F

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Part III

EnvironmentalProtection Agency40 CFR Part 51

Regional Haze Regulations and Guidelinesfor Best Available Retrofit Technology(BART) Determinations; Final Rule
PREPARATION, ADOPTION, AND

SUBMITrAL OF IMPLEMENTATION

PLANS

• 1. The authority citation for part 51continues to read as follows:

Authority: 23 U.S.C. 101; 42 U.S.C. 7410—

7671q.

• 2. Section 51.302 is amended by

revising paragraph (c)(4)(iii) to read as

follows:

§ 51.302 Implementation control strategies

for reasonably attributable visibility

impairment.

* * * * *

(c) * * *

(4) * * *(iii) BART must be determined for

fossil-fuel fired generating plants having

a total generating capacity in excess of

750 megawatts pursuant to “Guidelines

for Determining Best Available Retrofit

Technology for Coal-fired Power Plantsand Other Existing Stationary Facilities”

(1980), which is incorporated by

reference, exclusive of appendix

E to the

Guidelines, except that options more

stringent than NSPS must be

considered. Establishing a BART

emission limitation equivalent to the

NSPS level of control is not a sufficient

basis to avoid the analysis of control

options required by the guidelines. Thisdocument is EPA publication No. 450/3—80—009b and has been approved for

incorporation by reference by the

Director of the Federal Register in

accordance with 5 U.S.C. 552(a) and 1

CFR part 51. It is for sale from the U.S.

Department of Commerce, NationalTechnical Information Service, 5285Port Royal Road, Springfield, Virginia

22161. It is also available for inspection

from the National Archives and Records

Administration (NARA). For

information on the availability of thismaterial at NARA, call 202—741—6030,or go to: http://www.orchives.gov/

federoLregister/index.html.

• 3, Section 51.308 is amended by

revising paragraph (N removing andreserving paragraph (c), revising

paragraphs (e)(1)(ii), (e)(3), and (e)(4),and adding paragaphs (e)(5) and (6) toread as follows:

(c) (Reservedl * * * * *(e) * * *

(i) * * *(ii)

A determination of BART for each

BART-eligible source in the State that

emits any air pollutant which may

reasonably be anticipated to cause or

contribute to any impairment of

visibility in any mandatory Class IFederal area. All such sources are

subject to BART.

(A) The determination of BART must

be based on an analysis of the best

system of continuous emission control

technology available and associated

emission reductions achievable for each

BART-eligible source that is subject to

BART within the State. In this analysis,

the State must take into considerationthe technology available, the costs of

compliance, the energy and nonair

quality environmental impacts of

compliance, any pollution controlequipment in use at the source, the

remaining useful life of the source, and

the degree of improvement in visibility

which may reasonably be anticipated toresult from the use of such technology.

(B) The determination of BART for

fossil-fuel fired power plants having a

total generating capacity greater than

750 megawatts must be made pursuant

to the guidelines in appendix

Y of this

part (Guidelines for BART

Determinations Under the Regional

Haze Rule).

(C) Exception.

A State is not required

to make a determination of BART for

SO2or for NOx if a BART-eligible

source has the potential to emit less

than 40 tons per year of suchpollutant(s), or for PM10 if a BARTeligible source emits less than 15 tons

per year of such pollutant. * * * * *

(3)

A State which opts under 40 CFR

51.308(e)(2) to implement an emissions

trading program or other alternativemeasure rather than to require sources

subject to BART to install, operate, and

maintain BART may satisfy the final

step of the demonstration required by

that section as follows: If the

distribution of emissions is not

substantially different than under

reasonable progress” if both of the

following two criteria are met:

(i) Visibility does not decline in any

Class I area, and

(ii) There is an overall improvement

in visibility, determined by comparing

the average differences between BART

and the alternative over all affectedClass I areas.

(4)

A State that opts to participate in

the Clean Air Interstate Rule cap-andtrade and trade program under part 96

AAA—EEE need not require affected

BART-eligible EGU’s to install, operate,

and maintain BART.

A State that

chooses this option may also include

provisions for a geographic

enhancement to the program to address

the requirement under § 5 1.302(c)

related to BART for reasonablyattributable impairment from the

pollutants covered by the CAIR cap-andtrade program.

(5) After a State has met the

requirements for BART or implemented

emissions trading program or other

alternative measure that achieves more

reasonable progress than the installation

and operation of BART, BART-eligible

sources will be subject to the

requirements of paragraph (d) of this

section in the same manner as othersources.

(6) Any BART-eligible facility subject

to the requirement under paragraph (e)

of this section to install, operate, and

maintain BART may apply to the

Administrator for an exemption fromthat requirement. An application for an

exemption will be subject to the

requirements of § 51.303(a)(2)—(h). * * * * *• 4. Appendix

Y to Part 51 is added to

read as follows:

Appendix

Y to Part 51—Guidelines for

BART Determinations Under theRegional Haze Rule

Table of ContentsI. Introduction and Overview

A. What is the purpose of the guidelines?

B. What does the CAA require generally for

improving visibility?

C. What is the BART requirement in the

CAA?

0. What types of visibility problems does

EPA address in its regulations?
emission units

3. Step 3: Compare the potential emissions

to the 250 ton/yr cutoff

4. Final step: Identify the emission units

and pollutants that constitute the BART

eligible source.

III. How to Identify Sources ‘Subject to

BART”

IV. The BART Determination: Analysis of

BART Options

A. What factors must I address in the

BART Analysis?

B. What is the scope of the BART review?

C. How does a BART review relate to

maximum achievable control technology

(MACT) standards under CAA section112?

D. What are the five basic steps of a caseby-case BART analysis?

1. Step 1: How do I identify all available

retrofit emission control techniques?

2. Step 2: How do I determine whether the

options identified in Step 1 are

technically feasible?

3. Step 3: How do I evaluate technically

feasible alternatives?

4. Step 4: For a BART review, what

impacts am I expected to calculate andreport? What methods does EPArecommend for the impacts analyses?

a. Impact analysis part 1: how do I estimate

the costs of control?

b. What do we mean by cost effectiveness?

c. How do I calculate average cost

effectiveness?

d. How do I calculate baseline emissions?

e. How do I calculate incremental cost

effectiveness?

f. What other information should I provide

in the cost impacts analysis?

g. What other things are important to

consider in the cost impacts analysis?

h. Impact analysis part 2: How should I

analyze and report energy impacts?

i. Impact analysis part 3: How do I analyze

“non-air quality environmental

impacts?”

j. Impact analysis part 4: What are

examples of non-air quality

environmental impacts?

k. How do I take into account a project’s

“remaining useful life” in calculatingcontrol costs?

5. Step 5: How should I determine

visibility impacts in the BART

determination?

E. How do I select the “best” alternative,

using the results of Steps 1 through 5?

1. Summary of the impacts analysis

2. Selecting a “best” alternative

3. In selecting a “best” alternative, should

I consider the affordability of controls?

4. SO2limits for utility boilers

CFR 51.300 through 51.309. These

regulations require, in 40 CFR 51.308(e), that

certain types of existing stationary sources of

air pollutants install best available retrofit

technology (BART). The guidelines are

designed to help States and others (1)identify those sources that must comply with

the BART requirement, and (2) determine thelevel of control technology that represents

BART for each source.B. Whot does the CAA require generolly for

improving visibility?

Section 169A of the CAA, added to the

CAA by the 1977 amendments, requires

States to protect and improve visibility in

certain scenic areas of national importance.

The scenic areas protected by section 169A

are “the mandatory Class I Federal Areas * * * where visibility is an important

value.” In these guidelines, we refer to these

as “Class I areas.” There are 156 Class I areas,including 47 national parks (under the

jurisdiction of the Department of Interior—National Park Service), 108 wilderness areas

(under the jurisdiction of the Department of

the Interior—Fish and Wildlife Service or the

Department of Agriculture—U.S. Forest

Service), and one International Park (under

the jurisdiction of the Roosevelt-Campobello

International Commission). The Federal

Agency with jurisdiction over a particularClass I area is referred to in the CAA as theFederal Land Manager.

A complete list of the

Class I areas is contained in 40 CFR 81.401

through 81.437, and you can find a map of

the Class I areas at the following Internet site:

http://www.epo.gov/ttn/oorpg/tl/fr_notices/

clossimp.gif.

The CAA establishes a national goal of

eliminating man-made visibility impairment

from all Class I areas, As part of the plan forachieving this goal, the visibility protection

provisions in the CAA mandate that EPAissue regulations requiring that States adopt

measures in their State implementation plans

(SIPs), including long-term strategies, to

provide for reasonable progress towards thisnational goal. The CAA also requires States

to coordinate with the Federal LandManagers as they develop their strategies foraddressing visibility.

C. Whot is the BART requirement in the

CAA?

1. Under section 169A(b)(2)(A) of the CAA,

States must require certain existing stationary

sources to install BART. The BART provision

applies to “major stationary sources” from 26

identified source categories which have thepotential to emit 250 tons per year or more

of any air pollutant. The CAA requires onlysources which were put in place during a

control as BART, States are required by

section 169A(g) of the CAA to consider:

(a) The costs of compliance,

(b) The energy and non-air quality

environmental impacts of compliance,

(c) Any existing pollution control

technology in use at the source,

(d) The remaining useful life of the source,

and

(e) The degree of visibility improvement

which may reasonably be anticipated from

the use of BART.

3. The CAA further requires States to make

BART emission limitations part of their SIPs.

As with any SIP revision, States mustprovide an opportunity for public comment

on the BART determinations, and EPA’s

action on any SIP revision will be subject to

judicial review.D. Whot types of visibility problems does EPA

oddress in its regulotions?

I. We addressed the problem of visibility

in two phases. In 1980, we publishedregulations addressing what we termed

“reasonably attributable” visibility

impairment. Reasonably attributable

visibility impairment is the result of

emissions from one or a few sources that are

generally located in close proximity to a

specific Class I area. The regulations

addressing reasonably attributable visibility

impairment are published in 40 CFR 51.300

through 51.307.

2. On July 1, 1999, we amended these

regulations to address the second, more

common, type of visibility impairmentknown as “regional haze.” Regional haze isthe result of the collective contribution of

many sources over a broad region. The

regional haze rule slightly modified 40 CFR

51.300 through 51.307, including the

addition of a few definitions in § 51.301, andadded new

§ 51.308 and 51.309.

E. Whot ore the BART requirements in EPA’s

regionol hoze regulotions?

1. In the July 1, 1999 rulemaking, we added

a BART requirement for regional haze. We

amended the BART requirements in 2005.You will find the BART requirements in 40

CFR 51.308(e). Definitions of terms used in40 CFR 51.308(e)(1) are found in 40 CFR

5 1.301.

2. As we discuss in detail in these

guidelines, the regional haze rule codifies

and clarifies the BART provisions in theCAA. The rule requires that States identify

and list “BART-eligible sources,” that is, that

States identify and list those sources that fall

within the 26 source categories, were put in

place during the 15-year window of timefrom 1962 to 1977, and have potential
—States must identify the best system of

continuous emission control technology foreach source subject to HART taking intoaccount the technology available, the costsof compliance, the energy and non-air

quality environmental impacts ofcompliance, any pollution controlequipment in use at the source, the

remaining useful life of the source, and the

degree of visibility improvement that may

be expected from available control

technology.

3. After a State has identified the level of

control representing BART (if any), it mustestablish an emission limit representing

HART and must ensure compliance with thatrequirement no later than 5 years after EPAapproves the SIP. States may establishdesign, equipment, work practice or otheroperational standards when limitations on

measurement technologies make emission

standards infeasible.

