the units actually modified.” 45 FR 52676, 52681 (Aug. 7, 1980). Later in this preamble, 

EPA elaborated as follows with a specific example: 
25 

 

GHG-Specific Considerations

The application of BACT to GHGs has the potential to place greater importance on 

determining the scope of the entity or equipment to which BACT applies. Under existing rules, a 

permitting authority evaluating applications to construct new sources has the flexibility to 

consider source-wide energy efficiency strategies (over an entire production process or across 

multiple production process) to reduce GHG emissions from the proposed new source. EPA 

interprets the language of the BACT definition in CAA §169, which requires consideration of 

“production processes and available methods, systems, and techniques ... for control of [each] 

pollutant,” to include control methods that can be used facility-wide. As noted above, for a 

modification of an existing facility, EPA’s existing regulations state that BACT only applies to 

emission units that are physically or operationally changed.58 

EPA has historically interpreted the BACT requirement to be inapplicable to secondary 

emissions, which are defined to include emissions that may occur as a result of the construction 

or operation of a major stationary source but do not come from the source itself.59 Thus, under 

this interpretation of EPA rules, a BACT analysis should not include (in Step 1 of the process) 

energy efficient options that may achieve reductions in a facility’s demand for energy from the 

electric grid but that cannot be demonstrated to achieve reduction in emissions released from the 

stationary source (e.g., within the property boundary). Nevertheless, as discussed in more detail 

below, EPA recommends that permitting authorities consider in a portion of the BACT analysis 

(Step 4) how available strategies for reducing GHG emissions from a stationary source may 

affect secondary GHG emissions from offsite locations. 

B. BACT Step 1 – Identify All Available Control Options 

General Concepts

The first step in the top-down BACT process is to identify all “available” control options. 

Available control options are those air pollution control technologies or techniques (including 

lower-emitting processes and practices) that have the potential for practical application to the 

emissions unit and the regulated pollutant under evaluation. To satisfy the statutory 

requirements of BACT, EPA believes that the applicant must focus on technologies that have 

been demonstrated to achieve the highest levels of control for the pollutant in question, 

regardless of the source type in which the demonstration has occurred. 

 The proposal required BACT for the new or modified emissions units which were associated with the 

modification and not for those unchanged emissions units at the same source. Thus, if an existing boiler at 

a source were modified or a new boiler added in such a way as to significantly increase particulate 

emissions, only that boiler would be subject to BACT, not the other emissions units at the source. 

Id. at 52722. See also Letter from Robert Miller, EPA Region 5 to Lloyd Eagan, Wisconsin DNR (Feb. 8, 2000) 

(PSD applicability for debottlenecked source). 

58 40 CFR 52.21(j)(3). 

59 44 FR 51924, 51947 (Sept. 5, 1979); 40 CFR 52.21(b)(18). 
26 

Air pollution control technologies and techniques include the application of alternative 

production processes, methods, systems, and techniques, including clean fuels or treatment or 

innovative fuel combustion techniques for control of the affected pollutant. In some 

circumstances, inherently lower-polluting processes are appropriate for consideration as 

available control alternatives. The control options should include not only existing controls for 

the source category in question, but also controls determined through “technology transfer” that 

are applied to source categories with exhaust streams that are similar to the source category in 

question. The 1990 Workshop Manual provides useful guidelines for issues related to 

technology transfer among process applications. Primary factors that should be considered are 

the characteristics of the gas stream to be controlled, the comparability of the production 

processes (e.g., batch versus continuous operation, frequency of process interruptions, special 

product quality concerns, etc.), and the potential impacts on other emission points within the 

source. Also, technologies in application outside the United States should be considered to the 

extent that the technologies have been successfully demonstrated in practice. In general, if a 

control option has been demonstrated in practice on a range of exhaust gases with similar 

physical and chemical characteristics and does not have a significant negative impact on process 

operations, product quality, or the control of other emissions, it may be considered as potentially 

feasible for application to another process. 

Technologies that formed the basis for an applicable NSPS (if any) should, in most 

circumstances, be included in the analysis, as BACT cannot be set at an emission control level 

that is less stringent than that required by the NSPS.60 In cases where a NSPS is proposed, the 

NSPS will not be controlling for BACT purposes since it is not a final action and the proposed 

standard may change, but the record of the proposed standard (including any significant public 

comments on EPA’s evaluation) should be weighed when considering available control 

strategies and achievable emission levels for BACT determinations made that are completed 

before a final standard is set by EPA. However, even though a proposed NSPS is not a 

controlling floor for BACT, the NSPS is an independent requirement that will apply to an NSPS 

source that commences construction after an NSPS is proposed and carries with it a strong 

presumption as to what level of control is achievable. This is not intended to limit available 

options to only those considered in the development of the NSPS. For example, in addition to 

considering controls addressed in an NSPS rulemaking, controls selected in lowest achievable 

emission rate (LAER) determinations are available for BACT purposes, should be included as 

control alternatives included in BACT Step 1, and may frequently be found to represent the top 

control alternative at later steps in the BACT analysis.61 

EPA has placed potentially applicable control alternatives identified and evaluated in the 

BACT analysis into the following three categories: 

 

60 40 CFR 52.21(b)(12). While this guidance is being issued at a time when no NSPS have been established for 

GHGs, permitting authorities must consider any applicable NSPS as a controlling floor in determining BACT once 

any such standards are final. 

61 EPA has stated that technologies designated as meeting lowest achievable emission rate (LAER) – which are 

required in NSR permits issues to sources in non-attainment areas – are available for BACT purposes, must be 

included in the list of control alternatives in step 1, and will usually represent the top control alternative. 1990 

Workshop Manual at B.5. 
27 

• Inherently Lower-Emitting Processes/Practices/Designs,62

• Add-on Controls, and

• Combinations of Inherently Lower Emitting Processes/Practices/Designs and Add-on 

Controls. 

The BACT analysis should consider potentially applicable control techniques from all of 

the above three categories. Lower-polluting processes (including design considerations) should 

be considered based on demonstrations made on the basis of manufacturing identical or similar 

products from identical or similar raw materials or fuels. Add-on controls, on the other hand, 

should be considered based on the physical and chemical characteristics of the pollutant-bearing 

emission stream. 

As explained later in this guidance, in the course of the BACT analysis, one or more of 

the available options may be eliminated from consideration because they are demonstrated to be 

technically infeasible or have unacceptable energy, economic, and environmental impacts on a 

case- and fact-specific basis. However, such options should still be included in Step 1 of the 

BACT process, since the purpose of Step 1 of the process is to cast a wide net and identify all 

control options with potential application to the emissions unit under review that should be 

subject to scrutiny under later steps of the process. 

While Step 1 is intended to capture a broad array of potential options for pollution 

control, this step of the process is not without limits. EPA has recognized that a Step 1 list of 

options need not necessarily include inherently lower polluting processes that would 

fundamentally redefine the nature of the source proposed by the permit applicant.63 BACT 

should generally not be applied to regulate the applicant’s purpose or objective for the proposed 

facility. 

In assessing whether an option would fundamentally redefine a proposed source, EPA 

recommends that permitting authorities apply the analytical framework recently articulated by 

the Environmental Appeals Board.64 Under this framework, a permitting authority should look 

first at the administrative record to see how the applicant defined its goal, objectives, purpose or 

basic design for the proposed facility in its application. The underlying record will be an 

essential component of a supportable BACT determination that a proposed control technology 

redefines the source.65 The permitting authority should then take a “hard look” at the applicant’s 

proposed design in order to discern which design elements are inherent for the applicant’s 

purpose and which design elements may be changed to achieve pollutant emissions reductions 

 

62 While the 1990 Workshop Manual generally refers to “Inherently Lower Polluting Processes/Practices,” the 

discussion contained in that portion of the Manual makes it clear that lower emitting designs may also be considered 

in Step 1 of the top-down analysis. See 1990 Workshop Manual at B.14 (stating that “the ability of design 

considerations to make the process inherently less polluting must be considered as a control alternative for the 

source”). 

63 In re Prairie State Generating Company, 13 E.A.D. 1, 23 (EAB 2006). 64 See, generally, In the Matter of American Electric Power Service Corporation, Southwest Electric Power 

Company, John W. Turk Plant, Petition No. VI-2008-01 (Order on Petition) (December 15, 2009) (title V order 

referencing and applying framework developed by the EAB) ; In the Matter of Cash Creek Generation, LLC, 

Petition Nos. IV-2008-1 & IV-2008-2 (Order on Petition) (December 15, 2009) (same). 65 In re Desert Rock Energy Company, PSD Appeal No. 08-03 et al. (EAB Sept. 24, 2009), slip op. at 65, 76. 
28 

without disrupting the applicant’s basic business purpose for the proposed facility. In doing so, 

the permitting authority should keep in mind that BACT, in most cases, should not be applied to 

regulate the applicant’s purpose or objective for the proposed facility.66 This approach does not 

preclude a permitting authority from considering options that would change aspects (either minor 

or significant) of an applicants’ proposed facility design in order to achieve pollutant reductions 

that may or may not be deemed achievable after further evaluation at later steps of the process. 

EPA does not interpret the CAA to prohibit fundamentally redefining the source and has 

recognized that permitting authorities have the discretion to conduct a broader BACT analysis if 

they desire.67 The “redefining the source” issue is ultimately a question of degree that is within 

the discretion of the permitting authority. However, any decision to exclude an option on 

“redefining the source” grounds must be explained and documented in the permit record, 

especially where such an option has been identified as significant in public comments.68

In circumstances where there are varying configurations for a particular type of source, 

the applicant should include in the application a discussion of the reasons why that particular 

configuration is necessary to achieve the fundamental business objective for the proposed 

construction project. The permitting authority should determine the applicant’s basic or 

fundamental business purpose or objective based on the record in each individual case. For 

example, the permitting authority can consider the intended function of an electric generating 

facility as a baseload or peaking unit in assessing the fundamental business purpose of a permit 

applicant.69 However, a factor that might be considered at later steps of the top-down BACT 

process, such as whether a process or technology can be applied on a specific type of source 

(Step 2) or the cost of constructing a source with particular characteristics (Step 4), should not be 

used as a justification for eliminating an option in Step 1 of the BACT analysis. Thus, cost 

savings and avoiding the risk of an apparently achievable technology transfer are not 

appropriately considered to be a part of the applicant’s basic design or fundamental business 

purpose or objective.70 Since BACT Step 4 also includes consideration of “energy” impacts 

from the control options under consideration, such impacts should not be used to justify 

excluding an option in Step 1 of a top-down BACT analysis. 

 

66 The EPA Environmental Appeals Board has applied this framework for evaluating redefining the source questions 

in three cases involving coal-fired power plants. In re Desert Rock Energy Company, PSD Appeal No. 08-03 et al. 

(EAB Sept. 24, 2009); In re Northern Michigan University, PSD Appeal No. 08-02 (EAB Feb. 18, 2009); In re 

Prairie State Generating Company, 13 E.A.D. 1 (EAB 2006). For additional examples of how EPA approached the 

redefining the source issue in the context of power plants prior to developing this analytical framework, see the 

following decisions. In re Old Dominion Electric Cooperative, 3 E.A.D. 779 (Adm’r 1992); In re Hawaiian 

Commercial & Sugar Co., 4 E.A.D. 95 (EAB 1992); In re SEI Birchwood Inc., 5 E.A.D. 25 (EAB 1994). EPA also 

considered this issue in the context of waste incinerators prior to developing the recommended analytical 

framework. In re Pennsauken, 2 E.A.D. 667 (Adm’r 1988); In the Matter of Spokane Regional Waste-to-Energy 

Facility, 2 E.A.D. 809 (Adm’r 1989); In the Matter of Brooklyn Navy Yard Resource Recovery Facility, 3 E.A.D. 

867 (EAB 1992); In re Hillman Power Co., LLC, 10 E.A.D. 673, 684 (EAB 2002). In another case, EPA considered 

this question in the context of a conversion of a natural-gas fired taconite ore facility to a petcoke fuel. In re 

Hibbing Taconite Co., 2 E.A.D. 838 (Adm’r 1989). For an example of the application of this concept to a fiberglass 

manufacturing facility, see In re Knauf Fiber Glass, 8 E.A.D 121 (EAB 1998). 67 In re Knauf Fiber Glass, 8 E.A.D. at 136; In re Old Dominion Cooperative, 3 E.A.D. at 793. 68 In re Desert Rock Energy Company, slip op. at 70-71, 76-77; In the Matter of Cash Creek Generation, Order at 7-

10. 

69 In re Prairie State Generating Company, 13 E.A.D. at 25 (recognizing distinction between sources designed to 

provide base load power and those designed to function as peaking facilities). 

70 In re Prairie State Generating Company, 13 E.A.D. at 23, n.23. 
29 

The CAA includes “clean fuels” in the definition of BACT.71 Thus, clean fuels which 

would reduce GHG emissions should be considered, but EPA has recognized that the initial list 

of control options for a BACT analysis does not need to include “clean fuel” options that would 

fundamentally redefine the source. Such options include those that would require a permit 

applicant to switch to a primary fuel type (i.e., coal, natural gas, or biomass) other than the type 

of fuel that an applicant proposes to use for its primary combustion process. For example, when 

an applicant proposes to construct a coal-fired steam electric generating unit, EPA continues to 

believe that permitting authorities can show in most cases that the option of using natural gas as 

a primary fuel would fundamentally redefine a coal-fired electric generating unit.72 Ultimately, 

however, a permitting authority retains the discretion to conduct a broader BACT analysis and to 

consider changes in the primary fuel in Step 1 of the analysis. EPA does not classify the option 

of using a cleaner form of the same type of fuel that a permit applicant proposes to use as a 

change in primary fuel, so these types of options should be assessed in a top-down BACT 

analysis in most cases.73 For example, a permitting authority may consider that some types of 

coal can have lower emissions of GHG than other forms of coal, and they may insist that the 

lower emitting coal be evaluated in the BACT review. Furthermore, when a permit applicant has 

incorporated a particular fuel into one aspect of the project design (such as startup or auxiliary 

applications), this suggests that a fuel is “available” to a permit applicant. In such circumstances, 

greater utilization of a fuel that the applicant is already proposing to use in some aspect of the 

project design should be listed as an option in Step 1 unless it can be demonstrated that such an 

option would disrupt the applicant’s basic business purpose for the proposed facility.74 

Although not required in Step 1 of the BACT process, the applicant may also evaluate 

and propose to apply innovative technologies that qualify for coverage under the innovative 

control technology waiver in EPA rules.75 Under this waiver, a source is allowed an extended 

period of time to bring innovative technology into compliance with the required performance 

level. To be considered “innovative,” a control technique must meet the provisions of 40 CFR 

52.21(b)(19) or, where appropriate, the applicable definition in a state SIP. In the early 1990s, 

EPA did not consider it appropriate to grant applications for this waiver for proposed projects 

 

71 42 USC 7579(3). EPA has not yet updated the definition of BACT in the PSD regulations to reflect the addition 

of the “clean fuels” language that occurred in the 1990 amendments to the Clean Air Act. 40 CFR 52.21(b)(12); 40 

CFR 51.166(b)(12). Nevertheless, EPA reads and applies its regulations consistent with the terms of the Clean Air 

Act. 

72 See, e.g., 1990 Workshop Manual at B.13; In re Old Dominion Electric Cooperative, 3 E.A.D. at 793-94; In re 

SEI Birchwood Inc., 5 E.A.D. at 28, n. 8. But see In re Hibbing Taconite Co., 2 E.A.D. 838, 843(Adm’r 

1989) (finding it reasonable to consider burning natural gas instead of or in combination with coal where the plant at 

issue was already equipped to burn natural gas).

73 See In re Old Dominion Electric Cooperative, 3 E.A.D. at 793 (stating that the BACT analysis includes 

consideration of fuels cleaner than that proposed by the applicant); In re Inter-Power of New York, 5 E.A.D. 130, 

145-150 (EAB 1994) (upholding permitting authorities BACT analysis involving coals with different sulfur 

contents). But see In re Prairie State Generating Company, 13 E.A.D. at 27-28 (finding the permitting authority 

properly excluded consideration of lower sulfur coal as redefining the source since the power plant at issue was colocated with a mine and designed to burn the coal from that mine) . 74 In the Matter of Cash Creek Generation, Order at 7-10. 75 40 CFR 52.21(v); 40 CFR 51.166(s). 
30 

that were the same as or similar to projects for which the waiver had previously been granted.76 

However, in 1996, EPA said that it was inclined to allow additional waivers if the criteria in the 

CAA for such a waiver under the NSPS program were met. EPA proposed revisions to this 

provision in the PSD rules to incorporate the statutory criteria from the NSPS program, which 

specifies that such waivers may not exceed the number the administrator finds necessary to 

ascertain whether the criteria for issuing a waiver are met.77 Though the 1996 proposal was 

never issued as final policy, EPA continues to adhere to the view expressed in that 1996 proposal 

and will consider approving more than one waiver under these conditions. 

GHG-Specific Considerations

Permit applicants and permitting authorities should identify all “available” GHG control 

options that have the potential for practical application to the source under consideration. The 

application of BACT to GHGs does not affect the discretion of a permitting authority to exclude 

options that would fundamentally redefine a proposed source. GHG control technologies are 

likely to vary based on the type of facility, processes involved, and GHGs being addressed. The 

discussion below is focused on energy efficiency and carbon capture and storage (CCS) because 

these control approaches may be applicable to a wide range of facilities that emit large amounts 

of CO2. Information on other technologies and mitigation approaches to control CO2 as well as 

the other GHGs (e.g., methane) is found in Appendix J. 

 The application of methods, systems, or techniques to increase energy efficiency is a key 

GHG-reducing opportunity that falls under the category of “lower-polluting processes/practices.” 

Use of inherently lower-emitting technologies, including energy efficiency measures, represents 

an opportunity for GHG reductions in these BACT reviews. In some cases, selecting a more 

energy efficient process or project design is preferred over end-of-stack controls; in other cases, 

an energy efficient measure can be used effectively in tandem with end-of-stack controls to 

achieve additional control of criteria pollutants. Applying the most energy efficient technologies 

at a source should in most cases translate into fewer overall emissions of all air pollutants per 

unit of energy produced. Selecting technologies, measures and options that are energy efficient 

translates not only in the reduction of emissions of the particular regulated NSR air pollutant 

undergoing BACT review, but it also may achieve collateral reductions of emissions of other 

pollutants, as well as GHGs. 

