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 27711November 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 appl y to a particular situation bas ed upon the individual facts and circumstances. This guidance does not change or subs titute for any law, regulation, or any other legally binding requirement and is not legally en forceable. The use of non-mandatory language such as “guidance,” “recommend,” “may,” “sh ould,” and “can,” is intended to describe EPA policies and recommendations. Mandatory termi nology such as “must” and “required” are intended to describe controlling requirements under the terms of th e Clean Air Act and EPA regulations, but this document does not establis h legally binding require ments in and of itself.i 

# Table of Contents

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

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

A. C ALCULATING GHG M ASS -B ASED AND CO 2 E -B ASED E MISSIONS ................................................................ 11

B. PSD A PPLICABILITY FOR GHG S

- N EW S OURCES .......................................................................................... 12

C. PSD A PPLICABILITY FOR GHG S

- M ODIFIED S OURCES .................................................................................. 13

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

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

III. BACT A NALYSIS ............................................................................................................ .. 18

A. D ETERMINING THE S COPE OF THE BACT A NALYSES ..................................................................................... 24

B. BACT S TEP 1

– I DENTIFY A LL A VAILABLE C ONTROL O PTIONS .................................................................... 25

C. BACT S TEP 2

– E LIMINATE T ECHNICALLY I NFEASIBLE O PTIONS .................................................................. 34

D. BACT S TEP 3

– R ANKING OF C ONTROLS ....................................................................................................... 38

E. BACT S TEP 4

– E CONOMIC

, E NERGY

, AND E NVIRONMENTAL I MPACTS ........................................................ 39

F. BACT S TEP 5

– S ELECTING BACT ................................................................................................................ 45

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

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

A. G ENERAL C ONCEPTS AND T ITLE V R EQUIREMENTS ...................................................................................... 51

B. T ITLE V A PPLICABILITY R EQUIREMENTS AND GHG S .................................................................................... 52

C. P ERMITTING R EQUIREMENTS ......................................................................................................................... 53

D. T ITLE V F EES

.............................................................................................................................. ................... 56

E. F LEXIBLE P ERMITS

.............................................................................................................................. ........... 56

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

# 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 Fl ow Chart – Existing Sources (January 2, 2011, through June 30, 2011)

Appendix D. GHG Applicability Fl ow 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 – Pe troleum 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 requirements 1
for greenhouse gases (GHGs) that begin to ap ply 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) reiterat es and emphasizes relevant past EPA guidance on the PSD and title V review processes for othe r 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 perm itting authorities and other stakeholders regarding how these permitting programs will apply to GHG emissions.

This document is organized into sections w ith 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 permitti ng 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 be st 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 an alysis for a modified source, example BACT analyses, compilations of resources for estima ting 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 m odifications 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 qual ity standards (NAAQS)

1 Such requirements are reflected in pr ovisions of the Clean Air Act, EPA rule s, 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 re ferred to as prevention of significant deterioration (PSD) permits, while permits for major sources emitting nonattainment pollutants and located in nonattainment areas ar e 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 so urces 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 severa l 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 Janua ry 2, 2011, must addre ss emissions of GHGs.

These actions included new rules that estab lished a common sense approach to phase in permitting requirements for greenhouse gas (GHG) em issions from stationary sources, beginning with large industrial sources that are already subj ect 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 welf are (“the endangerment finding”), and that the combined emissions of these GHGs from new motor vehicles cause and contribute to the air pollu tion that endangers public health a nd welfare (“the cause and contribute finding”). 3 These findings did not themselves im pose any requirements to control GHG emissions, but they were a prerequisite to fina lizing GHG standards for ve hicles under title II of the Act. Thereafter, on May 7, 2010, EPA issu ed 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 exis ting interpretation regard ing 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 po llutant 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 Econ omy (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 al so 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 fo r model year 2012 vehicles. Thus, under EPA’s interpretation of the Act and applicable rules, construction permits issued 6 under the PSD program on or after January 2, 2011, must c ontain conditions addres sing GHG emissions.

With respect to title V operating perm its, the April 2, 2010 notice reiterated EPA’s interpretation that the 100 tons per year (T PY) major source threshold for title V operating permits is triggered only by polluta nts “subject to regula tion” under the Act. EPA also explained that the Agency interprets “subject to regula tion” 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 th e Act takes effect).

On June 3, 2010, EPA issued a final rule th at “tailors” the applicability provisions of the PSD and title V programs to enable EPA and st ates 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 requi rements 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, includi ng the nation’s largest GHG emitters ( i.e., power plants, refineries, and cement production facilities). Emi ssions 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 Tail oring 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 im plementing the “top down” best available control technology (BACT) analysis and the two steps of the applicability procedures for modifications. The first Tailoring Rule step be gins on January 2, 2011, and ends on June 30, 2011, and this step

6 Consistent with its regulations in 40 CFR Part 124, EP A uses the term “issued” to describe the time when a permitting authority issues a PSD permit after public comme nt 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 pe rmit becomes effective or final agency ac tion 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 beco mes 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 requir ement 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 s ources 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 ta ke 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 th rough any future steps. Future steps are not discussed further in this guida nce 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 CO 2 equivalent (CO 2 e) subject to PSD or title V permitting for GHG

emissions before 2016. For additional informa tion regarding the steps of the PSD and title V implementation processes for GHGs, please refe r to the preamble of the Tailoring Rule. 8

This guidance does not reiterate all the provi sions 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 a nd other stakeholders going through the PSD and title V permitting processes. Should there be a ny 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, aggreg ation of related physical or operational changes, the definition of a stationary source, debottlenecking, treatment of fugitive emissions, determining creditable emissions redu ctions, or routine maintenance, repair and replacement. Readers that are interested in understanding these aspects of the federal program should rely on current Agency rule s and guidance when permitting GHGs.

EPA Regional Offices should apply the policie s 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 cas e 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 Regi onal 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 pe rmitting 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 sour ces of certain air pollutants, defined as “regulated NSR pollutants,” and major modificati ons 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 s ources become subject to PSD, these sources must, in order to obtain a PSD permit, meet th e various PSD requirements. For example, they must apply BACT, demonstrate compliance with ai r 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, vegetati on, and visibility. These PSD requirements are the subject of

Sections III and IV of this document.

In this section, we discuss how the C AA 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 opera tional change that “increases the amount” of any air pollutant emitted by the source. 12

EPA’s regulations implement these PSD a pplicability requirements through use of different terminology, and, in the case of GHGs, with additional limitatio ns. Specifically, the regulations apply the PSD requirements to any major stationary sour ce that begins actual construction (if the source is new) or that unde rtakes a major modification (if the source is existing). 13 The term major stationary s ource 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 categori es, 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 physic al 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 re gulations, 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 whic h EPA has promulgated a NAAQS or a new source performance standard (NSPS), certain ozone depl eting 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 non attainment. 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 increa se 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 whic h the source is major. Thus, the regulations quoted above require a two-step applicability process for mo difications. 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 signifi cant increase in Step 1, then PSD does not apply. If there is a significant in crease in Step 1, then Step 2 applie s, which involves determining if the modification results in a significant net emissions increase. The Step 2 calculation includes

creditable emissions increases and decreases fr om 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 re gulations as the period th at 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 propos ed emissions changes to new or existing emissions units are calculated, at the discretion of the owner or ope rator 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 year s, 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 sour ces 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 translat es into less raw material and/or fuel consumption for the same amount of output of product. Consequently, as l ong 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 th e actual-to-projected-act ual 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 projec tion, PSD may apply.7 course, other factors must be considered as we ll 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 influen ce 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 th e maximum emissions of the source operating at full design capacity. Restri ctions on production or operation that limit a source’s PTE include limitations on quantities of raw materials cons umed, fuel combusted, hours of operation, or conditions which specify that the source must inst all, 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 existi ng major stationary sources for one or more regulated NSR pollutants. 23 Once properly established in the source’s permit, subsequent modifications to existing emissions un its, or the addition of new emissions units, are not subject to PSD for the PAL pollutant if th e 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 re gulated NSR pollutant under the PSD major source permitting program when they are emitte d by new sources or modifications in amounts that meet the Tailoring Rule’s set of applicabilit y thresholds, which phase in over time. For PSD purposes, GHGs are a single air pollutant defined 24 as the aggregate group of the following six

gases:

- carbon dioxide (CO 2 )

- nitrous oxide (N 2 O)

- methane (CH 4 )

- hydrofluorocarbons (HFCs)

- perfluorocarbons (PFCs)

- sulfur hexafluoride (SF 6 )

22 See, generally, EPA Guidance on Limiting Potential to Emit (P TE) 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 a nyway, due to emissions of another regulated NSR pollutant, are subject to regulation and therefor e 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 a nother regulated NSR pollu tant and increases its emissions of GHGs by at least the specified thre shold 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 modificatio n.”) 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 unde r Step 1. In addition, for new sources that are not anyway sources and for modifications th at are not anyway modifications, emissions of GHGs in at least specified threshold amounts ar e also treated as subj ect to regulation and therefore as a regulated NSR pollutant.

