Wednesday, 

July 6, 2005 

Part III 

Environmental 

Protection Agency 

40 CFR Part 51 

Regional Haze Regulations and Guidelines 

for Best Available Retrofit Technology 

(BART) Determinations; Final Rule 

39164 Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 

identifying control options that would cost 

many thousands of dollars per ton. Unless 

there are new technologies subsequent to the 

MACT standards which would lead to costeffective increases in the level of control, you 

may rely on the MACT standards for 

purposes of BART. 

We believe that the same rationale also 

holds true for emissions standards developed 

for municipal waste incinerators under CAA 

section 111(d), and for many NSR/PSD 

determinations and NSR/PSD settlement 

agreements. However, we do not believe that 

technology determinations from the 1970s or 

early 1980s, including new source 

performance standards (NSPS), should be 

considered to represent best control for 

existing sources, as best control levels for 

recent plant retrofits are more stringent than 

these older levels. 

Where you are relying on these standards 

to represent a BART level of control, you 

should provide the public with a discussion 

of whether any new technologies have 

subsequently become available. 

D. What Are the Five Basic Steps of a Caseby-Case BART Analysis? 

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 with 

a practical potential for application to the 

emissions unit and the regulated pollutant 

under evaluation. Air pollution control 

technologies can include a wide variety of 

available methods, systems, and techniques 

for control of the affected pollutant. 

Technologies required as BACT or LAER are 

available for BART purposes and must be 

included as control alternatives. The control 

alternatives can include not only existing 

controls 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 been 

applied to (or permitted for) full scale 

operations need not be considered as 

available; we do not expect the source owner 

to purchase or construct a process or control 

device that has not already been 

demonstrated in practice. 

2. Where a NSPS exists for a source 

category (which is the case for most of the 

categories affected by BART), you should 

include a level of control equivalent to the 

12 In identifying ‘‘all’’ options, you must identify 

the most stringent option and a reasonable set of 

options for analysis that reflects a comprehensive 

list of available technologies. It is not necessary to 

list all permutations of available control levels that 

exist for a given technology—the list is complete if 

it includes the maximum level of control each 

technology is capable of achieving. 

NSPS as one of the control options.13 The 

NSPS standards are codified in 40 CFR part 

60. We note that there are situations where 

NSPS standards do not require the most 

stringent level of available control for all 

sources within a category. For example, postcombustion NOX controls (the most stringent 

controls for stationary gas turbines) are not 

required under subpart GG of the NSPS for 

Stationary Gas Turbines. However, such 

controls must still be considered available 

technologies for the BART selection process. 

3. Potentially applicable retrofit control 

alternatives can be categorized in three ways. 

• 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 our 

intent 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 because 

they 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 BART as a 

requirement to redesign the source when 

considering available control alternatives. 

For example, where the source subject to 

BART is a coal-fired electric generator, we do 

not 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 BART 

review, there will often be control measures 

or devices already in place. For such 

emission units, it is important to include 

control options that involve improvements to 

existing controls and not to limit the control 

options only to those measures that involve 

a complete replacement of control devices. 

Example: For a power plant with an 

existing wet scrubber, the current control 

efficiency is 66 percent. Part of the reason for 

13 In EPA’s 1980 BART guidelines for reasonably 

attributable visibility impairment, we concluded 

that NSPS standards generally, at that time, 

represented the best level sources could install as 

BART. In the 20 year period since this guidance 

was developed, there have been advances in SO2 

control technologies as well as technologies for the 

control of other pollutants, confirmed by a number 

of 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 the 

BART 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. 

the relatively low control efficiency is that 22 

percent of the gas stream bypasses the 

scrubber. A BART review identifies options 

for improving the performance of the wet 

scrubber by redesigning the internal 

components of the scrubber and by 

eliminating or reducing the percentage of the 

gas stream that bypasses the scrubber. Four 

control options are identified: (1) 78 percent 

control based upon improved scrubber 

performance while maintaining the 22 

percent bypass, (2) 83 percent control based 

upon improved scrubber performance while 

reducing the bypass to 15 percent, (3) 93 

percent control based upon improving the 

scrubber performance while eliminating the 

bypass entirely, (this option results in a ‘‘wet 

stack’’ operation in which the gas leaving the 

stack is saturated with water) and (4) 93 

percent as in option 3, with the addition of 

an indirect reheat system to reheat the stack 

gas above the saturation temperature. You 

must consider each of these four options in 

a BART analysis for this source. 