For these reasons, EPA encourages permitting authorities to use the discretion available 

under the PSD program to include the most energy efficient options in BACT analyses for both 

GHG and non-GHG regulated NSR pollutants. While energy efficiency can reduce emissions of 

all combustion-related emissions, it is a particularly important consideration for GHGs since the 

use of add-on controls to reduce GHG emissions is not as well-advanced as it is for most 

combustion-derived pollutants. Initially, in many instances energy efficient measures may serve 

as the foundation for a BACT analysis for GHGs with add-on pollution control technology and 

 

76 1990 Workshop Manual at B.13; Memo from Ed Lillis, Chief, Permits Program Branch, to Kenneth Eng, Chief, 

Air Compliance Branch, Kamine Development Corporation's (KDC) Request for a Prevention of Significant 

Deterioration (PSD) Innovative Control Technology Waiver (August 20, 1991). 77 61 FR 38250, 38281 (July 23, 1996). 
31 

other strategies added as they become more accessible. Energy efficient options that should be 

considered in Step 1 of a BACT analysis for GHGs can be classified in two categories. 

 

The first category of energy efficiency improvement options includes technologies or 

processes that maximize the efficiency of the individual emissions unit. For example, the 

processes that may be used in electric generating facilities have varying levels of efficiency, 

measured in terms of amount of heat input that is used in the process or in terms of per unit of 

the amount of electricity that is produced. When a permit applicant proposes to construct a 

facility using a less efficient boiler design, such as a pulverized coal (PC) or circulating fluidized 

bed (CFB) boiler using subcritical steam pressure, a BACT analysis for this source should 

include more efficient options such as boilers with supercritical and ultra-supercritical steam 

pressures. Furthermore, combined cycle combustion turbines, which have higher efficiencies 

than simple cycle turbines, should be listed as options when an applicant proposes to construct a 

natural gas-fired facility. In coal-fired permit applications, EPA believes that integrated 

gasification combined cycle (IGCC) should also be listed for consideration when it is more 

efficient than the proposed technology.78 However, these options may be evaluated under the 

redefining the source framework described above and excluded from consideration at Step 1 of a 

top-down analysis on a case-by-case basis if it can be shown that application of such a control 

strategy would disrupt the applicant’s basic or fundamental business purpose for the proposed 

facility.

The second category of energy efficiency improvements includes options that could 

reduce emissions from a new greenfield facility by improving the utilization of thermal energy 

and electricity that is generated and used on site. As noted previously, BACT reviews for 

modified units at existing sources should focus on the emitting unit that is being physically or 

operationally changed. However, when reviewing a PSD permit application for the construction 

of a new facility that creates its own energy (thermal or electric) for its own use, EPA 

recommends that permitting authorities consider technologies or processes that not only 

maximize the efficiency of the individual emitting units, but also process improvements that 

impact the facility’s energy utilization assuming it can be shown that efficiencies in energy use 

by the facility’s higher-energy-using equipment, processes or operations could lead to reductions 

in emissions from the facility. EPA has long recognized that “a control option [considered in the 

 

78 EPA no longer subscribes to the reasoning used by the Agency in a 2005 letter to justify excluding IGCC from 

consideration in all cases on redefining the source grounds. Letter from Stephen Page, EPA OAQPS to Paul Plath, 

E3 Consulting, Best Available Control Technology Requirements for Proposed Coal-Fired Power Plant Projects

(Dec. 13, 2005) (last paragraph on page 2). The Environmental Appeals Board subsequently rejected the application 

of this reasoning in an individual permit decision, where the record did not demonstrate that IGCC was inconsistent 

with the fundamental objectives of the permit applicant or distinguish between prior permit decisions that evaluated 

the technology in more detail. In re Desert Rock Energy Company, Slip. Op. at 68-69. Based on this decision, EPA 

also concluded that a state permit decision following substantially the same reasoning lacked a reasoned basis for 

excluding further consideration of IGCC. In the Matter of: American Electric Power Service Corporation, Order at 

8-12. However, EPA continues to interpret the relevant provisions of the CAA, as described in the 2005 letter 

(pages 1-2), to provide discretion for permitting authorities to exclude options that would fundamentally redefine a 

proposed source, provided the record includes an appropriate justification in each case In re Desert Rock Energy 

Company, Slip. Op. at 76. Thus, IGCC should not be categorically excluded from a BACT analysis for a coal fired 

electric generating unit, and this technology should not be excluded on redefining the source grounds at Step 1 of a 

BACT analysis in any particular case unless the record clearly demonstrates why the permit applicant’s basic or 

fundamental business purpose would be frustrated by application of this process. 
32 

BACT analysis] may be an ‘add-on’ air pollution control technology that removes pollutants 

from a facility’s emissions stream, or an ‘inherently lower-polluting process/practice’ that 

prevents emissions from being generated in the first instance.”79

For example, an applicant proposing to build a new facility that will generate its own 

energy with a boiler could also consider ways to optimize the thermal efficiency of a new heat 

exchanger that uses the steam from the new boiler. Moreover, the design, operation, and 

maintenance of a steam distribution and utilization system may influence how much steam is 

needed to complete a specific task. If the steam is distributed and utilized with optimal 

efficiency, less steam may be needed. In many cases, lower steam demand could result in lower 

fuel use and lower emissions at a new facility. Since lower-emitting processes should be 

considered in BACT reviews, opportunities to utilize energy more efficiently and therefore to 

produce less of it are appropriate considerations in a BACT review for a new facility. As 

discussed in the previous section, the evaluation of options in this second category can be 

facilitated by defining, in the case of new sources, the entity subject to BACT on a basis that 

encompasses the significant energy-using equipment, processes or operations of the facility. 

For the first category of energy efficiency options described above, the number of options 

available for a given type of emissions unit at an existing or new source will generally be limited 

in number and not significantly expand the number of options that have traditionally been 

considered in BACT analyses for previously regulated NSR pollutants. However, the second 

category of options appropriate for consideration at a new greenfield facility may include 

equipment or processes that have the effect of lowering emissions because their efficient use of 

energy means that the facility’s energy-producing emitting unit can produce less energy. 

Evaluation of options in this second category need not include an assessment of each and every 

conceivable improvement that could marginally improve the energy efficiency of the new facility 

as a whole (e.g., installing more efficient light bulbs in the facility’s cafeteria), since the burden 

of this level of review would likely outweigh any gain in emissions reduction achieved.80 EPA 

instead recommends that the BACT analyses for units at a new facility concentrate on the 

efficiency of equipment that uses the largest amounts of energy, since energy efficient options 

 

79 In re Knauf Fiberglass, GMBH, 8 EAD 121, 129 (EAB 1999) (citing 1990 NSR Workshop Manual at B.10, 

B.13). In Knauf Fiberglass the EPA's Environmental Appeals Board observed that “[t]he permitting authority may 

require consideration of alternative production processes in the BACT analysis when appropriate.” Id. at 136. The 

EAB remanded a PSD permit for a facility that manufactured fiberglass insulation because of several deficiencies in 

the BACT analysis for the source. One of these deficiencies noted by the Board was the failure to sufficiently 

consider the possibility of applying an alternative process for producing the fiberglass that was used by another 

facility in the industry that had lower levels of PM10 emissions using the same add on controls. The source argued 

that it was unable to reduce its PM10 emissions to levels similar to its competitor because the competitor used a 

different production process that enabled it to achieve lower PM10 emissions levels. The EAB acknowledged that if 

the competitor's process was a proprietary trade secret, then such an option might be technically infeasible (not 

commercially available) for the source under evaluation, but called for the permit record to document this fact and 

for the applicant to seriously consider pollution control designs for other facilities that were a matter of public 

record. 8 EAD at 139-144. After the initial remand in 1999, the EAB later upheld a revised permit that was based 

on the conclusion that it was not technically feasible for this source to use the lower-polluting process used by its 

competitor because the process was proprietary and not commercially available to Knauf. In re Knauf Fiberglass, 

GMBH, 9 EAD 1 (EAB 2000). 80 One federal court has recognized the undesirability of making the BACT analysis into a “Sisyphean labor where 

there was always one more option to consider.” Sierra Club v. EPA, 499 F.3d 653, 655 (7th Cir. 2007). 
33 

for such units and equipment (e.g., induced draft fans, electric water pumps) will have a larger 

impact on reducing the facility’s emissions. EPA also recommends that permit applicants at new 

sources propose options that are defined as an overall category or suite of techniques to yield 

efficiency in energy utilization that could then be evaluated and judged by the permitting 

authority and the public against established benchmarks. Comparing the proposed suite of 

techniques to such benchmarks, which represent a high level of performance within an industry, 

would demonstrate that the new facility will achieve commensurate levels of efficiency using the 

proposed methods. Such an approach would leave some flexibility for the permit applicant to 

suggest the precise mix of measures that would meet the desired benchmark, and avoid including 

in a permit review an assessment of a large number of different combinations of technology 

choices for smaller pieces of equipment. 

While engineering calculations and results from similar equipment demonstrations can 

often enable the permit applicant or engineer to closely estimate the energy efficiency of a unit, 

we recognize that, in some cases, it may be more difficult to fully and accurately predict the 

energy efficiency of a unit for BACT purposes. Commonly, the responsible design engineers or 

vendors will provide both estimated “expected” results and “guaranteed” results. Such estimates 

can be provided for the permitting authority’s consideration. The difference between expected 

and guaranteed results gives some indication of the uncertainty and risk tolerances included in 

the guaranteed value. Still, in some cases, the ultimate efficiency of the unit may not be 

accurately known without testing the installed equipment, especially if multiple vendors or 

multiple design engineers are involved. Of course, this is substantially similar to many current 

permitting situations, such as when combustion enhancements are installed for controlling 

emissions of criteria pollutants and the exact effect on efficiency is somewhat uncertain until it is 

operationally tested. Thus, where there is some reasonable uncertainty regarding performance of 

specified efficiency measures, or the combination of measures, the permit can be written to 

acknowledge that uncertainty. As in the past, the permitting authority has the discretion to set a 

permit limit informed by properly conservative engineering estimates, or to set permit conditions 

that make allowance for adjustments of the BACT limits based on operational experience. 

For the purposes of a BACT analysis for GHGs, EPA classifies CCS as an add-on 

pollution control technology81 that is “available”82 for large CO2-emitting facilities including 

 

81 EPA recognizes that CCS systems may have some unique aspects that differentiate them from the types of 

equipment that have the traditionally been classified as add-on pollution controls (i.e., scrubbers, fabric filters, 

electrostatic precipitators). However, since CCS systems have more similarities to such devices than inherently 

lower-polluting processes, EPA believes that CCS systems are best classified as add-on controls for purposes of a 

top-down BACT analysis. 

82 As noted above, a control option is “available” if it has a potential for practical application to the emissions unit 

and the regulated pollutant under evaluation. Thus, even technologies that are in the initial stages of full 

development and deployment for an industry, such as CCS, can be considered “available” as that term is used for the 

specific purposes of a BACT analysis under the PSD program. In 2010, the Interagency Task Force on Carbon 

Capture and Storage was established to develop a comprehensive and coordinated federal strategy to speed the 

commercial development and deployment of this clean coal technology. As part of its work, the Task Force 

prepared a report that summarizes the state of CCS and identified technical and non-technical challenges to 

implementation. EPA, which participated in the Interagency Task Force, supports the Task Force’s 

recommendations concerning ongoing investment in demonstrations of the CCS technologies based on the report’s 

conclusion that: “Current technologies could be used to capture CO2 from new and existing fossil energy power 

plants; however, they are not ready for widespread implementation primarily because they have not been 
34 

fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams (e.g.,

hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene 

oxide production, cement production, and iron and steel manufacturing). For these types of 

facilities, CCS should be listed in Step 1 of a top-down BACT analysis for GHGs. This does not 

necessarily mean CCS should be selected as BACT for such sources. Many other case-specific 

factors, such as the technical feasibility and cost of CCS technology for the specific application, 

size of the facility, proposed location of the source, and availability and access to transportation 

and storage opportunities, should be assessed at later steps of a top-down BACT analysis. 

However, for these types of facilities and particularly for new facilities, CCS is an option that 

merits initial consideration and, if the permitting authority eliminates this option at some later 

point in the top-down BACT process, the grounds for doing so should be reflected in the record 

with an appropriate level of detail. 

In identifying control technologies in BACT Step 1, the applicant needs to survey the 

range of potentially available control options. EPA recognizes that dissemination of data and 

information detailing the function of the proposed control equipment or process is essential if 

permitting agencies are to reach consistent conclusions on the availability of GHG technology 

across industries. In the initial phase of PSD permit reviews for GHGs, background information 

about certain emission control strategies may be limited and technologies may still be under 

development. For example, alternative technologies are being developed for reusing carbon or 

sequestering carbon in a form or location other than through injection into underground 

formations. When these technologies are more developed, they could be included in Step 1 of 

the top-down BACT process. EPA will add information to the RBLC as it becomes available 

and supplement the information in the GHG Mitigation Measures Database.83 The Agency may 

also issue additional white papers for selected stationary source sectors in the future. 

C. BACT Step 2 – Eliminate Technically Infeasible Options 

General Concepts

 Under the second step of the top-down BACT analysis, a potentially applicable control 

technique listed in Step 1 may be eliminated from further consideration if it is not technically 

feasible for the specific source under review. A demonstration of technical infeasibility should 

be clearly documented and should show, based on physical, chemical, or engineering principles, 

that technical difficulties would preclude the successful use of the control option on the 

emissions unit under review. 

 demonstrated at the scale necessary to establish confidence for power plant application. Since the CO2 capture 

capacities used in current industrial processes are generally much smaller than the capacity required for the purposes 

of GHG emissions mitigation at a typical power plant, there is considerable uncertainty associated with capacities at 

volumes necessary for commercial deployment.” See Report of the Interagency Task Force on Carbon Capture and 

Storage, p.50 (http://www.epa.gov/climatechange/policy/ccs_task_force.html). 

83 EPA has developed a new online tool (GHG Mitigation Measures Database) that includes specific performance 

and cost data on current and developing GHG control measures. It also provides available data on other potential 

environmental impacts a GHG control measure may have. Currently, the database includes information on GHG 

controls for electric generating and cement production. This database can be found on EPA’s website at 

http://www.epa.gov/nsr/ghgpermitting.html 
35 

 EPA considers a technology to be technically feasible if it has been demonstrated in 

practice or is available and applicable to the source type under review. The term “demonstrated” 

is focused on the technology being used in the same type of source, such as a similar plant 

producing the same product. Therefore, EPA considers a technology to be “demonstrated,” if it 

has been installed and operated successfully on the type of source at issue. If application of a 

technology to the source type under review has not been demonstrated, then questions regarding 

“availability” and “applicability” should be considered.84 In the context of a technical feasibility 

analysis, the terms “availability” and “applicability” relate to the use of technology in a situation 

that appears similar even if it has not been used in the same industry. Specifically, EPA 

considers a technology to be “available” where it can be obtained through commercial channels 

or is otherwise available within the common meaning of the term.85 EPA considers an available 

technology to be “applicable” if it can reasonably be installed and operated on the source type 

under consideration. Where a control technology has been applied on one type of source, this is 

largely a question of the transferability of the technology to another source type. A control 

technique should remain under consideration if it has been applied to a pollutant-bearing gas 

stream with similar chemical and physical characteristics. The control technology would not be 

applicable if it can be shown that there are significant differences that preclude the successful 

operation of the control device. For example, the temperature, pressure, pollutant concentration, 

or volume of the gas stream to be controlled, may differ so significantly from previous 

applications that it is uncertain the control device will work in the situation currently undergoing 

review. 

 Evaluations of technical feasibility should consider all characteristics of a technology 

option, including its development stage, commercial applications, scope of installations, and 

performance data. The applicant is responsible for providing evidence that a potential control 

measure is technically infeasible. However, the permitting authority is responsible for deciding 

technical feasibility. The permitting authority may require the applicant to address the 

availability and applicability of a new or emerging technology based on information that 

becomes available during the consideration of the permit application. 

 Information regarding what vendors will guarantee should be considered in the BACT 

selection process with all the other relevant factors, such as BACT emission rates for other 

recently permitted sources, projected cost and effectiveness of controls, and experience with the 

technology on similar gas streams. Commercial guarantees are a contract between the permit 

applicant and the vendor to establish the risk of non-performance the vendor is willing to accept, 

and they typically establish the remedy for failure to perform and the test methods for 

acceptance. A permit applicant uses these guarantees to provide its investors and lenders with 

reasonable assurances that the proposed facility will reliably perform its intended function and 

consistently meet the proposed permit limits. While permit applicants use these guarantees as 

protection from overly optimistic vendor claims for new technologies, experience demonstrates 

that these terms and conditions can also be customized for each circumstance to imply greater or 

lesser performance, depending on the stringency of the guarantees and associated penalties for 

 

84 In re Cardinal FG Company, 12 E.A.D. 153, 166 (EAB 2005); In re Steel Dynamics, Inc., 9 E.A.D. 165, 199 

(EAB 2000). 

85 In re Cardinal FG Company, 12 E.A.D. at 14; In re Steel Dynamics, Inc., 9 E.A.D. at 199. 
36 

nonperformance. The willingness of vendors to provide guarantees and the limits of these 

guarantees can be an important factor in determining the level of performance specified in a PSD 

permit. However, a control technology should not be eliminated in Step 2 of the top-down 

BACT process based solely on the inability to obtain a commercial guarantee from a vendor on 

the application of technology to a source type. The willingness of vendors to guarantee a certain 

level of performance should be considered by the permitting authority later in the BACT process 

when proposing a specific emissions limit or level of performance in the PSD permit. 

GHG-Specific Considerations

 EPA’s historic approach to assessing technical feasibility that is summarized above and 

described in the 1990 Workshop Manual and subsequent actions such as EAB decisions is 

generally applicable to GHGs. The nature of the concerns and remedies arising from 

identification of available technologies is well-explained in the 1990 Workshop Manual and 

other referenced documents. However, technologies available for controlling traditional 

pollutants were, in many cases, well-developed at the time that the 1990 Workshop Manual was 

drafted. Similarly, we expect the commercial availability of different GHG controls to increase 

in the coming years. Permitting authorities need to make sure that their decisions regarding 

technical infeasibility are well-explained and supported in their permitting record, paying 

particular attention to the most recent information from the commercial sector and other 

recently-issued permits. 