F. What is included in the guidelines?

1. The guidelines provide a process for

making BART determinations that States canuse in implementing the regional haze BARTrequirements on a source-by-source basis, asprovided in 40 CFR 51.308(e)(1). States mustfollow the guidelines in making HARTdeterminations on a source-by-source basisfor 750 megawatt (MW) power plants but are

not required to use the process in the

guidelines when making HART

determinations for other types of sources.

2. The HART analysis process, and the

contents of these guidelines, are as follows:

(a) Identification of all BART-eligible

sources. Section II of these guidelinesoutlines a step-by-step process for identifying

HART-eligible sources.

(b) Identification ofsources subject to

BART. As noted above, sources “subject toHART” are those HART-eligible sourceswhich “emit a pollutant which mayreasonably be anticipated to cause orcontribute to any impairment of visibility inany Class I area.” We discuss considerationsfor identifying sources subject to HART insection III of the guidance.

(c) The BART determinotion process. For

each source subject to HART, the next step

is to conduct an analysis of emissions controlalternatives. This step includes theidentification of available, technicallyfeasible retrofit technologies, and for each

technology identified, an analysis of the cost

of compliance, the energy and non-air quality

environmental impacts, and the degree of

visibility improvement in affected Class I

areas resulting from the use of the control

technology. As part of the HART analysis, the

State should also take into account the

limits are discussed in section

V of these

guidelines.

G. Who is the target audience for the

guidelines?

1. The guidelines are written primarily for

the benefit of State, local and Tribal agencies,

and describe a process for making the HARTdeterminations and establishing the emission

limitations that must be included in their

SIPs or Tribal implementation plans (TIPs).

Throughout the guidelines, which are writtenin a question and answer format, we ask

questions “How do * * *? and answer

with phrases “you should * * ‘, you must * * * “ The “you” means a State, local orTribal agency conducting the analysis. Wehave used this format to make the guidelinessimpler to understand, but we recognize that

States have the authority to require source

owners to assume part of the analytical

burden, and that there will be differences inhow the supporting information is collected

and documented. We also recognize that data

collection, analysis, and rule development

maybe performed by Regional Planning

Organizations, for adoption within each SIPor TIP.

2. The preamble to the 1999 regional haze

rule discussed at length the issue of Tribalimplementation of the requirements tosubmit a plan to address visibility. Asexplained there, requirements related to

visibility are among the programs for which

Tribes maybe determined eligible andreceive authorization to implement under the

“Tribal Authority Rule” (“TAR”) (40 CFR

49.1 through 49.11). Tribes are not subject to

the deadlines for submitting visibility

implementation plans and may use a

modular approach to CAA implementation.We believe there are very few HART-eligiblesources located on Tribal lands. Where suchsources exist, the affected Tribe may applyfor delegation of implementation authorityfor this rule, following the process set forth

in the TAR.H. Do EPA regulations require the use of

these guidelines?

Section 169A(b) requires us to issue

guidelines for States to follow in establishingHART emission limitations for fossil-fuel

fired power plants having a capacity inexcess of 750 megawatts. This document

fulfills that requirement, which is codified in40 CFR 51.308(e)(lj(ii)(H). The guidelinesestablish an approach to implementing the

requirements of the HART provisions of theregional haze rule; we believe that theseprocedures and the discussion of the

requirements of the regional haze rule andthe CAA should be useful to the States. For

g

Figure 1 shows the steps for identifying

whether the source is a “HART-eligible

source:”

Step 1: Identify the emission units in the

HART categories,

Step 2: Identify the start-up dates of those

emission units, and

Step 3: Compare the potential emissions to

the 250 ton/yr cutoff.

Figure 1. How to determine whether a

source is HART-eligible:

Step 1: Identify emission units in the

HART categories

Does the plant contain emissions units in one

or more of the 26 source categories?-No -+Stop-4 Yes

4 Proceed to Step 2

Step 2: Identify the start-up dates of these

emission units

Do any of these emissions units meet the

following two tests?

In existence on August 7, 1977

AND

Hegan operation after August 7, 1962

-No -eStop

-, Yes -4 Proceed to Step 3

Step 3: Compare the potential emissions

from these emission units to the 250 ton/yrcutoff

Identify the “stationary source” that

includes the emission units youidentified in Step 2.

Add the current potential emissions from

all the emission units identified in StepsI and 2 that are included within the“stationary source” boundary.

Are the potential emissions from these

units 250 tons per year or more for anyvisibility-impairing pollutant?-No -Stop—, Yes -4 These emissions unitscomprise the “HART-eligible source.”

1. Step 1: Identify Emission Units in the

HART Categories

1. The HART requirement only applies to

sources in specific categories listed in theCAA. The HART requirement does not apply

to sources in other source categories,regardless of their emissions. The listed

categories are:

(1) Fossil-fuel fired steam electric plants of

more than 250 million Hritish thermal units

(HTU) per hour heat input,

(2) Coal cleaning plants (thermal dryers),(3) Kraft pulp mills,(4) Portland cement plants,(5) Primary zinc smelters,

(6) Iron and steel mill plants,(7) Primary aluminum ore reduction

plants,
(18) Fuel conversion plants,(19) Sintering plants,(20) Secondary metal production facilities,(21) Chemical process plants,(22) Fossil-fuel boilers of more than 250

million BTUs per hour heat input,

(23) Petroleum storage and transfer

facilities with a capacity exceeding 300,000

barrels,

(24) Taconite ore processing facilities,(25) Class fiber processing plants, and(26) Charcoal production facilities.

2. Some plants may have emission units

from more than one category, and someemitting equipment may fit into more thanone category. Examples of this situation are

sulfur recovery plants at petroleumrefineries, coke oven batteries and sinteringplants at steel mills, and chemical processplants at refineries. For Step 1, you identifyall of the emissions units at the plant that fitinto one or more of the listed categories. You

do not identify emission units in other

categories.

Example:

A mine is collocated with an

electric steam generating plant and a coalcleaning plant. You would identify emission

units associated with the electric steam

generating plant and the coal cleaning plant,

because they are listed categories, but not the

mine, because coal mining is not a listed

category.

3. The category titles are generally clear in

describing the types of equipment to be

listed. Most of the category titles are very

broad descriptions that encompass all

emission units associated with a plant site

(for example, “petroleum refining” and “kraft

pulp mills”). This same list of categories

appears in the PSD regulations. States andsource owners need not revisit any

interpretations of the list made previously forpurposes of the PSD program. We provide thefollowing clarifications for a few of thecategory titles:

(1) “Steam electric plants of more than 250

million BTU/hr heat input.” Because thecategory refers to “plants,” we interpret thiscategory title to mean that boiler capacitiesshould be aggregated to determine whether

the 250 million BTU/hr threshold is reached.This definition includes only those plantsthat generate electricity for sale. Plants that

cogenerate steam and electricity also fall

within the definition of “steam electricplants”. Similarly, combined cycle turbines

are also considered “steam electric plants”

because such facilities incorporate heat

recovery steam generators. Simple cycleturbines, in contrast, are not “steam electric

plants” because these turbines typically donot generate steam,

process description at a p

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different BART category—for example, a

boiler at a Kraft pulp mill that, in additionto providing steam or mechanical power,uses the waste liquor from the process as a

fuel. In general, if the process uses any byproduct of the boiler and the boiler’s function

is to serve the process, then the boiler isintegral to the process and should beconsidered to be part of the processdescriptiod.

Also, you should consider a multi-fuel

boiler to be a “fossil-fuel boiler” if it burns

any amount of fossil fuel. You may takefederally and State enforceable operational

limits into account in determining whether amuhi-fuel boiler’s fossil fuel capacity

exceeds 250 million Btu/hr.

(3) ‘Petroleum storage and transfer

facilities with a capacity exceeding 300,000

barrels.” The 300,000 barrel cutoff refers to

total facility-wide tank capacity for tanks thatwere put in place within the 1962—1977 time

period, and includes gasoline and other

petroleum-derived liquids.

(4) “Phosphate rock processing plants.”

This category descriptor is broad, andincludes all types of phosphate rock

processing facilities, including elementalphosphorous plants as well as fertilizer

production plants.

(5) “Charcoal production facilities.” We

interpret this category to include charcoal

briquet manufacturing and activated carbon

production.

(6) “Chemical process plants.” and

pharmaceutical manufacturing. Consistent

with past policy, we interpret the category

“chemical process plants” to include those

facilities within the 2-digit Standard

Industrial Classification (SIC) code 28.

Accordingly, we interpret the term “chemical

process plants” to include pharmaceutical

manufacturing facilities.

(7) “Secondary metal production.” We

interpret this category to include nonferrousmetal facilities included within SIC code

3341, and secondary ferrous metal facilities

that we also consider to be included within

the category “iron and steel mill plants.”

(8) “Primary aluminum ore reduction.” We

interpret this category to include those

facilities covered by 40 CFR 6 0.190, the new

source performance standard (NSPS) for

primary aluminum ore reduction plants. Thisdefinition is also consistent with thedefinition at 40 CFR 63.840.2. Step 2: Identify the Start-Up Dates of the

Emission Units

1. Emissions units listed under Step I are

BART-eligible only if they were “inexistence” on August 7, 1977 but were not

“in operation” before August 7, 1962.

canceled or modified without substantial loss

to the owner or operator, to undertake a

program of construction of the facility to be

completed in a reasonable time.” 40 CFR

5 1. 301.

As this definition is essentially identical to

the definition of “commence construction”

as that term is used in the PSD regulations,

the two terms mean the same thing. See 40CFR 51.165(a)(1)(xvi) and 40 CFR 52.21(bj(9).

Under this definition, an emissions unitcould be “in existence” even if it did not

begin operating until several years after 1977.

Example: The owner of a source obtained

all necessary permits in early 1977 andentered into binding construction agreements

in June 1977. Actual on-site construction

began in late 1978, and construction was

completed in mid-1979. The source began

operating in September 1979. The emissions

unit was “in existence” as of August 7, 1977.

Major stationary sources which

commenced construction AFTER August 7,

1977 (i.e., major stationary sources which

were not “in existence” on August 7, 1977)were subject to new source review (NSR)under the PSD program. Thus, the August 7,

1977 “in existence” test is essentially the

same thing as the identification of emissions

units that were grandfathered from the NSR

review requirements of the 1977 CAAamendments.

3. Sources are not BART-eligible if the only

change at the plant during the relevant timeperiod was the addition of pollution controls.

For example, if the only change at a coppersmelter during the 1962 through 1977 time

period was the addition of acid plants for thereduction of SO2emissions, these emission

controls would not by themselves trigger aBART review.

What does “in operation before August 7,

1962” mean?

An emissions unit that meets the August 7,

1977 “in existence” test is not BART-eligible

if it was in operation before August 7, 1962.

“In operation” is defined as “engaged in

activity related to the primary design

function of the source.” This means that asource must have begun actual operations byAugust 7, 1962 to satisfy this test.

Example: The owner or operator entered

into binding agreements in 1960. Actual onsite construction began in 1961, andconstruction was complete in mid-1962. Thesource began operating in September 1962.

The emissions unit was not “in operation”before August 7, 1962 and is therefore subject

to BART.What is a “reconstructed source?’

1. Under a number of CAA programs, an

existing source which is completely or
if 

the fixed capital cost of the new

component exceeds 50 percent of the fixedcapital cost of a comparable entirely newsource.” The rule also states that “lalny finaldecision as to whether reconstruction hasoccurred must be made in accordance with

the provisions of §560.15 (0(1) through (3) ofthis title.” “[Tjhe provisions of §5 60.15(11(1)through (3)” refers to the general provisions

for New Source Performance Standards(NSPS). Thus, the same policies and

procedures for identifying reconstructed

“affected facilities” under the NSPS program

must also be used to identify reconstructed

“stationary sources” for purposes of the

BART requirement.