7. You are expected to identify potentially 

applicable retrofit control technologies that 

represent the full range of demonstrated 

alternatives. Examples of general information 

sources to consider include: 

• The EPA’s Clean Air Technology Center, 

which includes the RACT/BACT/LAER 

Clearinghouse (RBLC); 

• State and Local Best Available Control 

Technology Guidelines—many agencies have 

online information—for example South Coast 

Air Quality Management District, Bay Area 

Air Quality Management District, and Texas 

Natural 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—http:// 

www.epa.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.epa.gov/airmarkets/arp/ 

nox/controltech.html; 

• Performance of selective catalytic 

reduction on coal-fired steam generating 

units—final report. OAR/ARD, June 1997 

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

airmarkets/arp/nox/controltech.html); 

• Cost estimates for selected applications 

of NOX control technologies on stationary 

combustion 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 

Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 39165 

logical set to which controls would apply 

and that set of units may or may not all be 

BART-eligible. (For example, some units in 

that set may not have been constructed 

between 1962 and 1977.) 

9. If you find that a BART source has 

controls already in place which are the most 

stringent controls available (note that this 

means that all possible improvements to any 

control devices have been made), then it is 

not necessary to comprehensively complete 

each following step of the BART analysis in 

this section. As long these most stringent 

controls available are made federally 

enforceable for the purpose of implementing 

BART for that source, you may skip the 

remaining analyses in this section, including 

the visibility analysis in step 5. Likewise, if 

a 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 the 

options identified in Step 1 are technically 

feasible? 

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 emissions 

unit under review. You may then eliminate 

such technically infeasible control options 

from 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 installed 

and operated successfully for the type of 

source under review under similar 

conditions, or (2) the technology could be 

applied to the source under review. Two key 

concepts are important in determining 

whether a technology could be applied: 

‘‘availability’’ and ‘‘applicability.’’ As 

explained in more detail below, a technology 

is considered ‘‘available’’ if the source owner 

may obtain it through commercial channels, 

or it is otherwise available within the 

common sense meaning of the term. An 

available technology is ‘‘applicable’’ if it can 

reasonably be installed and operated on the 

source type under consideration. A 

technology that is available and applicable is 

technically feasible. 

What do we mean by ‘‘available’’ technology? 

1. The typical stages for bringing a control 

technology concept to reality as a commercial 

product 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 licensing 

and commercial availability. Similarly, we do 

not expect a source owner to conduct 

extended trials to learn how to apply a 

technology on a totally new and dissimilar 

source type. Consequently, you would not 

consider technologies in the pilot scale 

testing stages of development as ‘‘available’’ 

for purposes of BART review. 

3. Commercial availability by itself, 

however, is not necessarily a sufficient basis 

for concluding a technology to be applicable 

and therefore technically feasible. Technical 

feasibility, as determined in Step 2, also 

means a control option may reasonably be 

deployed on or ‘‘applicable’’ to the source 

type under consideration. 

Because a new technology may become 

available at various points in time during the 

BART analysis process, we believe that 

guidelines are needed on when a technology 

must be considered. For example, a 

technology 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 comment 

period 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 not 

consider technologies that become available 

after this date. 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 under 

consideration. In general, a commercially 

available control option will be presumed 

applicable if it has been used on the same or 

a similar source type. Absent a showing of 

this type, you evaluate technical feasibility 

by examining the physical and chemical 

characteristics of the pollutant-bearing gas 

stream, and comparing them to the gas 

stream characteristics of the source types to 

which the technology had been applied 

previously. Deployment of the control 

technology on a new or existing source with 

similar gas stream characteristics is generally 

a 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 technically 

feasible? 

1. Where you conclude that a control 

option identified in Step 1 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 an 

evaluation of the characteristics of the 

pollutant-bearing gas stream and the 

capabilities of the technology. Alternatively, 

a demonstration of technical infeasibility 

may involve a showing that there are 

unresolvable technical difficulties with 

applying the control to the source (e.g., size 

of the unit, location of the proposed site, 

operating problems related to specific 

circumstances of the source, space 

constraints, reliability, and adverse side 

effects on the rest of the facility). Where the 

resolution of technical difficulties is merely 

a matter of increased cost, you should 

consider the technology to be technically 

feasible. The cost of a control alternative is 

considered later in the process. 

2. The determination of technical 

feasibility is sometimes influenced by recent 

air quality permits. In some cases, an air 

quality permit may require a certain level of 

control, but the level of control in a permit 

is not expected to be achieved in practice 

(e.g., a source has received a permit but the 

project was canceled, or every operating 

source at that permitted level has been 

physically unable to achieve compliance 

with the limit). Where this is the case, you 

should provide supporting documentation 

showing 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 certain 

technology or emission limit to be achieved 

for 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 of 

themselves, provide a justification for 

eliminating the control technique on the 

basis of technical infeasibility. However, you 

may consider the cost of such modifications 

in estimating costs. This, in turn, may form 

the 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, we 

do 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 or 

an emissions limit is technically infeasible. 