 This guidance is being issued at a time when add-on control technologies for certain 

GHGs or emissions sources may be limited in number and in various stages of development and 

commercialization. A number of ongoing research, development, and demonstration programs 

may make CCS technologies more widely applicable in the future.86 These facts are important to 

BACT Step 2, wherein technically infeasible control options are eliminated from further 

consideration. When considering the guidance provided below, permitting authorities should be 

aware of the changing status of various control options for GHG emissions when determining 

BACT. 

 In the early years of GHG control strategies, consideration of commercial guarantees is 

likely to be involved in the BACT determination process. This type of guarantee may be more 

relevant for certain GHG controls because, unlike other pollutants with available, proven control 

technologies, some GHG controls may have a greater uncertainty regarding their expected 

performance. As noted above, the lack of availability of a commercial guarantee, by itself, is 

not a sufficient basis to classify a technology as “technologically infeasible” for BACT 

evaluation purposes, even for GHG control determinations. 

 As discussed earlier, although CCS is not in widespread use at this time, EPA generally 

considers CCS to be an “available” add-on pollution control technology for large CO2-emitting 

facilities and industrial facilities with high-purity CO2 streams. Assuming CCS has been 

included in Step 1 of the top-down BACT process for such sources, it now must be evaluated for 

technical feasibility in Step 2. CCS is composed of three main components: CO2 capture and/or 

 

86 For example, the U.S. Department of Energy has a robust CCS research, development, and demonstration 

program supported by annual appropriations and $3.4B of Recovery Act funds. See www.fe.doe.gov. 
37 

compression, transport, and storage. CCS may be eliminated from a BACT analysis in Step 2 if 

it can be shown that there are significant differences pertinent to the successful operation for 

each of these three main components from what has already been applied to a differing source 

type. For example, the temperature, pressure, pollutant concentration, or volume of the gas 

stream to be controlled, may differ so significantly from previous applications that it is uncertain 

the control device will work in the situation currently undergoing review. Furthermore, CCS 

may be eliminated from a BACT analysis in Step 2 if the three components working together are 

deemed technically infeasible for the proposed source, taking into account the integration of the 

CCS components with the base facility and site-specific considerations (e.g., space for CO2

capture equipment at an existing facility, right-of-ways to build a pipeline or access to an 

existing pipeline, access to suitable geologic reservoirs for sequestration, or other storage 

options).

 While CCS is a promising technology, EPA does not believe that at this time CCS will be 

a technically feasible BACT option in certain cases. As noted above, to establish that an option 

is technically feasible, the permitting record should show either that an available control option 

has been demonstrated in practice or is available and applicable, with the term “applicable” 

generally meaning a technology can reasonably be installed and operated on the source type 

under consideration. EPA recognizes the significant logistical hurdles that the installation and 

operation of a CCS system presents and that sets it apart from other add-on controls that are 

typically used to reduce emissions of other regulated pollutants and already have an existing 

reasonably accessible infrastructure in place to address waste disposal and other offsite needs. 

Logistical hurdles for CCS may include obtaining contracts for offsite land acquisition (including 

the availability of land), the need for funding (including, for example, government subsidies), 

timing of available transportation infrastructure, and developing a site for secure long term 

storage. Not every source has the resources to overcome the offsite logistical barriers necessary 

to apply CCS technology to its operations, and smaller sources will likely be more constrained in 

this regard. Based on these considerations, a permitting authority may conclude that CCS is not 

applicable to a particular source, and consequently not technically feasible, even if the type of 

equipment needed to accomplish the compression, capture, and storage of GHGs are determined 

to be generally available from commercial vendors. 

The level of detail supporting the justification for the removal of CCS in Step 2 will vary 

depending on the nature of the source under review and the opportunities for CO2 transport and 

storage. As with all top-down BACT analyses, cost considerations should not be included in 

Step 2 of the analysis, but can be considered in Step 4. In circumstances where CO2

transportation and sequestration opportunities already exist in the area where the source is, or 

will be, located, or in circumstances where other sources in the same source category have 

applied CCS in practice, the project would clearly warrant a comprehensive consideration of 

CCS. In these cases, a fairly detailed case-specific analysis would likely be needed to dismiss 

CCS. However, in cases where it is clear that there are significant and overwhelming technical 

(including logistical) issues associated with the application of CCS for the type of source under 

review (e.g., sources that emit CO2 in amounts just over the relevant GHG thresholds and 

produce a low purity CO2 stream) a much less detailed justification may be appropriate and 

acceptable for the source. In addition, a permitting authority may make a determination to 

dismiss CCS for a small natural gas-fired package residential boiler, for example, on grounds 
38 

that no reasonable opportunity exists for the capture and long-term storage or reuse of captured 

CO2 given the nature of the project. That finding may be sufficient to dismiss CCS for similar 

units in subsequent BACT reviews, provided the facts upon which the original finding was made 

also apply to the subsequent units and are still valid. 

D. BACT Step 3 – Ranking of Controls 

General Concepts

After the list of all available controls is winnowed down to a list of the technically 

feasible control technologies in Step 2, Step 3 of the top-down BACT process calls for the 

remaining control technologies to be listed in order of overall control effectiveness for the 

regulated NSR pollutant under review. The most effective control alternative (i.e., the option 

that achieves the lowest emissions level) should be listed at the top and the remaining 

technologies ranked in descending order of control effectiveness. The ranking of control options 

in Step 3 determines where to start the top-down BACT selection process in Step 4.87 

In determining and ranking technologies based on control effectiveness, applicants and 

permitting authorities should include information on each technology’s control efficiency (e.g.,

percent pollutant removed, emissions per unit product), expected emission rate (e.g., tons per 

year, pounds per hour, pounds per unit of product, pounds per unit of input, parts per million), 

and expected emissions reduction (e.g., tons per year). The metrics chosen for ranking should 

best represent the array of control technology alternatives under consideration. While inputbased metrics have traditionally been the preferred ranking format for many BACT analyses, for 

some source types, particularly combustion sources, it may be more appropriate to rank control 

options based on output-based metrics that would fully consider the thermal efficiency of the 

options when determining control effectiveness. In particular, where the output of the facility or 

the affected source is relatively homogeneous, an output-based standard (e.g., pounds per 

megawatt hour of electricity, pounds per ton of cement, etc.) may best present the overall 

emissions control of an array of control options. Where appropriate, net output-based standards 

provide a direct measure of the efficiency of an operation’s emission reducing efforts. However, 

in the simple case of a new or modified fuel-fired unit, the thermal efficiency of the unit can be a 

useful ranking metric. Furthermore, when the output of the facility is a changing mix of 

products, an output-based standard may not be appropriate. 

 

GHG-Specific Considerations

As discussed in earlier sections, the options considered in a BACT analysis for GHG 

emissions will likely include, but not necessarily be limited to, control options that result in 

energy efficiency measures to achieve the lowest possible emission level. Where plant-wide 

measures to reduce emissions are being considered as GHG control techniques, the concept of 

 

87 EPA has previously recommended that Step 3 of a BACT analysis include an assessment of the energy, 

environmental, and economic impacts of each remaining option on the list. However, these considerations are not 

actually applied until Step 4 of the process. Thus, the compilation of this information can be accomplished in either 

Step 3 or Step 4 of the process. See 1990 Workshop Manual at B.25. 
39 

overall control effectiveness will need to be refined to ensure the suite of measures with the 

lowest net emissions from the facility is the top-ranked measure. Ranking control options based 

on their net output-based emissions ensures that the thermal efficiency of the control option, as 

well as the power demand of that control measure, is fully considered when comparing options in 

Step 3 of the BACT analysis. Finally, to best reflect the impact on the environment, the ranking 

of control options should be based on the total CO2e rather than total mass or mass for the 

individual GHGs. 

E. BACT Step 4 – Economic, Energy, and Environmental Impacts 

General Concepts

Under Step 4 of the top-down BACT analysis, permitting authorities must consider the 

economic, energy, and environmental impacts arising from each option remaining under 

consideration. Accordingly, after all available and technically feasible control options have been 

ranked in terms of control effectiveness (BACT Step 3), the permitting authority should consider 

any specific energy, environmental, and economic impacts identified with those technologies to 

either confirm that the top control alternative is appropriate or determine it to be inappropriate. 

The “top” control option should be established as BACT unless the applicant demonstrates, and 

the permitting authority agrees, that the energy, environmental, or economic impacts justify a 

conclusion that the most stringent technology is not “achievable” in that case. If the most 

stringent technology is eliminated in this fashion, then the next most stringent alternative is 

considered, and so on. 

In BACT Step 4, the applicant and permitting authority should consider both direct and 

indirect impacts of the emissions control option or strategy being evaluated. EPA has previously 

referred to BACT Step 4 as the “collateral impacts analysis,”88 but this term is primarily 

applicable only to the environmental impact analysis. Overall, the Step 4 analysis is more 

accurately described as an environmental, economic, and energy impacts analysis that includes 

both direct and indirect (i.e., collateral) considerations. 

The economic impacts component of the analysis should focus on direct economic 

impacts calculated in terms of cost effectiveness (dollars per ton of pollutant emission reduced). 

Cost effectiveness should be addressed on both an average basis for each measure and 

combination of measures, and on an incremental basis comparing the costs and emissions 

performance level of a control option to the cost and performance of the next most stringent 

control option.89 The emphasis should be on the cost of control relative to the amount of 

pollutant removed, rather than economic parameters that provide an indication of the general 

affordability of the control alternative relative to the source. To justify elimination of an option 

on economic grounds, the permit applicant should demonstrate that the costs of pollutant 

removal for that option are disproportionately high.90 Appendix K provides further direction on 

 

88 In re Hillman Power, 10 E.A.D. at 683; In the Matter of Columbia Gulf Transmission Co., 2 E.A.D. 824, 828 n. 5 

(Adm’r 1989); In re Kawaihae Cogeneration Project, 7 E.A.D. 107, 116-17 (EAB 1997). 

89 1990 Workshop Manual, Section IV.D.2.b (B.36 – B.44). 

90 1990 Workshop Manual at B.31-32. 
40 

determining and considering cost effectiveness of control options. As noted in Appendix K, cost 

estimates used in BACT are typically accurate to within ± 20 to 30 percent. 

EPA has traditionally called for the energy impacts analysis to consider only direct 

energy consumption and not indirect energy impacts, such as the energy required to produce raw 

materials for construction of control equipment.91 Direct energy consumption impacts include 

the consumption of fuel and the consumption of electrical or thermal energy. This energy 

impacts analysis should include an assessment of demand for both electricity that is generated 

onsite and power obtained from the electrical grid, and may include an evaluation of impacts on 

fuel scarcity or a locally desired fuel mix in a particular area. Applicants and permitting 

authorities should examine whether the energy requirements for each control option result in any 

significant or unusual energy penalties or benefits.92 The costs associated with direct energy 

impacts should be calculated and included in the economic impacts analysis (i.e., cost 

analysis).93 

Since a BACT limitation must reflect the maximum degree of reduction achievable for 

each regulated pollutant, the environmental impacts analysis in Step 4 should concentrate on 

impacts other than direct impacts due to emissions of the regulated pollutant in question. EPA 

has previously recommended focusing the BACT environmental impacts analysis in this manner 

to avoid confusion with the separate air quality impact analysis required under the CAA and PSD 

regulations for primarily the pollutants that are covered by NAAQS.94 However, focusing Step 4 

of the BACT analysis on increases in emissions of pollutants other than those the technology was 

designed to control is also justified because the essential purpose of BACT requirement is to 

achieve the maximum degree of reduction of the particular pollutant under evaluation. In this 

context, it is generally unnecessary to explicitly consider or justify the environmental benefits of 

reducing the pollutant subject to the BACT analysis, since these benefits are presumed under the 

CAA’s mandate to reduce emissions of each regulated pollutant to the maximum degree 

achievable, considering energy, environmental, and economic impacts. Thus, in this context, it 

is reasonable to interpret the “environmental impact” component of the BACT requirement to 

focus on the indirect or collateral environmental impacts that may result from selection of control 

options that achieve the maximum degree of reduction for the pollutant under evaluation. 

EPA has recognized that consideration of a wide variety of environmental impacts is 

appropriate in BACT Step 4, such as solid or hazardous waste generation, discharges of polluted 

water from a control device, visibility impacts, demand on local water resources, and emissions 

of other pollutants subject to NSR or pollutants not regulated under NSR such as air toxics.95 

EPA has also recognized that the environmental impacts analysis may examine trade-offs 

between emissions of various pollutants resulting from the application of a specific control 

technique.96 For instance, in selecting the BACT limit for carbon monoxide (CO) for a facility in 

 

91 In re Power Holdings, PSD Appeal No. 09-04 (EAB Aug. 13, 2010), slip op. at 22, n.17 (citing 1990 Workshop 

Manual at B.30). 

92 1990 Workshop Manual at B.29. 

93 1990 Workshop Manual at B.30. 

94 1990 Workshop Manual at B.46. 

95 1990 Workshop Manual at B.46; In the Matter of North County Resource Recovery Assoc., 2 E.A.D. 229, 230 

(Adm’r 1986).; In the Matter of Columbia Gulf Transmission Co., 2 E.A.D. at 828. 96 1990 Workshop Manual at B.49. 
41 

an area that is nonattainment for ozone, a permitting authority may need to assess whether it is 

more important to select a less stringent control for CO emissions to avoid an unacceptable 

increase in NOX emissions associated with the CO control technology. EPA has generally not 

attempted to place specific limits on the scope of the Step 4 environmental impacts analysis, but 

has focused on “any significant or unusual environmental impacts.”97

To date, the environmental impacts analysis has not been a pivotal consideration when 

making BACT determinations in most cases.98 Typically, applicants and permitting authorities 

focus on direct economic impacts (i.e., cost effectiveness as measured in annualized cost per tons 

of pollutant removed by that control) as the reason for not selecting the top-ranked control option 

as BACT; however, there have been instances where environmental impacts have been a 

deciding factor in selecting a specific control technology as BACT (i.e., water usage for 

scrubbers).99 

Because the Step 4 impacts analysis is intended to help the permitting authority identify 

and weigh the various beneficial and detrimental impacts of the emissions control option or 

strategy being evaluated, EPA has recognized that permitting authorities have flexibility in 

deciding how to weigh the trade-offs associated with emissions control options. However, 

inherent with the flexibility is the responsibility of the permitting authority to develop a full 

permit record that explains those decisions given the specific facts of the facility at issue.100

GHG-Specific Considerations

There are compelling public heath and welfare reasons for BACT to require all GHG 

reductions that are achievable, considering economic impacts and the other listed statutory 

factors. As a key step in the process of making GHGs a regulated pollutant, EPA has considered 

scientific literature on impacts of GHG emissions and has made a final determination that 

emissions of six GHGs endanger both the public health and the public welfare of current and 

future generations.101 Among the public health impacts and risks that EPA cited are anticipated 

increases in ambient ozone and serious ozone-related health effects, increased likelihood of heat 

waves affecting mortality and morbidity, risk of increased intensity of hurricanes and floods, and 

increased severity of coastal storm events due to rising sea levels. With respect to public 

welfare, EPA cited numerous and far-ranging risks to food production and agriculture, forestry, 

 

97 In re Hillman Power 10 E.A.D. at 684 (internal quotations omitted). 

98 1990 Workshop Manual at B.49-50; In the Matter of Columbia Gulf Transmission Co., 2 E.A.D. at 828; In re 

Hillman Power, 10 E.A.D. at 688; In re Kawaihae Cogeneration, 7 E.A.D. at 117. 99 Wyoming Dept. of Environmental Quality, Basin Electric Power Cooperative – Dry Fork Station, Permit 

Application Analysis NSR-AP-3546 (Feb. 5, 2007) at 11 (selecting a dry scrubber as BACT based, in part, on the 

“negative environmental impact” of the higher water use associated with the wet scrubber); cf. In re Kawaihae 

Cogeneration Project, 7 E.A.D. at 114-119 (upholding permitting decision in which the permitting authority 

considered the environmental impacts of ammonia used for SCR technology but found the increase in ammonia 

emissions were not significant enough to warrant use of less stringent NOx control technology) 

100 1990 Workshop Manual at B.8-9. See also Alaska Dept. of Environmental Conservation v. EPA, 540 U.S. 461, 

485-495 (2004) (finding EPA has the authority to review state BACT decisions to determine whether they complied 

with the CAA and upholding EPA’s right to issue stop construction orders upon finding a state permitting 

authority’s BACT determination was unreasonable). 

101 Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air 

Act; Final Rule, 74 FR 66496, December 15, 2009. 
42 

water resources, sea level rise and coastal areas, energy, infrastructure, and settlements, and 

ecosystems and wildlife. The potentially serious adverse impacts of extreme events such as 

wildfires, flooding, drought and extreme weather conditions also supported EPA’s finding. 

The energy, environmental, and economic impacts discussed in the section above should 

be considered for each GHG control technology when conducting a top-down analysis. In 

conducting the energy, environmental and economic impacts analysis, permitting authorities 

have “a great deal of discretion” in deciding the specific form of the BACT analysis and the 

weight to be given to the particular impacts under consideration.102 EPA and other permitting 

authorities have most often used this analysis to eliminate more stringent control technologies 

with significant or unusual effects that are unacceptable in favor of the less stringent 

technologies with more acceptable collateral environmental effects. However, EPA has also 

interpreted the BACT requirements to allow for a more stringent technology to remain in 

consideration as BACT if the collateral environmental benefits of choosing such a technology 

outweigh the economic or energy costs of that selection.103 In other words, the permitting 

authority is not limited to evaluating the impacts of only the “top” or most effective technology 

but can assess the impacts of all technologies under consideration.104 The same principle applies 

when assessing technologies for controlling GHGs. 

When conducting a BACT analysis for GHGs, the environmental impact analysis should 

continue to concentrate on impacts other than the direct impacts due to emissions of the 

regulated pollutant in question. Where GHG control strategies affect emissions of other 

regulated pollutants, applicants and permitting authorities should consider the potential trade-offs 

of selecting particular GHG control strategies. Likewise, when conducting a BACT analysis for 

other regulated NSR pollutants, applicants and permitting authorities should take care to consider 

how the control strategies under consideration may affect GHG emissions. For example, 

controlling volatile organic compound (VOC) emissions with a catalytic oxidation system 

creates GHG emissions in the form of CO2. Permitting authorities have flexibility when 

evaluating the trade-offs associated with decreasing one pollutant at the cost of increasing 

another, and the specific considerations made will depend on the facts of the specific permit at 

issue. For options that involve improvements in the energy efficiency of a source, EPA does not 

expect there to be significant trade-offs in emissions of regulated pollutants since energy 

efficiency improvements should generally reduce emissions of all pollutants resulting from 

combustion processes. 