For GHGs, the Tailoring Rule does not change the basic PSD applic ability 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 applicabil ity threshold for, the source

based on CO 2 equivalent (CO 2 e) emissions as well as its G HG 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 CO 2 e 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 si x 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 flowch arts in Appendices A through D.

CO 2 e 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 app licability analysis.

In the annual US inventory of GHG emissions and sinks, EPA has reported that the LandUse, Land-Use Change and Forestry (LULUCF) sect or (including those st ationary sources using biomass for energy) in the United States is a net carbon sink, taking in to 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 understan d that most sources are likely to treat this mass-based evaluation as an initial screen from a pr actical standpoint, since th ey would not proceed to calculate emissions on a

CO 2 e 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 part ially or wholly, emissions of GHG from bioenergy and other biogenic sources for the purposes of the BACT an alysis and the PSD program based on the view that the biomass used to produce bioenergy feed stocks 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 certa in types of biomass and other biogenic sources ( e.g., biogas from landfills) for energy generation, c onsistent with existing air quality standards. In particular, a variety of federa l and state policies have recogni zed that some types of biomass can be part of a national strategy to reduce depe ndence 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 ev aluating the environmental, en ergy 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 unde rtaking 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 si mplify 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 evalua ting “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 dete rminations with respect to certain types of biomass. The agency is currently reviewing th e comments received in response to the July 15, 2010 Call for Information (CFI) that solicited fee dback from stakeholders on approaches to accounting for GHG emissions from bioe nergy 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 accoun ting 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 th e Tailoring Rule, whether the issuance of a supplemental rule is appropriate to address wh ether 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 ru les for different types of feedstocks that reflect the net impact of their ca rbon 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 CO 2 

### e-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 CO 2 e basis.

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

amounts:

50,000 TPY of CO 2 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 (s ee 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 CO 2 e-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 CO 2 e

Note: Short tons (2,000 lbs), not long or me tric 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 GH Gs - 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 ne w source would be equal to or greater than 75,000 TPY on a CO 2 e 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 ne w source would be equal to or greater than 100,000 TPY CO 2 e basis and equal to or greater than the applicable major source threshold ( i.e., 100 or 250 TPY, depending on the source category 31 ) on a mass basis for

GHGs.

The PSD applicability criteri a discussed above for new sources are summarized in Table II-A below. Flowcharts for applicability dete rminations 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 CO 2 e requirements would automa tically 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 Applicabil ity 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 CO 2 e 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 CO 2 e OR

• Source has a GHG PTE equal to or greater

than:

o 100,000 TPY CO 2 e, 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 re quired 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 CO 2 e basis and greater than zero TPY

on a mass basis.

b. Tailoring Rule Step 2 - PSD Applicability Te st for GHG in PSD Permits Issued on or after July 1, 2011

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

any of the following is true:

• PSD for GHGs would be required un der 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

CO 2 e basis and is equal to or greater than 100/250 TPY (depending on the source category) on a mass basis 32 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 CO 2 e basis and greater than zero TPY on a mass basis.

OR BOTH:

o The existing source is minor 33 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 CO 2 e 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 modifi ed 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 ma jor 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 CO 2 e 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 (dependi ng on the source category).15 Table II-B. Summary PSD Applicability Crit eria 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

CO 2 e, 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 CO 2 e, 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 CO 2 e 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 CO 2 e, 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 CO 2 e, and

o 100/250 TPY mass basis16 

### 2. Contemporaneous Netting

As noted above, assessing PSD applicabilit y for a modification at an existing major stationary source against the GHG em issions thresholds is a two-st ep process. Step 1 of the applicability analysis considers only the cred itable increases from the proposed modification itself. Step 2 of the applicability analysis, which is often referred to as “contemporaneous netting,” considers all creditabl e increases and decreases (including increases and decreases resulting from the proposed modification) occu rring at the source during the “contemporaneous period.” The federal “contemporaneous period” for GHG emissions is no different than the federal contemporaneous period for other regulat ed NSR pollutants, which covers the period beginning 5 years before construc tion of the proposed modificati on through the date that the

increase from the modification occurs.

It should be noted that both the contemporan eous period and the baseline period will, at least for a while, require reference to emissions prior to the January 2, 2011 date that PSDapplies to GHG-emitting sources. That is, because the contemporaneous period includes a fiveyear “look back,” for several years after Januar y 2, 2011, the contemporaneous period for netting of GHG emissions includes periods before Ja nuary 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 CO 2 e-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 CO 2 e emissions increase resulting from the modification, calculated as the sum of

the six GHGs on a CO 2 e basis ( i.e., with GWPs applied) is equal to or greater than 75,000 TPY CO 2 e. No emissions decreases are considered in this calculation ( i.e., if the sum of the change in the six GHGs on a CO 2 e 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 CO 2 e 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 un it 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 CO 2 e 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 appli cability test for modi fied sources of GHGs are presented in Appendices C and D. A ppendix 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 s ection 165(a)(4) of the CAA, in federal regulations at 40 CFR 52.21(j), in rules setting forth the requir ements 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, Subpa rt A - Subpart FFF. CA A § 169(3) defines BACT

as:

an emissions limitation (including a visibl e emission standard) based on the maximum degree of reduction for each pollutant subj ect to regulation unde r 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 app lication of production proce sses and available methods, systems, and techniques, including fuel clean ing, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant....

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

review.

The CAA and corresponding implementing regul ations 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 ava ilable emissions-reducing technology or technique would achieve, as well as the energy, environmen tal, 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 th e maximum degree of reduction achievable for each pollutant subject to BACT through the applicat ion of the selected te chnology or technique. However, if the permitting authority determines that technical or economic limitations on the application of a measurement methodology w ould make a numerical emissions standard infeasible for one or more pollutants, it may es tablish design, equipment, work practices or operational standards to satis fy the BACT requirement. 35

Top-Down BACT Process

EPA recommends that permitting authorities co ntinue 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) recogni zed that the top-down framework is the “predominant method for determining BACT” and recommended that perm itting authorities continue to use their existing BACT determinations process, such as the top-down framewo rk, in conducting BACT analyses for GHGs. CAAAC, Interim Phase I Report of the Climate Change Work Group of the Permits, New Source Review and Toxics19 all available control technologies for a given pollutant to be id entified and ranked in descending order of control effectiveness. The permit a pplicant should first ex amine the highest-ranked (“top”) option. The top-ranke d options should be establishe d as BACT unless the permit applicant demonstrates to the satisfaction of the permitting authority that technical considerations, or energy, environmental, or eco nomic 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 ef fective 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 pollu tion 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 th ese considerations do not justify eliminating the top-ranked option, it should be selected as BA CT at the fifth step. However, if the energy, environmental, or economic impacts of the top-ra nked option demonstrate that this option is not achievable, then the evaluation remains in St ep 4 of the process a nd continues with an examination of the energy, environmental, and economic impacts of the second-ranked option. This Step 4 assessment should continue until an ac hievable option is identified for each source. The highest-ranked option that ca nnot be eliminated is selected as BACT at Step 5, which includes the development of an emissions limitati on that is achievable by the particular source using the selected control strategy. Thus, the in clusion 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/caaa c/climate/2010_02_Interi mPhaseIReport.pdf.

37 1990 Workshop Manual at B.2.20 EPA developed the top-down process in orde r 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 applicab le regulations. EPA Regional Offices that implement the federal PSD program (through Fede ral Implementation Plan s (FIPs)) and state permitting authorities that implement the fede ral program through a delegation of federal authority from an EPA Regional Office should appl y 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-dow n BACT process as a binding requirement through rule. 39 Thus, permitting authorities that im plement an EPA-approved PSD permitting program contained in their State Implementati on Plans (SIPs) may us e another process for determining BACT in permits they issue, incl uding BACT for GHGs, so long as that process (and each BACT determination made through that pr ocess) complies with th e 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 re quire that each state program apply the applicable crit eria in the definition of BACT. 41 Furthermore, EPA has certain oversight responsibilities with respect to th e 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 a pproved programs are reasoned and fa ithful 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 a pply to the aspects that are unique to GHGs. In addition, Appendices F, G, and H to this doc ument 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 justif y the conclusions reached by the permitting authority than can be provided in this guidance.

The most comprehensive discussion of th e 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, a nd 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 Administra tor 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-D own” 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 (O rder 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 Work shop Manual that has jigsaw puzzle pi eces on the cover, is not available online, and has some minor differences from the online vers ion. 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 th is 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 essent ial component of a successful BACT analysis (whether it follows the top-down process or another approach) is th e record supporting the decisions reached by the permitting authority. Permitting authorities should ensure that the BACT requirements contained in the final PSD permit are supporte d and justified by the informati on 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 rele vant statutory and regulatory requirements, the permitting authority must also provide notice of its pr eliminary 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 al so reflect careful consid eration and response to each significant consider ation raised in public comments. Each BACT analysis must be supported by a complete permitting record that show s consideration of all the relevant factors.