Generally, you should make decisions about 

technical feasibility based on chemical, and 

engineering analyses (as discussed above), in 

conjunction with information about vendor 

guarantees. 

5. A possible outcome of the BART 

procedures discussed in these guidelines is 

the evaluation of multiple control technology 

alternatives which result in essentially 

equivalent emissions. It is not our intent to 

encourage 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 the 

detailed impacts analysis (Step 4 below). For 

example, if two or more control techniques 

result in control levels that are essentially 

identical, considering the uncertainties of 

emissions factors and other parameters 

39166 Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 

pertinent to estimating performance, you may 

evaluate only the less costly of these options. 

You should narrow the scope of the BART 

analysis in this way only if there is a 

negligible difference in emissions and energy 

and non-air quality environmental impacts 

between control alternatives. 

3. STEP 3: How do I evaluate technically 

feasible alternatives? 

Step 3 involves evaluating the control 

effectiveness of all the technically feasible 

control alternatives identified in Step 2 for 

the pollutant and emissions unit under 

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 can 

operate 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-polluting 

processes to one another or to add-on 

controls. In such cases, it is generally most 

effective to express emissions performance as 

an average steady state emissions level per 

unit of product produced or processed. 

Examples of common metrics: 

• Pounds of SO2 emissions 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 (ESPs) 

are two of the many examples of such control 

techniques that can perform at a wide range 

of levels. It is not our intent to require 

analysis of each possible level of efficiency 

for a control technique as such an analysis 

would result in a large number of options. It 

is 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 decisions 

and performance data (e.g., manufacturer’s 

data, engineering estimates and the 

experience of other sources) when 

identifying an emissions performance level 

or levels to evaluate. 

2. In assessing the capability of the control 

alternative, latitude exists to consider special 

circumstances pertinent to the specific 

source under review, or regarding the prior 

application of the control alternative. 

However, you should explain the basis for 

choosing the alternate level (or range) of 

control in the BART analysis. Without a 

showing of differences between the source 

and other sources that have achieved more 

stringent emissions limits, you should 

conclude that the level being achieved by 

those other sources is representative of the 

achievable level for the source being 

analyzed. 

3. You may encounter cases where you 

may wish to evaluate other levels of control 

in addition to the most stringent level for a 

given device. While you must consider the 

most stringent level as one of the control 

options, you may consider less stringent 

levels of control as additional options. This 

would be useful, particularly in cases where 

the selection of additional options would 

have widely varying costs and other impacts. 

4. Finally, we note that for retrofitting 

existing sources in addressing BART, you 

should consider ways to improve the 

performance of existing control devices, 

particularly when a control device is not 

achieving the level of control that other 

similar sources are achieving in practice with 

the same device. For example, you should 

consider requiring those sources with 

electrostatic precipitators (ESPs) performing 

below currently achievable levels to improve 

their performance. 

4. STEP 4: For a BART 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 the 

following analyses when you make a BART 

determination: 

Impact analysis part 1: Costs of 

compliance, 

Impact analysis part 2: Energy impacts, and 

Impact analysis part 3: Non-air quality 

environmental impacts. 

Impact analysis part 4: Remaining useful 

life. 

In this section, we describe how to conduct 

each of these three analyses. You are 

responsible for presenting an evaluation of 

each impact along with appropriate 

supporting information. You should discuss 

and, where possible, quantify both beneficial 

and adverse impacts. In general, the analysis 

should focus on the direct impact of the 

control 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, to 

specify 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 to 

install separate and/or different control 

devices. The analysis should provide a clear 

summary list of equipment and the 

associated control costs. Inadequate 

documentation of the equipment whose 

emissions 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 

design parameters include equipment 

vendors, background information documents 

used to support NSPS development, control 

technique guidelines documents, cost 

manuals developed by EPA, control data in 

trade publications, and engineering and 

performance test data. The following are a 

few examples of design parameters for two 

example control measures: 

Examples of design Control device parameters 

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 control 

option will achieve the level of emission 

control being evaluated. You should include 

in your analysis documentation of your 

assumptions regarding design parameters. 

Examples of supporting references would 

include the EPA OAQPS Control Cost 

Manual (see below) and background 

information documents used for NSPS and 

hazardous pollutant emission standards. If 

the 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 data 

supplied by an equipment vendor (i.e., 

budget estimates or bids) or by a referenced 

source (such as the OAQPS Control Cost 

Manual, Fifth Edition, February 1996, EPA 

453/B–96–001).14 In order to maintain and 

improve consistency, cost estimates should 

be based on the OAQPS Control Cost Manual, 

where possible.15 The Control Cost Manual 

addresses most control technologies in 

sufficient detail for a BART analysis. The 

cost analysis should also take into account 

any site-specific design or other conditions 

identified above that affect the cost of a 

particular BART technology option. 