When weighing any trade-offs between emissions of GHGs and emissions of other 

regulated NSR pollutants, EPA recommends that permitting authorities focus on the relative 

levels of emissions rather than endpoint impacts. As a general matter, GHG emissions contribute 

to global warming and other climate changes that result in impacts on the environment and 

society. However, due to the global scope of the problem, climate change modeling and 

evaluations of risks and impacts of GHG emissions currently is typically conducted for changes 

in emissions orders of magnitude larger than the emissions from individual projects that might be 

analyzed in PSD permit reviews. Quantifying these exact impacts attributable to the specific 

 

102 In re Hillman Power, 10 E.A.D. at 684. 103 In the Matter of North County Resource Recovery Assoc., 2 E.A.D. at 230-31. 104 In re Knauf Fiber Glass, 8 E.A.D. at 131 n. 15. 
43 

GHG source obtaining a permit in specific places is not currently possible with climate change 

modeling. Given these considerations, an assessment of the potential increase or decrease in the 

overall level of GHG emissions from a source would serve as the more appropriate and credible 

metric for assessing the relative environmental impact of a given control strategy. Thus, when 

considering the trade-offs between the environmental impacts of a particular level of GHG 

reduction and a collateral increase in another regulated NSR pollutant, rather than attempting to 

determine or characterize specific environmental impacts at particular locations, EPA 

recommends that permitting authorities focus on the amount of GHG emission reductions that 

may be gained or lost by employing a particular control strategy and how that compares to the 

level of collateral increase for other regulated NSR pollutants. 

In determining how to value or weigh any trade-offs in emissions for regulated pollutants 

(including GHGs), permitting authorities should continue to focus on “significant or unusual 

environmental impacts that have the potential to affect the selection or elimination of a control 

alternative.”105 Relatively small collateral increases of another pollutant need not be of concern, 

unless even that small increase would be significant, such as a situation where an area is close to 

exceeding a NAAQS or PSD increment and the additional increase could push the area into 

nonattainment. Thus, to assess the significance of an emissions increase or decrease, a 

permitting authority should give some consideration to the impacts of a given amount of 

emissions. However, permitting authorities need not consider every possible environmental 

endpoint impact of every conceivable technology. The top-down BACT process calls for 

evaluating only those control alternatives that remain under consideration at BACT Step 4 of the 

analysis. Thus, when a trade-off is present, permitting authorities may limit their consideration 

of environmental impacts to only to those control options in which the comparison of GHG 

emissions to other regulated NSR pollutants might actually lead to a different selection of BACT 

for that facility. 

With respect to the evaluation of the economic impacts of GHG control strategies, it may 

be appropriate in some cases to assess the cost effectiveness of a control option in a less detailed 

quantitative (or even qualitative) manner. For instance, when evaluating the cost effectiveness of 

CCS as a GHG control option, if the cost of building a new pipeline to transport the CO2 is 

extraordinarily high and by itself would be considered cost infeasible, it would not be necessary 

for the applicant to obtain a vendor quote and evaluate the cost effectiveness of a CO2 capture 

system. As with all evaluations of economics, a permitting authority should explain its decisions 

in a well-documented permitting record. 

EPA recognizes that at present CCS is an expensive technology, largely because of the 

costs associated with CO2 capture and compression, and these costs will generally make the price 

of electricity from power plants with CCS uncompetitive compared to electricity from plants 

with other GHG controls. Even if not eliminated in Step 2 of the BACT analysis, on the basis of 

the current costs of CCS, we expect that CCS will often be eliminated from consideration in 

Step 4 of the BACT analysis, even in some cases where underground storage of the captured 

CO2 near the power plant is feasible. However, there may be cases at present where the 

economics of CCS are more favorable (for example, where the captured CO2 could be readily 

sold for enhanced oil recovery), making CCS a more viable option under Step 4. In addition, as 

 

105 In re Hillman Power, 10 E.A.D. at 684. 
44 

a result of the ongoing research and development described in the Interagency Task Force Report 

noted above, CCS may become less costly and warrant greater consideration in Step 4 of the 

BACT analysis in the future. 

As in the past for criteria pollutant BACT determinations, the final decision regarding the 

reasonableness of calculated cost effectiveness values will be made by the permitting authority. 

This decision is typically made by considering previous regulatory and permitting decisions for 

similar sources. As noted above, to justify elimination of a control option on economic grounds, 

the permit applicant should demonstrate that the costs of pollutant removal for the particular 

option are disproportionately high. However, given that there is little history of BACT analyses 

for GHG at this time, there is not a wealth of GHG cost effectiveness data from prior permitting 

actions for a permitting authority to review and rely upon when determining what cost level is 

considered acceptable for GHG BACT. As the permitting of sources of GHG progresses and 

more experience is gained, additional data to determine what is cost effective in the context of 

individual permitting actions will become known and should be included in the RBLC. We note, 

however, that when looking at pollutants historically regulated under the PSD Program, such as 

criteria pollutants, the cost effectiveness of a control device is based on a significantly lower 

volume of emissions than the amount of emissions that are emitted by most sources of GHGs. 

For example, a new boiler that is subject to the NSPS and emits 250 TPY of NOX will emit well 

above 100,000 TPY of CO2e. As a result, even taking account of the current limited data and 

consequent uncertainty concerning the costs of GHG BACT, it is reasonable to anticipate that the 

cost effectiveness numbers (in $/ton of CO2e) for the control of GHGs will be significantly lower 

than those of the cost effectiveness values for controls of criteria pollutants that have evolved 

over time.106 

 

With respect to energy impacts in a BACT analysis for GHGs, the relative energy 

demands of the options under consideration for reducing emissions from the facility obtaining a 

permit should be considered when weighing options for reducing direct emissions of GHGs in 

Step 4 of the analysis, regardless of the location where the thermal or electrical energy for the 

facility is produced. This analysis should include an assessment of how particular control 

options for GHGs may impact the amount of energy that must be produced at an offsite location 

to support the operation of the facility obtaining the permit. Given the potential emissions from 

generation of electricity, such impacts may also be considered in the context of environmental 

impacts.107 

Permitting authorities also have flexibility when evaluating the trade-offs between 

energy, environmental, and economic impacts. In selecting a technology for GHG control, a 

permitting authority may find that while a control option with high overall efficiency has higher 

economic costs, those costs are outweighed by the overall reduction of emissions of all pollutants 

that comes from that efficiency. There are no “right” answers to these permitting decisions that 

can be described in this general guidance, because permitting authorities have a wide range of 

 

106 For consistency purposes, cost effectiveness for GHG control options should be based on dollars per ton of CO2e 

removed, rather than total mass or mass for the individual GHGs.

107 As discussed above in the section on Step 1, energy efficiency improvements that only function to reduce the 

secondary emissions associated with offsite combustion to produce energy at another location should not be 

considered as options in the BACT analysis under existing EPA interpretations of its regulations. 
45 

discretion in their consideration of the various direct and indirect economic, energy, and 

environmental impacts that might be informative to the top-down BACT analysis for GHG 

emissions, as well as the BACT determinations for other pollutants. Given the case-by-case 

nature of the BACT analysis and the importance of considering impacts on the local environment 

and community (e.g., job loss and the potential movement of production overseas), EPA still 

believes this flexibility provided for deciding how best to weigh the trade-offs associated with a 

particular emissions control option continues to be appropriate when evaluating BACT for 

GHGs. The exact scope and detail of that consideration – including the final decision regarding 

various trade-offs that may arise in a permitting decision – is dependent on many factors, 

including the specific facts of the proposed facility, local interests and concerns, and the nature 

of issues raised in public comments. Accordingly, permitting authorities must ensure that their 

impacts analysis fully considers the relevant facts and concerns for the facility at issue and that 

the support for the environmental, economic, and energy choices made during the impacts 

analysis of the BACT determination is well-documented in the permit record. In so doing, we 

encourage permitting authorities to use their discretion to consider the full range of impacts from 

the various controls that could result in facilities that are energy efficient and that lower the 

overall impact of the GHG emissions from those facilities, while maintaining relatively high 

levels of controls of other pollutants. 

F. BACT Step 5 – Selecting BACT 

General Concepts

In Step 5 of the BACT determination process, the most effective control option not 

eliminated in Step 4 should be selected as BACT for the pollutant and emissions unit under 

review and included in the permit. During Step 3, permitting authorities often compare 

technologies or control alternatives that have a range of potential effectiveness for reducing the 

pollutant emissions at issue, and thus they must identify an expected emissions reduction range 

for each technology. In setting the BACT limit in Step 5, the permitting authority should look at 

the range of performance identified previously and determine a specific limit to include in the 

final permit. In determining the appropriate limit, the permitting authority can consider a range 

of factors, including the ability of the control option to consistently achieve a certain emissions 

rate, available data on past performance of the selected technology, and special circumstances at 

the specific source under review which might affect the range of performance.108 In setting 

BACT limits, permitting authorities have the discretion to select limits that do not necessarily 

reflect the highest possible control efficiencies but that will allow compliance on a consistent 

basis, and thus may consider safety factors unique to the particular circumstances of the 

technology and facility at issue in setting the limits.109 EPA has also recognized that in some 

circumstances, it may be acceptable to establish BACT limits that can be adjusted or optimized 

as the performance of a technology becomes clearer after a period of operation.110

 

108 In re Prairie State Generating Company, 13 E.A.D. at 67-71. 

109 In re Prairie State Generating Company, 13 E.A.D. at 71, 73 110 In re AES Puerto Rico, L.P., 8 E.A.D. 324, 348-50 (EAB 1999), In re Hadson Power 14-Buena Vista, 4 E.A.D. 

258, 291 (EAB 1992).
46 

The permitting authority is also responsible for defining the form of the BACT limits, 

and making them enforceable as a practical matter.111 In determining the form of the limit, the 

permitting authority should consider issues such as averaging times and units of measurement. 

For example, a final permit may include a limit based on pounds of emissions on a 24-hour 

rolling average or a limit representing a percentage of pollutant per weight allowed in the fuel. 

When making sure the limit is practically enforceable, the permitting authority must include 

information regarding the methods that will be used for determining compliance with the limits 

(such as operational parameters, timing, testing methods, etc.) and ensure that there is no 

ambiguity in the permit terms themselves.112

Finally, the permitting authority bears the responsibility in Step 5 to fully justify the 

BACT decision in the permit record. Regardless of the control level proposed by the applicant 

as BACT, the ultimate determination of BACT is made by the permitting authority after public 

review is complete. The applicant’s role is primarily to provide information on the various 

control options and, when it proposes a less stringent control option, provide a detailed rationale 

and supporting documentation for eliminating the more stringent options. It is the responsibility 

of the permitting authority to review the documentation and rationale presented in order to: (1) 

ensure that the applicant has addressed all of the most effective control options that could be 

applied and; (2) determine that the applicant has adequately demonstrated that energy, 

environmental, or economic impacts justify any proposal to eliminate the more effective control 

options. Where the permitting authority does not accept the basis for the proposed elimination of 

a control option, the agency may inform the applicant of the need for more information regarding 

the control option. However, the BACT selection essentially should default to the highest level 

of control for which the applicant could not adequately justify its elimination based on energy, 

environmental and economic impacts. If the applicant is unable to provide to the permitting 

authority’s satisfaction an adequate demonstration for one or more control alternatives, the 

permitting authority should proceed to establish BACT and prepare a draft permit based on the 

most effective control option for which an adequate justification for rejection was not provided. 

GHG-Specific Considerations

We expect many permits issued after January 2, 2011, to initially place more of an 

emphasis on energy efficiency, given the role it plays in affecting emissions of GHGs. For 

energy producing sources, as noted above, one way to incorporate the energy efficiency of a 

process unit into the BACT analysis is to compare control effectiveness in BACT Step 3 based 

on output-based emissions of each of the control options. Even in cases where another metric is 

used in Step 3 to compare options, once an option is selected in Step 5, permitting authorities 

may consider converting the BACT emissions limit to a net output basis for the permitted 

emissions limit. EPA encourages permitting authorities to consider establishing an output-based 

BACT emissions limit, or a combination of output- and input-based limits, wherever feasible and 

appropriate to ensure that BACT is complied with at all levels of operation. Although developed 

as part of a voluntary program, EPA believes the draft handbook entitled Output-Based 

Regulations: A Handbook for Air Regulators (August 2004) may provide relevant information to 

 

111 See generally EPA Guidance on Limiting Potential to Emit (PTE) in New Source Permitting (June 13, 1989), 

available at http://www.epa.gov/reg3artd/permitting/t5_epa_guidance.htm. 112 In re Prairie State Generating Company, 13 E.A.D. at 83, 120. 
47 

assist permitting authorities in establishing limits based on output.113 Furthermore, since the 

environmental concern with GHGs is with their cumulative impact in the environment, metrics 

should focus on longer-term averages (e.g., 30- or 365-day rolling average) rather than shortterm averages (e.g., 3- or 24-hr rolling average). 

In addition to a permit containing specific numerical emissions limits established in a 

BACT analysis, a permit can also include conditions requiring the use of a work practice such as 

an Environmental Management System (EMS) focused on energy efficiency as part of that 

BACT analysis. The ENERGY STAR program provides useful guidance on the elements of an 

energy management program. The inclusion of such a requirement would be appropriate where 

it is technically impractical to measure emissions and/or energy use from all of the equipment 

and processes of the plant and apply an output-based standard to each of them. For example, a 

candidate might be a factory with many different pieces of equipment and processes that use 

energy. In addition to a BACT emissions limit on the boiler providing energy, the permit could 

also lay out a requirement to implement an EMS along with a requirement that all suggested 

actions that result in net savings have to be implemented. Consequently, the plant will operate in 

the most efficient manner through gradual achievable improvements. However, design, 

equipment, or work practice standards may not be used in lieu of a numerical emissions 

limitation(s) unless there is a demonstration in the record that the criteria for applying such a 

standard are satisfied. 

 

113 Output-Based Regulations: A Handbook for Air Regulators (Draft Final Report) (August 2004), available at

http://www.epa.gov/chp/documents/obr_final_9105.pdf. 
48 

IV. Other PSD Requirements 

General Concepts

The PSD requirements include several provisions requiring new and modified major 

stationary sources to conduct air quality analyses that may involve air quality modeling and 

ambient monitoring. The applicant must demonstrate that the emissions of any regulated NSR 

pollutant do not cause or contribute to a violation of any NAAQS or PSD increments.114 Several 

months of ambient air quality data must also be collected in some circumstances to support this 

analysis.115 In addition, as part of the “additional impacts analysis,” the applicant must provide 

an analysis of the air quality impact of the source or modification, including an analysis of the 

impairment to visibility, soils, and vegetation (but not vegetation with no significant commercial 

or recreational value) that would occur as a result of the source or modification and general 

commercial, residential, industrial, and other growth associated with the source or 

modification.116 Under the federal PSD rules, this analysis may also include monitoring of 

visibility in any Federal Class I area near the source or modification “for such purposes and by 

such means as the Administrator deems necessary and appropriate.”117 A demonstration must be 

made that emissions will not cause or contribute to a violation of any Class I increment and will 

not have an adverse impact on any air quality related value (AQRV), as defined by the Federal 

Land Manager, in such area.118 Under PSD, if a source’s proposed project may impact a Class I 

area, the Federal Land Manager must be notified so this office may fulfill its responsibility for 

evaluating a source’s projected impact on the AQRVs and recommending either approval or 

disapproval of the source’s permit application based on anticipated impacts. 

GHG-Specific Considerations

The Tailoring Rule includes the following statement with respect to these requirements: 

“There are currently no NAAQS or PSD increments established for GHGs, and therefore 

these PSD requirements would not apply for GHGs, even when PSD is triggered for 

GHGs. However, if PSD is triggered for a GHG emissions source, all regulated NSR 

pollutants which the new source emits in significant amounts would be subject to PSD 

requirements. Therefore, if a facility triggers review for regulated NSR pollutants that 

are non-GHG pollutants for which there are established NAAQS or increments, the air 

quality, additional impacts, and Class I requirements would apply to those pollutants.”119 

Since there are no NAAQS or PSD increments for GHGs,120 the requirements in sections 

52.21(k) and 51.166(k) of EPA’s regulations to demonstrate that a source does not cause or 

 

114 42 USC 7475(a)(3); 40 CFR 52.21(k); 40 CFR 51.166(k). 115 40 CFR 52.21(m); 40 CFR 51.166(m); 40 CFR 52.21(i)(5); 40 CFR 51.166(i)(5). 116 40 CFR 52.21(o); 40 CFR 51.166(o). 117 40 CFR 52.21(o)(3). 118 40 CFR 52.21(p); 40 CFR 51.166(p). 

119 75 FR at 31520. 120 In addition, GHGS have not been designated as a precursor for any criteria pollutant under section 302(g) of the 

Clean Air Act or in EPA’s PSD rules. 
49 

contribute to a violation of the NAAQS is not applicable to GHGs. Thus, we do not recommend 

that PSD applicants be required to model or conduct ambient monitoring for CO2 or GHGs. 

Monitoring for GHGs is not required because EPA regulations provide an exemption in 

sections 52.21(i)(5)(iii) and 51.166(i)(5)(iii) for pollutants that are not listed in the appropriate 

section of the regulations, and GHGs are not currently included in that list. However, it should 

be noted that sections 52.21(m)(1)(ii) and 51.166(m)(1)(ii) of EPA’s regulations apply to 

pollutants for which no NAAQS exists. These provisions call for collection of air quality 

monitoring data “as the Administrator determines is necessary to assess ambient air quality for 

that pollutant in any (or the) area that the emissions of that pollutant would affect.” In the case 

of GHGs, the exemption in sections 52.21(i)(5)(iii) and 51.166(i)(5)(iii) is controlling since 

GHGs are not currently listed in the relevant paragraph. Nevertheless, EPA does not consider it 

necessary for applicants to gather monitoring data to assess ambient air quality for GHGs under 

section 52.21(m)(1)(ii), section 51.166(m)(1)(ii), or similar provisions that may be contained in 

state rules based on EPA’s rules. GHGs do not affect “ambient air quality” in the sense that EPA 

intended when these parts of EPA’s rules were initially drafted. Considering the nature of GHG 

emissions and their global impacts, EPA does not believe it is practical or appropriate to expect 

permitting authorities to collect monitoring data for purpose of assessing ambient air impacts of 

GHGs. 