This guidance (including the appendi ces) provides some preliminary EPA views on some key issues that may arise in a BACT analys is for GHGs. It is impor tant to recognize that this document does not provide any final determin ation of BACT for a particular source, since such determinations can only be made by i ndividual 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 reco mmends 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 regulati ons. Thus, depending on the relevant facts and circumstances, permitting authorities have the di scretion 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 st ringent than any appl icable 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”, targ eting specific industrial sectors, prov ide 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 PSD22 BACT determinations for GHGs that will need to be made without the benefit of having an NSPS and supporting technical documents to info rm 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 c ontrol strategies and may reflect advances in control technology or reductions in the co sts or other impacts of using particular control strategies. Thus, the guidan ce in this document should be viewed taking into consideration the potential deve lopment of an NSPS for a partic ular 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 considerat ion in a top-down BACT analysis.

Importance of Energy Efficiency

As discussed in greater detail below, EPA be lieves 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, pro cesses and practices at the emitting unit. In general, a more energy efficient technology bur ns 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 approxi mately 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 anal ysis helps reduce the products of combustion, which includes not only GHGs but other regulated NSR pollutants ( e.g., NO X , SO 2 , PM/PM 10 /PM 2.5 , CO, etc.). Thus, it is also importan t to emphasize that energy efficiency should

be considered in BACT determinations for a ll regulated NSR pollutants (not just GHGs). Additional considerations concerning energy effi ciency 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 rele vant to the source in ques tion, may provide useful information regarding energy effici ent 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 cons tructed 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 (Aug ust 2007) at 6 (finding that the absolute efficiency difference between supercriti cal and subcritical boilers is 2.3% (39.1% compared to 36.8%), which is equivalent to a 5.9% reduction in fuel use), available athttp://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 resour ces 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 benchm arking tools called plan t Energy Performance Indicators (EPIs). 50 For sectors where an EPI has been de veloped, these tools may be used to assess a plant’s performance compared to the i ndustry. At a unit and process level, ENERGY STAR has developed sector-specific Energy Guid es for a number of industries. These Energy Guides discuss in detail processes and tec hnologies that a permit applicant or permitting authority may wish to consider. This type of info rmation 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 sc ope of the “major stationary source” is determined by the de finition in 40 CFR 52.21(b)(1), and th e 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 re gulations 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 equi pment 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 unit 52 at a facility and has also encouraged applicants and permitting authorities to consid er logical groupings of emissions units as appropriate on a case-by-case basis. 53

For new sources triggering PSD review, th e 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 enviro nmental performance of the overall facility. The term “facility” and “source” used in applic able 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 ne t emissions increase would occur at the source 55 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 co ntext 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 m odification. 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 re sults from a modification. This concept is frequently described as “debottlenecking” because the upstream or downstream emission in creases that are accounted for in the analysis are often the result of increased throughput acro ss 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) (Int ermet 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 em issions from the proposed new source. EPA interprets the language of the BACT definiti on in CAA §169, which requires consideration of “production processes and availabl e methods, systems, and techni ques ... 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 existi ng regulations state that BACT only applies to emission units that are physically or operationally changed. 58

EPA has historically interpreted the BACT re quirement to be inapplicable to secondary emissions, which are defined to include emissions that may occur as a re sult of the construction or operation of a major sta tionary 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 reductio ns in a facility’s demand for energy from the electric grid but that cannot be demonstrated to achieve reduction in emi ssions released from the stationary source ( e.g., within the property boundary). Nevert heless, as discussed in more detail below, EPA recommends that permitting authoritie s consider in a portion of the BACT analysis (Step 4) how available strate gies 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 t hose air pollution contro l technologies or techniques (including lower-emitting processes and practices) that have the potential for practical application to the emissions unit and the regulated pollutant unde r evaluation. To satisfy the statutory requirements of BACT, EPA believes that the ap plicant must focus on technologies that have been demonstrated to achieve the highest leve ls of control for the pollutant in question, regardless of the source type in whic h 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 te chnologies and techniqu es include the applic ation of alternative production processes, methods, systems, and techni ques, including clean fuels or treatment or innovative fuel combustion techniques for cont rol of the affected pollutant. In some circumstances, inherently lower-polluting pro cesses are appropriate for consideration as

available control alternatives. The control options s hould include not only existing controls for the source category in question, but also cont rols determined through “technology transfer” that are applied to source categories with exhaust stre ams 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. Pr imary 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, fre quency of process interruptions, special product quality concerns, etc.), and the potential impacts on othe r emission points within the source. Also, technologies in appl ication outside the Unit ed States should be considered to the extent that the technologies have been successfully demonstrated in practi ce. In general, if a control option has been demonstrated in prac tice 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 co ntrol 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 standa rd (including any significant public comments on EPA’s evaluation) should be we ighed 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 inde pendent requirement that will apply to an NSPS

source that commences construction after an NSPS is proposed and car ries with it a strong presumption as to what level of control is achi evable. This is not intended to limit available options to only those considered in the developm ent of the NSPS. For example, in addition to considering controls addressed in an NSPS rulema king, controls selected in lowest achievable emission rate (LAER) determinations are avai lable for BACT purposes, should be included as control alternatives included in BACT Step 1, and may frequently be fo und to represent the top control alternative at later steps in the BACT analysis. 61

EPA has placed potentially applicable control a lternatives 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-attain ment 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 Emittin g Processes/Practices/D esigns and Add-on

Controls

.

The BACT analysis should consider potentially applicable control t echniques from all of the above three categories. Lo wer-polluting processe s (including design c onsiderations) 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 ch emical characteristics of the pollutant-bearing

emission stream.

As explained later in this guidance, in the c ourse of the BACT analysis, one or more of the available options may be eliminated from cons ideration 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 opti ons should still be included in Step 1 of the BACT process, since the purpose of Step 1 of th e process is to cast a wide net and identify all control options with potential a pplication 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 br oad array of potential options for pollution control, this step of the proce ss is not without limits. EPA has recognized that a Step 1 list of options need not necessarily include inhere ntly lower polluting processes that would fundamentally redefine the nature of th e 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 funda mentally 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 f acility in its application. Th e underlying record will be an essential component of a suppor table 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 disc ern which design elements are inherent for the applicant’s purpose and which design elements may be chan ged 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 pollutin g 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 (Ord er 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 (O rder on Petition) (December 15, 2009) (same).

65 In re Desert Rock Energy Company , PSD Appeal No. 08-03 et al. (EAB Se pt. 24, 2009), slip op. at 65, 76.28 without disrupting the a pplicant’s basic business purpose for th e 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 ob jective for the proposed facility. 66 This approach does not preclude a permitting authority from considering op tions that would change aspects (either minor or significant) of an applicants’ proposed facility design in orde r to achieve pollutant reductions that may or may not be deemed achievable after fu rther 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 di scretion to conduct a broader BACT analysis if they desire. 67 The “redefining the source” issue is ultim ately 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 expl ained and documented in the permit record, especially where such an option has been id entified as significant in public comments. 68

In circumstances where there are varying config urations for a particul ar type of source, the applicant should include in th e application a discussion of th e 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 base d 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 asse ssing the fundamental business purpose of a permit applicant. 69 However, a factor that might be consid ered at later steps of the top-down BACT process, such as whether a process or technol ogy can be applied on a specific type of source (Step 2) or the cost of construc ting a source with particular charac teristics (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 appare ntly achievable tec hnology transfer are not appropriately considered to be a part of the applic ant’s basic design or fundamental business purpose or objective. 70 Since BACT Step 4 also include s 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 co al-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 natura l-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 opti ons include those that would require a permit applicant to switch to a primary fuel type ( i.e., coal, natural gas, or biom ass) other than the type of fuel that an applicant proposes to use for its primary combustion process. For example, when an applicant proposes to construc t a coal-fired steam electric ge nerating 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 redefi ne a coal-fired elec tric generating unit. 72 Ultimately, however, a permitting authority retains the discreti on to conduct a broader BACT analysis and to consider changes in the primary fuel in Step 1 of the analysis. EPA doe s not classify the option of using a cleaner form of the same type of fu el 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 othe r 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 in to one aspect of the project desi gn (such as startup or auxiliary applications), this suggests that a fuel is “availab le” to a permit ap plicant. In su ch 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 th e 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 waiv er 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 contro l 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 occu rred 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 cl eaner than that propos ed 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 waiver s 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 st atutory 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 adhe re 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 doe s not affect the discretion of a permitting authority to exclude options that would fundamentally redefine a pr oposed source. GHG control technologies are likely to vary based on the type of facility, pr ocesses involved, and GHGs being addressed. The discussion below is focused on energy efficien cy and carbon capture and storage (CCS) because these control approaches may be applicable to a wide range of facilities that emit large amounts

of CO 2 . Information on other technologies and mitigation approaches to control CO 2 as well as the other GHGs ( e.g., methane) is found in Appendix J.