14The OAQPS Control Cost Manual 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 document 

is available at the following Web site: http:// 

www.epa.gov/ttn/catc/dir1/cs1ch2.pdf. 

15 You should include documentation for any 

additional information you used for the cost 

calculations, including any information supplied by 

vendors that affects your assumptions regarding 

purchased equipment costs, equipment life, 

replacement of major components, and any other 

element of the calculation that differs from the 

Control Cost Manual. 

Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 39167 

b. What do we mean by cost effectiveness? 

Cost effectiveness, in general, is a criterion 

used to assess the potential for achieving an 

objective in the most economical way. For 

purposes of air pollutant analysis, 

‘‘effectiveness’’ is measured in terms of tons 

of pollutant emissions removed, and ‘‘cost’’ 

is measured in terms of annualized control 

costs. We recommend two types of costeffectiveness calculations—average cost 

effectiveness, and incremental cost 

effectiveness. 

c. How do I calculate average cost 

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 

cost 16 

Baseline annual emissions—Annual 

emissions with Control option 

Because you calculate costs in (annualized) 

dollars per year ($/yr) and because you 

calculate emissions rates in tons per year 

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

per ton ($/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 

16 Whenever you calculate or report annual costs, 

you should indicate the year for which the costs are 

estimated. For example, if you use the year 2000 as 

the basis for cost comparisons, you would report 

that an annualized cost of $20 million would be: 

$20 million (year 2000 dollars). 

or capacity utilization, type of fuel, raw 

materials or product mix or type) will differ 

from past practice, and if this projection has 

a deciding effect in the BART determination, 

then you must make these parameters or 

assumptions into enforceable limitations. In 

the absence of enforceable limitations, you 

calculate baseline emissions based upon 

continuation of past practice. 

3. For example, the baseline emissions 

calculation for an emergency standby 

generator may consider the fact that the 

source owner would not operate more than 

past practice of 2 weeks a year. On the other 

hand, baseline emissions associated with a 

base-loaded turbine should be based on its 

past practice which would indicate a large 

number 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, BART 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 should 

also calculate incremental cost effectiveness. 

You should consider the incremental cost 

effectiveness in combination with the average 

cost effectiveness when considering whether 

to eliminate a control option. The 

incremental 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 following 

formula (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 annual 

emissions) ¥ (Next control option 

annual emissions) 

Example 1: Assume that Option F on 

Figure 2 has total annualized costs of $1 

million to reduce 2000 tons of a pollutant, 

and that Option D on Figure 2 has total 

annualized costs of $500,000 to reduce 1000 

tons of the same pollutant. The incremental 

cost effectiveness of Option F relative to 

Option D is ($1 million ¥ $500,000) divided 

by (2000 tons ¥ 1000 tons), or $500,000 

divided by 1000 tons, which is $500/ton. 

Example 2: Assume that two control 

options exist: Option 1 and Option 2. Option 

1 achieves a 1,000 ton/yr reduction at an 

annualized cost of $1,900,000. This 

represents an average cost of ($1,900,000/ 

1,000 tons) = $1,900/ton. Option 2 achieves 

a 980 tons/yr reduction at an annualized cost 

of $1,500,000. This represents an average cost 

of ($1,500,000/980 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 an 

overall 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 BART 

technology. 

2. You should exercise care in deriving 

incremental costs of candidate control 

options. Incremental cost-effectiveness 

comparisons 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 for 

total emissions reductions for all control 

alternatives identified in the BART 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.) 

ER06JY05.000</GPH>

39168 Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 

Example: 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, G, 

and H, represent the least-cost envelope, as 

we depict by the cost curve connecting them. 

Points A, C and E are inferior options, and 

you should not use them in calculating 

incremental cost effectiveness. Points A, C 

and E represent inferior controls because B 

will buy more emissions reductions for less 

money than A; and similarly, D and F will 

buy more reductions for less money than C 

and 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, as 

shown 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 G, and options G and 

H. 

4. A comparison of incremental costs can 

also be useful in evaluating the viability of 

a specific control option over a range of 

efficiencies. For example, depending on the 

capital and operational cost of a control 

device, total and incremental cost may vary 

significantly (either increasing or decreasing) 

over the 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 one 

candidate control option is known to exist. 