3. You should identify reconstructions on

an emissions unit basis, rather than on aplantwide basis. That is, you need to identifyonly the reconstructed emission units

meeting the 50 percent cost criterion. You

should include reconstructed emission units

in the list of emission units you identified in

Step 1. You need consider as possible

reconstructions only those emissions unitswith the potential to emit more than 250 tonsper year of any visibility-impairing pollutant.

4. The “in operation” and “in existence”

tests apply to reconstructed sources. If an

emissions unit was reconstructed and began

actual operation before August 7, 1962, it is

not DART-eligible. Similarly, any emissionsunit for wbicb a reconstruction

“commenced” after August 7, 1977, is not

DART-eligible.How are modifications treated under theDART provision?

1. The NSPS program and the major source

NSR program both contain the concept ofmodifications. In general, tbe term

“modification” refers to any physical change

or change in the method of operation of anemissions unit that results in an increase in

emissions.

2. The DART provision in the regional haze

rule contains no explicit treatment ofmodifications or how modified emissionsunits, previously subject to the requirementto install best available control technology

(DACTj, lowest achievable emission rate(LAER) controls, and/or NSPS are treated

under the rule. As the DART requirements inthe CAA do not appear to provide anyexemption for sources which have been

modified since 1977, the best interpretation

of the CAA visibility provisions is that a

subsequent modification does not change a

unit’s construction date for the purpose ofDART applicability. Accordingly, if an

emissions unit began operation before 1962,

it is not DART-eligible if it was modified

between 1962 and 1977, so long as themodification is not also a “reconstruction.”

p

of emissions units at a given plant site,including reconstructed emissions units, thatare within one or more of the DARTcategories and that were placed intooperation within the 1962—1977 time

window. The third step is to determinewhether the total emissions represent acurrent potential to emit that is greater than

250 tons per year of any single visibility

impairing pollutant. Fugitive emissions, to

the extent quantifiable, must be counted. Inmost cases, you will add the potential

emissions from all emission units on the list

resulting from Steps I and 2. In a few cases,you may need to determine whether the plantcontains more than one “stationary source”as the regional haze rule defines that term,and as we explain further below.

What pollutants should I address?

Visibility-impairing pollutants include the

following:

(1) Sulfur dioxide (SO 2),(2) Nitrogen oxides (NOx), and(3) Particulate matter.

You may use PM10 as an indicator for

particulate matter in this intial step. [Note

that we do not recommend use of totalsuspended particulates (TSP) as in indicatorfor particulate matter.] As emissions of PM10include the components of PM2.5as a subset,

there is no need to have separate 250 tonthresholds for PM10 and PM25;250 tons of

PM1erepresents at most 250 tons of PM2.5,

and at most 250 tons of any individualparticulate species such as elemental carbon,crustal material, etc.

However, if you determine that a source of

particulate matter is DART-eligible, it will beimportant to distinguish between the fineand coarse particle components of directparticulate emissions in the remainder of the

DART analysis, including for the purpose ofmodeling the source’s impact on visibility.This is because although both fine and coarseparticulate matter contribute to visibilityimpairment, the long-range transport of fine

particles is of particular concern in the

formation of regional haze. Thus, for

example, air quality modeling results used in

the DART determination will provide a more

accurate prediction of a source’s impact on

visibility if the inputs into the model account

for the relative particle size of any directly

emitted particulate matter (i.e. PM10 vs.

PM15).

You should exercise judgment in deciding

whether the following pollutants impair

visibility in an area:

(4) Volatile organic compounds (VOCj, and

(5) Ammonia and ammonia compounds.

You should use your best judgment in

deciding whether VOC or ammonia

judgement in assessing the degree of

visibility impacts due to emissions of VOC

and emissions of ammonia or ammonia

compounds. You should fully document the

basis for judging that a VOC or ammonia

source merits DART review, including yourassessment of the source’s contribution tovisibility impairment.

What does the term “potential” emissionsmean?

The regional haze rule defines potential to

emit as follows:

“Potential to emit” means the maximum

capacity of a stationary source to emit a

pollutant under its physical and operational

design. Any physical or operational

limitation on the capacity of the source toemit a pollutant including air pollutioncontrol equipment and restrictions on hoursof operation or on the type or amount of

material combusted, stored, or processed,

shall be treated as part of its design if the

limitation or the effect it would have onemissions is federally enforceable. Secondaryemissions do not count in determining the

potential to emit of a stationary source.The definition of “potential to emit” means

that a source which actually emits less than

250 tons per year of a visibility-impairing

pollutant is DART-eligible if its emissionswould exceed 250 tons per year whenoperating at its maximum capacity given its

physical and operational design (and

considering all federally enforceable andState enforceable permit limits.)

Example:

A source, while operating at onefourth of its capacity, emits 75 tons per year

of SO2.If it were operating at 100 percent ofits maximum capacity, the source would emit

300 tons per year. Decause under the above

definition such a source would have“potential” emissions that exceed 250 tons

per year, the source (if in a listed categoryand built during the 1962—1977 time

window) would be DART-eligible.How do I identify whether a plant has morethan one “stationary source?”

1. The regional haze rule, in 40 CFR

5 1.301, defines a stationary source as a“building, structure, facility or installation

which emits or may emit any air pollutant.” 2

‘Fine particles: Overview ofAtmospheric

Chemistry, Sources of Emissions, and Ambient

Monitoring Data, Memorandum to Docket OAR

2002—006, April 1, 2005.

ZNote: Most of these terms and definitions are the

same for regional haze and the ioao visibility

regulations. For the regional haze rule we use theterm “DART-eligible source” rather than “existingstationary facility” to clarify that only a limitedsubset of existing stationary sources are sub]ect toDART.
amended by the 1977 Supplement (U.S.Government Printing Office stock numbers

4101—0066 and 003—005—00176—0,respectively).

2. In applying this definition, it is

necessary to determine which facilities arelocated on “contiguous or adjacentproperties.” Within this contiguous and

adjacent area, it is also necessary to group

those emission units that are under “common

control.” We note that these plant boundary

issues and “common control” issues are very

similar to those already addressed inimplementation of the title

V operating

permits program and in NSR.

3. For emission units within the

“contiguous or adjacent” boundary and

under common control, you must group

emission units that are within the same

industrial grouping (that is, associated with

the same 2-digit SIC code) in order to definethe stationary source. 3For most plants on the

BART source category list, there will only beone 2-digit SIC that applies to the entire

plant. For example, all emission units

associated with kraft pulp mills are withinSIC code 26, and chemical process plants

will generally include emission units that are

all within SIC code 28. The “2-digit SIC test”applies in the same way as the test is applied

in

4.

the

For

major

purposes

source

of

NSR

the regional

programs. 4

haze rule,

you must group emissions from all emissionunits put in place within the 1962—1977 time

period that are within the 2-digit SIC code,even if those emission units are in differentcategories on the BART category list.

Examples:

A chemical plant which started

operations within the 1962 to 1977 time

period manufactures hydrochloric acid

(within the category title “Hydrochloric,

sulfuric, and nitric acid plants”) and various

organic chemicals (within the category title“chemical process plants”). All of the

emission units are within SIC code 28 and,

therefore, all the emission units are

3We recognize that we are in a transition period

from the use of the SIC system to a new systemcalled the North American Industry Classification

System (NAICS). For purposes of identifying BART

eligible sources, you may use either 2-digit SICS orthe equivalent in the NAtCS system.

4 The concept of support facility used for

the NSR program applies here as well. Supportfacilities, that is facilities that convey, store orotherwise assist in the production of the principalproduct, must be grouped with primary facilities

even when the facilities fall wihin separate SICcodes. For purposes of BART reviews, however,

such support facilities Ia) must be within one of the

26 listed source categories and Ib) must have been

in existence as of August 7, 1977, and (c) must nothave been in operation as of August 7, 1962.

4. Final Step: Identify the Emissions Unitsand Pollutants That Constitute the BARTEligible Source

If the emissions from the list of emissions

units at a stationary source exceed a potentialto emit of 250 tons per year for any visibilityimpairing pollutant, then that collection of

emissions units is a BART-eligible source.

Example:

A stationary source comprises

the following two emissions units, with the

following potential emissions:

Emissions unit

A

200 tons/yr SOa150 tons/yr NOx25 tons/yr PM

Emissions unit B

100 tons/yr SO275 tons/yr NOx10 tons/yr PM

For this example, potential emissions of SO2

are 300 tons/yr. which exceeds the 250 tons/yr threshold. Accordingly, the entire

“stationary source”, that is, emissions units

A and B, may be subject to a BART review

for SO2,NOx, and PM, even though thepotential emissions of PM and NOx at eachemissions unit are less than 250 tons/yr each.

Example: The total potential emissions,

obtained by adding the potential emissions of

all emission units in a listed category at a

plant site, are as follows:

200 tons/yr SO2

150 tons/yr NOx

25 tons/yr PM

Even though total emissions exceed 250

tons/yr, no individual regulated pollutantexceeds 250 tons/yr and this source is notBART-eligible.

Can States establish de minimis levels of

emissions for pollutants at BART-eligible

sources?

In order to simplify BART determinations,

States may choose to identify de minimis

levels of pollutants at BART-eligible sources

(but are not required to do so). De minimis

values should be identified with the purposeof excluding only those emissions so

minimal that they are unlikely to contributeto regional haze. Any de minimis values thatyou adopt must not be higher than the PSD

applicability levels: 40 tons/yr for SO and

NOx and 15 tons/yr for PMie. These de

minimis levels may only be applied on a

plant-wide basis.III. How to Identify Sources “Subject to

BART”

Once you have compiled your list of

BART-eligible sources, you need todetermine whether (1) to make BARTdeterminations for all of them or (2) to

, y

y 

perform an initial examination to determinewhether a particular BART-eligible source or

group of sources causes or contributes tovisibility impairment in nearby Class I areas.

If your analysis, or information submitted bythe source, shows that an individual sourceor group of sources (or certain pollutantsfrom those sources) is not reasonablyanticipated to cause or contribute to any

visibility impairment in a Class I area, thenyou do not need to make BART

determinations for that source or group of

sources (or for certain pollutants from thosesources). In such a case, the source is not

“subject to BART” and you do not need to

apply the five statutory factors to make a

BART determination. This section of theGuideline discusses several approaches that

you can use to exempt sources from theBART determination process.

A. What Steps Do I Follow To Determine

Whether a Source or Group of Sources Cause

or Cantribute to Visibility Impairmentfor

Purposes of RAPT?

1. How Do I Establish a Threshold?

One of the first steps in determining

whether sources cause or contribute tovisibility impairment for purposes of BARTis to establish a threshold (measured in

deciviews) against which to measure the

visibility impact of one or more sources.

A

single source that is responsible for a 1.0

deciview change or more should beconsidered to “cause” visibility impairment;a source that causes less than a 1.0 deciviewchange may still contribute to visibility

impairment end thus be subject to BART.

Because of varying circumstances affecting

different Class I areas, the appropriate

threshold for determining whether a source

“contributes to any visibility impairment” for

the purposes of BART may reasonably differ

across States. As a general matter, any

threshold that you use for determiningwhether a source “contributes” to visibility

impairment should not be higher than 0.5deciviews.

In setting a threshold for “contribution,”

you should consider the number of emissions

sources affecting the Class I areas at issue and

the magnitude of the individual sources’

impacts. 5In general, a larger number ofsources causing impacts in a Class I area may

warrant a lower contribution threshold.