The application of methods, systems, or tech niques to increase energy efficiency is a key GHG-reducing opportunity that falls under the category of “lower-po lluting processes/ practices.” Use of inherently lower-emitting technologies, in cluding 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 pref erred over end-of-stack c ontrols; in other cases, an energy efficient measure can be used effectiv ely in tandem with end-of-stack controls to

achieve additional control of criteria pollutants. Applying th e 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, m easures and options that are energy efficient translates not only in the reducti on of emissions of the particul ar 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 particul arly 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 Corpor ation'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 accessi ble. 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 im provement options incl udes technologies or processes that maximize the efficiency of the individual emissions unit. For example, the processes that may be used in electric generatin g 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 app licant 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 pressu re, a BACT analysis for this source should include more efficient options such as boilers with supercritical and u ltra-supercritical steam pressures. Furthermore, combined cycle com bustion turbines, which have higher efficiencies than simple cycle turbines, should be listed as op tions 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 considerat ion when it is more efficient than the proposed technology. 78 However, these options may be evaluated under the redefining the source framework desc ribed 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 im provements 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 reviewi ng 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 consid er technologies or processes that not only maximize the efficiency of the individual emittin g units, but also process improvements that impact the facility’s energy uti lization assuming it can be shown that efficiencies in energy use by the facility’s higher-energy-usi ng equipment, processes or opera tions could lead to reductions in emissions from the facility. EPA has long r ecognized 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 ground s. Letter from Stephen Page , EPA OAQPS to Paul Plath, E3 Consulting , Best Available Control Technology Requiremen ts 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 substa ntially the same reasoning lacked a reasoned basis for excluding further consideration of IGCC. In the Matter of: American Elect ric 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 authoritie s 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 so urce 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 polluti on control technology that removes pollutants from a facility’s emissions stream, or an ‘i nherently lower-polluting process/practice’ that prevents emissions from being ge nerated 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 utiliza tion 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 ut ilize 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 sect ion, 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 op tions 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 numbe r of options that have traditionally been considered in BACT analyses for previously regulated NSR pollutants. However, the second category of options appropriate for considera tion 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-pr oducing 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 im prove 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 w ould 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 obse rved that “[t]he permitting authority may require consideration of alternativ e 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. On e 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 lowe r 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 u nder 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 ma king 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 utilizati on that could then be evaluate d and judged by the permitting authority and the public agains t 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 achie ve commensurate levels of efficiency using the proposed methods. Such an approach would leav e 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 fr om 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” resu lts and “guaranteed” results. Such estimates can be provided for the permitting authority’s co nsideration. The difference between expected and guaranteed results gives some indication of th e uncertainty and risk tolerances included in the guaranteed value. Still, in some cases, th e ultimate efficiency of the unit may not be accurately known without testing the installed e quipment, 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 eff ect on efficiency is somewhat uncertain until it is operationally tested. Thus, where there is some reasonable uncertainty re garding performance of specified efficiency measures, or the combina tion of measures, the permit can be written to acknowledge that uncertainty. As in the past, th e permitting authority has the discretion to set a permit limit informed by properly conservative e ngineering estimates, or to set permit conditions that make allowance for adjustments of th e BACT limits based on operational experience.

For the purposes of a BACT analysis fo r GHGs, EPA classifies CCS as an add-on pollution control technology 81 that is “available” 82 for large CO 2 -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 an d 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 CO 2 from new and existing fossil energy power plants; however, they are not ready for widespread implementation primarily because they have not been34 fossil fuel-fired power plants and indu strial facilities with high-purity CO 2 streams ( e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron an d 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 BA CT for such sources. Many other case-specific factors, such as the technical feasibility and cost of CCS tec hnology for the specific application, size of the facility, proposed location of the sour ce, 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 particul arly 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 technologi es in BACT Step 1, the a pplicant needs to survey the range of potentially avai lable control options. EPA recognize s that dissemination of data and information detailing the function of the proposed control equipment or pr ocess is essential if permitting agencies are to reach consistent c onclusions on the availability of GHG technology

across industries. In the init ial phase of PSD permit reviews for GHGs, background information about certain emission control strategies ma y be limited and technologies may still be under development. For example, alternative technolo gies are being developed for reusing carbon or sequestering carbon in a form or location ot her than through inject ion into underground formations. When these technologies are more de veloped, they could be included in Step 1 of the top-down BACT process. EPA will add info rmation 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 Tec hnically 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 fr om 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 e ngineering principles,

that technical difficulties w ould preclude the successful use of the control option on the

emissions unit under review.

demonstrated at the scale necessary to establish co nfidence for power plant a pplication. Since the CO 2 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.html35 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 cons iders 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 unde r review has not been demonstr ated, then questions regarding “availability” and “applicabil ity” 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 ha s been applied on one type of source, this is largely a question of the transferability of th e 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 char acteristics. The contro l technology would not be applicable if it can be shown that there are sign ificant 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 controll ed, may differ so significantly from previous applications that it is uncertain the control devi ce will work in the situation currently undergoing

review.

Evaluations of technical feas ibility should consider all char acteristics of a technology option, including its development stage, commerci al applications, scope of installations, and performance data. The applicant is responsible for providing evidence th at a potential control measure is technically infeasible. However, th e 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 considerat ion of the permit application.

Information regarding what vendors will gua rantee should be considered in the BACT selection process with all the other relevant f actors, 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 fa ilure to perform and the test methods for acceptance. A permit applicant uses these guarant ees 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. Wh ile permit applicants use these guarantees as protection from overly optimistic vendor claims for new technologies, ex perience demonstrates

that these terms and conditions can also be cust omized for each circumstance to imply greater or lesser performance, depending on th e 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 determin ing the level of performance specified in a PSD permit. However, a control technology should no t 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 le vel of performance in the PSD permit.

GHG-Specific Considerations

EPA’s historic approach to assessing techni cal feasibility that is summarized above and described in the 1990 Workshop Manual and subse quent actions such as EAB decisions is generally applicable to GHGs. The nature of the concerns and remedies arising from

identification of available tec hnologies is well-explained in the 1990 Workshop Manual and other referenced documents. However, tec hnologies 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 we ll-explained and supported in their permitting record, paying particular attention to the mo st recent information from the commercial sector and other recently-issued permits.

This guidance is being issu ed at a time when add-on c ontrol technologies for certain GHGs or emissions sources may be limited in numbe r and in various stages of development and commercialization. A number of ongoing resear ch, 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 cont rol options for GHG emissions when determining

BACT.

In the early years of GHG control strategies , consideration of co mmercial guarantees is likely to be involved in the BACT determination pr ocess. This type of guarantee may be more relevant for certain GHG controls because, unlike ot her pollutants with available, proven control technologies, some GHG controls may have a greater uncertainty rega rding their expected performance. As noted above, the lack of availa bility of a commercial guarantee, by itself, is not a sufficient basis to classify a technol ogy 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” a dd-on pollution control technology for large CO 2 -emitting

facilities and indus trial facilities with high-purity CO 2 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: CO 2 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 differe nces 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 a pplications 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 so urce, taking into account the integration of the CCS components with the base facility and site-specific considerations ( e.g., space for CO 2 capture equipment at an existi ng facility, right-of-ways to bui ld a pipeline or access to an existing pipeline, access to suitable geologic re servoirs for sequestration, or other storage options).

While CCS is a promising technology, EPA doe s not believe that at this time CCS will be a technically feasible BACT option in certain cases. As noted a bove, 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 ava ilable and applicable, with the term “applicable” generally meani ng a technology can reasonably be installed and operated on the source type under consideration. EPA recognizes the significan t logistical hurdles th at 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 re gulated pollutants and already have an existing reasonably accessible infrastructure in place to ad dress 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 ov ercome the offsite logistical barriers necessary to apply CCS technology to its operations, and sm aller sources will likely be more constrained in this regard. Based on these considerations, a pe rmitting 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 fr om commercial vendors.

The level of detail supporting the justification for the remova l of CCS in Step 2 will vary depending on the nature of the source under review and the opportunities for CO 2 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 consider ed in Step 4. In circumstances where CO 2 transportation and sequestration oppo rtunities already exis t in the area where the source is, or will be, located, or in circumstances where ot her sources in the same source category have applied CCS in practice, the pr oject would clearly warrant a co mprehensive consideration of CCS. In these cases, a fairly detailed case-speci fic analysis would likely be needed to dismiss CCS. However, in cases where it is clear that there are signi ficant and overwhelming technical (including logistical) issues associated with th e application of CCS for the type of source under review ( e.g., sources that emit CO 2 in amounts just over the relevant GHG thresholds and produce a low purity CO 2 stream) a much less detailed jus tification may be appropriate and acceptable for the source. In addition, a perm itting authority may make a determination to dismiss CCS for a small natural gas-fired pack age residential boiler, for example, on grounds38 that no reasonable opportunity exis ts for the capture and long-term storage or reuse of captured

CO 2 given the nature of the project. That finding may be sufficient to dismiss CCS for similar units in subsequent BACT reviews, provided th e 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 availabl e 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. Th e most effective c ontrol alternative ( i.e., the option that achieves the lowest emissions level) s hould 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 t op-down BACT selection process in Step 4. 87

In determining and ranking technologies based on control effectiven ess, applicants and permitting authorities should include informa tion 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 cont rol technology alternatives unde r consideration. While inputbased metrics have traditionally been the prefer red 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 out put of the facility or the affected source is relatively homoge neous, 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 appropr iate, net output-based standards provide a direct measure of the efficiency of an operation’s emission reduci ng 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 standa rd 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 lowe st possible emission leve l. Where plant-wide measures to reduce emissions are being consider ed 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 op tion on the list. However, these considerations are not actually applied until Step 4 of the process. Thus, the comp ilation 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 t op-ranked measure. Ranking control options based on their net output-based emissions ensures that the thermal efficien cy 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 CO 2 e rather than total mass or mass for the

individual GHGs.