5. You should exercise caution not to 

misuse these techniques. For example, you 

may be faced with a choice between two 

available control devices at a source, control 

A and control B, where control B achieves 

slightly greater emission reductions. The 

average cost (total annual cost/total annual 

emission reductions) for each may be deemed 

to be reasonable. However, the incremental 

cost (total annual costA – B/total annual 

emission reductionsA – B) of the additional 

emission reductions to be achieved by 

control B may be very great. In such an 

instance, it may be inappropriate to choose 

control B, based on its high incremental 

costs, even though its average cost may be 

considered reasonable. 

6. In addition, when you evaluate the 

average or incremental cost effectiveness of a 

control alternative, you should make 

reasonable and supportable assumptions 

regarding 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 considered 

reasonable. (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 could 

greatly increase the cost per ton of emissions 

reduced of wet scrubbing as a control option. 

g. What other things are important to 

consider in the cost impacts analysis? 

In the cost analysis, you should take care 

not to focus on incomplete results or partial 

calculations. For example, large capital costs 

for a control option alone would not preclude 

selection of a control measure if large 

emissions reductions are projected. In such a 

case, low or reasonable cost effectiveness 

numbers 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. A 

source owner may, for example, benefit from 

the combustion of a concentrated gas stream 

rich in volatile organic compounds; on the 

other hand, more often extra fuel or 

electricity is required to power a control 

Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 39169 

device or incinerate a dilute gas stream. If 

such benefits or penalties exist, they should 

be quantified to the extent practicable. 

Because energy penalties or benefits can 

usually be quantified in terms of additional 

cost or income to the source, the energy 

impacts analysis can, in most cases, simply 

be factored into the cost impacts analysis. 

The fact of energy use in and of itself does 

not disqualify a technology. 

2. Your energy impact analysis should 

consider only direct energy consumption and 

not indirect energy impacts. For example, 

you could estimate the direct energy impacts 

of the control alternative in units of energy 

consumption at the source (e.g., BTU, kWh, 

barrels of oil, tons of coal). The energy 

requirements of the control options should be 

shown 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, where 

appropriate, factor these costs into the 

control cost analysis. 

3. You generally do not consider indirect 

energy impacts (such as energy to produce 

raw materials for construction of control 

equipment). 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 the 

impact 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 fuel 

may vary from region to region. However, in 

general, a scarce fuel is one which is in short 

supply locally and can be better used for 

alternative 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 regarding 

the use of locally or regionally available coal, 

and whether a given alternative would result 

in 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 other 

alternative 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 environmental 

impacts 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 the 

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 of 

secondary environmental impacts could 

include hazardous waste discharges, such as 

spent catalysts or contaminated carbon. 

Generally, these types of environmental 

concerns become important when sensitive 

site-specific receptors exist or when the 

incremental emissions reductions potential 

of the more stringent control is only 

marginally greater than the next mosteffective option. However, the fact that a 

control device creates liquid and solid waste 

that must be disposed of does not necessarily 

argue against selection of that technology as 

BART, particularly if the control device has 

been applied to similar facilities elsewhere 

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 proposed 

facility create greater problems than 

experienced 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 a 

consideration of site-specific circumstances. 

If you propose to adopt the most stringent 

alternative, then it is not necessary to 

perform this analysis of environmental 

impacts for the entire list of technologies you 

ranked in Step 3. In general, the analysis 

need 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 of 

the solid, liquid, and gaseous discharges from 

the control device or devices under review. 

Initially, you should perform a qualitative or 

semi-quantitative screening to narrow the 

analysis to discharges with potential for 

causing adverse environmental effects. Next, 

you should assess the mass and composition 

of any such discharges and quantify them to 

the extent possible, based on readily 

available information. You should also 

assemble 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) Water Impact 

You should identify the relative quantities 

of water used and water pollutants produced 

and discharged as a result of the use of each 

alternative 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 standards 

will be met and the availability and 

effectiveness of various techniques to reduce 

potential adverse effects. 

(2) Solid Waste Disposal Impact 

You could also compare the quality and 

quantity of solid waste (e.g., sludges, solids) 

that must be stored and disposed of or 

recycled as a result of the application of each 

alternative emission control system. You 

should consider the composition and various 

other characteristics of the solid waste (such 

as permeability, water retention, rewatering 

of dried material, compression strength, 

leachability of dissolved ions, bulk density, 

ability to support vegetation growth and 

hazardous characteristics) which are 

significant with regard to potential surface 

water pollution or transport into and 

contamination of subsurface waters or 

aquifers. 

(3) Irreversible or Irretrievable Commitment 

of Resources 

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 Environmental Impacts 

You may consider significant differences in 

noise levels, radiant heat, or dissipated static 

electrical energy of pollution control 

alternatives. Other examples of non-air 

quality environmental impacts would 

include 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 determinations 

as one element of the overall cost analysis. 