States remain free to use a threshold lower

than 0.5 deciviews if they conclude that the

We expect thet regional planning organizations

wilt have modeling information that identifiessources affecting visibility in individual class Iareas.
p

As explained in section II, you must use

your best judgement to determine whetherVOC or ammonia emissions are likely to havean impact on visibility in an area. Inaddition, although as explained in Section II,

you may use PM10 an indicator for particulatematter in determining whether a source is

HART-eligible, in determining whether a

source contributes to visibility impairment,

you should distinguish between the fine and

coarse particle components of directparticulate emissions. Although both fineand coarse particulate matter contribute to

visibility impairment, the long-rangetransport of fine particles is of particularconcern in the formation of regional haze. Air

quality modeling results used in the HART

determination will provide a more accurate

prediction of a source’s impact on visibilityif the inputs into the model account for the

relative particle size of any directly emitted

particulate matter (i.e. PM10 vs. PM25).

3. What Kind of Modeling Should I Use To

Determine Which Sources and PollutantsNeed Not He Subject to HART?

This section presents several options for

determining that certain sources need not be

subject to HART. These options rely on

different modeling and/or emissions analysisapproaches. They are provided for your

guidance. You may also use other reasonableapproaches for analyzing the visibilityimpacts of an individual source or group of

sources.

Option 1: In dividuol Source Attribution

Approoch (Dispersion Modeling)

You can use dispersion modeling to

determine that an individual source cannot

reasonably be anticipated to cause orcontribute to visibility impairment in a ClassI area and thus is not subject to HART. Under

this option, you can analyze an individual

source’s impact on visibility as a result of itsemissions of SO2,NOx and direct PMemissions. Dispersion modeling cannot

currently be used to estimate the predicted

impacts on visibility from an individual

source’s emissions of VOC or ammonia. You

may use a more qualitative assessment to

determine on a case-by-case basis which

sources of VOC or ammonia emissions may

be likely to impair visibility and should

Note that the contribution threshold should be

used to determine whether an individual source isreasonably anticipated to contribute to visibilityimpairment. You should not aggregate the visibility

effects of multiple sources and compare their

collective effects against your contrihutionthreshold because this would inappropriately create

a “contribute to contribution” test.

purposes, such as the visibility assessmentsaddressed in today’s rule, to account for thechemical transformation of SO2and NOx.

There are several steps for making an

individual source attribution using adispersion model:

1. Develop o modeling protocol. Some

critical items to include in the protocol are

the meteorological and terrain data that will

be used, as well as the source-specific

information (stack height, temperature, exit

velocity, elevation, and emission rates of

applicable pollutants) and receptor data fromappropriate Class I areas. We recommend

following EPA’s Interagency Workgroup on

Air Quality Modeling (IWA QM) Phose 2

Summory Report ond Recommendations for

Modeling Long Range Transport Impacts 9forparameter settings and meteorological datainputs. You may use other settings from

those in IWAQM, but you should identify

these settings and explain your selection of

these settings.

One important element of the protocol is

in establishing the receptors that will be usedin the model. The receptors that you useshould be located in the nearest Class I area

with sufficient density to identify the likelyvisibility effects of the source. For other Class

I areas in relatively close proximity to aBART-eligible source, you may model a fewstrategic receptors to determine whether

effects at those areas may be greater than atthe nearest Class I area. For example, you

might chose to locate receptors at these areas

at the closest point to the source, at the

highest and lowest elevation in the Class Iarea, at the IMPROVE monitor, and at theapproximate expected plume release height.

If the highest modeled effects are observed atthe nearest Class I area, you may choose not

to analyze the other Class I areas any further

as additional analyses might be unwarranted.

You should bear in mind that some

receptors within the relevant Class I area may

be less than 50 km from the source while

other receptors within that same Class I area

may be greater than 50 lan from the same

7The model code and its documentation are

available at no cost for download from http:/I

www.epa.govlscram001 /tt22.h tm#colpuff

The Guideline on Air Quality Models, 40 CFR

part 51, appendix W, addresses the regulatoryapplication of air quality models for assessingcriteria pollutants under the CAA, and describesfurther the procedures for using the CALPUFF

model, as well as for obtaining approval for the use

of

9

other, nonguideline models.

lntemgency Workgroup on Air Quality Modeling

[IWA QM) Phase 2 Summaiy Report and

Recommendationsfor Modeling Lang Range

Transport Impacts, U.S. Environmental Protection

Agency, EPA—454/R—98—019, Oecember 1998.

In developing your modeling protocol, you

may want to consult with EPA and yourregional planning organization (RPO). Upfront consultation will ensure that key

technical issues are addressed before youconduct your modeling.

2. With the accepted protocol and campare

the predicted visibility impacts with yourthreshold for “contribution.” You should

calculate daily visibility values for each

receptor as the change in deciviews

compared against natural visibilityconditions. You can use EPA’s “Guidance for

Estimating Natural Visibility Conditions

Under the Regional Haze Rule,” EPA—454/B—03—005 (September 2003) in making thiscalculation. To determine whether a source

may reasonably be anticipated to cause or

contribute to visibility impairment at Class Iarea, you then compare the impacts predicted

by the model against the threshold that you

have selected.

The emissions estimates used in the

models are intended to reflect steady-state

operating conditions during periods of highcapacity utilization. We do not generally

recommend that emissions reflecting periodsof start-up, shutdown, and malfunction be

used, as such emission rates could producehigher than normal effects than would betypical of most facilities. We recommend that

States use the 24 hour average actual

emission rate from the highest emitting dayof the meteorological period modeled, unless

this rate reflects periods start-up, shutdown,

or malfunction. In addition, the monthlyaverage relative humidity is used, rather than

the daily average humidity—an approachthat effectively lowers the peak values in

daily model averages.

For these reasons, if you use the modeling

approach we recommend, you should

compare your “contribution” thresholdagainst the 98th percentile of values. If the98th percentile value from your modeling is

less than your contribution threshold, then

you may conclude that the source does not

contribute to visibility impairment and is not

subject to BART.

Option 2: Use of Model Plants Ta Exempt

Individual Sources With Common

Characteristics

Under this option, analyses of model

plants could be used to exempt certainHART-eligible sources that share specificcharacteristics. It may be most useful to use

this type of analysis to identify the types of

small sources that do not cause or contribute

to visibility impairment for purposes of

BART, and thus should not be subject to aBART review. Different Class I areas may

have different characteristics, however, so
analyses that certain types of sources are notreasonably anticipated to cause or contributeto visibility impairment. To do this, you mayconduct your own modeling to establishemission levels and distances from Class Iareas on which you can rely to exemptsources with those characteristics. Forexample, based on your modeling you mightchoose to exempt all NOx-only sources thatemit less than a certain amount per year andare located a certain distance from a Class I

area. You could then choose to categoricallyexempt such sources from the BART

determination process.

Our analyses of visibility impacts from

model plants provide a useful example of thetype of analyses that can be used to exempt

categories of sources from BART.1O In our

analyses, we developed model plants (EGU5

and non-EGU5), with representative plume

and stack characteristics, for use inconsidering the visibility impact fromemission sources of different sizes andcompositions at distances of 50, 100 and 200kilometers from two hypothetical Class Iareas (one in the East and one in the West).As the plume and stack characteristics ofthese model plants were developedconsidering the broad range of sources withinthe ECU and non-ECU categories, they do notnecessarily represent any specific plant.However, the results of these analyses areinstructive in the development of an

exemption process for any Class I area.

In preparing our analyses, we have made

a number of assumptions and exercisedcertain modeling choices; some of these have

a tendency to lend conservatism to theresults, overstating the likely effects, while

others may understate the likely effects. On

balance, when all of these factors are

considered, we believe that our examplesreflect realistic treatments of the situations

being modeled. Based on our analyses, webelieve that a State that has established 0.5

deciviews as a contribution threshold could

reasonably exempt from the BART reviewprocess sources that emit less than 500 tonsper year of NOx or 502 (or combined NOxand 502), as long as these sources are locatedmore than 50 kilometers from any Class I

area; and sources that emit less than 1000

tons per year of NOx or 502 (or combinedNOx and 502) that are located more than 100kilometers from any Class I area. You do,however, have the option of showing other

thresholds might also be appropriate givenyour specific circumstances.

CALPUFF Analysis in Support of the June 2005

Changes to the Regional Haze Rule, U.S.Environmental Protection Agency, June 15, 2005,Docket No. OAR—2002—0076.

determine if emissions from these sourcescontribute to visibility impairment.

For example, emissions of SO2from your

BART-eligible sources may clearly cause orcontribute to visibility impairment whiledirect emissions of PM2.5from these sources

may not contribute to impairment. If you can

make such a demonstration, then you mayreasonably conclude that none of your BART

eligible sources are subject to BART for aparticular pollutant or pollutants. As notedabove, your demonstration should take intoaccount the interactions among pollutantsand their resulting impacts on visibility

before making any pollutant-specific

determinations.

Analyses may be conducted using several

alternative modeling approaches. First, you

may use the CALPUFF or other appropriatemodel as described in Option 1 to evaluatethe impacts of individual sources on

downwind Class I areas, aggregating those

impacts to determine the collectivecontribution of all BART-eligible sources to

visibility impairment. You may also use a

photochemical grid model. As a general

matter, the larger the number of sourcesbeing modeled, the more appropriate it maybe to use a photochemical grid model.

However, because such models aresignificantly less sensitive than dispersion

models to the contributions of one or a few

sources, as well as to the interactions amongsources that are widely distributed

geographically, if you wish to use a gridmodel, you should consult with the

appropriate EPA Regional Office to developan appropriate modeling protocol.IV. The BART Determination: Analysis of

BART Options

This section describes the process for the

analysis of control options for sources subject

to BART.A. Whotfoctors must I oddress in the BARTreview?

The visibility regulations define BART as

follows:

Best Avoiloble Retrofit Technology (BART)

means an emission limitation based on the

degree of reduction achievable through the

application of the best system of continuousemission reduction for each pollutant whichis emitted by. . . [a BART-eligible source].The emission limitation must be established,

on a case-by-case basis, taking intoconsideration the technology available, thecosts of compliance, the energy and non-airquality environmental impacts ofcompliance, any pollution control equipmentin use or in existence at the source, the

remaining useful life of the source, and the

environmental impacts of control options

(6) The visibility impacts analysis.

B. Whot is the scope of the BART review?

Once you determine that a source is subject

to BART for a particular pollutant, then foreach affected emission unit, you mustestablish BART for that pollutant. The BART

determination must address air pollution

control measures for each emissions unit orpollutant emitting activity subject to review.

Exompie: Plantwide emissions from

emission units within the listed categories

that began operation within the “timewindow” for BARTh are 300 tons/yr of NOx,

200 tons/yr of 802, and 150 tons/yr of

primary particulate. Emissions unit

A emits

200 tons/yr of NOx, 100 tons/yr of 802, and100 tons/yr of primary particulate. Other

emission units, units B through H, which

began operating in 1966, contribute lesser

amounts of each pollutant. For this example,a BART review is required for NOx, 802, andprimary particulate, and control options must

be analyzed for units B through

H as well as

unit A.

C. How does o BART review relote to

Moximum Achievobie Control Technology

(MACT) Stondords under CAA section 112,or to other emission limitotions required

under the CAA?