### E. BACT Step 4 – Economic, Ener gy, 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, afte r 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 th e 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 th e “collateral impacts analysis,” 88 but this term is primarily applicable only to the environmental impact anal ysis. 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 op tion to the cost and performan ce 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 paramete rs that provide an in dication 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, Secti on 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 impact s, 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 electric ity that is generated onsite and power obtained from the electrical gr id, 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 whethe r 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 include d 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 polluta nt 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 pol lutants 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 th e essential purpose of BACT requirement is to achieve the maximum degree of reduction of the pa rticular pollutant under evaluation. In this context, it is generally unnecessary to explicitly consider or justify the en vironmental benefits of reducing the pollutant subject to the BACT analys is, 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, a nd economic impacts. Thus, in this context, it is reasonable to interpret the “environmental im pact” 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 re duction 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 impact s, demand on local water resources, and emissions of other pollutants subject to NSR or pollutant s not regulated under NSR such as air toxics. 95
EPA has also recognized that the environmenta l impacts analysis may examine trade-offs between emissions of various po llutants resulting from the application of a specific control technique. 96 For instance, in selecting the BACT lim it 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 permitt ing authority may need to assess whether it is more important to select a less stringent cont rol for CO emissions to avoid an unacceptable

increase in NO X emissions associated with the CO cont rol 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 cont rol) as the reason for not sel ecting the top-ranke d control option as BACT; however, there have been instances where environmental impacts have been a deciding factor in selecting a sp ecific 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 detrimenta l impacts of the emissions control option or strategy being evaluated, EPA ha s recognized that permitting aut horities have flexibility in deciding how to weigh the trade-offs associated with emissions control options. However, inherent with the flexibility is the responsibil ity of the permitting authority to develop a full permit record that explains those decisions give n the specific facts of the facility at issue. 100

GHG-Specific Considerations

There are compelling public heath and welfare reasons fo r BACT to require all GHG reductions that are achievable, considering econ omic impacts and the other listed statutory factors. As a key step in th e process of making GHGs a regulat ed pollutant, EPA has considered scientific literature on impacts of GHG emissi ons 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 risk s 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 (s electing a dry scrubber as BA CT 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 foun d 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, D ecember 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 weat her conditions also supported EPA’s finding.

The energy, environmental, and economic imp acts 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 part icular 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 envi ronmental effects. However, EPA has also interpreted the BACT requirements to allow fo r a more stringent technology to remain in

consideration as BACT if the collateral environmental benefits of choosing such a technology outweigh the economic or ener gy costs of that selection. 103 In other words, the permitting authority is not limited to evaluating the impact s 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, th e 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 c ontrol strategies affect emissions of other regulated pollutants, applicants and permitting authorities should consider the potential trade-offs of selecting particular GHG cont rol strategies. Likewise, when conducting a BACT analysis for other regulated NSR pollutants, applicants and pe rmitting authorities should take care to consider how the control strategies under considerati on may affect GHG emissions. For example, controlling volatile organic compound (VOC) em issions with a catalytic oxidation system

creates GHG emissions in the form of CO 2 . Permitting authorities have flexibility when evaluating the trade-offs associated with decr easing 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 emi ssions 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 th at 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 impact s 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 th ese exact impacts attributable to the specific

102 In re Hillman Power , 10 E.A.D. at 684.

103 In the Matter of North Coun ty 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 considerat ions, an assessment of the potenti al increase or decrease in the

overall level of GHG emissions from a source woul d 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 envir onmental impacts of a particular level of GHG

reduction and a collateral increase in another regulated NSR polluta nt, rather than attempting to determine or characterize specific environm ental 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 trad e-offs in emissions for regulated pollutants (including GHGs), permitting aut horities should continue to fo cus 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 a nother 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 a dditional increase could push the area into nonattainment. Thus, to assess the significance of an emissions increase or decrease, a permitting authority should give some consider ation to the impacts of a given amount of emissions. However, permitting authorities need not consider every possible environmental endpoint impact of every conceivable techno logy. The top-down BACT process calls for evaluating only those control alte rnatives that remain under consid eration 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 c ontrol 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 contro l 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 in stance, when evaluating the cost effectiveness of CCS as a GHG control option, if the cost of building a new pipeline to transport the CO 2 is extraordinarily high and by itself would be consider ed cost infeasible, it would not be necessary for the applicant to obtain a vendor quote a nd evaluate the cost effectiveness of a CO 2 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 e xpensive technology, largely because of the

costs associated with CO 2 capture and compression, and these costs will generally make the price of electricity from power plants with CCS uncom petitive 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

CO 2 near the power plant is feasible. Howeve r, there may be cases at present where the

economics of CCS are more favorable (for example, where the captured CO 2 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 warra nt 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 el imination 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 hi story 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 re ly 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 dete rmine 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 histor ically regulated under th e 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 NO X will emit well above 100,000 TPY of CO 2 e. As a result, even taking acco unt of the current limited data and consequent uncertainty concerning the costs of GHG BACT, it is reason able to anticipate that the cost effectiveness numbers (in $/ton of CO 2 e) 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 re ducing emissions from the facility obtaining a permit should be considered when weighing optio ns for reducing direct emissions of GHGs in Step 4 of the analysis, regardless of the locati on where the thermal or electrical energy for the facility is produced. This analysis should in clude 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, becau se 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 CO 2 e 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 cons ideration of the various direct and indirect economic, energy, and environmental impacts that might be informa tive 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 th e 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 consid eration – including the fi nal decision regarding various trade-offs that may arise in a perm itting decision – is dependent on many factors, including the specific facts of th e proposed facility, local interest s and concerns, and the nature of issues raised in public comments. Accordingl y, permitting authorities mu st ensure that their impacts analysis fully considers the relevant fact s 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-docum ented in the permit record. In so doing, we encourage permitting authorities to use their discre tion to consider the full range of impacts from

the various controls that could result in faciliti es 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 a lternatives that have a range of pot ential 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 se lected technology, and sp ecial circumstances at the specific source under re view which might affect the range of performance. 108 In setting BACT limits, permitting authorities have the disc retion 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 un ique to the particular circumstances of the technology and facility at i ssue in setting the limits. 109 EPA has also recognized that in some circumstances, it may be acceptable to establish BA CT limits that can be adjusted or optimized as the performance of a technology beco mes 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 lim it 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 en forceable, the permitting authority must include information regarding the methods that will be used for determining compliance with the limits (such as operational parameters, timing, testi ng methods, etc.) and ensure that there is no ambiguity in the permit terms themselves. 112

Finally, the permitting authority bears the respon sibility in Step 5 to fully justify the BACT decision in the permit record. Regardless of the control level pr oposed 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 stri ngent 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 a ddressed all of the most effectiv e control options that could be applied and; (2) determine that the applican t has adequately demonstrated that energy, environmental, or economic impacts justify any pr oposal 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 appli cant of the need for more information regarding the control option. However, the BACT selectio n essentially should defaul t to the highest level of control for which the applican t could not adequately justify its elimination based on energy, environmental and economic impacts. If the a pplicant 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 establis h BACT and prepare a draft permit based on the most effective control option for which an adequa te justification for reje ction 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 wa y to incorporate the energy efficiency of a process unit into the BACT analysis is to comp are control effectiveness in BACT Step 3 based on output-based emissions of each of the control op tions. 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 author ities 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, EP A 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 th e 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 num erical emissions limits established in a BACT analysis, a permit can also include condition s requiring the use of a work practice such as an Environmental Management System (EMS) fo cused on energy efficiency as part of that BACT analysis. The ENERGY STAR program provi des 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-bas ed 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 lim it on the boiler providing energy, the permit could also lay out a requirement to implement an EM S along with a requirement that all suggested actions that result in net savings have to be im plemented. 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 th e 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 prov isions 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 cont ribute to a violation of a ny NAAQS or PSD increments. 114 Several months of ambient air quality data must also be collected in some circ umstances 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 sour ce 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 re sult of the source or modification and general commercial, residential, industrial, and ot her growth associated with the source or

modification. 116 Under the federal PSD rules, this an alysis may also include monitoring of visibility in any Federal Class I area near the source or modifi cation “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 mu st 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 applic ation based on anticipated impacts.