The ‘‘remaining useful life’’ of a source, if it 

represents a relatively short time period, may 

affect the annualized costs of retrofit 

controls. For example, the methods for 

calculating annualized costs in EPA’s 

OAQPS Control Cost Manual 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 Manual); you are 

conducting the BART analysis; and 

(2) The date the facility permanently stops 

operations. Where this affects the BART 

determination, this date should be assured by 

a federally- or State-enforceable restriction 

preventing further operation. 

3. We recognize that there may be 

situations where a source operator intends to 

shut down a source by a given date, but 

wishes to retain the flexibility to continue 

39170 Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 

operating beyond that date in the event, for 

example, that market conditions change. 

Where this is the case, your BART analysis 

may account for this, but it must maintain 

consistency with the statutory requirement to 

install BART within 5 years. Where the 

source chooses not to accept a federally 

enforceable condition requiring the source to 

shut down by a given date, it is necessary to 

determine whether a reduced time period for 

the remaining useful life changes the level of 

controls that would have been required as 

BART. 

If the reduced time period does change the 

level of BART controls, you may identify, 

and include as part of the BART emission 

limitation, the more stringent level of control 

that would be required as BART if there were 

no assumption that reduced the remaining 

useful life. You may incorporate into the 

BART 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 BART 

in place, the source is considered to be in 

violation of the BART emissions limit for 

each day of operation. 

5. Step 5: How should I determine visibility 

impacts in the BART determination? 

The following is an approach you may use 

to determine visibility impacts (the degree of 

visibility improvement for each source 

subject to BART) for the BART 

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 BART determination. When 

making this determination, we believe you 

have flexibility in setting absolute thresholds, 

target levels of improvement, or de minimis 

levels since the deciview improvement must 

be weighed among the five factors, and you 

are free to determine the weight and 

significance to be assigned to each factor. For 

example, a 0.3 deciview improvement may 

merit a stronger weighting in one case versus 

another, so one ‘‘bright line’’ may not be 

appropriate. [Note that if sources have 

elected to apply the most stringent controls 

available, consistent with the discussion in 

section E. step 1. below, you need not 

conduct, or require the source to conduct, an 

air quality modeling analysis for the purpose 

of determining its visibility impacts.] 

Use CALPUFF,17 or other appropriate 

dispersion model to determine the visibility 

improvement expected at a Class I area from 

the potential BART control technology 

applied to the source. Modeling should be 

conducted for SO2, NOX, and direct PM 

emissions (PM2.5 and/or PM10). If the source 

is making the visibility determination, you 

should review and approve or disapprove of 

the source’s analysis before making the 

expected improvement determination. There 

are several steps for determining the 

17 The model code and its documentation are 

available at no cost for download from http:// 

www.epa.gov/scram001/tt22.htm#calpuff. 

visibility impacts from an individual source 

using a dispersion model: 

• Develop a modeling protocol. 

Some critical items to include in a 

modeling protocol are meteorological and 

terrain data, as well as source-specific 

information (stack height, temperature, exit 

velocity, elevation, and allowable and actual 

emission rates of applicable pollutants), and 

receptor data from appropriate Class I areas. 

We recommend following EPA’s Interagency 

Workgroup on Air Quality Modeling 

(IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long Range 

Transport Impacts 18 for parameter settings 

and meteorological data inputs; the use of 

other 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 area 

with sufficient density to identify the likely 

visibility effects of the source. For other Class 

I areas in relatively close proximity to a 

BART-eligible source, you may model a few 

strategic 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 I 

area, at the IMPROVE monitor, and at the 

approximate expected plume release height. 

If the highest modeled effects are observed at 

the 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 km from the same 

source. As indicated by the Guideline on Air 

Quality 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 method 

for modeling sources less than 50 km. In 

situations where you are assessing visibility 

impacts for source-receptor distances less 

than 50 km, you should use expert modeling 

judgment in determining visibility impacts, 

giving consideration to both CALPUFF and 

other EPA-approved methods. 

In developing your modeling protocol, you 

may want to consult with EPA and your 

regional planning organization (RPO). Upfront consultation will ensure that key 

technical issues are addressed before you 

conduct your modeling. 

• For each source, run the model, at precontrol and post-control emission rates 

according 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 precontrol scenario). Calculate the model results 

for each receptor as the change in deciviews 

compared against natural visibility 

18 Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long Range 

Transport Impacts, U.S. Environmental Protection 

Agency, EPA–454/R–98–019, December 1998. 

conditions. Post-control emission rates are 

calculated as a percentage of pre-control 

emission rates. For example, if the 24-hr precontrol emission rate is 100 lb/hr of SO2, 

then the post control rate is 5 lb/hr if the 

control efficiency being evaluated is 95 

percent. 