Furthermore, consistent with EPA’s statement in the Tailoring Rule, EPA believes it is 

not necessary for applicants or permitting authorities to assess impacts from GHGs in the context 

of the additional impacts analysis or Class I area provisions of the PSD regulations for the 

following policy reasons. Although it is clear that GHG emissions contribute to global warming 

and other climate changes that result in impacts on the environment, including impacts on Class I 

areas and soils and vegetation due to the global scope of the problem, climate change modeling 

and evaluations of risks and impacts of GHG emissions is typically conducted for changes in 

emissions orders of magnitude larger than the emissions from individual projects that might be 

analyzed in PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG 

source obtaining a permit in specific places and points would not be possible with current 

climate change modeling. Given these considerations, GHG emissions would serve as the more 

appropriate and credible proxy for assessing the impact of a given facility. Thus, EPA believes 

that the most practical way to address the considerations reflected in the Class I area and 

additional impacts analysis is to focus on reducing GHG emissions to the maximum extent. In 

light of these analytical challenges, compliance with the BACT analysis is the best technique that 

can be employed at present to satisfy the additional impacts analysis and Class I area 

requirements of the rules related to GHGs. 

Applicants and permitting authorities should note that, while we are not recommending 

these analyses for GHG emissions, the incorporation of GHGs into the PSD program does not 

change the need for sources and permitting authorities to address these requirements for other 

regulated NSR pollutants. Accordingly, if PSD is triggered for a GHG emissions source, all 

regulated NSR pollutants which the source emits in significant amounts would be subject to 

these other PSD requirements. Therefore, if a facility triggers review for regulated NSR 

pollutants that are non-GHG pollutants for which there are established NAAQS or increments, 
50 

the air quality, additional impacts, and Class I requirements must be satisfied for those pollutants 

and the applicant and permitting authority are required to conduct the necessary analysis. 
51 

V. Title V Considerations 

A. General Concepts and Title V Requirements 

Under the CAA, major sources (and certain other sources) must apply for, and operate in 

accordance with, an operating permit that contains conditions necessary to assure compliance 

with all CAA requirements applicable to the source.121 The operating permit requirements under 

title V are intended to improve sources’ compliance with other CAA requirements. Title V 

generally does not add new pollution control requirements, but it does require that each permit 

contain all air quality control requirements or “applicable requirements” required under the CAA 

(e.g., NSPS and SIP requirements, including PSD), and it requires that certain procedural 

requirements be followed, especially with respect to compliance with these requirements. 

“Applicable requirements” for title V purposes include stationary source requirements, but do 

not include mobile source requirements. Procedural requirements include providing review of 

permits by EPA, states, and the public, requiring permit holders to track, report, and annually 

certify their compliance status with respect to their permit requirements, and otherwise ensuring 

that permits contain conditions to assure compliance with applicable requirements. 

This section discusses title V requirements as they pertain to GHGs. These include the 

applicability requirement for title V permitting due to GHG emissions (e.g., when a source will 

become subject to title V for the first time due to its GHG emissions), and requirements for 

permit applications and permit content. Under Step 1 of the Tailoring Rule, no sources become 

major sources requiring a title V permit solely as a result of GHG emissions. Beginning in 

Step 2 of the Tailoring Rule, a stationary source may be a major source subject to title V 

permitting requirements solely on the basis of its GHG emissions, provided the source exceeds 

the thresholds established in the Tailoring Rule (discussed below). 

 Under both Step 1 and Step 2 of the Tailoring Rule, sources and permitting authorities 

need to meet the generally applicable title V application and permitting requirements as they 

pertain to GHG applicable requirements established under other CAA programs (e.g., the PSD 

program). The source’s operating permit application generally must contain emissions-related 

information for: (1) all pollutants for which the source is major (see the definition of “major 

stationary source” in 40 CFR 70.2, which incorporates the requirements that a pollutant be 

subject to regulation, and an emissions threshold for GHG); and (2) all emissions of “regulated 

air pollutants” (which, under 40 CFR 70.2, includes criteria pollutants, VOCs, and pollutants 

regulated under CAA Section 111 or 112 standards, but does not currently include GHGs). In 

addition, the permitting authority shall require sources to provide additional emissions 

information sufficient to verify which requirements are applicable to the source and other 

specific information that may be necessary to implement and enforce other applicable 

requirements of the CAA or to determine the applicability of such requirements.122 

 

121 Details of the title V program are addressed in rules promulgated by EPA – 40 CFR part 70 addresses programs 

implemented by state and local agencies and tribes, and 40 CFR part 71 addresses programs generally implemented 

by EPA. 

122 40 CFR 70.5. 
52 

Since the Tailoring Rule establishes a phased applicability approach under title V, the 

pertinent requirements vary somewhat between the first two steps of the Tailoring Rule. The 

following is a summary of the key requirements and some general examples with respect to 

title V applicability and title V permitting requirements (including permit application and permit 

content) with respect to GHGs under Steps 1 and 2 of the Tailoring Rule. 

 

B. Title V Applicability Requirements and GHGs 

Applicability requirements for title V permitting as they apply to GHG emissions are 

summarized in the following table and explained in more detail in subsections B.1 and B.2 

following the table: 

Table V-A. Summary of Title V Applicability Criteria for Sources of GHGs 

January 2, 2011, to June 30, 2011 

(Step 1 of the Tailoring Rule) 

On or after July 1, 2011 

(Step 2 of the Tailoring Rule) 

No sources are subject to title V permitting 

solely as a result of their emissions of GHGs. 

(Thus, no new title V sources come into the title V 

program as a result of GHG emissions.) 

[Note, however, that for sources subject to, or that 

become newly subject to, title V for non-GHG 

pollutants (i.e., “anyway sources”), sources and 

permitting authorities need to meet the generally 

applicable title V application and permitting 

requirements as necessary to address GHG 

applicable requirements established under other 

CAA programs.]* 

 

The following sources are subject to title V 

permitting requirements as a result of their GHG 

emissions: 

• Existing or newly constructed GHG 

emission sources (not already subject to 

title V) that emit or have a PTE equal to 

or greater than: 

o 100,000 TPY CO2e; and

o 100 TPY GHGs mass basis 

 

[Note that in Step 2, as under Step 1, for all 

“anyway sources” subject to title V, sources and 

permitting authorities need to meet the generally 

applicable title V application and permitting 

requirements as necessary to address GHG 

applicable requirements established under other 

CAA programs (e.g., the PSD program)] * 

* It is expected, at least at the outset, that this will consist primarily of meeting application and permitting 

requirements necessary to assure compliance with PSD permitting requirements for GHGs. See accompanying 

text in Section C. Permitting Requirements for further discussion and examples.

1. Applicability under Tailoring Rule Step 1 

 Under Step 1, no sources are subject to title V permitting solely as a result of their 

emissions of GHGs. Thus no new title V sources come into the title V program as a result of 

GHG emissions. However, sources otherwise required to have title V permits for non-GHG 

pollutants (i.e., “anyway” title V sources) will be required to address GHGs as part of their 

title V permitting to the extent necessary to assure compliance with GHG applicable 

requirements established under other CAA programs. Section C below describes how sources 

and permitting authorities should consider addressing GHG requirements in permitting actions. 
53 

2. Applicability under Tailoring Rule Step 2 

 Beginning in Step 2 of the Tailoring Rule, a stationary source may be a major source 

subject to title V permitting requirements solely on the basis of its GHG emissions, provided the 

source exceeds the thresholds established in the Tailoring Rule. GHG emission sources that emit 

or have the PTE at least 100,000 TPY CO2e, and also emit or have the PTE 100 TPY of GHGs 

on a mass basis will be required to obtain a title V permit if they do not already have one. It is 

important to note that the requirement to obtain a title V permit will not, by itself, result in the 

triggering of additional substantive requirements for control of GHG. Rather, these new title V 

permits will simply incorporate whatever applicable CAA requirements, if any, apply to the 

source being permitted. 

Both of the following conditions need to be met in order for title V to apply under Step 2 of the 

Tailoring Rule to a GHG emission source: 

(1) An existing or newly constructed source emits or has the PTE GHGs in amounts that 

equal or exceed 100 TPY calculated as the sum of the six well-mixed GHGs on a mass 

basis (no GWPs applied). 

(2) An existing or newly constructed source emits or has the PTE GHGs in amounts that 

equal or exceed 100,000 TPY calculated as the sum of the six well-mixed GHGs on a 

CO2e basis (GWPs applied). 

 In Step 2, as under Step 1, for all sources otherwise subject to title V for non-GHG 

pollutants (i.e., anyway sources), sources and permitting authorities will need to meet the 

generally applicable title V application and permitting requirements as they pertain to GHG 

applicable requirements established under other CAA programs (e.g., the PSD program). See 

Section C below for further discussion of permitting requirements. 

C. Permitting Requirements 

Under both Steps 1 and 2 of the Tailoring Rule, as with other applicable requirements 

related to non-GHG pollutants, any applicable requirement for GHGs must be addressed in the 

title V permit (i.e., the permit must contain conditions necessary to assure compliance with 

applicable requirements for GHGs). EPA anticipates that the initial applicable requirements for 

GHGs will be in the form of GHG control requirements resulting from PSD permitting actions. 

It is important to note that GHG reporting requirements for sources established under EPA’s 

final rule for the mandatory reporting of GHGs (40 CFR Part 98: Mandatory Greenhouse Gas 

Reporting, hereafter referred to as the “GHG reporting rule”) are currently not included in the 

definition of applicable requirement in 40 CFR 70.2 and 71.2. Although the requirements 

contained in the GHG reporting rule currently are not considered applicable requirements under 

the title V regulations, the source is not relieved from the requirement to comply with the GHG 

reporting rule separately from compliance with their title V operating permit. It is the 

responsibility of each source to determine the applicability of the GHG reporting rule and to 

comply with it, as necessary. However, since the requirements of the GHG reporting rule are not 
54 

considered applicable requirements under title V, they do not need to be included in the title V 

permit. 

 Under both Steps 1 and 2 of the Tailoring Rule, sources will need to include in their 

title V permit applications, among other things: citation and descriptions of any applicable 

requirements for GHGs (e.g., GHG BACT requirements resulting from a PSD review process), 

information pertaining to any associated monitoring and other compliance activities, and any 

other information considered necessary to determine the applicability of, and impose, any 

applicable requirements for GHGs. This is the same application information required under 

title V for applicable requirements pertaining to conventional pollutants. 

 As a general matter, all title V permits issued by permitting authorities must contain, 

among other things, emissions limitations and standards necessary to assure compliance with all 

applicable requirements for GHGs, all monitoring and testing required by applicable 

requirements for GHGs, and additional compliance certification, testing, monitoring, reporting, 

and recordkeeping requirements sufficient to assure compliance with GHG-related terms and 

conditions of the permit. Permitting authorities will also need to request from sources any 

information deemed necessary to determine or impose GHG applicable requirements. 

 It is possible that some sources will need to address GHG-related information in their 

applications even if they will ultimately not have any GHG-specific applicable requirements 

(such as a PSD-related BACT requirement for GHGs) included in their permit. This is because, 

as noted above, permitting authorities would need to request information related to identifying 

GHG emission sources and other information if they determine such information is necessary to 

determine applicable requirements. Following is an explanation of the basis for requesting this 

information and some examples of these types of scenarios under Steps 1 and 2 of the Tailoring 

Rule. 

Under Step 1 of the Tailoring Rule, no source can be major for purposes of title V solely 

on the basis of its GHG emissions, so the requirement set forth in 40 CFR 70.5 for the source to 

provide emissions-related information for pollutants for which the source is major does not 

apply. In addition, as GHGs are not currently considered regulated air pollutants under the 

title V regulations, the requirement to provide emissions-related information for regulated air 

pollutants does not apply. However, consistent with the requirements set forth in 40 CFR 70.5, 

permitting authorities will need to ask for any emissions or other information they deem 

necessary to determine applicability of, or impose, a CAA requirement.123 Therefore, during 

Step 1 of the Tailoring Rule, any source going through a title V permitting action (i.e., applying 

for a title V operating permit or undergoing a permit revision, reopening or renewal) would need 

to provide GHG emissions or other information if a permitting authority needs the information to 

determine applicability of a CAA requirement (e.g., PSD).124 The following is an example of 

where this request for information might occur: 

 

123 Note that the phrase “subject to regulation” in the definition of major source in the title V regulations affects 

when a source may be a major source subject to title V as a result of emissions of a pollutant. If a source is already 

subject to title V, its application must include any information considered necessary to determine or impose a GHG 

applicable requirement – this is true even before GHGs become “subject to regulation” for major sources purposes. 124 40 CFR 70.5(c)(5). 
55 

An existing title V source is making a physical change that triggers PSD for NOX. This 

change will result in additional applicable requirements for NOX emissions controls but, 

according to the applicant, does not trigger BACT review for GHGs. In this case, as part 

of its analysis of the application for permit revision under its title V program, the 

permitting authority may determine it necessary to verify that the project did not trigger 

BACT requirements for GHG emissions, and therefore may need to request the applicant 

to submit GHG emissions information related to the project sufficient for the permitting 

authority to determine that PSD did not apply for GHG emissions from the project. This 

information could include such items as identification and descriptions of any GHG 

emission units and estimates of GHG emissions associated with the modification project. 

Under Step 2 of the Tailoring Rule, beginning July 1, 2011, a stationary source may be 

subject to title V permitting requirements solely on the basis of its GHG emissions, provided the 

source is equal to or greater than the 100,000 TPY CO2e subject to regulation threshold (as well 

as the 100 TPY major source mass-based threshold) on a PTE basis. As noted above, sources 

generally must provide information regarding all emissions of pollutants for which they are 

major. In many cases, particularly where the source has no applicable requirements for GHGs, 

emissions descriptions (instead of estimates) may be sufficient. For sources subject to the GHG 

reporting rule, the emissions description requirements in the title V rules will generally be 

satisfied by information provided under the reporting rule. Further elaboration on the 

requirement for emissions data is provided in the White Paper 1 guidance on title V.125 The 

following is an example of a permitting scenario under title V during Step 2 of the Tailoring 

Rule: 

As of July 1, 2011, an existing facility not previously subject to title V has a GHG PTE 

over 100,000 TPY CO2e and over 100 TPY on a mass basis. Therefore, according to the 

Tailoring Rule applicability criteria for GHG sources, this source becomes subject to 

title V solely based on its GHG emissions as of July 1, 2011. First, it will need to apply 

for a title V permit within 12 months of July 1, 2011 (unless an earlier date has been 

established by the permitting authority). Second, assuming that the facility does not have 

any applicable requirements for GHG emissions (such as a GHG BACT requirement 

resulting from a PSD review), the permitting authority may deem it sufficient that the 

facility simply provide a description of the GHG emission sources at the facility that 

cause the facility to exceed the applicability criteria threshold for GHGs under title V, 

rather than a detailed quantification of its GHG emission sources. Lastly, the source 

would also need to provide other emissions information as necessary for non-GHG 

emission sources (e.g., information on emissions of regulated air pollutants, information 

for fee calculation, etc.) 

It is also important to note that sources that are newly subject to title V solely as a result 

of their GHG emissions will also need to provide in their title V permit applications required 

information regarding all other applicable requirements that apply to it under the Act (e.g., SIP 

 

125 Office of Air Quality Planning and Standards, White Paper for Streamlined Development of Part 70 Permit 

Applications (July 10, 1995). 
56 

regulations). The following is an example of this permitting scenario under Step 2 of the 

Tailoring Rule: 

A facility becomes subject to title V permitting requirements solely on the basis of its 

GHG emissions on July 2, 2011, and, therefore, must apply for a title V permit. The 

facility has an applicable requirement, such as a SIP requirement imposing an opacity 

limit on fuel-burning equipment that lacks periodic monitoring and monitoring sufficient 

to assure compliance. Even if the newly subject title V source did not have any specific 

GHG-related requirements to include in the title V permit, under this scenario, the 

facility must propose appropriate monitoring, recordkeeping and reporting (MRR) to 

assure compliance with the opacity standard in its permit application and the permitting 

authority must add appropriate MRR to the operating permit for that opacity standard 

(which may be the MRR proposed by the facility or other requirements) under the 

authority of the Act. 

D. Title V Fees 

EPA rules currently do not require sources to pay any title V fees based on GHG 

emissions or to otherwise quantify GHG emissions strictly for title V fee purposes. However, 

throughout Steps 1 and 2 of the Tailoring Rule, the statutory and regulatory requirement to 

collect fees sufficient to cover all reasonable (direct and indirect) costs required to develop and 

administer title V programs still applies.126 Permitting authorities need to review resource needs 

for GHG-emitting sources and determine if their existing fee structure is adequate. If not, 

permitting authorities would need to raise fees to cover the direct and indirect costs of the 

program or develop alternative approaches. EPA will work with permitting authorities that 

request assistance concerning establishing title V fees related to GHG emissions. 

E. Flexible Permits 

The final Flexible Air Permitting Rule (74 FR 51418), promulgated on October 6, 2009, 

reflects EPA’s policy and rules governing the use of flexible air permits. A flexible air permit 

(FAP) is a title V operating permit that by its design authorizes the source owner to make certain 

types or categories of physical and/or operational changes without further review or approval of 

the individual changes by the permitting authority. Flexible air permits cannot circumvent, 

modify, or contravene any applicable requirement and, instead, by their design must assure 

compliance with each one. Based on our evaluation of State FAP pilots in addition to providing 

greater operational flexibility, FAPs can result in greater environmental protection, lower 

administrative costs, pollution prevention and increased energy efficiency. 