For VOC and PM souces subject to MACF

standards, States may streamline the analysis

by including a discussion of the MACF

controls and whether any major new

technologies have been developedsubsequent to the MACT standards. We

believe that there are many VOC and PM

sources that are well controlled because they

are regulated by the MACT standards, which

EPA developed under CAA section 112, For

a few MACT standards, this may also be truefor 802. Any source subject to MACF

standards must meet a level that is asstringent as the best-controlled 12 percent ofsources in the industry. Examples of thesehazardous air pollutant sources which

effectively control VOC and PM emissions

include (among others) secondary lead

facilities, organic chemical plants subject to

the hazardous organic NESHAP (HON),

pharmaceutical production facilities, andequipment leaks and wastewater operationsat petroleum refineries. We believe that, inmany cases, it will be unlikely that Stateswill identify emission controls morestringent than the MACT standards without

11 That is, emission units that were in existence

on August 7, 1977 and which began actualoperation on or after August 7, 1962.
technology determinations from the 1970s orearly 1980s, including new sourceperformance standards (NSPS), should beconsidered to represent best control forexisting sources, as best control levels for

recent plant retrofits are more stringent thanthese older levels.

Where you are relying on these standards

to represent a BART level of control, you

should provide the public with a discussionof whether any new technologies havesubsequently become available.

D. Whot Are the Five Bosic Steps of o Cose

by-Cose BART Anolysis?

The five steps are:

STEP 1—Identify All 12 Available Retrofit

Control Technologies,

STEP 2—Eliminate Technically Infeasible

Options,

STEP 3—Evaluate Control Effectiveness of

Remaining Control Technologies,

STEP 4—Evaluate Impacts and Document

the Results, and

STEP 5—Evaluate Visibility Impacts.

1. STEP 1: How do I identify all available

retrofit emission control techniques?

1. Available retrofit control options are

those air pollution control technologies witha practical potential for application to theemissions unit and the regulated pollutantunder evaluation. Air pollution control

technologies can include a wide variety ofavailable methods, systems, and techniquesfor control of the affected pollutant.

Technologies required as BACT or LAER are

available for DART purposes and must be

included as control alternatives. The controlalternatives can include not only existingcontrols for the source category in question

but also take into account technology transfer

of controls that have been applied to similar

source categories and gas streams.Technologies which have not yet beenapplied to (or permitted for) full scaleoperations need not be considered asavailable; we do not expect the source owner

to purchase or construct a process or control

device that has not already beendemonstrated in practice.

2. Where a NSPS exists for a source

category (which is the case for most of thecategories affected by BART), you shouldinclude a level of control equivalent to the

‘21n identifying all” options, you must identify

the most stringent option and a reasonable set of

options for analysis that reflects a comprehensivelist of available tectmologies. It is not necessary to

list all permutations of available control levels thatexist for a given technology—the list is complete ifit includes the maximum level of control each

technology is capable of achieving,

g

y

• Pollution prevention: use of inherently

lower-emitting processes/practices, including

the use of control techniques (e.g. low-NOx

burners) and work practices that prevent

emissions and result in lower “productionspecific” emissions (note that it is not ourintent to direct States to switch fuel forms,

e.g. from coal to gas),

• Use of (and where already in place,

improvement in the performance of) add-on

controls, such as scrubbers, fabric filters,

thermal oxidizers and other devices that

control and reduce emissions after they are

produced, and

• Combinations of inherently loweremitting processes and add-on controls.

4. In the course of the BART review, one

or more of the available control options may

be eliminated from consideration becausethey are demonstrated to be technically

infeasible or to have unacceptable energy,cost, or non-air quality environmental

impacts on a case-by-case (or site-specific)

basis, However, at the outset, you should

initially identify all control options with

potential application to the emissions unit

under review.

5. We do not consider DART as a

requirement to redesign the source whenconsidering available control alternatives.For example, where the source subject toDART is a coal-fired electric generator, we donot require the BART analysis to consider

building a natural gas-fired electric turbine

although the turbine may be inherently less

polluting on a per unit basis.

6. For emission units subject to a DART

review, there will often be control measures

or devices already in place. For such

emission units, it is important to includecontrol options that involve improvements toexisting controls and not to limit the controloptions only to those measures that involvea complete replacement of control devices.

Exomple: For a power plant with an

existing wet scrubber, the current controlefficiency is 66 percent. Part of the reason for

13th EPA’s 1980 BART guidelines for reasonably

attributable visibility impairment, we concludedthat N5P5 standards generally, at that time,

represented the best level sourcee could install asDART. In the 20 year period since this guidance

was developed, there have been advances in 502

control technologies as well as technologies for the

control of other pollutants, confirmed by a numberof recent retrofits at Western power plants.Accordingly, EPA no longer concludes that the

NSPS level of controls automatically represents

“the best these sources can install.” Analysis of theDART factors could result in the selection of a

NSPS level of control, but you should reach this

conclusion only after considering the full range of

control options.

reducing the bypass to 15 percent, (3) 93percent control based upon improving thescrubber performance while eliminating thebypass entirely, (this option results in a “wetstack” operation in which the gas leaving the

stack is saturated with water) and (4) 93percent as in option 3, with the addition ofan indirect reheat system to reheat the stack

gas above the saturation temperature. You

must consider each of these four options in

a DART analysis for this source.

7. You are expected to identify potentially

applicable retrofit control technologies that

represent the full range of demonstratedalternatives. Examples of general informationsources to consider include:

• The EPA’s Clean Air Technology Center,

which includes the RACT/BACT/LAERClearinghouse (RBLC);

• State and Local Best Available Control

Technology Guidelines—many agencies have

online information—for example South Coast

Air Quality Management District, Bay AreaAir Quality Management District, and TexasNatural Resources Conservation Commission;

• Control technology vendors;• Federal/State/Local NSR permits and

associated inspection/performance test

reports;

• Environmental consultants;• Technical journals, reports and

newsletters, air pollution control seminars;

and

• The EPA’s NSR bulletin board—htfp://

www.epo.gov/ttn/nsr;

• Department of Energy’s Clean Coal

Program—technical reports;

• The NOx Control Technology “Cost

Tool”—Clean Air Markets Division Web

page—http://www.epo.gov/oirmorkets/orp/nox/controltech html;

• Performance of selective catalytic

reduction on coal-fired steam generatingunits—final report. OAR/ARD, June 1997

(also available at http://www.epo.gov/

oirmorkets/orp/nox/controltech html);

• Cost estimates for selected applications

of NOx control technologies on stationarycombustion boilers. OAR/ARD June 1997.(Docket for NOx SIP Call, A—96—56, item II—

A—03);

• Investigation of performance and cost of

NOx controls as applied to group 2 boilers.

OAR/ARD, August 1996. (Docket for Phase II

NOx rule, A—95—28, item IV—A—4);

• Controlling SO2 Emissions:

A Review of

Technologies. EPA—600/R--00—093, USEPA/

ORD/NRMRL, October 2000; and

• The OAQPS Control Cost Manual.You are expected to compile appropriate

information from these information sources.

8. There may be situations where a specific

set of units within a fenceline constitutes the
enforceable for the purpose of implementingBART for that source, you may skip the

remaining analyses in this section, includingthe visibility analysis in step 5. Likewise, ifa source commits to a BART determination

that consists of the most stringent controls

available, then there is no need to complete

the remaining analyses in this section.

2. STEP 2; How do I determine whether theoptions identified in Step I are technicallyfeasible?

In Step 2, you evaluate the technical

feasibility of the control options you

identified in Step 1. You should document a

demonstration of technical infeasibility and

should explain, based on physical, chemical,or engineering principles, why technical

difficulties would preclude the successful

use of the control option on the emissionsunit under review. You may then eliminatesuch technically infeasible control optionsfrom further consideration in the BART

analysis.

In general, what do we mean by technical

feasibility?

Control technologies are technically

feasible if either (1) they have been installedand operated successfully for the type ofsource under review under similarconditions, or (2) the technology could be

applied to the source under review. Two keyconcepts are important in determining

whether a technology could be applied;

“availability” and “applicability.” As

explained in more detail below, a technologyis considered “available” if the source ownermay obtain it through commercial channels,

or it is otherwise available within thecommon sense meaning of the term. Anavailable technology is “applicable” if it can

reasonably be installed and operated on the

source type under consideration.

A

technology that is available and applicable istechnically feasible.

What do we mean by “available” technology?

1. The typical stages for bringing a control

technology concept to reality as a commercialproduct are;

• Concept stage;• Research and patenting;• Bench scale or laboratory testing;

• Pilot scale testing;• Licensing and commercial

demonstration; and

• Commercial sales.2.

A control technique is considered

available, within the context presented

above, if it has reached the stage of licensingand commercial availability. Similarly, we do

not expect a source owner to conduct

Because a new technology may become

available at various points in time during theBART analysis process, we believe that

guidelines are needed on when a technology

must be considered. For example, atechnology may become available during the

public comment period on the State’s rule

development process. Likewise, it is possible

that new technologies may become available

after the close of the State’s public commentperiod and before submittal of the SIP to

EPA, or during EPA’s review process on the

SIP submittal. In order to provide certainty

in the process, all technologies should be

considered if available before the close of the

State’s public comment period. You need notconsider technologies that become availableafter this data. As part of your analysis, you

should consider any technologies brought to

your attention in public comments. If you

disagree with public comments asserting that

the technology is available, you should

provide an explanation for the public record

as to the basis for your conclusion.

What do we mean by “applicable”technology?

You need to exercise technical judgment in

determining whether a control alternative is

applicable to the source type underconsideration. In general, a commerciallyavailable control option will be presumed

applicable if it has been used on the same ora similar source type. Absent a showing ofthis type, you evaluate technical feasibilityby examining the physical and chemical

characteristics of the pollutant-bearing gasstream, and comparing them to the gasstream characteristics of the source types towhich the technology had been appliedpreviously. Deployment of the controltechnology on a new or existing source with

similar gas stream characteristics is generallya sufficient basis for concluding the

technology is technically feasible barring a

demonstration to the contrary as described

below.

What type of demonstration is required if I

conclude that an option is not technicallyfeasible?

1. Where you conclude that a control

option identified in Step I is technically

infeasible, you should demonstrate that the

option is either commercially unavailable, or

that specific circumstances preclude its

application to a particular emission unit.Generally, such a demonstration involves anevaluation of the characteristics of thepollutant-bearing gas stream and the

capabilities of the technology. Alternatively,a demonstration of technical infeasibility

may involve a showing that there are

air quality permits. In some cases, an airquality permit may require a certain level ofcontrol, but the level of control in a permitis not expected to be achieved in practice(e.g., a source has received a permit but the

project was canceled, or every operatingsource at that permitted level has been

physically unable to achieve compliancewith the limit). Where this is the case, you

should provide supporting documentationshowing why such limits are not technically

feasible, and, therefore, why the level of

control (but not necessarily the technology)may be eliminated from further

consideration. However, if there is a permit

requiring the application of a certaintechnology or emission limit to be achievedfor such technology, this usually is sufficient

justification for you to assume the technical

feasibility of that technology or emission

limit.

3. Physical modifications needed to resolve

technical obstacles do not, in and ofthemselves, provide a justification for

eliminating the control technique on the

basis of technical infeasibility. However, you

may consider the cost of such modificationsin estimating costs. This, in turn, may formthe basis for eliminating a control technology

(see later discussion).

4. Vendor guarantees may provide an

indication of commercial availability and the

technical feasibility of a control technique

and could contribute to a determination of

technical feasibility or technical infeasibility,

depending on circumstances. However, wedo not consider a vendor guarantee alone to

be sufficient justification that a control

option will work. Conversely, lack of a

vendor guarantee by itself does not present

sufficient justification that a control option oran emissions limit is technically infeasible.Generally, you should make decisions about

technical feasibility based on chemical, and

engineering analyses (as discussed above), inconjunction with information about vendor

guarantees.