• Make the net visibility improvement 

determination. 

Assess the visibility improvement based on 

the modeled change in visibility impacts for 

the pre-control and post-control emission 

scenarios. You have flexibility to assess 

visibility improvements due to BART 

controls by one or more methods. You may 

consider 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 BART-eligible 

sources should be subject to a BART 

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 source 

apportionment 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/MMBtu, ppm); 

(3) Expected emissions reductions (tons 

per year); 

(4) Costs of compliance—total annualized 

costs ($), cost effectiveness ($/ton), and 

incremental cost effectiveness ($/ton), and/or 

any other cost-effectiveness measures (such 

as $/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 control 

options for BART. Whatever the order in 

which you choose to evaluate options, you 

should always (1) display the options 

evaluated; (2) identify the average and 

incremental costs of each option; (3) consider 

the energy and non-air quality environmental 

impacts of each option; (4) consider the 

remaining useful life; and (5) consider the 

modeled visibility impacts. You should 

provide a justification for adopting the 

technology that you select as the ‘‘best’’ level 

of control, including an explanation of the 

Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 39171 

CAA factors that led you to choose that 

option over other control levels. 

2. In the case where you are conducting a 

BART determination for two regulated 

pollutants on the same source, if the result 

is two different BART technologies that do 

not work well together, you could then 

substitute a different technology or 

combination of technologies. 

3. In selecting a ‘‘best’’ alternative, should I 

consider the affordability of controls? 

1. Even if the control technology is cost 

effective, there may be cases where 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 on 

plant operations you may consider them in 

the selection process, but you may wish to 

provide 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 SO2 of either 

95 percent control or 0.15 lbs/MMBtu, for 

each EGU greater than 200 MW that is 

currently uncontrolled unless you determine 

that an alternative control level is justified 

based on a careful consideration of the 

statutory factors. Thus, for example, if the 

source demonstrates circumstances affecting 

its ability to cost-effectively reduce its 

emissions, you should take that into account 

in determining whether the presumptive 

levels of control are appropriate for that 

facility. For a currently uncontrolled EGU 

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 

could be used in your BART determination 

considering the five factors specified in CAA 

section 169A(g)(2). While these levels may 

represent current control capabilities, we 

expect that scrubber technology will 

continue to improve and control costs 

continue to decline. You should be sure to 

consider the level of control that is currently 

best achievable at the time that you are 

conducting your BART analysis. 

For coal-fired EGUs with existing postcombustion SO2 controls achieving less than 

50 percent removal efficiencies, we 

recommend that you evaluate constructing a 

new FGD system to meet the same emission 

limits as above (95 percent removal or 0.15 

lb/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 the 

fuel oil burned to 1 percent or less by weight. 

For those BART-eligible EGUs with preexisting post-combustion SO2 controls 

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 SO2 

removal efficiency of the scrubber system. 

Increasing a scrubber system’s reliability, and 

conversely decreasing its downtime, by way 

of optimizing operation procedures, 

improving maintenance practices, adjusting 

scrubber chemistry, and increasing auxiliary 

equipment redundancy, are all ways to 

improve average SO2 removal 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 SO2 removal 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; 

(f) Redesign Spray Header or Nozzle 

Configuration. 

We recommend that as you evaluate 

upgrade options for dry scrubber systems, 

you should consider the following cost 

effective upgrades, in no particular order: 

(a) Use of Performance Additives; 

(b) Use of more Reactive Sorbent; 

(c) Increase the Pulverization Level of 

Sorbent; 

(d) Engineering redesign of atomizer or 

slurry injection system. 

You should evaluate scrubber upgrade 

options based on the 5 step BART analysis 

process. 

5. Nitrogen oxide limits for utility boilers

You should establish specific numerical 

limits for NOX control for each BART 

determination. For power plants with a 

generating capacity in excess of 750 MW 

currently using selective catalytic reduction 

(SCR) or selective non-catalytic reduction 

(SNCR) for part of the year, you should 

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

using SCR 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 EGUs greater than 200 MW 

located at greater than 750 MW power plants 

and operating without post-combustion 

controls (i.e. SCR or SNCR), we have 

provided presumptive NOX limits, 

differentiated by boiler design and type of 

coal burned. You may determine that an 

alternative control level is appropriate based 

on a careful consideration of the statutory 

factors. For coal-fired EGUs greater than 200 

MW located at power plants 750 MW or less 

in 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 EGU boiler 

has 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. 