GHG-Specific Considerations

The Tailoring Rule includes the following stat ement with respect to these requirements:

“There are currently no NAAQS or PSD increm ents 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 si gnificant amounts would be subject to PSD requirements. Therefore, if a facility trig gers 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 re quirements 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 th e NAAQS is not applicable to GHGs. Thus, we do not recommend that PSD applicants be required to m odel or conduct ambient monitoring for CO 2 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 ar e not listed in the appropriate section of the regulations, and GHGs are not curren tly 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 Administra tor determines is necessary to assess ambient air quality for that pollutant in any (or the) area that the emissi ons of that pollutant would affect.” In the case of GHGs, the exemption in sections 52.21(i)(5)( iii) and 51.166(i)(5)(ii i) is controlling since GHGs are not currently listed in th e relevant paragraph. Nevert heless, EPA does not consider it necessary for applicants to gather monitoring da ta 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 a ffect “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 be lieve 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 statemen t in the Tailoring Rule, EPA believes it is not necessary for applicants or permitting authoriti es 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, c limate change modeling and evaluations of risks and impacts of GHG em issions is typically conducted for changes in emissions orders of magnitude larger than the em issions 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 consider ations, GHG emissions would serve as the more appropriate and credible proxy fo r assessing the impact of a give n facility. Thus, EPA believes that the most practical way to address the c onsiderations reflected in the Class I area and additional impacts analysis is to focus on reduc ing 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 incorpora tion 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 whic h there are established NAAQS or increments,50 the air quality, additional impacts, and Class I requ irements 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 othe r 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’ comp liance with other CAA requirements. Title V generally does not add new pollution control requ irements, but it does require that each permit contain all air quality control requirements or “a pplicable 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 in clude stationary source requirements, but do not include mobile source requirements. Proce dural 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 s ource may be a major s ource 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 Tailo ring 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 applic ation generally must c ontain 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 incorpor ates the requirements that a pollutant be subject to regulation, and an emissions threshol d for GHG); and (2) all emissions of “regulated air pollutants” (which, under 40 CFR 70.2, incl udes criteria pollutants, VOCs, and pollutants regulated under CAA Section 111 or 112 standa rds, 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 pr omulgated 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 Step s 1 and 2 of the Tailoring Rule.



### B. Title V Applicability Re quirements and GHGs

Applicability requirements for title V perm itting 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 Applic ability 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 s ources 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 neces sary 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 CO 2 e; 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 neces sary 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 requir ements 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 requ ired to have title V permits for non-GHG pollutants ( i.e., “anyway” title V sources) will be require d 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 program s. Section C below describes how sources and permitting authorities should consider addr essing 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 th e Tailoring Rule. GHG emission sources that emit or have the PTE at least 100,000 TPY CO 2 e, 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 fo r 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

CO 2 e basis (GWPs applied).

In Step 2, as under Step 1, for all so urces 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 pe rmitting requirements as they pertain to GHG applicable requirements estab lished 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 Ru le, as with other applicable requirements related to non-GHG pollutants, a ny 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 appl icable requirements for GHGs will be in the form of GHG control require ments resulting from PSD permitting actions. It is important to note that GHG reporting requi rements 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 sour ce 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 not54 considered applicable requirement s under title V, they do not need to be included in the title V permit.

Under both Steps 1 and 2 of the Tailoring Ru le, 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 mon itoring and other compliance activities, and any other information considered necessary to de termine the applicability of, and impose, any applicable requirements for GHGs. This is th e same application information required under title V for applicable requirements pe rtaining to conventional pollutants.

As a general matter, all title V permits i ssued by permitting authorities must contain, among other things, emissions limitations and sta ndards necessary to assu re compliance with all applicable requirements for GHGs, all monito ring 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 w ill ultimately not have any GHG-sp ecific 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 ba sis 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 sour ce 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 pollu tants 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 sour ce 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 re sult 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 NO X . This change will result in additional applicable requirements for NO X

emissions controls but, according to the applicant, does not trigger BAC T review for GHGs. In this case, as part of its analysis of the application for perm it revision under its title V program, the permitting authority may determin e it necessary to verify that the project did not trigger BACT requirements for GHG emissions, and theref ore may need to request the applicant to submit GHG emissions information related to the project suffici ent 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 asso ciated 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 CO 2 e subject to regulati on 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 a ll emissions of pollutants for which they are major. In many cases, particularly where th e source has no applicable requirements for GHGs, emissions descriptions (instead of estimates) ma y be sufficient. For sources subject to the GHG reporting rule, the emissions description require ments 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 CO 2 e and over 100 TPY on a mass basis. Therefore, according to the Tailoring Rule applicability cr iteria 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). S econd, 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 desc ription of the GHG emission so urces 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 emi ssions information as necessary for non-GHG emission sources (e.g., information on emission s 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 provid e in their title V permit applications required information regarding all other applicable re quirements that apply to it under the Act ( e.g., SIP

125 Office of Air Quality Planning and Standards, White Paper for Streamlined D evelopment 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 permitt ing requirements solely on the basis of its GHG emissions on July 2, 2011, and, therefor e, 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 monito ring and monitoring sufficient to assure compliance. Even if the newly s ubject title V source di d not have any specific GHG-related requirements to include in the title V permit, under this scenario, the facility must propose appropriate monito ring, 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 ope rating permit for that opacity standard (which may be the MRR proposed by the fa cility 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 ti tle 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 gove rning the use of flexible air permits. A flexible air permit (FAP) is a title V operating permit that by its desi gn authorizes the source owner to make certain types or categories of physical and/or operationa l changes without further review or approval of the individual changes by the permitting author ity. 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 evaluati on of State FAP pilots in addition to providing greater operational flexibility, FAPs can result in greater environmen tal protection, lower administrative costs, pollution preven tion 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 ma ny 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. Th e combination of plantw ide emissions limits, alternative operating scenarios, and/or advan ce approvals of categorie s of operational changes can eliminate the need for case-by-case eval uation (under title V and PSD/NSR) for future energy-efficient equipment upgrades, thereby reduci ng 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-effi cient 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 regulator y requirements up-front.

EPA encourages permitting authorities and s ources to consider FAPs, particularly in situations where a source is planning to im plement 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 determini ng the applicability of PSD to GHGs, which first evaluates the

sum of the GHG emissions on a CO 2 e 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 practi cal standpoint, since they would not proceed to calculate emissions on a CO 2 e basis if they would not trigger PSD or title V on a

mass basis. 127 Accordingly, the examples provided in the attached appendice s take a variety of approaches for undertaking the required CO 2 e and mass-based calculations, and permit applicants and permitting authorities may use the pr ocesses identified in this guidance or another process for determining applicab ility of PSD to GHGs in permits they issue so long as that process complies with the relevant st atutory and regulatory requirements.

127 75 FR 31514, 31522 (June 3, 2010).A-1 

### Appendix A. GHG Applicabil ity Flow Chart – New Sources (January 2, 2011, through June 30, 2011)

4. Determine the new source's potentia l to emit (PTE) in tons per year (TPY) for each of the 6 GHG pollutants (CO 2 , CH 4 , N 2 O, 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 CO 2 equivalent (CO 2 e) 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 CO 2 e 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 potentia l to emit (PTE) in tons per year (TPY) for each of the 6 GHG pollutants (CO 2 , CH 4 , N 2 O, 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 CO 2 e basis

equal to or greater than
100,000 TPY? 3. Calculate the GHG emissions on a CO 2 equivalent (CO 2 e) basis using the global warming potential f actors applied to the mass of each of the 6 GHG pollutants.

4.

NO Go to

Element 7B-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 CO 2 e 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

pageC-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 (baselin e) emissions in tons per year (TPY) for units that are part of the modification for each of the 6 GHG pollutants (CO 2 , CH 4 , N 2 O, 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

Jul y 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.

YESC-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 CO 2 e 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 CO 2 equivalent (CO 2 e) 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 CO 2 e 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 em issions 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 a nd 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 ac tivity 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

b asis.

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, cr editable increase or decrease in emissions of each of the 6 GHG pollutants to their CO 2 e 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

CO 2 e basis equal to or greater than

75,000 TPY

CO 2 e? 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 CO 2 e 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 (CO 2 , CH 4 , N 2 O, HFCs, PFCs and SF6).

Determine the mass based sum. Convert the emissions of GHG pollutants to their CO 2 e emissions, using the global warming potential f actors applied to the mass of each of the 6 GHG pollutants and sum the CO 2 e emissions.