FAP approaches can significantly reduce the administrative resources associated with 

CAA permitting requirements and provide a streamlined path for installing new energy-efficient 

equipment at industrial facilities. While many energy-efficient equipment upgrades may not 

 

126 42 USC 7661a(b)(3)(B); 40 CFR 70.9. 
57 

trigger air permitting requirements, some changes have the potential to trigger permitting actions 

or applicability determination activities. The combination of plantwide emissions limits, 

alternative operating scenarios, and/or advance approvals of categories of operational changes 

can eliminate the need for case-by-case evaluation (under title V and PSD/NSR) for future 

energy-efficient equipment upgrades, thereby reducing time delays, uncertainty, and transaction 

costs in making these changes. In the absence of FAP approaches, air permitting considerations 

may cause a facility to forego or delay energy-efficient equipment upgrades that have potential to 

trigger air permitting requirements. FAP approaches can be used to accommodate these types of 

changes in a streamlined manner that addresses all applicable regulatory requirements up-front. 

EPA encourages permitting authorities and sources to consider FAPs, particularly in 

situations where a source is planning to implement an ongoing program designed to improve 

energy efficiency and reduce GHG over time. 
58 

VI. Appendices 

Note: The regulatory changes implemented in the Tailoring Rule set forth a two-part 

applicability process determining the applicability of PSD to GHGs, which first evaluates the 

sum of the GHG emissions on a CO2e basis in order to determine whether the source’s emissions 

are a regulated NSR pollutant, and, if so, then evaluates the sum of the GHG emissions on a 

mass basis in order to determine if there is a major source or major modification of such 

emissions. However, we noted in the Tailoring Rule preamble that most sources are likely to 

treat the mass-based analysis as an initial screen from a practical standpoint, since they would 

not proceed to calculate emissions on a CO2e basis if they would not trigger PSD or title V on a 

mass basis.127 Accordingly, the examples provided in the attached appendices take a variety of 

approaches for undertaking the required CO2e and mass-based calculations, and permit 

applicants and permitting authorities may use the processes identified in this guidance or another 

process for determining applicability of PSD to GHGs in permits they issue so long as that 

process complies with the relevant statutory and regulatory requirements. 

 

127 75 FR 31514, 31522 (June 3, 2010). 
A-1 

Appendix A. GHG Applicability Flow Chart – New Sources 

 (January 2, 2011, through June 30, 2011) 

4. Determine the new source's potential to emit (PTE) in tons per year 

(TPY) for each of the 6 GHG pollutants (CO2, CH4, N2O, HFCs, PFCs 

and SF6) taking into account enforceable limits. 

Go to 

next 

page 

YES

YES 

NO NO 

START 

GHG emissions are not

subject to PSD as part of 

this permit review. 

Will the permit 

be issued on or 

after January 2, 

2011 but before 

July 1, 2011? 

Is this a new 

stationary source 

subject to PSD for 

a regulated NSR 

pollutant other 

than GHGs? 

NO 

YES

Will the permit 

be issued on or 

after July 1, 

2011? 

See New Source Flow 

Chart in Appendix B 

1. 

2. 

3. 

GHG emissions are not

subject to PSD as part of 

this permit review. 
A-2 

GHG emissions are subject to 

PSD as part of this permit 

review. 

Are the potential 

GHG emissions 

equal to or 

greater than 

75,000 TPY 

5. Calculate the GHG emissions on a CO2 equivalent (CO2e) basis 

using the global warming potential factors applied to the mass of 

each of the 6 GHG pollutants. 

YES 

NO 

6. 

From 

prior 

page 

GHG emissions are not

subject to PSD as part of 

this permit review. 

* The mass-based emission threshold of zero TPY has been 

excluded from this flow chart because any new source that meets 

the 75,000 TPY CO2e requirement would automatically exceed that 

mass based rate. 
B-1 

Appendix B. GHG Applicability Flow Chart – New Sources 

(On or after July 1, 2011) 

2. Determine the new source’s potential to emit (PTE) in tons per year 

(TPY) for each of the 6 GHG pollutants (CO2, CH4, N2O, HFCs, PFCs 

and SF6) taking into account enforceable limits. 

YES

NO 

If earlier, see New Source 

Flow Chart in Appendix A. 

Will the permit 

be issued on or 

after July 1, 

2011? 

1. 

START 

YES 

Go to 

next 

page 

Are the potential 

GHG emissions 

on a CO2e basis 

equal to or 

greater than 

100,000 TPY? 

3. Calculate the GHG emissions on a CO2 equivalent (CO2e) basis 

using the global warming potential factors applied to the mass of each 

of the 6 GHG pollutants. 

4. 

NO Go to 

Element 7 
B-2 

Is this a new 

stationary source 

subject to PSD for a 

regulated NSR 

pollutant other than 

GHGs?

NO 

YES 

NO 

GHG emissions are not

subject to PSD as part of 

this permit review. 

GHG emissions are subject to 

PSD as part of this permit 

review.

Are the potential 

GHG emissions 

equal to or 

greater than 

75,000 TPY 

8. 

* The mass-based emission threshold of zero TPY has been 

excluded from this flow chart because any new source that meets 

the 75,000 TPY CO2e requirement would automatically exceed that 

mass based rate. 

Are the potential 

GHG emissions on a 

mass basis less than 

250 TPY (or 

100 TPY if the new 

source is in a listed 

category)? 

5. Calculate the total GHG emissions on a 

mass basis.

YES 

NO 

7. 

6. 

YES 

GHG emissions are not

subject to PSD as part of 

this permit review. 

GHG emissions are subject to 

PSD as part of this permit 

review. 

From 

prior 

page 
C-1 

Appendix C. GHG Applicability Flow Chart – Existing Sources 

(January 2, 2011, through June 30, 2011) 

 

128 For new units, the past actual emissions are zero. 

129 For new units that are not like-kind replacements, future actual emissions are always the PTE. 

4. Determine the past actual (baseline) emissions in tons per year (TPY) 

for units that are part of the modification for each of the 6 GHG 

pollutants (CO2, CH4, N2O, HFCs, PFCs and SF6).128

5. Determine the future projected actual emissions (or PTE) in TPY for 

units that are part of the modification for each of the 6 GHG 

pollutants.129 

YES

NO 

Go to 

next 

page 

Will the permit 

be issued on or 

after July 1, 

2011? 

Is this modification 

subject to PSD 

permitting for a 

regulated NSR 

pollutant other than 

GHGs? 

NO 

YES

Will the permit 

be issued on or 

after January 2, 

2011 but before 

July 1, 2011? 

See Existing Source 

Flow Chart in 

Appendix D. 

NO 

1. 2.

3.

START 

GHG emissions are not

subject to PSD as part of 

this permit review. 

GHG emissions are not

subject to PSD as part of 

this permit review. 

YES
C-2 

 

 

130 Emission decreases are not considered at this step. 

11. For all units that have an emissions increase, sum the GHG emissions on a CO2e 

basis.130

Go to 

next 

page 

10. For each unit, convert any increase or decrease in emissions of each of the 6 GHG 

pollutants to their CO2 equivalent (CO2e) emissions using the global warming 

potential factors applied to the mass of each of the 6 GHG pollutants and sum them 

for each unit to arrive at one GHG CO2e number for each unit. 

8. For all units that have an emissions increase, sum the GHG emissions on a mass 

basis 

From 

prior 

page 

Is the sum of 

GHG emissions 

increase greater 

than zero TPY? 

9.

YES

NO GHG emissions are not

subject to PSD as part of 

this permit review. 

6. For each unit, determine the increase or decrease in emissions of each of the 6 

GHG pollutants by subtracting past actual emissions from future actual emissions.

7. For each unit, sum any increase or decrease in GHG emissions on a mass basis.
C-3 

 

131 Creditable decreases are only those that have not been relied upon in prior PSD review and will be practically 

enforceable by the time construction begins. 

13. Contemporaneous netting analysis is required. Identify all 

contemporaneous creditable increases and decreases in emissions for each of 

the 6 GHG pollutants on a mass basis.131

Is the sum of GHG 

emissions 

increases equal to 

or greater than 

75,000 TPY? 

From 

prior 

page 

NO 

YES

14. For each creditable activity or event, determine the increase or decrease in 

emissions for each of the 6 GHG pollutants on mass basis.

15. Sum the increases and decreases, including the increases and decreases 

from the proposed modification, for each of the 6 GHG pollutants on a mass 

basis. 

16. Calculate the net GHG emissions on a mass basis. 

Go to 

next 

page 

12.

GHG emissions are not

subject to PSD as part of 

this permit review. 
C-4 

18. Convert any contemporaneous, creditable increase or decrease in 

emissions of each of the 6 GHG pollutants to their CO2e emissions using the 

global warming potential factors applied to the mass of each of the 6 GHG 

pollutants and sum them. 

Are the net GHG 

emissions on a 

CO2e basis equal 

to or greater than 

75,000 TPY 

CO2e? 

Are the net GHG 

emissions on a 

mass basis over 

zero TPY? 

From 

prior 

page 

NO 

YES 

19. Calculate the net GHG emissions on a CO2e basis. 

NO 

17.

20.

GHG emissions are not

subject to PSD as part of 

this permit review. 

GHG emissions are not

subject to PSD as part of 

this permit review. 

GHG emissions are subject to 

PSD as part of this permit 

review. 
D-1 

Appendix D. GHG Applicability Flowchart – Existing Sources 

(On or after July 1, 2011) 

 

 

132 For new units, the past actual emissions are zero. 

3. Determine the potential to emit (PTE) for the existing stationary source, before the 

modification, for each of the 6 GHG pollutants (CO2, CH4, N2O, HFCs, PFCs and SF6). 

Determine the mass based sum. Convert the emissions of GHG pollutants to their CO2e 

emissions, using the global warming potential factors applied to the mass of each of the 6 

GHG pollutants and sum the CO2e emissions.

6. Determine the past actual (baseline) emissions in tons per 

year (TPY) for units that are part of the modification for each of 

the 6 GHG pollutants (CO2, CH4, N2O, HFCs, PFCs and SF6).132

YES

NO 

Is this modification 

subject to PSD 

permitting for a 

regulated NSR 

pollutant other than 

GHGs? 

Will the permit 

be issued on or 

after July 1, 

2011? 

If earlier, see Existing 

Source Flow Chart in 

Appendix C. 

1.

2. 

NO 

YES

NO 

YES

Are the potential 

GHG emissions 

equal or greater than 

both 100,000 TPY 

CO2e and 250 TPY 

(100 TPY if listed) 

on a mass basis? 

4. 

Are GHG emissions 

of the modification 

equal or greater than 

both 100,000 TPY 

CO2e and 250 TPY 

(100 TPY if listed) on 

a mass basis?

5. 

NO 

GHG emissions are subject to 

PSD as part of this permit 

review.

Go to 

next 

page 

YES

GHG emissions are not

subject to PSD as part of 

this permit review. 

START 
D-2 

 

133 For new units that are not like-kind replacements, future actual emissions are always the PTE. 134 Emission decreases are not considered in this step. 

8. For each unit, determine the increase or decrease in mass emissions of 

each of the 6 GHG pollutants by subtracting past actual emissions from future 

actual emissions.133 

13. Sum the GHG emissions on a CO2e basis for all units that have 

an emissions increase.134

From 

prior 

page 

7. For units that are part of the modification, determine the future projected 

actual emissions (or PTE) in TPY for each of the 6 GHG pollutants.

9. For each unit, sum any increase or decrease in GHG emissions on a mass 

basis. 

GHG emissions are not

subject to PSD as part of 

this permit review. 

12. For each unit, convert any increase or decrease in emissions of 

each of the 6 GHG pollutants to their CO2e emissions using the global 

warming potential factors applied to the mass of each of the 6 GHG 

pollutants and sum them for each unit to arrive at one GHG CO2e 

number for each unit. 

10. For all units that have a mass emissions increase, sum the GHG emissions 

on a mass basis.

Is the sum of 

GHG mass 

emissions 

increase over 

zero TPY? 

YES

NO 

11.

Go to 

next 

page 
D-3 

 

135 Creditable decreases are only those that have not been relied upon in prior PSD review and will be practically 

enforceable by the time construction begins. 

15. Contemporaneous netting analysis is required. Identify all 

contemporaneous creditable increases and decreases in emissions for each of 

the 6 GHG pollutants on a mass basis.135

Is the CO2e sum 

of the increases 

over 75,000 TPY 

CO2e? 

From 

prior 

page 

14.

GHG emissions are not

subject to PSD as part of 

this permit review. 

NO 

YES

16. For each creditable activity or event, determine the increase or decrease in 

emissions for each of the 6 GHG pollutants. 

17. Sum the increases and decreases, including the increases and decreases 

from the proposed modification, for each of the 6 GHG pollutants on a mass 

basis. 

18. Calculate the net GHG emissions on a mass basis. 

Are the net GHG 

emissions on a 

mass basis over 

zero TPY? 

Go to 

next 

page 

NO

YES

19.

GHG emissions are not

subject to PSD as part of 

this permit review. 
D-4 

20. Convert any contemporaneous, creditable increase or decrease in 

emissions of each of the 6 GHG pollutants to their CO2e emissions 

using the global warming potential factors applied to the mass of each 

of the 6 GHG pollutants and sum them. 

Are the net GHG 

emissions on a 

CO2e basis equal 

to or greater than 

75,000 TPY 

CO2e? 

From 

prior 

page 

21. Calculate the net GHG emissions on a CO2e basis. 

NO 

YES

22.

GHG emissions are subject to 

PSD as part of this permit 

review. 

GHG emissions are not

subject to PSD as part of 

this permit review. 
E-1 

Appendix E. Example of PSD Applicability for a Modified Source 

 

Example Scenario:

• An existing stationary source is major for PSD and modifications involving GHGs may be 

major and possibly subject to PSD. 

• The proposed modification consists of the addition of a new emissions unit (Unit #2) and a 

modification to existing emissions unit (Unit #1). Both units emit one or more compounds 

identified as a GHG. 

• Emissions Unit A was added at the source 3 years ago. 

• The GHG emissions used in PSD applicability analyses is a sum of the compounds emitted 

at the emission unit. 

Unit #2 A new emissions unit with a proposed emissions increase of 77,000 TPY of CO2 (1 x 

77,000 TPY CO2 = 77,000 TPY CO2e).136

Unit #1 The modified existing Unit #1 will result in a CO2 emissions increase of 50 TPY (1 x 

50 TPY = 50 TPY CO2e) and a CH4 emissions decrease of 90 TPY (21 x 90 TPY CH4 = 

1890 TPY CO2e). The pre- and post-change emissions are: 

• Baseline actual GHG mass emissions are 400 TPY of CO2 and 100 TPY of CH4, which is 

a total of 500 TPY of GHGs on a mass basis. 

• Proposed GHG emissions after the change are 460 TPY (450 TPY from CO2, 10 TPY 

from CH4), which is a 40 TPY decrease from baseline actual emissions on a mass basis. 

• Baseline actual CO2e emissions are 400 TPY CO2e (1 x 400 TPY of CO2) plus 

2,100 TPY of CO2e (21 x 100 TPY of CH4) = 2500 TPY of CO2e. 

• Proposed CO2e emissions after the change are 450 TPY of CO2e (1 x 450 TPY of CO2) 

plus 210 TPY of CO2e (21 x 10 TPY of CH4) = 660 TPY of CO2e. 

Unit A Three years ago, during the contemporaneous period, there was an emissions increase of 

10,000 TPY CO2 (10,000 TPY CO2e) from the addition of a new emissions unit (Unit A) at the 

source. There are no other creditable emissions increases or decreases during the 

contemporaneous period. 

 

Note: The source must calculate emissions changes from existing emissions units being modified (e.g., Unit #1) and 

in preparing that calculation, the source must compare the emission unit's baseline actual emissions to either (1) a 

projection of its future actual emissions; or (2) its potential to emit (PTE). See 40 CFR 52.21(b)(41)(ii). Any 

creditable emissions decreases from existing emissions units must be decreases in baseline actual emissions. The 

requirements of the PSD rules apply to these calculations and determinations as applicable. 

Mass-Based Calculations 

(Step 1) In this step, only consider emissions increases of GHGs from the proposed 

modification.

Unit #2 77,000 TPY mass emissions increase of GHGs. 

 

136 For the purposes of this example, the Global Warming Potential values are from the 40 CFR Part 98 Table A-1, 

as of the date of this document. 
E-2 

Unit #1 The proposed GHG emissions are 460 TPY, which is a 40 TPY GHG mass emissions 

decrease from the baseline actual emissions of 500 TPY. The change at Unit #1 results in a 

decrease in GHG emissions and is therefore not considered in Step 1. 

Increases = 77,000 TPY GHG mass emissions increase from Unit #2 is greater than zero TPY, 

so 

Go to Step 2 and conduct contemporaneous netting 

(Step 2) In this step, include the creditable emissions increases and decreases of GHGs from the 

project and all other contemporaneous and creditable emissions increases and decreases of 

GHGs. 

Net emissions increase = 77,000 TPY GHG mass emissions from Unit #2 minus a 40 TPY 

GHG decrease from Unit #1 plus a 10,000 TPY GHG increase from Unit A equals 86,960 TPY 

GHG mass emissions. This net emissions increase is greater than zero TPY, so 

Go to the CO2e-based calculations 

CO2e-Based Calculations 

(Step 1) In this step only consider CO2e emissions increases from the modification.

Unit #2 77,000 TPY CO2e emissions increase 

Unit #1 The proposed CO2e emissions after the modification are 660 TPY CO2e, which is a 

1,840 TPY CO2e decrease from baseline actual emissions of 2,500 TPY CO2e. Since it is a 

decrease, ignore the change in CO2e emissions.

Increases = 77,000 TPY CO2e emissions increase from Unit #2 is equal to or greater than 

75,000 TPY CO2e, so 

Go to Step 2 and conduct contemporaneous netting 

(Step 2) In this step consider all emissions increases and decreases of CO2e from the proposed 

project and all other contemporaneous and creditable emissions increases and decreases of 

CO2e. 

Net emissions increase = 77,000 TPY CO2e emissions increase from Unit #2 minus 1,840 TPY 

CO2e emissions decrease from Unit #1 plus a 10,000 TPY CO2e emissions increase from Unit A 

equals 85,160 TPY CO2e emissions. This net emissions increase is equal to or greater than 

75,000 TPY CO2e. 
E-3 

Results: The modification is both a “significant emissions increase” (Step 1) and a 

“significant net emissions increase” (Step 2) in both the mass and CO2e-based calculations; 

therefore, the modification as proposed is major and subject to PSD for GHGs.
F-1 

Appendix F. BACT Example – Natural Gas Boiler 

[Disclaimer: The control options listed here and the outcomes of this example are presented for illustrative 

purposes only. They do not represent any specific guidance or direction from EPA relative to a BACT 

determination for this type of source.]