39172 Federal Register / Vol. 70, No. 128 / Wednesday, July 6, 2005 / Rules and Regulations 

TABLE 1.—PRESUMPTIVE NO 19 X EMISSION LIMITS FOR BART-ELIGIBLE COAL-FIRED UNITS.

NOX presumptive 

Unit type Coal type limit 

(lb/mmbtu) 20 

Dry-bottom wall-fired .................................................................
 Bituminous ................................................................................
 0.39 

Sub-bituminous ........................................................................ 0.23 

Lignite ....................................................................................... 0.29 

Tangential-fired ......................................................................... Bituminous ................................................................................
 0.28 

Sub-bituminous ........................................................................ 0.15 

Lignite ....................................................................................... 0.17 

Cell Burners .............................................................................. Bituminous ................................................................................
 0.40 

Sub-bituminous ........................................................................ 0.45 

Dry-turbo-fired ........................................................................... 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 current 

combustion control technology, i.e. the 

careful control of combustion air and lowNOX burners. For units that cannot meet 

these limits using such technologies, you 

should consider whether advanced 

combustion control technologies such as 

rotating opposed fire air should be used to 

meet these limits. 

Because of the relatively high NOX 

emission rates of cyclone units, SCR is more 

cost-effective than the use of current 

combustion control technology for these 

units. The use of SCRs at cyclone units 

burning bituminous coal, sub-bituminous 

coal, and lignite should enable the units to 

cost-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 SCR for coal-fired 

cyclone units greater than 200 MW located at 

750 MW power plants. As with the other 

presumptive limits established in this 

guideline, you may determine that an 

alternative level of control is appropriate 

based on your consideration of the relevant 

statutory factors. For other cyclone units, you 

should review the use of SCR and consider 

whether these post-combustion controls 

should be required as BART. 

For oil-fired and gas-fired EGUs larger than 

200MW, we believe that installation of 

current combustion control technology to 

control NOX is generally highly cost-effective 

and should be considered in your 

determination of BART for these sources. 

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

identified as BART-eligible, thus no presumptive 

limit was determined. Similarly, no wet-bottom 

tangential-fired units burning sub-bituminous were 

identified as BART-eligible. 

20 These limits reflect the design and 

technological assumptions discussed in the 

technical support document for NOX limits for 

these guidelines. See Technical Support Document 

for BART NOX Limits for Electric Generating Units 

and Technical Support Document for BART NOX 

Limits for Electric Generating Units Excel 

Spreadsheet, Memorandum to Docket OAR 2002– 

0076, April 15, 2005. 

Many such units can make significant 

reductions in NOX emissions which are 

highly 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 economic 

limitations in the application of a 

measurement methodology to a particular 

emission unit make a conventional emissions 

limit infeasible, you may instead prescribe a 

design, equipment, work practice, operation 

standard, or combination of these types of 

standards. You should consider allowing 

sources to ‘‘average’’ emissions across any set 

of BART-eligible emission units within a 

fenceline, so long as the emission reductions 

from each pollutant being controlled for 

BART would be equal to those reductions 

that would be obtained by simply controlling 

each of the BART-eligible units that 

constitute BART-eligible source. 

You should ensure that any BART 

requirements are written in a way that clearly 

specifies the individual emission unit(s) 

subject to BART regulation. Because the 

BART requirements themselves are 

‘‘applicable’’ requirements of the CAA, they 

must be included as title V permit conditions 

according to the procedures established in 40 

CFR 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 provision 

does not necessarily require the use of 

21See Technical Support Document for BART 

NOX Limits for Electric Generating Units and 

Technical Support Document for BART NOX Limits 

for Electric Generating Units Excel Spreadsheet, 

Memorandum to Docket OAR 2002–0076, April 15, 

2005. 

continuous emissions monitoring (CEMs), it 

is important that sources employ techniques 

that ensure compliance on a continuous 

basis. Monitoring requirements generally 

applicable to sources, including those that 

are subject to BART, are governed by other 

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

(compliance assurance monitoring); 40 CFR 

70.6(a)(3) (periodic monitoring); 40 CFR 

70.6(c)(1) (sufficiency monitoring). Note also 

that while we do not believe that CEMs 

would necessarily be required for all BART 

sources, 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 (contain 

appropriate averaging times, compliance 

verification procedures and recordkeeping 

requirements). In light of the above, the 

permit 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 for 

adequate reporting and recordkeeping so that 

air 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 a 

definition of ‘‘boiler operating day’’ that is 

consistent 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 be 

any 24-hour period between 12:00 midnight 

and the following midnight during which 

any fuel is combusted at any time at the 

steam 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 6560–50–P 

22 70 FR 9705, February 28, 2005.