6. Determine the past actual (b aseline) emissions in tons per year (TPY) for units that are part of the modification for each of the 6 GHG pollutants (CO 2 , CH 4 , N 2 O, 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

CO 2 e 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

CO 2 e 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. STARTD-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 incr ease or decrease in mass emissions of each of the 6 GHG pollutants by subtrac ting past actual emissions from future

actual emissions. 133

13. Sum the GHG emissions on a CO 2 e 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 incr ease or decrease in emissions of each of the 6 GHG pollutants to their CO 2 e 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 CO 2 e number for each unit. 10. For all units that have a mass emi ssions 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

pageD-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 a nd decreases in emissions for each of the 6 GHG pollutants on a mass basis. 135 Is the CO 2 e sum of the increases over 75,000 TPY

CO 2 e? 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 even t, 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 CO 2 e emissions using the global warming potential f actors applied to the mass of each of the 6 GHG pollutants and sum them.

Are the net GHG

emissions on a

CO 2 e basis equal to or greater than

75,000 TPY

CO 2 e? From prior

page

21. Calculate the net GHG emissions on a CO 2 e 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 App licability for a Modified Source

Example Scenario:

• An existing stationary source is major for PSD and modificat ions involving GHGs may be major and possibly subject to PSD.

• The proposed modification consists of the addi tion 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 CO 2 (1 x 77,000 TPY CO 2 = 77,000 TPY CO 2 e). 136

Unit #1 The modified existing Unit #1 will result in a CO 2 emissions increase of 50 TPY (1 x

50 TPY = 50 TPY CO 2 e) and a CH 4 emissions decrease of 90 TPY (21 x 90 TPY CH 4 = 1890 TPY CO 2 e). The pre- and post-change emissions are:

• Baseline actual GHG mass emissions are 400 TPY of CO 2 and 100 TPY of CH 4 , which is

a total of 500 TPY of GHGs on a mass basis.

• Proposed GHG emissions after the cha nge are 460 TPY (450 TPY from CO 2 , 10 TPY

from CH 4 ), which is a 40 TPY decrease from base line actual emissions on a mass basis.

• Baseline actual CO 2 e emissions are 400 TPY CO 2 e (1 x 400 TPY of CO 2 ) plus 2,100 TPY of CO 2 e (21 x 100 TPY of CH 4 ) = 2500 TPY of CO 2 e.

• Proposed CO 2 e emissions after the change are 450 TPY of CO 2 e (1 x 450 TPY of CO 2 ) plus 210 TPY of CO 2 e (21 x 10 TPY of CH 4 ) = 660 TPY of CO 2 e.

Unit A Three years ago, during the contemporaneous period, there was an emissions increase of 10,000 TPY CO 2 (10,000 TPY CO 2 e) from the addition of a new emissions unit (Unit A) at the

source. There are no other creditable em issions 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 th e 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 exis ting emissions units must be decrease s 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, th e 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 therefor e not considered in Step 1.

Increases = 77,000 TPY GHG mass emissions increase fr om 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 credit able 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 incr ease is greater than zero TPY, so

Go to the CO 2 e- based calculations

CO 2 e-Based Calculations

(Step 1 ) In this step only consider CO 2 e emissions increases from the modification.

Unit #2 77,000 TPY CO 2 e emissions increase

Unit #1 The proposed CO 2 e emissions after the m odification are 660 TPY CO 2 e, which is a 1,840 TPY CO 2 e decrease from baseline actual emissions of 2,500 TPY CO 2 e. Since it is a decrease, ignore the change in CO 2 e emissions.

Increases = 77,000 TPY CO 2 e emissions increase from Unit #2 is equal to or greater than 75,000 TPY CO 2 e, so

Go to Step 2 and conduct contemporaneous netting

(Step 2 ) In this step consider all em issions increases and decreases of CO 2 e from the proposed project and all other contemporaneous and credit able emissions increases and decreases of

CO 2 e

.

Net emissions increase = 77,000 TPY CO 2 e emissions increase from Unit #2 minus 1,840 TPY

CO 2 e emissions decrease from Unit #1 plus a 10,000 TPY CO 2 e emissions increase from Unit A equals 85,160 TPY CO 2 e emissions. This net emissions increase is equal to or greater than 75,000 TPY CO 2 e.E-3 Results: The modification is both a “sig nificant emissions increase” (Step 1) and a “significant net emissions increase” (Step 2) in both the mass and CO 2 e-based calculations; therefore, the modification as proposed is major and subject to PSD for GHGs.F-1 

### Appendix F. BACT Exam ple – 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 inst all, at an existing PSD major source, a new 250 MMBtu/hour natural gas-fire d boiler. The projec t’s emissions increas e is in excess of 75,000 TPY CO 2 e and the permit will be issued in Marc h 2011, so the project is subject to BACT for GHGs under Step 1 of the Tailoring Rule . For the sake of si mplicity, this example focuses on the section of the BACT analys is 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 boile r is tuned for optimal thermal efficiency.

• Boiler Oxygen Trim Control – Stack oxygen leve l is monitored and the inlet air flow is adjusted for optimal thermal efficiency.

• Use of an Economizer – A heat exchanger is us ed to transfer some of the heat from the boiler exhaust gas to the incoming boiler feedwa ter. 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 boile r as feedwater, the bo iler heating load is reduced and the thermal efficiency increases.

As would be appropriate under EP A’s guidelines for Step 1 of th e 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 combusti on 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 bo iler is necessary to fulfill the fundamental business purpose of providing process steam (and not generating elect ricity) and because a varying steam demand requires the ability to startup and shutdown the bo iler 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 applican t 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 s howed that any of these options was not demonstrated or available or applicable to this type of source.

Step 3 : Evaluation and ranking of cont rols 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. Assu me 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 CO 2 control efficiency because fuel use is directly related to CO 2 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 th an an economizer in recovering exhaust heat, and so the applicant narrowed the review to the econ omizer only. In this example, the applicant’s analysis next considered the e ffectiveness of the boiler controls in combinations and found that

the most effective combination of measures is the use of four measures – oxyge n 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 anal ysis 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, th e applicant found that, gi ven the size and other characteristics of this facility, the packages including boiler blowdown heat recovery was not cost effective (as an incremental measure compar ed to cost born by similar facilities) and the

next most effective combination of measures fo r 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 rela ted 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 addi tional 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 faci lity 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 author ity included the following permit terms in the permit:

• Emission limit expressed in lbs of CO 2 e emissions per pound of steam produced, averaged over 30 day rolling periods;

• CO 2 e emissions are to be determined based on metered natural gas use and the application of standa rd 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 ca libration 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 CO 2 e 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 con duct 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 S ubpart 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 th e permitting authority determine that the NSPS is a useful starting point for a GHG BACT dete rmination since it has detailed requirements for the design and operation of th e gas collection system.

For capture of the landfill gas, the application uses complian ce with the NSPS as the starting point. For control, the appli cant identified the follo wing 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 combus tion engines to generate electricity, or

• treatment of the gas for delivery to a natural gas pipeline.

The applicant did not identify or propose any alte rnative control options in the application, and none were suggested in public comments. Ho wever, the permitting authority did ask the applicant to expand the review to consider tw o other control measures : (1) a requirement to

collect and control landfi ll gas earlier in the life of the landfill than is sp ecified 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 co llection and treatment) and four control options listed for the control of the landfill gas that is collected (fla ring, 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 a ccepted elimination of that option from further consideration.

Step 3 : Evaluation and ranking of cont rols 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 CO 2 e emissions over the life of the landfill, ba sed on the current business plan and design, as the effectiveness indicator. The applicant explained that the CO 2 e emissions estimates in their application reflected the direct emissions of GHGs and the CO 2 produced for the options where that gas was combusted on site. The applicati on 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 th at the maximum amount of gas would be captured and most of the gas would not be combusted on site. The record al so 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 wh ile generating relatively small on-site CO 2 emissions in the process.

Step 4 : Evaluating the most effective c ontrols and documenting results

In this step, the applicant completed an analysis of the cost effectiven ess of control measures, expressed as $/ton of GHG reduced, and also determ ined the incremental cost effectiveness. In this example, the applicant’s analysis first f ound 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 co llection was cost effectiv e in both the flare and the engines case. There was also evidence in th e record showing that the flare was more cost effective because revenue from the sale of power fr om 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, th e application noted that there was a positive environmental impact from the use of a flare because NO X 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 associ ated emissions. In responding to the comments, the permitting authority determined that this benefit outweighed the lower NO X emissions from the flare. The permit record also demonstrated that the use of engines or a flare would haveG-3 nearly equal CO 2 e control effectiveness. Accordingly, the permitting authority found that the environmental benefits arising from the engi nes-based system outwei ghed the flare’s cost

effectiveness and environmental benefits of lower NO X 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 propos ed facility was NSPS compliance with early implementation of the capture a nd 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 opera tion requirements of the applicable NSPS

with a revised condition for earlier capture and contro l of the gas.

• A requirement to combust the collected gas in engines with the cr eation and use of an O&M plan for the engines to assure that they operate efficiently.H-1 

### Appendix H. BACT Example – Pe troleum 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 hydroge n in order to convert crude oil to finished products. In this example, a permit applicant proposes a modi fication project to expand the hydrogen production and hydrotreati ng capacity of an existing ma jor 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 CO 2 e 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 provide d in a gas-fired reformer furnace. The CO generated by the initial SMR reaction further re acts with the steam to generate hydrogen and

CO 2

. The hydrogen is then separated from the CO 2 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 fr om that step (containing some hydrogen, CO 2 , 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 e xhaust and the process st reams 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.