5.

A possible outcome of the BART

procedures discussed in these guidelines is

the evaluation of multiple control technologyalternatives which result in essentiallyequivalent emissions. It is not our intent toencourage evaluation of unnecessarily large

numbers of control alternatives for every

emissions unit. Consequently, you should

use judgment in deciding on those

alternatives for which you will conduct thedetailed impacts analysis (Step 4 below). Forexample, if two or more control techniques

result in control levels that are essentiallyidentical, considering the uncertainties of

emissions factors and other parameters
review.

Two key issues in this process include:

(1) Making sure that you express the degree

of control using a metric that ensures an

“apples to apples” comparison of emissions

performance levels among options, and

(2) Giving appropriate treatment and

consideration of control techniques that canoperate over a wide range of emission

performance levels.

What are the appropriate metrics for

comparison?

This issue is especially important when

you compare inherently lower-pollutingprocesses to one another or to add-oncontrols. In such cases, it is generally mosteffective to express emissions performance asan average steady state emissions level per

unit of product produced or processed.

Examples of common metrics:

• Pounds of SO2emissions per million Btu

heat input, and

• Pounds of NOx emissions per ton of

cement produced.How do I evaluate control techniques with a

wide range of emission performance levels?

1. Many control techniques, including both

add-on controls and inherently lower

polluting processes, can perform at a wide

range of levels. Scrubbers and high and low

efficiency electrostatic precipitators (ESP5)are two of the many examples of such control

techniques that can perform at a wide rangeof levels. It is not our intent to requireanalysis of each possible level of efficiencyfor a control technique as such an analysis

would result in a large number of options. Itis important, however, that in analyzing the

technology you take into account the most

stringent emission control level that the

technology is capable of achieving. You

should consider recent regulatory decisionsand performance data (e.g., manufacturer’sdata, engineering estimates and the

experience of other sources) whenidentifying an emissions performance levelor levels to evaluate.

2. In assessing the capability of the control

alternative, latitude exists to consider specialcircumstances pertinent to the specificsource under review, or regarding the priorapplication of the control alternative,

However, you should explain the basis forchoosing the alternate level (or range) ofcontrol in the DART analysis. Without ashowing of differences between the sourceand other sources that have achieved more

stringent emissions limits, you shouldconclude that the level being achieved by

those other sources is representative of the

achievable level for the source beinganalyzed.

performance of existing control devices,particularly when a control device is notachieving the level of control that othersimilar sources are achieving in practice with

the same device. For example, you should

consider requiring those sources withelectrostatic precipitators (ESPs) performing

below currently achievable levels to improvetheir performance.4. STEP 4: For a DART review, what impacts

am I expected to calculate and report? What

methods does EPA recommend for the

impacts analysis?

After you identify the available and

technically feasible control technology

options, you are expected to conduct thefollowing analyses when you make a BARTdetermination:

Impact analysis part 1: Costs of

compliance,

Impact analysis part 2: Energy impacts, andImpact analysis part 3: Non-air quality

environmental impacts.

Impact analysis part 4: Remaining useful

life.

In this section, we describe bow to conduct

each of these three analyses. You are

responsible for presenting an evaluation of

each impact along with appropriatesupporting information. You should discussand, where possible, quantify both beneficial

and adverse impacts. In general, the analysisshould focus on the direct impact of thecontrol alternative.a. Impact analysis part 1: how do I estimate

the costs of control?

1. To conduct a cost analysis, you:(1) Identify the emissions units being

controlled,

(2) Identify design parameters for emission

controls, and

(3) Develop cost estimates based upon

those design parameters.

2. It is important to identify clearly the

emission units being controlled, that is, tospecify a well-defined area or process

segment within the plant. In some cases,multiple emission units can be controlled

jointly. However, in other cases, it may be

appropriate in the cost analysis to consider

whether multiple units will be required toinstall separate and/or different control

devices. The analysis should provide a clear

summary list of equipment and theassociated control costs. Inadequatedocumentation of the equipment whoseemissions are being controlled is a potential

cause for confusion in comparison of costs of

the same controls applied to similar sources.

3. You then specify the control system

design parameters. Potential sources of these

Wet Scrubbers .. Type of sorbent used (lime,

limestone, etc.).

Gas pressure drop.

Liquid/gas ratio.

Selective Cata- Ammonia to NOx molar

lytic Reduction, ratio.

Pressure drop.

Catalyst life.

4. The value selected for the design

parameter should ensure that the controloption will achieve the level of emissioncontrol being evaluated. You should include

in your analysis documentation of yourassumptions regarding design parameters.Examples of supporting references wouldinclude the EPA OAQPS Control Cost

Mon uol (see below) and background

information documents used for NSPS and

hazardous pollutant emission standards. Ifthe design parameters you specified differ

from typical designs, you should document

the difference by supplying performance test

data for the control technology in question

applied to the same source or a similar

source.

5. Once the control technology alternatives

and achievable emissions performance levels

have been identified, you then develop

estimates of capital and annual costs. The

basis for equipment cost estimates also

should be documented, either with datasupplied by an equipment vendor (i.e.,

budget estimates or bids) or by a referenced

source (such as the OAQPS Control Cost

Mon uol, Fifth Edition, February 1996, EPA453/B96flO1). 14In order to maintain andimprove consistency, cost estimates should

be based on the OA4QPS Control Cost Mon uol,where possible.15 The Control Cost Mon uol

addresses most control technologies insufficient detail for a BART analysis. Thecost analysis should also take into accountany site-specific design or other conditions

identified above that affect the cost of aparticular DART technology option.

1The OAQPS Control Cost Monuol is updated

periodically. While this citation refers to the latest

version at the time this guidance was written, you

should use the version that is current as of when

you conduct your impact analysis. This documentis available at the tollowing web site: http://

wsvw.epo.gov/ttn/cotc/dirl/csl ch2.pdf.

55You should include documentation for my

additional information you used for the cost

calculations, including any information supplied by

vendors that affects your assumptions regardingpurchased equipment costs, equipment life,

replacement of major components, and any other

element of the calculation that differs from the

Control Cost Mon uol.
effectiveness?

Average cost effectiveness means the total

annualized costs of control divided by

annual emissions reductions (the difference

between baseline annual emissions and the

estimate of emissions after controls), using

the following formula:

Average cost effectiveness (dollars per ton

removed) = Control option annualized

castle

Baseline annual emissions—Annual

emissions with Control option

Because you calculate costs in (annualized)

dollars per year ($/yr) and because youcalculate emissions rates in tons per year

(tons/yr), the result is an average costeffectiveness number in (annualized) dollars

per ton (s/ton) of pollutant removed.

d. How do I calculate baseline emissions?

1. The baseline emissions rate should

represent a realistic depiction of anticipated

annual emissions for the source. In general,

for the existing sources subject to BART, you

will estimate the anticipated annual

emissions based upon actual emissions from a baseline period.

2. When you project that future operating

parameters (e.g., limited hours of operation

you calcutate or report annual costs,

you should indicate the year for which the costs are

estimated. For example, if you use the year 2000 asthe basis for cost comparisons, you would report

that an annualized cost of $20 million would be:

S20 million (year 2000 dollars).

hand, baseline emissions associated with a

base-loaded turbine should be based on its

past practice which would indicate a largenumber of hours of operation. This produces a significantly higher level of baseline

emissions than in the case of the emergency/

standby unit and results in more costeffective controls. As a consequence of the

dissimilar baseline emissions, DART for the

two cases could be very different.

e. How do I calculate incremental cost

effectiveness?

1. In addition to the average cost

effectiveness of a control option, you shouldalso calculate incremental cost effectiveness.

You should consider the incremental costeffectiveness in combination with the average

cost effectiveness when considering whether

to eliminate a control option. Theincremental cost effectiveness calculation

compares the costs and performance level of a control option to those of the next most

stringent option, as shown in the followingformula (with respect to cost per emissions

reduction):

Incremental Cost Effectiveness (dollars per

incremental ton removed) = (Total

annualized costs of control option)

— (Total annualized costs of next control

option) ÷ (Control option annualemissions)

— (Next control option

annual emissions)

Example I: Assume that Option F on

Figure 2 has total annualized costs of $1

million to reduce 2000 tons of a pollutant,

a 980 tons/yr reduction at an annualized cost

of $1,500,000. This represents an average costof (51,500,000/980 tons) = $1,531/ton. The

incremental cost effectiveness of Option 1

relative to Option 2 is ($1,900,000

— $1,500,000) divided by (1,000 tons

— 980

tons). The adoption of Option 1 instead of

Option 2 results in an incremental emission

reduction of 20 tons per year at an additional

cost of $400,000 per year. The incremental

cost of Option 1, then, is $20,000 per ton

— 11 times the average cost of $1,900 per ton.

While $1,900 per ton may still be deemed

reasonable, it is useful to consider both the

average and incremental cost in making anoverall cost-effectiveness finding. Of course,

there may be other differences between these

options, such as, energy or water use, or nonair environmental effects, which also should

be considered in selecting a DART

technology.

2. You should exercise care in deriving

incremental costs of candidate control

options. Incremental cost-effectivenesscomparisons should focus on annualized cost

and emission reduction differences between

“dominant” alternatives. To identify

dominant alternatives, you generate a

graphical plot of total annualized costs fortotal emissions reductions for all control

alternatives identified in the DART analysis,and by identifying a “least-cost envelope” as

shown in Figure 2. (A “least-cost envelope”

represents the set of options that should be

dominant in the choice of a specific option.)
I

Exampie: Eight technically feasible control

options for analysis are listed. These are

represented as A through H in Figure 2. The

dominant set of control options, B, D, F, C,

and H, represent the least-cost envelope, as

we depict by the cost curve connecting them.Points A, C and E are inferior options, andyou should not use them in calculatingincremental cost effectiveness. Points A, Cand E represent inferior controls because B

will buy more emissions reductions for less

money than A; and similarly, D and F willbuy more reductions for less money than Cand E, respectively.

3. In calculating incremental costs, you:(1) Array the control options in ascending

order of annualized total costs,

(2) Develop a graph of the most reasonable

smooth curve of the control options, asshown in Figure 2. This is to show the “leastcost envelope” discussed above; and

(3) Calculate the incremental cost

effectiveness for each dominant option,

which is the difference in total annual costs

between that option and the next most

stringent option, divided by the difference in

emissions, after controls have been applied,

between those two control options. For

example, using Figure 2, you would calculate

incremental cost effectiveness for the

difference between options B and D, options

D and F, options F and C, and options C andH.

4. A comparison of incremental costs can

also be useful in evaluating the viability ofa specific control option over a range of

efficiencies. For example, depending on thecapital and operational cost of a controldevice, total and incremental cost may vary

significantly (either increasing or decreasing)over the operational range of a control

device. Also, the greater the number of

possible control options that exist, the more

weight should be given to the incremental

costs vs. average costs. It should be noted

that average and incremental cost

effectiveness are identical when only onecandidate control option is known to exist.

5. You should exercise caution not to

misuse these techniques. For example, youmay be faced with a choice between two

available control devices at a source, controlA and control B, where control B achievesslightly greater emission reductions. Theaverage cost (total annual cost/total annual

emission reductions) for each maybe deemed

to be reasonable. However, the incremental

cost (total annual costA — a/total annualemission reductionsA — a) of the additionalemission reductions to be achieved bycontrol B may be very great. In such an

instance, it maybe inappropriate to choose

control B, based on its high incremental

costs, even though its average cost may beconsidered reasonable.