Project Scope: The permit applicant is proposing to install, at an existing PSD major source, a 

new 250 MMBtu/hour natural gas-fired boiler. The project’s emissions increase is in excess of 

75,000 TPY CO2e and the permit will be issued in March 2011, so the project is subject to 

BACT for GHGs under Step 1 of the Tailoring Rule. For the sake of simplicity, this example 

focuses on the section of the BACT analysis for GHG emissions from the project. 

The top-down BACT determination is carried out in the following five steps: 

Step 1: Identifying all available controls 

For purposes of this example, assume that the permit application listed the following available 

controls in the GHG BACT analysis: 

• Boiler Annual Tune-up – Once a year the boiler is tuned for optimal thermal efficiency. 

• Boiler Oxygen Trim Control – Stack oxygen level is monitored and the inlet air flow is 

adjusted for optimal thermal efficiency. 

• Use of an Economizer – A heat exchanger is used to transfer some of the heat from the 

boiler exhaust gas to the incoming boiler feedwater. Preheating the feedwater in this way 

reduces boiler heating load, increases its thermal efficiency and reduces emissions. 

• Boiler Blowdown Heat Recovery – Periodically or continuously, some water in the boiler 

is removed as a means of avoiding the build-up of water impurities in the boiler. A heat 

exchanger is used to transfer some of the heat in the hot blowdown water for preheating 

feedwater. This increases the boiler’s thermal efficiency. 

• Condensate Recovery – As the boiler steam is used in the heat exchanger, it condenses. 

When hot condensate is returned to the boiler as feedwater, the boiler heating load is 

reduced and the thermal efficiency increases. 

 

As would be appropriate under EPA’s guidelines for Step 1 of the BACT process, the permitting 

authority asked the applicant to expand the analysis to consider an air preheater (which recovers 

heat in the boiler exhaust gas to preheat combustion air). Accordingly, at this stage in this 

example, the permit applicant and permitting authority identified six control measures. 

Further, a public comment was received arguing that the analysis should include a combined 

cycle natural gas-fired turbine that is more efficient than the proposed boiler. Since the 

application explains that a boiler is necessary to fulfill the fundamental business purpose of 

providing process steam (and not generating electricity) and because a varying steam demand 

requires the ability to startup and shutdown the boiler quickly (due to the fluctuating operational 

demands of the facility, as substantiated in the application), the permitting authority declined to 

list the option in Step 1 of the BACT analysis on the grounds it would redefine the source. The 

permitting authority thoroughly documented this decision in its response to comments. 
F-2 

Step 2: Eliminating technically infeasible options 

At this stage of the review, the permit applicant and the permitting authority examine all options 

for technical feasibility. For this example, the permitting authority determined that the seven 

controls identified are technically feasible because nothing in the record showed that any of these 

options was not demonstrated or available or applicable to this type of source. 

Step 3: Evaluation and ranking of controls by their effectiveness. 

At this step, the permit applicant and permitting authority need to select a measure of 

effectiveness to compare and rank the options. Assume in this example that the applicant ranked 

control measures for the boiler based on their impact on the thermal efficiency of the boiler, after 

finding that thermal efficiency was a useful indicator of CO2 control efficiency because fuel use 

is directly related to CO2 emissions for the boiler and the impact of control measures. 

The permit applicant completed the control effectiveness analysis showing that the most 

effective single measure is oxygen trim control. The applicant’s analysis also showed that the 

use of an air preheater was no more effective than an economizer in recovering exhaust heat, and 

so the applicant narrowed the review to the economizer only. In this example, the applicant’s 

analysis next considered the effectiveness of the boiler controls in combinations and found that 

the most effective combination of measures is the use of four measures – oxygen trim control, an 

economizer, condensate recovery and blowdown heat recovery – which was approved by the 

permitting authority. 

Step 4: Evaluating the most effective controls and documenting results 

In this step, the permit applicant completed an analysis of the cost effectiveness of measures and 

combinations of measures, expressed as $/ton of GHG reduced, as well as an incremental cost 

effectiveness analysis. In this example, the applicant found that, given the size and other 

characteristics of this facility, the packages including boiler blowdown heat recovery was not 

cost effective (as an incremental measure compared to cost born by similar facilities) and the 

next most effective combination of measures for the boiler was the use of oxygen trim control, 

an economizer and condensate recovery. The applicant documented this decision in the 

permitting record and the permitting authority agreed. 

Significant energy and environmental impacts are also considered in this step. In this example, 

the record also showed that the recovery and reuse of condensate would reduce the use of boiler 

treatment chemicals and the generation of related waste and thus would reduce the amount of 

water going to wastewater treatment at the site. Since condensate recovery was still in 

consideration, this information provided additional record support continuing to consider 

condensate recovery part of the technology option. 
F-3 

Step 5: Selecting BACT 

With the analysis and record complete, the permitting authority determines BACT in this last 

step. In this example, the permitting authority determined, and the record showed, that BACT 

for GHGs from the proposed facility was the combination of oxygen trim control, an economizer 

and condensate recovery for the boiler, along with a high transfer efficiency design for the heat 

exchanger. Accordingly, the permitting authority included the following permit terms in the 

permit: 

• Emission limit expressed in lbs of CO2e emissions per pound of steam produced, 

averaged over 30 day rolling periods; 

• CO2e emissions are to be determined based on metered natural gas use and the 

application of standard emission factors; 

• Steam production determined from a gauge on the outlet of the boiler; 

• In addition, there would be a requirement to install the boiler as described in the 

application and BACT determination; 

• There would be a requirement to implement a preventive maintenance program for the air 

to fuel ratio controller of the boiler; and 

• A requirement for periodic maintenance and calibration of the natural gas meter and the 

steam flow analyzer. 

 
G-1 

Appendix G. BACT Example – Municipal Solid Waste Landfill 

[Disclaimer: The control options listed here and the outcomes of this example are presented for illustrative 

purposes only. They do not represent any specific guidance or direction from EPA relative to a BACT 

determination for this type of source.]

Project Scope: The permit applicant proposes to build a new, large municipal solid waste 

landfill. As the solid waste in a landfill decomposes, landfill gas (composed of methane, carbon 

dioxide, and trace amounts of organic compounds) is formed. The application shows that the 

PTE of the landfill expressed as CO2e emissions is in excess of 100,000 TPY. The permit will 

be issued after June 2011, so BACT will apply to the GHG emissions under Step 2 of the 

Tailoring Rule. For the sake of simplicity, this example focuses on the section of the BACT 

analysis for the capture and control of the landfill gas from the project. 

The permit applicant and reviewing authority conduct their BACT determination using the five 

steps of the top-down processes as follows: 

Step 1: Identifying all available controls 

The permit applicant and permitting authority agree that the BACT review for a landfill logically 

has two elements: the capture of the landfill gas and the control of emissions of that gas. In this 

example, there is an existing NSPS (Part 60 Subpart WWW) applicable to non-methane organic 

compounds (NMOC) emissions from Municipal Solid Waste (MSW) landfills, which addresses 

the capture and control of landfill gas. While the NSPS addresses a different component of the 

emissions than GHGs, the permit applicant and the permitting authority determine that the NSPS 

is a useful starting point for a GHG BACT determination since it has detailed requirements for 

the design and operation of the gas collection system. 

For capture of the landfill gas, the application uses compliance with the NSPS as the starting 

point. For control, the applicant identified the following three NSPS options as a starting point 

for the BACT determination: 

• venting to an on-site flare, 

• use of the gas in on-site internal combustion engines to generate electricity, or 

• treatment of the gas for delivery to a natural gas pipeline. 

The applicant did not identify or propose any alternative control options in the application, and 

none were suggested in public comments. However, the permitting authority did ask the 

applicant to expand the review to consider two other control measures: (1) a requirement to 

collect and control landfill gas earlier in the life of the landfill than is specified in the NSPS, and 

(2) the use of a gas turbine to generate power rather than internal combustion engines. 

At this stage, there are two control measures listed for gas capture (NSPS compliant system and 

a NSPS system with earlier gas collection and treatment) and four control options listed for the 

control of the landfill gas that is collected (flaring, fueling engines, fueling a gas turbine, and 

treatment and routing of the gas to a pipeline). 
G-2 

Step 2: Eliminating technically infeasible options 

At this stage of the review, the applicant and permitting authority assess the technical feasibility 

of each option. In this example, the applicant demonstrated that the volume of gas from the 

proposed facility would be inadequate to fuel a commercially available gas turbine. The 

permitting authority reviewed the record regarding the technical infeasibility for the gas turbine 

option, found it was adequate, and accepted elimination of that option from further consideration. 

Step 3: Evaluation and ranking of controls by their effectiveness 

At this step, the permit applicant and permitting authority need to determine a metric for ranking 

the control effectiveness of the options under consideration. In this case, the application used 

total CO2e emissions over the life of the landfill, based on the current business plan and design, 

as the effectiveness indicator. The applicant explained that the CO2e emissions estimates in their 

application reflected the direct emissions of GHGs and the CO2 produced for the options where 

that gas was combusted on site. The application also considered combinations of capture 

systems and controls for overall effectiveness. The record showed that early capture of gas and 

conversion of the gas to pipeline quality for export were likely to be the most effective 

combination, from a PSD perspective, given that the maximum amount of gas would be captured 

and most of the gas would not be combusted on site. The record also showed that flaring and the 

use of engines were similar in their control of overall on-site GHG emissions, with both controls 

reducing methane emissions significantly while generating relatively small on-site CO2

emissions in the process. 

Step 4: Evaluating the most effective controls and documenting results 

In this step, the applicant completed an analysis of the cost effectiveness of control measures, 

expressed as $/ton of GHG reduced, and also determined the incremental cost effectiveness. In 

this example, the applicant’s analysis first found that conversion of gas to pipeline quality was 

not cost effective, explaining that this control option would more than double the overall cost of 

the project since the landfill was far from an existing pipeline, and the permitting authority 

agreed that it should be eliminated for further consideration in the BACT analysis. The record 

also showed that the NSPS system with early collection was cost effective in both the flare and 

the engines case. There was also evidence in the record showing that the flare was more cost 

effective because revenue from the sale of power from use of engines was too little to offset the 

added cost of the engines and a power transmission line. 

The applicant and permitting authority also considered the collateral energy and environmental 

impacts of the options. In this example, the application noted that there was a positive 

environmental impact from the use of a flare because NOX emissions for a flare would be lower 

than those for the engines. Some public comments identified positive energy and environmental 

offsite impacts arising from the fact that using landfill gas to generate electricity would displace 

some other offsite energy generation and associated emissions. In responding to the comments, 

the permitting authority determined that this benefit outweighed the lower NOX emissions from 

the flare. The permit record also demonstrated that the use of engines or a flare would have 
G-3 

nearly equal CO2e control effectiveness. Accordingly, the permitting authority found that the 

environmental benefits arising from the engines-based system outweighed the flare’s cost 

effectiveness and environmental benefits of lower NOX emissions. 

Step 5: Selecting BACT 

The permitting authority determines BACT in this last step. In this example, the permitting 

authority determined that BACT for the proposed facility was NSPS compliance with early 

implementation of the capture and control system with engines combusting the landfill gas to 

generate electricity. Accordingly, the permitting authority included the following permit terms in 

the permit: 

• Compliance with the landfill design and operation requirements of the applicable NSPS 

with a revised condition for earlier capture and control of the gas. 

• A requirement to combust the collected gas in engines with the creation and use of an 

O&M plan for the engines to assure that they operate efficiently. 
H-1 

Appendix H. BACT Example – Petroleum Refinery Hydrogen Plant 

[Disclaimer: The control options listed here and the outcomes of this example are presented for illustrative 

purposes only. They do not represent any specific guidance or direction from EPA relative to a BACT 

determination for this type of source.] 

Project Scope: 

Petroleum refineries produce and utilize hydrogen in order to convert crude oil to finished 

products. In this example, a permit applicant proposes a modification project to expand the 

hydrogen production and hydrotreating capacity of an existing major source refinery. The 

application submitted by the permit applicant shows that the project has a significant emissions 

increase and a significant net emissions increase on both a CO2e basis and a mass basis. The 

permitting authority will issue the permit in October 2011, so PSD is triggered for GHGs in Step 

2 of the Tailoring Rule. For simplicity, this example addresses the GHG BACT analysis for the 

new hydrogen plant only. 

Accordingly to the application, the proposed project utilizes the most common method of 

producing hydrogen at a refinery, the steam methane reforming (SMR) process. In SMR, 

methane and steam are reacted via a catalyst to produce hydrogen and CO. The reaction is 

endothermic and the necessary heat is provided in a gas-fired reformer furnace. The CO 

generated by the initial SMR reaction further reacts with the steam to generate hydrogen and 

CO2. The hydrogen is then separated from the CO2 and other impurities. In this example, the 

application shows that the purification is done using a Pressure Swing Adsorption Unit. The 

permit applicant proposes to use the offgas from that step (containing some hydrogen, CO2, and 

other gases) as part of the fuel for the reformer furnace. 

The top-down BACT determination is carried out in the following five steps: 

Step 1: Identifying all available controls 

Assume for purposes of this example that the permit application lists the following control 

options for GHG emissions: 

• Furnace Air/Fuel Control – An oxygen sensor in the furnace exhaust is to be used to 

control the air and fuel ratio in the furnace on a continuous basis for optimal efficiency. 

• Waste Heat Recovery – The overall thermal efficiency is to be optimized through the 

recovery of heat from both the furnace exhaust and the process streams to preheat the 

furnace combustion air, to preheat the feed to the furnace and to produce steam for use in 

the process and elsewhere in the refinery. 

• CO2 Capture and Storage – Capture and compression, transport, and geologic storage of 

the CO2. (Some refineries isolate hydrogen reformer CO2 for sale but that is not a part of 

this example project.) 

The permitting authority did not require the applicant to identify any alternative control options 

beyond those in the application, and none were suggested in public comments. 
H-2 

Step 2: Eliminating technically infeasible options 

At this stage of the review, the permit applicant and the permitting authority examine the control 

options for technical feasibility. In this example, the permitting record shows that all three 

controls are technically feasible because there is no evidence that any of these options are not 

demonstrated or available or applicable to this type of source. 

Step 3: Evaluation and ranking of controls by their effectiveness. 

At this step, the permit applicant and permitting authority need to select a measure of 

effectiveness to compare and rank the options. In this example, the applicant ranked control 

measures for the hydrogen plant based on the GHG emissions per unit of hydrogen produced. 

The applicant and the permitting authority agreed that such an output-based indicator was a good 

way to capture the overall effect of multiple energy efficiency measures used in the design of a 

complex process such as this. 

The permit applicant then completed a control effectiveness analysis, in which benchmarking 

data on the energy efficiency and GHG emissions of recently installed hydrogen plants was 

provided. The applicant showed that by incorporating various heat recovery measures this 

hydrogen plant would be a lower emitter (on an output basis) than similar new plants, and the 

permitting authority concurred in that determination. The applicant’s analysis considered the 

effectiveness of each individual measure and combinations of measures. In this case, the 

applicant determined that the most effective combination was one in which all three options were 

included. 

Step 4: Evaluating the most effective controls and documenting results 

In this step, the permit applicant completed an analysis of the cost effectiveness of measures and 

combinations of measures, expressed as $/ton of GHG reduced. The applicant also determined 

the incremental cost effectiveness. In this example, the information supplied by the applicant 

demonstrated that the transport and sequestration of CO2 would not be cost effective because the 

nearest prospective location for sequestration was more than 500 miles away and there was not 

an existing pipeline or other suitable method for CO2 transport between the refinery and the 

sequestration location. Accordingly, the record showed that the cost of transport was significant 

in comparison to the amount of CO2 to be sequestered and the cost of the project overall. 

Although the permitting authority affirmed this determination, in responding to public comments 

on the issue, the permitting authority did note that in circumstances in which a refinery was 

located near an oil field that used CO2 injection for enhanced recovery, the cost for transport and 

sequestration would likely be in a range that would not exclude the transport control option from 

the list of technologies that would continue to be considered in the BACT analysis. 

Permit applicants and permitting authorities also consider other significant energy and 

environmental impacts in this step. In this case, none were presented in the application, and the 

only significant public comment on the issue was addressed by the permitting authority, as noted 

above. 
H-3 

Step 5: Selecting BACT 

With the analysis and record complete, the permitting authority determines BACT. In this 

example, the permitting authority determined that BACT was a combination of furnace 

combustion control and integrated waste heat recovery. Accordingly, the permitting authority 

included the following permit terms in the permit: 

• Emission limit in pounds of CO2e emitted per pound of hydrogen produced, averaged 

over rolling 30-day periods. 

• CO2e emissions would be determined by metering natural gas sent to the hydrogen plant. 

With prior approval of the agency, the emissions could be adjusted for excess fuel gas 

sent to other parts of the refinery. A separate meter and fuel analysis would be needed to 

get that credit. 

• Hydrogen production would be metered. 

• The heat recovery systems would need to be installed as described in the application. 

• There would need to be a written program for calibration and maintenance of meters. 
I-1 

Appendix I. Resources for GHG Emission Estimation 

The following are a number of methods that are traditionally used to estimate PTE from sources 

and relevant emissions units: 

• Federally enforceable operational limits, including the effect of pollution control 

equipment; 

• Performance test data on similar units; 

• Equipment vendor emissions data and guarantees; 

• Test data from EPA documents, including background information documents for new 

source performance standards, national emissions standards for hazardous air pollutants, 

and Section 111(d) standards for designated pollutants; 

• AP-42 Emission Factors; 

• Emission factors from technical literature; and 

• State emission inventory questionnaires for comparable sources. 

These approaches remain relevant for GHG emissions calculations and serve as the fundamental 

approaches to estimating emissions for permitting applications. For example, direct 

measurements methods such as continuous emissions monitors (CEMs) would continue to be a 

preferred means to form the starting point basis for estimating emissions from GHG emissions 

units. However, because GHG emissions historically have not been subject to regulation under 

air permitting programs, and there are unique GHG emission source categories, there is not as 

widespread representation or long-term experience with GHG estimation techniques and 

measurement methods as there is for conventional pollutants under the above approaches. The 

purpose of this section is to identify additional references and resources that may be useful when 

evaluating GHG emission sources and deciding which estimation methods to use.137

Mandatory Reporting of Greenhouse Gases. This final rule was issued on October 30, 2009 (74 

FR 56260), and established GHG reporting requirements for all sectors of the economy and 

should be considered a primary reference for sources and permitting authorities in estimating 

GHG emissions and establishing measurement techniques when preparing or processing permit 

applications. The rule includes procedures for estimating GHG emissions from the source 

categories that are responsible for the majority of stationary source GHG emissions in the U.S. 