• CO 2 Capture and Storage – Capture and compressi on, transport, and geologic storage of

the CO 2 . (Some refineries isolate hydrogen reformer CO 2 for sale but that is not a part of this example project.)

The permitting authority did not require the applican t 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 applican t and the permitting authority examine the control options for technical feasibility. In this exam ple, 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 applic able to this type of source.

Step 3 : Evaluation and ranking of cont rols 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 installe d hydrogen plants was provided. The applicant showed that by incor porating various heat r ecovery measures this hydrogen plant would be a lower emitter (on an output basis) than similar new plants, and the permitting authority concurred in that determinati on. The applicant’s analysis considered the

effectiveness of each individual measure and comb inations 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 c ontrols and documenting results

In this step, the permit applicant completed an anal ysis 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 trans port and sequestration of CO 2 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 ot her suitable method for CO 2 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 CO 2 to be sequestered and the co st of the project overall. Although the permitting authority affirmed this de termination, 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 CO 2 injection for enhanced recove ry, the cost for transport and sequestration would likely be in a range that wo uld 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 al so 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 a ddressed 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 re covery. Accordingly, the permitting authority included the following permit terms in the permit:

• Emission limit in pounds of CO 2 e emitted per pound of hydrogen produced, averaged over rolling 30-day periods.

• CO 2 e 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 refi nery. 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, in cluding 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 emissi ons standards for haza rdous air pollutants, and Section 111(d) standards for designated pollutants;

• AP-42 Emission Factors;

• Emission factors from technical literature; and

• State emission inventory questionn aires for comparable sources.

These approaches remain relevant for GHG emissi ons 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 basi s for estimating emissions from GHG emissions units. However, because GHG emissions historica lly 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 e xperience with GHG estimation techniques and

measurement methods as there is for conventio nal pollutants under the ab ove approaches. The purpose of this section is to iden tify additional references and res ources that may be useful when evaluating GHG emission sources and deci ding 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 tec hniques when preparing or processing permit applications. The rule includes procedures for estimating GHG emissions from the source categories that are responsible fo r the majority of stationary so urce GHG emissions in the U.S. The procedures identify where applications of direct measurement techniques are viable and

describes emission factor and mass-balance ba sed 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 im ply that such sources or emissions units are excluded from permitting requirements. For example, as of the date of this publication CO 2 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 appro aches can be used to estimate a source’s PTE when correctly adjusted to reflect future condi tions 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 uni ts and which are applied on a case-by-case basis depending on specific operating pa rameters for the affected sources.

Other reference sources that may prove usef ul to sources and permitting authorities in identifying, characterizing and estimating emi ssions 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 Partnershi ps for GHG Reductions:

− Landfill Methane Outreach Progr am (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 Partners hip 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 CO 2 emission sources, such as:

• Wastewater (CO 2 from treatment processes a nd digester gas combustion)

• Ethanol Fermentation Processes (CO 2 )

EPA is currently researching and developing em ission estimating procedures for these biogenic

CO 2 sources and will be making these available in the near future through EPA’s website (www.epa.gov). Prior to these methods becoming avai lable, sources will still be responsible for including these emissions for GHG permitting pur poses and will need to propose methods for assessing and measuring these emissions that ar e 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 Partnershi ps for GHG Reductions:

- Landfill Methane Outreach Progr am (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 Partners hip (http://www.epa.gov/highgwp/aluminumpfc/index.html)

- CHP Partnership Program (http://www.epa.gov/chp)

• SF Emission Reduction Partners hip 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.cf m?c=industry.bus_industry_info_center

• DOE Industrial Technologies Program: http://www1.eere.en ergy.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.htmK-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 us ed to assess the potential for achieving an objective at least cost. Effectiveness is measur ed in terms of tons of pollutant emissions

removed. Cost is measured in te rms of annualized control costs.

Cost effectiveness calculations can be conducte d 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. Ther e are limits to the use of cost-effectiveness analysis. For example, cost-effectiveness analys is should not be used to set the environmental objective. Second, cost-effectivenes s 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-effectivene ss, 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 re quirements 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, calcula ted using realistic upper boundary operating assumptions. When calculating the cost effectiv eness 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 do es not mean that the source operates in

an absolute worst case manner all the time. For example, in devel oping a realistic upper boundary case, baseline emissions ca lculations can also consider inherent physical or operational

constraints on the source. Such constraints s hould accurately reflect th e true upper boundary of the source’s ability to physically operate a nd the applicant should submit documentation to verify these constraints. If the applicant does not adequa tely verify these constraints, then the reviewing agency should not be compelled to cons ider these constraints in calculating baseline emissions. In addition, the reviewing agency may require the applicant to calculate cost effectiveness based on values exceeding the uppe r boundary assumptions to determine whether or not the assumptions have a deciding role in th e BACT determination. If the assumptions have a deciding role in the BACT determination, th e 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 stor age tank might vary significantly with temperature, volatility of liquid stored, and thro ughput. In this case, po tential 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 dete rmining 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 termin al should consider emissions based on the most volatile liquids at a high annual th roughput 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 evaluati ng the cost effectiveness of a control option for a specific source. For example, if for a sour ce or industry, histori cal 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 co mparing cost effectiveness, the same realistic upper boundary assumptions must, however, be us ed for both the source in question and other sources (or source categories) that will late r be compared during the BACT analysis.

For example, suppose (based on verified histor ic 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 fr om a high VOC content to a relatively low VOC content. The source verifies that its operation wi ll 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 exp ected mix of inks that would be expected to result in an upper boundary case annual VOC emissi ons rather than an assumption that only one color ( i.e., the ink with the highest VOC content) w ill be applied exclusively during the whole

year.

In another example, suppose sources in a partic ular industry historically operate at most at 85 percent capacity. For BACT cost effectiveness purposes (but not for applicability), an applicant may calculate cost effectiveness usi ng 85 percent capacity. However, in comparingK-3 costs with similar sources, the applicant must consistently use an 85 percent capacity factor for

the cost effectiveness of c ontrols on those other sources.

Although permit conditions are normally used to make operating assumptions enforceable, the use of “standard industry practic e” 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 enforc eable 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 base line emissions. This is necessary to ensure that the permit reflects the conditions under which the source intends to operate.

For example, the baseline emissions calculati on 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 woul d not consider limited hours of operation. This produces a significantly hi gher level of baseline emissions than in the case of the emergency/standby unit a nd results in more cost effectiv e 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 exp licit 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 baseli ne 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 desi gn specifications contained in the permit application.

For some sources it may be more difficu lt to define what emissions level actually represents uncontrolled emissions in calculating baseline emissi ons. 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 co ating or application ra te 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 th e amount of emissions reductions to be achieved by the installation of various contro l 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 applicati on rates that would be us ed by the source, rather than by highest VOC based coating materials or rate of application in general.K-4 Conversely, if uncontrolled emissions are unde restimated, emissions reductions to be achieved by the various contro l options would also be unde restimated 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 ab ility 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 calcula ted. The incremental cost

effectiveness should be examined in combination with the total cost eff ectiveness in order to justify elimination of a control option. The incr emental cost effectiveness calculation compares the costs and emissions performance level of a cont rol option to those of th e next most stringent option, as shown in the following formula:

Incremental Cost (dollars per incremental ton removed) =

Total costs (annualized) of control option - Tota l 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 s hould focus on annualized cost and emission

reduction differences between dominant alternatives. Dominant set of control alternatives are determined by generating what is called the enve lope of least-cost alte rnatives. This is a graphical plot of total annualized costs for a tota l emissions reductions for all control alternatives identified in the BACT analysis (see Figure B-1).K-5K-6 For example, assume that eight technically available control options for analysis are listed in the BACT hierarchy. These are re presented as A through H in Figure B-1. In calculating incremental costs, th e analysis should only be conducte d 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 enve lope depicted by the curv ilinear 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 a nd 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 sele cting the dominant set of controls when calculating incremental costs. First, the contro l options need to be rank ordered in ascending order of annualized total costs. Then, as Fi gure B-1 illustrates, the most reasonable smooth curve of the control options is pl otted. 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 illustra ted 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 Re duced (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 effi ciencies. 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 oper ation range of a control device.

As a precaution, differences in incremental costs among dominant alternatives cannot be used by itself to argue one dominan t 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 prefe rred to F on grounds of

incremental cost effectiveness.

In addition, when evaluating the total or in cremental cost effectiveness of a control alternative, reasonable and suppor table assumptions regarding c ontrol efficiencies should be made. An unrealistically low assessment of the emission redu ction potential of a certain technology could result in inflated cost effectiveness figures.

The final decision regarding th e reasonableness of calculated cost effectiveness values will be made by the review authority consider ing 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.