6. In addition, when you evaluate the

average or incremental cost effectiveness of a

control alternative, you should make

reasonable and supportable assumptionsregarding control efficiencies. An

unrealistically low assessment of the

emission reduction potential of a certain

technology could result in inflated costeffectiveness figures.

f. What other information should I provide in

the cost impacts analysis?

You should provide documentation of any

unusual circumstances that exist for the

source that would lead to cost-effectiveness

estimates that would exceed that for recent

retrofits. This is especially important in cases

where recent retrofits have cost-effectiveness

values that are within what has been

considered a reasonable range, but your

analysis concludes that costs for the source

being analyzed are not consideredreasonable. (A reasonable range would be a

range that is consistent with the range of cost

effectiveness values used in other similar

permit decisions over a period of time.)

Example: In an arid region, large amounts

of water are needed for a scrubbing system.

Acquiring water from a distant location couldgreatly increase the cost per ton of emissionsreduced of wet scrubbing as a control option.g. What other things are important toconsider in the cost impacts analysis?

In the cost analysis, you should take care

not to focus on incomplete results or partialcalculations, For example, large capital costsfor a control option alone would not precludeselection of a control measure if large

emissions reductions are projected. In such a

case, low or reasonable cost effectivenessnumbers may validate the option as an

appropriate BART alternative irrespective of

the large capital costs. Similarly, projects

with relatively low capital costs may not be

cost effective if there are few emissions

reduced.h. Impact analysis part 2: How should I

analyze and report energy impacts?

1. You should examine the energy

requirements of the control technology and

determine whether the use of that technology

results in energy penalties or benefits. Asource owner may, for example, benefit from

the combustion of a concentrated gas streamrich in volatile organic compounds; on the

other hand, more often extra fuel orelectricity is required to power a control

Inferior

Costs

A Emissions

1 1 I t I I I I I I

WICREASING EMISSiONS REDUCTION (rons/yr) w
of the control alternative in units of energyconsumption at the source (e.g., BTU, kwh,

barrels of oil, tons of coal). The energy

requirements of the control options should heshown in terms of total (and in certain cases,also incremental) energy costs per ton of

pollutant removed. You can then convert

these units into dollar costs and, whereappropriate, factor these costs into thecontrol cost analysis.

3. You generally do not consider indirect

energy impacts (such as energy to produce

raw materials for construction of controlequipment). However, if you determine,

either independently or based on a showing

by the source owner, that the indirect energy

impact is unusual or significant and that theimpact can be well quantified, you may

consider the indirect impact.

4. The energy impact analysis may also

address concerns over the use of locally

scarce fuels. The designation of a scarce fuelmay vary from region to region. However, in

general, a scarce fuel is one which is in short

supply locally and can be better used foralternative purposes, or one which may not

be reasonably available to the source either

at the present time or in the near future.

5. Finally, the energy impacts analysis may

consider whether there are relative

differences between alternatives regardingthe use of locally or regionally available coal,

and whether a given alternative would resultin significant economic disruption or

unemployment. For example, where two

options are equally cost effective and achieve

equivalent or similar emissions reductions,

one option may be preferred if the otheralternative results in significant disruption or

unemployment.

I. Impact analysis part 3: How do I analyze

“non-air quality environmental impacts?”

1. In the non-air quality related

environmental impacts portion of the BART

analysis, you address environmental impacts

other than air quality due to emissions of the

pollutant in question. Such environmentalimpacts include solid or hazardous waste

generation and discharges of polluted water

from a control device.

2. You should identify any significant or

unusual environmental impacts associated

with a control alternative that have tbe

potential to affect the selection or elimination

of a control alternative. Some control

technologies may have potentially significant

secondary environmental impacts. Scrubber

effluent, for example, may affect water

quality and land use. Alternatively, water

availability may affect the feasibility and

costs of wet scrubbers. Other examples ofsecondary environmental impacts could

and the solid or liquid waste is similar to

those other applications. On the other hand,where you or the source owner can show that

unusual circumstances at the proposedfacility create greater problems thanexperienced elsewhere, this may provide a

basis for the elimination of that control

alternative as BART.

3. The procedure for conducting an

analysis of non-air quality environmental

impacts should be made based on aconsideration of site-specific circumstances.

If you propose to adopt the most stringentalternative, then it is not necessary to

perform this analysis of environmentalimpacts for the entire list of technologies you

ranked in Step 3. In general, the analysisneed only address those control alternatives

with any significant or unusual

environmental impacts that have the

potential to affect the selection of a control

alternative, or elimination of a more stringent

control alternative. Thus, any important

relative environmental impacts (both positive

and negative) of alternatives can be compared

with each other.

4. In general, the analysis of impacts starts

with the identification and quantification ofthe solid, liquid, and gaseous discharges from

the control device or devices under review.Initially, you should perform a qualitative orsemi-quantitative screening to narrow the

analysis to discharges with potential forcausing adverse environmental effects. Next,

you should assess the mass and composition

of any such discharges and quantify them to

the extent possible, based on readilyavailable information. You should alsoassemble pertinent information about the

public or environmental consequences of

releasing these materials.j. Impact analysis part 4: what are examples

of non-air quality environmental impacts?

The following are examples of how to

conduct non-air quality environmental

impacts:

(1) Woterlmpoct

You should identify the relative quantities

of water used and water pollutants produced

and discharged as a result of the use of eachalternative emission control system. where

possible, you should assess the effect on

ground water and such local surface water

quality parameters as ph, turbidity, dissolved

oxygen, salinity, toxic chemical levels,

temperature, and any other important

considerations. The analysis could consider

whether applicable water quality standardswill be met and the availability andeffectiveness of various techniques to reduce

potential adverse effects.

(2) Solid Woste Disposol Impoct

contamination of subsurface waters oraquifers.

(3) Irreversible or Irretrievoble Commitment

ofResources

You may consider the extent to which the

alternative emission control systems may

involve a trade-off between short-term

environmental gains at the expense of longterm environmental losses and the extent to

which the alternative systems may result in

irreversible or irretrievable commitment of

resources (for example, use of scarce water

resources).

(4) Other Adverse Environmentol Impocts

You may consider significant differences in

noise levels, radiant heat, or dissipated static

electrical energy of pollution control

alternatives. Other examples of non-airquality environmental impacts wouldinclude hazardous waste discharges such as

spent catalysts or contaminated carbon.

k. How do I take into account a project’s

“remaining useful life” in calculating control

costs?

1. You may decide to treat the requirement

to consider the source’s “remaining useful

life” of the source for BART determinationsas one element of the overall cost analysis.The “remaining useful life” of a source, if it

represents a relatively short time period, mayaffect the annualized costs of retrofitcontrols. For example, the methods for

calculating annualized costs in EPA’s

OAQPS Control Cost Mon uol require the use

of a specified time period for amortization

that varies based upon the type of control. If

the remaining useful life will clearly exceed

this time period, the remaining useful life has

essentially no effect on control costs and on

the BART determination process. where the

remaining useful life is less than the time

period for amortizing costs, you should use

this shorter time period in your cost

calculations.

2. For purposes of these guidelines, the

remaining useful life is the difference

between:

(1) The date that controls will be put in

place (capital and other construction costs

incurred before controls are put in place can

be rolled into the first year, as suggested in

EPA’s OAQPS Control Cost Mon uol); you are

conducting the BART analysis; and

(2) The date the facility permanently stops

operations, where this affects the BARTdetermination, this date should be assured by

a federally- or State-enforceable restrictionpreventing further operation.

3. we recognize that there maybe

situations where a source operator intends toshut down a source by a given date, but

wishes to retain the flexibility to continue
If the reduced time period does change the

level of BART controls, you may identify,and include as part of the HART emission

limitation, the more stringent level of controlthat would be required as HART if there were

no assumption that reduced the remaininguseful life. You may incorporate into theHART emission limit this more stringent

level, which would serve as a contingency

should the source continue operating more

than 5 years after the date EPA approves the

relevant SIP, The source would not be

allowed to operate after the 5-year mark

without such controls. If a source does

operate after the 5-year mark without HART

in place, the source is considered to be inviolation of the HART emissions limit for

each day of operation.5. Step 5: How should I determine visibility

impacts in the HART determination?

The following is an approach you may use

to determine visibility impacts (the degree of

visibility improvement for each sourcesubject to HART) for the HART

determination. Once you have determined

that your source or sources are subject to

BART, you must conduct a visibility

improvement determination for the source(s)as part of the HART determination. When

making this determination, we believe youhave flexibility in setting absolute thresholds,

target levels of improvement, or do minimislevels since the deciview improvement must

be weighed among the five factors, and youare free to determine the weight andsignificance to be assigned to each factor. Forexample, a 0.3 deciview improvement may

merit a stronger weighting in one case versusanother, so one “bright line” may not he

appropriate. [Note that if sources haveelected to apply the most stringent controlsavailable, consistent with the discussion insection E. step 1. below, you need notconduct, or require the source to conduct, anair quality modeling analysis for the purpose

of determining its visibility impacts.)

Use CALPUFF,’ 7or other appropriate

dispersion model to determine the visibility

improvement expected at a Class I area fromthe potential HART control technology

applied to the source. Modeling should be

conducted for 502, NOx, and direct PM

emissions (PM15 and/or PM10).If the sourceis making the visibility determination, you

should review and approve or disapprove ofthe source’s analysis before making theexpected improvement determination. Thereare several steps for determining the

“The model code and its documentation are

available at no cost for download from http://

www.epa.govlscromOolltt22.hfm#calpuff.

Transport Impacts’ 5for parameter settings

and meteorological data inputs; the use ofother settings from those in IWAQM should

be identified and explained in the protocol.

One important element of the protocol is

in establishing the receptors that will be used

in the model. The receptors that you use

should be located in the nearest Class I areawith sufficient density to identify the likelyvisibility effects of the source. For other ClassI areas in relatively close proximity to aHART-eligible source, you may model a fewstrategic receptors to determine whether

effects at those areas may be greater than at

the nearest Class I area. For example, you

might chose to locate receptors at these areas

at the closest point to the source, at the

highest and lowest elevation in the Class Iarea, at the IMPROVE monitor, and at theapproximate expected plume release height.

If the highest modeled effects are observed at

the nearest Class I area, you may choose notto analyze the other Class I areas any furtheras additional analyses might be unwarranted.

You should bear in mind that some

receptors within the relevant Class I area maybe less than 50 km from the source while

other receptors within that same Class I area

may be greater than 50 km from the same

source. As indicated by the Guideline on Air

Qualify Models, this situation may call for

the use of two different modeling approaches

for the same Class I area and source,

depending upon the State’s chosen methodfor modeling sources less than 50 km. In

situations where you are assessing visibilityimpacts for source-receptor distances less

than 50 km, you should use expert modeling

judgment in determining visibility impacts,

giving consideration to both CALPUFF andother EPA-approved methods.

In developing your modeling protocol, you

may want to consult with EPA and yourregional planning organization (RPO). Upfront consultation will ensure that keytechnical issues are addressed before you

conduct your modeling.

• For each source, run the model, at pre

control and post-control emission ratesaccording to the accepted methodology in the

protocol.

Use the 24-hour average actual emission

rate from the highest emitting day of the

meteorological period modeled (for the pre

control scenario). Calculate the model resultsfor each receptor as the change in deciviews

compared against natural visibility

‘8lnferogency Workgroup on Air Quality

Modeling (IWA QM) Phase 2 Summary Reporf and

Recommendations for Modeling Long Range

Transport Impacts, U.S. Environmental Protection

Agency, EPA—454/R—98—019, Oecember 1998.

y 

p

controls by one or more methods. You mayconsider the frequency, magnitude, and

duration components of impairment.