The procedures identify where applications of direct measurement techniques are viable and 

describes emission factor and mass-balance based approaches where direct measurement 

techniques are not applicable or available. 

 

137 The exclusion of a source or emission unit category from these sources does not imply that such sources or 

emissions units are excluded from permitting requirements. For example, as of the date of this publication CO2

from biomass combustion is not included in determining applicability under the mandatory reporting rule, but is 

included in determining applicability under both PSD and title V programs as described in the Tailoring Rule. Also, 

there are not methods identified for all possible GHG emitting sources and units in the current mandatory reporting 

rule. 
I-2 

While the GHG mandatory reporting rule is focused on estimating and reporting actual

emissions from source categories, the basic approaches can be used to estimate a source’s PTE 

when correctly adjusted to reflect future conditions and operating parameters. Since many of the 

affected GHG source categories and emissions units have been or will be subject to permitting 

requirements for conventional, non-GHG pollutants, sources should use similar adjustments to 

fuel throughput, activity data, and emissions for determining PTE for GHG that have been used 

in existing PSD and title V guidance for those units and which are applied on a case-by-case 

basis depending on specific operating parameters for the affected sources. 

Other reference sources that may prove useful to sources and permitting authorities in 

identifying, characterizing and estimating emissions from GHG emission sources include the 

following: 

• ENERGY STAR Industrial Sector Energy Guides and Plant Energy Performance 

Indicators (benchmarks) 

http://www.energystar.gov/epis 

• US EPA National Greenhouse Gas Inventory 

http://epa.gov/climatechange/emissions/usinventoryreport.html

• EPA’s Climate Leaders Protocols 

http://www.epa.gov/stateply/index.html 

• EPA’s Voluntary Partnerships for GHG Reductions: 

− Landfill Methane Outreach Program (http://www.epa.gov/lmop/) 

− CHP Partnership Program (http://www.epa.gov/chp) 

− Green Power Partnership (http://www.epa.gov/greenpower) 

− Coalbed Methane Outreach Program (http://www.epa.gov/cmop/index.html) 

− Natural Gas STAR Program (http://www.epa.gov/gasstar/index.html) 

− Voluntary Aluminum Industrial Partnership: 

http://www.epa.gov/highgwp/aluminum-pfc/index.html 

• SF Emission Reduction Partnership for the Magnesium Industry: 

http://www.epa.gov/highgwp/magnesium-sf6/index.html 

• PFC Reduction/Climate Partnership for the Semiconductor Industry: 

http://www.epa.gov/highgwp/semiconductor-pfc/index.html 

• Landfill Gas Emissions Model 

 User’s Guide at: http://www.epa.gov/ttncatc1/dir1/landgem-v302-guide.pdf. 
I-3 

There are few distinct source categories and or specific GHG pollutants that are not represented 

in the reference sources noted above, that could potentially be subject to permitting requirements 

for GHGs. These include primarily biogenic CO2 emission sources, such as: 

• Wastewater (CO2 from treatment processes and digester gas combustion) 

• Ethanol Fermentation Processes (CO2) 

EPA is currently researching and developing emission estimating procedures for these biogenic 

CO2 sources and will be making these available in the near future through EPA’s website 

(www.epa.gov). Prior to these methods becoming available, sources will still be responsible for 

including these emissions for GHG permitting purposes and will need to propose methods for 

assessing and measuring these emissions that are adequate for all GHG permitting requirements. 

Permitting authorities will need to review these methods to determine their appropriate 

application for GHG permitting. 
J-1 

Appendix J. Resources for GHG Control Measures 

The following are several information sources to consider when looking for available GHG 

control measures when conducting a BACT analysis. 

• EPA’s GHG Mitigation Measures Database 

http://www.epa.gov/nsr/ghgpermitting.html 

 

• EPA’s Sector GHG Control White Papers 

http://www.epa.gov/nsr/ghgpermitting.html

• EPA’s RACT/BACT/LAER Clearinghouse (RBLC) 

http://cfpub.epa.gov/rblc/ 

• ENERGY STAR Guidelines for Energy Management 

http://www.energystar.gov/guidelines

• ENERGY STAR Industrial Sector Energy Guides 

http://www.energystar.gov/epis

• EPA’s Climate Leaders Protocols 

http://www.epa.gov/stateply/index.html 

• Report of the Interagency Task Force on Carbon Capture and Storage

http://www.epa.gov/climatechange/policy/ccs_task_force.html

• EPA’s Lean and Energy Toolkit 

http://www.epa.gov/lean/toolkit/LeanEnergyToolkit.pdf 

• EPA’s Voluntary Partnerships for GHG Reductions: 

- Landfill Methane Outreach Program (http://www.epa.gov/lmop/) 

- Coalbed Methane Outreach Program (http://www.epa.gov/cmop/index.html) 

- Natural Gas STAR Program (http://www.epa.gov/gasstar/index.html) 

- Voluntary Aluminum Industrial Partnership (http://www.epa.gov/highgwp/aluminumpfc/index.html) 

- CHP Partnership Program (http://www.epa.gov/chp) 

• SF Emission Reduction Partnership for the Magnesium Industry: 

 http://www.epa.gov/highgwp/magnesium-sf6/index.html 

• PFC Reduction/Climate Partnership for the Semiconductor Industry: 

 http://www.epa.gov/highgwp/semiconductor-pfc/index.html 

• DOE’s Industrial Technologies Program (Best Practices): 

http://www1.eere.energy.gov/industry/bestpractices/ 
J-2 

In addition to the above sources of information, once permitting authorities gain experience with 

GHG BACT determinations, useful information on GHG permitting decisions will be present in 

the EPA’s RBLC and Control Technology Center.

Additionally, the following are several information sources that may be helpful when including 

benchmarking as part of a BACT analysis. 

• EPA Energy Star Industrial Energy Management Information Center: 

http://www.energystar.gov/index.cfm?c=industry.bus_industry_info_center 

• DOE Industrial Technologies Program: 

http://www1.eere.energy.gov/industry/ 

• Lawrence Berkeley National Laboratory Industrial Energy Analysis Program: 

http://industrial-energy.lbl.gov/ 

• European Union Energy Efficiency Benchmarks: 

http://ec.europa.eu/environment/climat/emission/benchmarking_en.htm
K-1 

Appendix K. Calculating Cost Effectiveness for BACT 

The following excerpt is from the Draft 1990 NSR Workshop Manual (pages B.36-B.44) 

IV.D.2.b. COST EFFECTIVENESS 

Cost effectiveness is the economic criterion used to assess the potential for achieving an 

objective at least cost. Effectiveness is measured in terms of tons of pollutant emissions 

removed. Cost is measured in terms of annualized control costs. 

Cost effectiveness calculations can be conducted on an average, or incremental basis. The 

resultant dollar figures are sensitive to the number of alternatives costed as well as the 

underlying engineering and cost parameters. There are limits to the use of cost-effectiveness 

analysis. For example, cost-effectiveness analysis should not be used to set the environmental 

objective. Second, cost-effectiveness should, in and of itself, not be construed as a measure of 

adverse economic impacts. There are two measures of cost-effectiveness that will be discussed 

in this section: (1) average cost-effectiveness, and (2) incremental cost-effectiveness. 

Average Cost Effectiveness 

Average cost effectiveness (total annualized costs of control divided by annual emission 

reductions, or the difference between the baseline emission rate and the controlled emission rate) 

is a way to present the costs of control. Average cost effectiveness is calculated as shown by the 

following formula: 

Average Cost Effectiveness (dollars per ton removed) = 

Control option annualized cost 

 Baseline emissions rate - Control option emissions rate 

Costs are calculated in (annualized) dollars per year ($/yr) and emissions rates are 

calculated in tons per year (tons/yr). The result is a cost effectiveness number in (annualized) 

dollars per ton ($/ton) of pollutant removed. 

Calculating Baseline Emissions 

The baseline emissions rate represents a realistic scenario of upper boundary uncontrolled 

emissions for the source. The NSPS/NESHAP requirements or the application of controls, 

including other controls necessary to comply with State or local air pollution regulations, are not 

considered in calculating the baseline emissions. In other words, baseline emissions are 

essentially uncontrolled emissions, calculated using realistic upper boundary operating 

assumptions. When calculating the cost effectiveness of adding post process emissions controls 

to certain inherently lower polluting processes, baseline emissions may be assumed to be the 

emissions from the lower polluting process itself. In other words, emission reduction credit can 

be taken for use of inherently lower polluting processes. 
K-2 

Estimating realistic upper-bound case scenario does not mean that the source operates in 

an absolute worst case manner all the time. For example, in developing a realistic upper 

boundary case, baseline emissions calculations can also consider inherent physical or operational 

constraints on the source. Such constraints should accurately reflect the true upper boundary of 

the source’s ability to physically operate and the applicant should submit documentation to 

verify these constraints. If the applicant does not adequately verify these constraints, then the 

reviewing agency should not be compelled to consider these constraints in calculating baseline 

emissions. In addition, the reviewing agency may require the applicant to calculate cost 

effectiveness based on values exceeding the upper boundary assumptions to determine whether 

or not the assumptions have a deciding role in the BACT determination. If the assumptions have 

a deciding role in the BACT determination, the reviewing agency should include enforceable 

conditions in the permit to assure that the upper bound assumptions are not exceeded. 

For example, VOC emissions from a storage tank might vary significantly with 

temperature, volatility of liquid stored, and throughput. In this case, potential emissions would 

be overestimated if annual VOC emissions were estimated by extrapolating over the course of a 

year VOC emissions based solely on the hottest summer day. Instead, the range of expected 

temperatures should be considered in determining annual baseline emissions. Likewise, 

potential emissions would be overestimated if one assumed that gasoline would be stored in a 

storage tank being built to feed an oil-fired power boiler or such a tank will be continually filled 

and emptied. On the other hand, an upper bound case for a storage tank being constructed to 

store and transfer liquid fuels at a marine terminal should consider emissions based on the most 

volatile liquids at a high annual throughput level since it would not be unrealistic for the tank to 

operate in such a manner. 

In addition, historic upper bound operating data, typical for the source or industry, may 

be used in defining baseline emissions in evaluating the cost effectiveness of a control option for 

a specific source. For example, if for a source or industry, historical upper bound operations call 

for two shifts a day, it is not necessary to assume full time (8760 hours) operation on an annual 

basis in calculating baseline emissions. For comparing cost effectiveness, the same realistic 

upper boundary assumptions must, however, be used for both the source in question and other 

sources (or source categories) that will later be compared during the BACT analysis. 

For example, suppose (based on verified historic data regarding the industry in question) 

a given source can be expected to utilize numerous colored inks over the course of a year. Each 

color ink has a different VOC content ranging from a high VOC content to a relatively low VOC 

content. The source verifies that its operation will indeed call for the application of numerous 

color inks. In this case, it is more realistic for the baseline emission calculation for the source 

(and other similar sources) to be based on the expected mix of inks that would be expected to 

result in an upper boundary case annual VOC emissions rather than an assumption that only one 

color (i.e., the ink with the highest VOC content) will be applied exclusively during the whole 

year. 

In another example, suppose sources in a particular industry historically operate at most 

at 85 percent capacity. For BACT cost effectiveness purposes (but not for applicability), an 

applicant may calculate cost effectiveness using 85 percent capacity. However, in comparing 
K-3 

costs with similar sources, the applicant must consistently use an 85 percent capacity factor for 

the cost effectiveness of controls on those other sources. 

Although permit conditions are normally used to make operating assumptions 

enforceable, the use of “standard industry practice” parameters for cost effectiveness calculations 

(but not applicability determinations) can be acceptable without permit conditions. However, 

when a source projects operating parameters (e.g., limited hours of operation or capacity 

utilization, type of fuel, raw materials or product mix or type) that are lower than standard 

industry practice or which have a deciding role in the BACT determination, then these 

parameters or assumptions must be made enforceable with permit conditions. If the applicant 

will not accept enforceable permit conditions, then the reviewing agency should use the absolute 

worst case uncontrolled emissions in calculating baseline emissions. This is necessary to ensure 

that the permit reflects the conditions under which the source intends to operate. 

For example, the baseline emissions calculation for an emergency standby generator may 

consider the fact that the source does not intend to operate more than 2 weeks a year. On the 

other hand, baseline emissions associated with a base-loaded turbine would not consider limited 

hours of operation. This produces a significantly higher level of baseline emissions than in the 

case of the emergency/standby unit and results in more cost effective controls. As a consequence 

of the dissimilar baseline emissions, BACT for the two cases could be very different. Therefore, 

it is important that the applicant confirm that the operational assumptions used to define the 

source’s baseline emissions (and BACT) are genuine. As previously mentioned, this is usually 

done through enforceable permit conditions which reflect limits on the source’s operation which 

were used to calculate baseline emissions. 

In certain cases, such explicit permit conditions may not be necessary. For example, a 

source for which continuous operation would be a physical impossibility (by virtue of its design) 

may consider this limitation in estimating baseline emissions, without a direct permit limit on 

operations. However, the permit agency has the responsibility to verify that the source is 

constructed and operated consistent with the information and design specifications contained in 

the permit application. 

For some sources it may be more difficult to define what emissions level actually 

represents uncontrolled emissions in calculating baseline emissions. For example, uncontrolled 

emissions could theoretically be defined for a spray coating operation as the maximum VOC 

content coating at the highest possible rate of application that the spray equipment could 

physically process, (even though use of such a coating or application rate would be unrealistic 

for the source). Assuming use of a coating with a VOC content and application rate greater than 

expected is unrealistic and would result in an overestimate in the amount of emissions reductions 

to be achieved by the installation of various control options. Likewise, the cost effectiveness of 

the options could consequently be greatly underestimated. To avoid these problems, 

uncontrolled emission factors should be represented by the highest realistic VOC content of the 

types of coatings and highest realistic application rates that would be used by the source, rather 

than by highest VOC based coating materials or rate of application in general. 
K-4 

Conversely, if uncontrolled emissions are underestimated, emissions reductions to be 

achieved by the various control options would also be underestimated and their cost 

effectiveness overestimated. For example, this type of situation occurs in the previous example if 

the baseline for the above coating operation was based on a VOC content coating or application 

rate that is too low [when the source had the ability and intent to utilize (even infrequently) a 

higher VOC content coating or application rate]. 

 

Incremental Cost Effectiveness 

In addition to the average cost effectiveness of a control option, incremental cost 

effectiveness between control options should also be calculated. The incremental cost 

effectiveness should be examined in combination with the total cost effectiveness in order to 

justify elimination of a control option. The incremental cost effectiveness calculation compares 

the costs and emissions performance level of a control option to those of the next most stringent 

option, as shown in the following formula: 

Incremental Cost (dollars per incremental ton removed) = 

Total costs (annualized) of control option - Total costs (annualized) of next control option 

Next control option emission rate - Control option emissions rate 

Care should be exercised in deriving incremental costs of candidate control options. 

Incremental cost-effectiveness comparisons should focus on annualized cost and emission 

reduction differences between dominant alternatives. Dominant set of control alternatives are 

determined by generating what is called the envelope of least-cost alternatives. This is a 

graphical plot of total annualized costs for a total emissions reductions for all control alternatives 

identified in the BACT analysis (see Figure B-1). 
K-5 
K-6 

For example, assume that eight technically available control options for analysis are 

listed in the BACT hierarchy. These are represented as A through H in Figure B-1. In 

calculating incremental costs, the analysis should only be conducted for control options that are 

dominant among all possible options. In Figure B-1, the dominant set of control options, A, B, 

D, F, G, and H, represent the least-cost envelope depicted by the curvilinear line connecting 

them. Points C and E are inferior options and should not be considered in the derivation of 

incremental cost effectiveness. Points A, C and E represent inferior controls because B will buy 

more emissions reduction for less money than A; and similarly, D and F will by more reductions 

for less money than E, respectively. 

Consequently, care should be taken in selecting the dominant set of controls when 

calculating incremental costs. First, the control options need to be rank ordered in ascending 

order of annualized total costs. Then, as Figure B-1 illustrates, the most reasonable smooth 

curve of the control options is plotted. The incremental cost effectiveness is then determined by 

the difference in total annual costs between two contiguous options divided by the difference in 

emissions reduction. An example is illustrated in Figure B-1 for the incremental cost 

effectiveness for control option F. The vertical distance, “delta” Total Costs Annualized, divided 

by the horizontal distance, “delta” Emissions Reduced (TPY), would be the measure of the 

incremental cost effectiveness for option F. 

A comparison of incremental costs can also be useful in evaluating the economic viability 

of a specific control option over a range of efficiencies. For example, depending on the capital 

and operational cost of a control device, total and incremental cost may vary significantly (either 

increasing or decreasing) over the operation range of a control device. 

As a precaution, differences in incremental costs among dominant alternatives cannot be 

used by itself to argue one dominant alternative is preferred to another. For example, suppose 

dominant alternative is preferred to another. For example, suppose dominant alternatives B, D 

and F on the least-cost envelope (see Figure B-1) are identified as alternatives for a BACT 

analysis. We may observe the incremental cost effectiveness between dominant alternative B 

and D is $500 per ton whereas between dominant alternative D and F is $1000 per ton. 

Alternative D does not dominate alternative F. Both alternatives are dominant and hence on the 

least cost envelope. Alternative D cannot legitimately be preferred to F on grounds of 

incremental cost effectiveness. 

In addition, when evaluating the total or incremental cost effectiveness of a control 

alternative, reasonable and supportable assumptions regarding control efficiencies should be 

made. An unrealistically low assessment of the emission reduction potential of a certain 

technology could result in inflated cost effectiveness figures. 

The final decision regarding the reasonableness of calculated cost effectiveness values 

will be made by the review authority considering previous regulatory decisions. Study cost 

estimates used in BACT are typically accurate to ± 20 to 30 percent. Therefore, control cost 

options which are within ± 20 to 30 percent of each other should generally be considered to be 

indistinguishable when comparing options.