Suggestions for making the determination

are:

Use of a comparison threshold, as is

done for determining if HART-eligible

sources should be subject to a HART

determination. Comparison thresholds can be

used in a number of ways in evaluating

visibility improvement (e.g. the number of

days or hours that the threshold was

exceeded, a single threshold for determining

whether a change in impacts is significant, or

a threshold representing an x percent change

in improvement).

• Compare the 98th percent days for the

pre- and post-control runs.

Note that each of the modeling options

may be supplemented with sourceapportionment data or source apportionment

modeling.

E. How do I select the “best” alternative,

using the results of Steps 1 through 5?

1. Summary of the Impacts Analysis

From the alternatives you evaluated in

Step 3, we recommend you develop a chart

(or charts) displaying for each of the

alternatives:

(1) Expected emission rate (tons per year,

pounds per hour);

(2) Emissions performance level (e.g.,

percent pollutant removed, emissions per

unit product, lb/MMHtu, ppm);

(3) Expected emissions reductions (tons

per year);

(4) Costs of compliance—total annualized

costs (5), cost effectiveness (S/ton), andincremental cost effectiveness (S/ton), and/orany other cost-effectiveness measures (suchas 5/deciview);

(5) Energy impacts;(6) Non-air quality environmental impacts;

and

(7) Modeled visibility impacts.

2. Selecting a “best” alternative

1. You have discretion to determine the

order in which you should evaluate controloptions for HART. Whatever the order in

which you choose to evaluate options, youshould always (1) display the optionsevaluated; (2) identify the average andincremental costs of each option; (3) consider

the energy and non-air quality environmentalimpacts of each option; (4) consider the

remaining useful life; and (5) consider themodeled visibility impacts. You shouldprovide a justification for adopting the

technology that you select as the “best” level

of control, including an explanation of the
installation of controls would affect the

viability of continued plant operations.

2. There may be unusual circumstances

that justify taking into consideration the

conditions of the plant and the economic

effects of requiring the use of a given control

technology. These effects would include

effects on product prices, the market share,and profitability of the source. Where there

are such unusual circumstances that are

judged to affect plant operations, you may

take into consideration the conditions of the

plant and the economic effects of requiring

the use of a control technology. Where these

effects are judged to have a severe impact onplant operations you may consider them in

the selection process, but you may wish toprovide an economic analysis that

demonstrates, in sufficient detail for public

review, the specific economic effects,

parameters, and reasoning. (We recognize

that this review process must preserve the

confidentiality of sensitive business

information). Any analysis may also consider

whether other competing plants in the same

industry have been required to install BART

controls if this information is available.

4. Sulfur dioxide limits for utility boilers

You must require 750 MW power plants to

meet specific control levels for 502 of either

95 percent control or 0.15 lbs/MMBtu, for

each ECU greater than 200 MW that is

currently uncontrolled unless you determine

that an alternative control level is justified

based on a careful consideration of thestatutory factors. Thus, for example, if the

source demonstrates circumstances affecting

its ability to cost-effectively reduce itsemissions, you should take that into account

in determining whether the presumptive

levels of control are appropriate for that

facility. For a currently uncontrolled ECU

greater than 200 MW in size, but located at a power plant smaller than 750 MW in size,

such controls are generally cost-effective and

y

g 

new FGD system to meet the same emission

limits as above (95 percent removal or 0.15lb/mmBtu), in addition to the evaluation of

scrubber upgrades discussed below. For oilfired units, regardless of size, you should

evaluate limiting the sulfur content of thefuel oil burned to 1 percent or less by weight.

For those BART-eligible ECUs with pre

existing post-combustion SO2controls

achieving removal efficiencies of at least 50

percent, your BART determination should

consider cost effective scrubber upgrades

designed to improve the system’s overall SO2

removal efficiency. There are numerous

scrubber enhancements available to upgrade

the average removal efficiencies of all types

of existing scrubber systems. We recommend

that as you evaluate the definition of

“upgrade,” you evaluate options that not

only improve the design removal efficiency

of the scrubber vessel itself, but also consider

upgrades that can improve the overall 802removal efficiency of the scrubber system.

Increasing a scrubber system’s reliability, andconversely decreasing its downtime, by way

of optimizing operation procedures,

improving maintenance practices, adjusting

scrubber chemistry, and increasing auxiliary

equipment redundancy, are all ways toimprove average SO2removal efficiencies.

We recommend that as you evaluate the

performance of existing wet scrubber

systems, you consider some of the following

upgrades, in no particular order, as potential

scrubber upgrades that have been proven in

the industry as cost effective means to

increase overall SO2removal of wet systems:

(a) Elimination of Bypass Reheat;

(b) Installation of Liquid Distribution

Rings;

(c) Installation of Perforated Trays;

(d) Use of Organic Acid Additives;

(e) Improve or Upgrade Scrubber Auxiliary

System Equipment;

process.

5. Nitrogen oxide limits for utility boilers

You should establish specific numerical

limits for NOx control for each BARTdetermination. For power plants with a

generating capacity in excess of 750 MW

currently using selective catalytic reduction

(SCR) or selective non-catalytic reduction

(S NCR) for part of the year, you should

presume that use of those same controls yearround is BART. For other sources currently

using 8CR or SNCR to reduce NOx emissions

during part of the year, you should carefully

consider requiring the use of these controls

year-round as the additional costs of

operating the equipment throughout the year

would be relatively modest.

For coal-fired ECUs greater than 200 MW

located at greater than 750 MW power plants

and operating without post-combustioncontrols (i.e. 8CR or SNCR), we have

provided presumptive NOx limits,

differentiated by boiler design and type of

coal burned. You may determine that analternative control level is appropriate based

on a careful consideration of the statutory

factors. For coal-fired ECUs greater than 200

MW located at power plants 750 MW or lessin size and operating without postcombustion controls, you should likewise

presume that these same levels are costeffective. You should require such utility

boilers to meet the following NOx emission

limits, unless you determine that an

alternative control level is justified based on

consideration of the statutory factors. The

following NOx emission rates were

determined based on a number of

assumptions, including that the ECU boilerhas enough volume to allow for installation

and effective operation of separated overfire

air ports. For boilers where these

assumptions are incorrect, these emission

limits may not be cost-effective.
0.45

Dry-turbo-tired Bituminous 0.32

Sub-bituminous 0.23

Wet-bottom tangential-fired Bituminous 0.62

MostEGUs can meet these presumptive

NO x limits through the use of currentcombustion control technology, i.e. thecareful control of combustion air and low

NOx burners. For units that cannot meetthese limits using such technologies, you

should consider whether advancedcombustion control technologies such as

rotating opposed fire air should be used tomeet these limits.

Because of the relatively high NOx

emission rates of cyclone units, 8CR is morecost-effective than the use of currentcombustion control technology for these

units. The use of SCRs at cyclone units

burning bituminous coal, sub-bituminous

coal, and lignite should enable the units tocost-effectively meet NOx rates of 0.10 lbs/

mmbtu. As a result, we are establishing a

presumptive NOx limit of 0.10 lbs/mmbtu

based on the use of 8CR for coal-firedcyclone units greater than 200 MW located at

750 MW power plants. As with the other

presumptive limits established in thisguideline, you may determine that analternative level of control is appropriate

based on your consideration of the relevant

statutory factors. For other cyclone units, you

should review the use of 8CR and considerwhether these post-combustion controlsshould be required as BART.

For oil-fired and gas-fired EGUs larger than

2 00MW, we believe that installation of

current combustion control technology tocontrol NOx is generally highly cost-effectiveand should be considered in yourdetermination of BART for these sources.

19No Cell burners, dry-turbo-fired units, nor wetbottom tangential-fired units burning lignite ware

identified as BART-eligible, thus no presumptivelimit was determined. Similarly, no wet-bottomtangential-fired units burning sub-bituminous wereidentified as BART-eligible.

2°These limits reflect the design and

technological assumptions discussed in thetechnical support document for NOx limits for

these guidelines. See Technical Support Document

for DART NOr Limits for Electric Generating Units

and Technical Support Documentfar DART NOrLimits for Electric Generating Units ExcelSpreadsheet, Memorandum to Docket OAR 2002—

0076, April 15, 2005.

Many such units can make signifi cant

reductions in NOx emissions which arehighly cost-effective through the application

of current combustion control technology,21

V. Enforceable Limits/Compliance Date

To complete the BART process, you must

establish enforceable emission limits that

reflect the BART requirements and require

compliance within a given period of time. In

particular, you must establish an enforceable

emission limit for each subject emission unit

at the source and for each pollutant subject

to review that is emitted from the source. In

addition, you must require compliance with

the BART emission limitations no later than

5 years after EPA approves your regional

haze SIP. If technological or economiclimitations in the application of ameasurement methodology to a particularemission unit make a conventional emissions

limit infeasible, you may instead prescribe a

design, equipment, work practice, operation

standard, or combination of these types ofstandards. You should consider allowingsources to “average” emissions across any setof BART-eligible emission units within a

fenceline, so long as the emission reductionsfrom each pollutant being controlled for

BART would be equal to those reductionsthat would be obtained by simply controllingeach of the B ART-eligible units thatconstitute BART-eligible source.

You should ensure that any BART

requirements are written in a way that clearlyspecifies the individual emission unit(s)subject to BART regulation. Because theBART requirements themselves are“applicable” requirements of the CAA, they

must be included as title

V permit conditions

according to the procedures established in 40CFR part 70 or 40 CFR part 71.

Section 302(k) of the CAA requires

emissions limits such as BART to be met on

a continuous basis. Although this provisiondoes not necessarily require the use of

215ee Technical Support Document for BART

NOx Limits for Electric Generating Units and

Technical Support Documentfor DART NOr Limits

for Electric Genemting Units Excel Spreadsheet,

Memorandum to Docket OAR 2002—0076, April 15,

2005.

continuous emissions monitoring (CEMs), it

is important that sources employ techniquesthat ensure compliance on a continuous

basis. Monitoring requirements generally

applicable to sources, including those thatare subject to BART, are governed by other

regulations. See, e.g., 40 CFR part 64

(compliance assurance monitoring); 40 CFR70.6(aj(3j (periodic monitoring); 40 CFR70.6(c)(1) (sufficiency monitoring). Note also

that while we do not believe that CEMswould necessarily he required for all BARTsources, the vast majority of electric

generating units potentially subject to BART

already employ CEM technology for other

programs, such as the acid rain program. In

addition, emissions limits must be

enforceable as a practical matter (containappropriate averaging times, compliance

verification procedures and recordkeeping

requirements). In light of the above, thepermit must:

• Be sufficient to show compliance or

noncompliance (i.e., through monitoring

times of operation, fuel input, or other

indices of operating conditions and

practices); and

• Specify a reasonable averaging time

consistent with established reference

methods, contain reference methods for

determining compliance, and provide foradequate reporting and recordkeeping so thatair quality agency personnel can determine

the compliance status of the source; and

• For EGUS, specify an averaging time of

a 30-day rolling average, and contain adefinition of “boiler operating day” that isconsistent with the definition in the

proposed revisions to the NSPS for utility

boilers in 40 CFR Part 60, subpart Da. 22 You

should consider a boiler operating day to beany 24-hour period between 12:00 midnight

and the following midnight during whichany fuel is combusted at any time at thesteam generating unit. This would allow 30-day rolling average emission rates to be

calculated consistently across sources.

[FR Doc. 05—12526 Filed 7—5—05; 8:45 am]

BILLING CODE 65B0—50-P

2270 FR 9705, February 26, 2005.