25304 Federal Register / Vol. 74, No. 100 / Wednesday, May 27, 2009 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2008–0260; FRL–8908–7] 

RIN 2060–AO57 

Standards of Performance for Coal 

Preparation and Processing Plants 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Supplemental proposal. 

SUMMARY: EPA is proposing a 

supplemental action to the proposed 

amendments to the new source 

performance standards for coal 

preparation and processing plants 

published on April 28, 2008. The 2008 

proposal, among other things, proposed 

to revise the particulate matter and 

opacity standards for thermal dryers, 

pneumatic coal cleaning equipment, 

and coal handling equipment located at 

coal preparation and processing plants. 

This supplemental action proposes to 

revise the particulate matter emissions 

and opacity limits included in the 

original proposal for thermal dryers, 

pneumatic coal-cleaning equipment, 

and coal handling equipment. It also 

proposes to expand the applicability of 

the thermal dryer standards so that the 

proposed standards for thermal dryers 

would apply to both direct contact and 

indirect contact thermal dryers drying 

all coal ranks and pneumatic coalcleaning equipment cleaning all coal 

ranks. In addition, it proposes to 

establish a sulfur dioxide emission limit 

and a combined nitrogen oxide and 

carbon monoxide emissions limit for 

thermal dryers. We are also proposing to 

amend the definition of coal for 

purposes of subpart Y to include 

petroleum coke and coal refuse. Finally, 

it proposes to establish work practice 

standards to control coal dust emissions 

from open storage piles and roadways 

associated with coal preparation and 

processing plants. 

DATES: Comments. Comments must be 

received on or before July 13, 2009. If 

anyone contacts EPA by June 8, 2009 

requesting to speak at a public hearing, 

EPA will hold a public hearing on June 

11, 2009. Under the Paperwork 

Reduction Act, comments on the 

information collection provisions must 

be received by the Office of 

Management and Budget (OMB) on or 

before June 26, 2009. 

Because, under the terms of a consent 

decree, the final action must be signed 

not later than September 26, 2009, EPA 

will not grant requests for extensions 

beyond these dates. 

ADDRESSES: Comments. Submit your 

comments, identified by Docket ID No. 

EPA–HQ–OAR–2008–0260, by one of 

the following methods: 

• http://www.regulations.gov. Follow 

the on-line instructions for submitting 

comments. 

• E-mail: a-and-r-docket@epa.gov. 

• By Facsimile: (202) 566–1741. 

• Mail: Air and Radiation Docket, 

U.S. EPA, Mail Code 6102T, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460. 

Please include a total of two copies. 

In addition, please mail a copy of your 

comments on the information collection 

provisions to the Office of Information 

and Regulatory Affairs, Office of 

Management and Budget (OMB), Attn: 

Desk Officer for EPA, 725 17th Street, 

NW., Washington, DC 20503. EPA 

requests a separate copy also be sent to 

the contact person identified below (see 

FOR FURTHER INFORMATION CONTACT). 

• Hand Delivery: EPA Docket Center, 

Docket ID Number EPA–HQ–OAR– 

2008–0260, EPA West Building, 1301 

Constitution Ave., NW., Room 3334, 

Washington, DC, 20004. Such deliveries 

are accepted only during the Docket’s 

normal hours of operation, and special 

arrangements should be made for 

deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2008– 

0260. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through regulations.gov or email. The http://www.regulations.gov 

Web site is an ‘‘anonymous access’’ 

system, which means EPA will not 

know your identity or contact 

information unless you provide it in the 

body of your comment. If you send an 

e-mail comment directly to EPA without 

going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD–ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional information 

about EPA’s public docket visit the EPA 

Docket Center homepage at http:// 

www.epa.gov/epahome/dockets.htm. 

Docket: All documents in the docket 

are listed in the http:// 

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http:// 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket EPA/DC, 

EPA West, Room 3334, 1301 

Constitution Ave., NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the Air 

and Radiation Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Mary Johnson, Energy Strategies Group, 

Sector Policies and Programs Division 

(D243–01), U.S. EPA, Research Triangle 

Park, NC 27711, telephone number (919) 

541–5025, facsimile number (919) 541– 

5450, electronic mail (e-mail) address: 

johnson.mary@epa.gov. 

SUPPLEMENTARY INFORMATION: Regulated 

Entities. Entities potentially affected by 

this proposed action include, but are not 

limited to, the following: 

Category NAICS1 Examples of regulated entities 

Industry ....................................................... 212111 Bituminous Coal and Lignite Surface Mining. 

212112 Bituminous Coal Underground Mining. 

221112 Fossil Fuel Electric Power Generation. 

212113 Anthracite Mining. 

213113 Support Activities for Coal Mining. 


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Category NAICS1 Examples of regulated entities 

322121 Paper (except Newsprint) Mills. 

324199 All other petroleum and coal products manufacturing. 

325110 Petrochemical Manufacturing. 

327310 Cement Manufacturing. 

331111 Iron and Steel Mills. 

Federal Government .................................. 22112 Fossil fuel-fired electric utility steam generating units owned by the Federal Government. 

State/local/tribal government ...................... 22112 

921150 

Fossil fuel-fired electric utility steam generating units owned by municipalities. Fossil 

fuel-fired electric steam generating units in Indian Country. 

1 North American Industry Classification System (NAICS) code. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by the proposed rule. This 

table lists categories of entities that may 

have coal preparation and processing 

plants regulated by this proposed rule. 

To determine whether your facility is 

regulated by the proposed rule, you 

should examine the applicability 

criteria in § 60.250 and the definitions 

in § 60.251. If you have any questions 

regarding the applicability of the 

proposed rule to a particular entity, 

contact the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section. 

WorldWide Web (WWW). Following 

the Administrator’s signature, a copy of 

the proposed amendments will be 

posted on the Technology Transfer 

Network’s (TTN) policy and guidance 

page for newly proposed or promulgated 

rules at http://www.epa.gov/ttn/oarpg. 

The TTN provides information and 

technology exchange in various areas of 

air pollution control. 

Public Hearing. If anyone contacts 

EPA by June 8, 2009 requesting to speak 

at a public hearing, EPA will hold a 

public hearing on June 11, 2009. If a 

public hearing is held, it will be held at 

10 a.m. at the EPA Facility Complex in 

Research Triangle Park, North Carolina 

or at an alternate site nearby. Contact 

Mrs. Pamela Garrett at 919–541–7966 to 

request a hearing, to request to speak at 

a public hearing, to determine if a 

hearing will be held, or to determine the 

hearing location. 

Outline. The information presented in 

this preamble is organized as follows: 

I. Background 

II. Summary of Proposed Amendments 

A. Affected Facilities 

B. PM and Opacity Limits for Thermal 

Dryers 

C. SO2, NOX, and CO Emission Limits for 

Thermal Dryers 

D. PM and Opacity Limits for Pneumatic 

Coal-Cleaning Equipment, Coal 

Processing and Conveying Equipment, 

Coal Storage Systems, and Transfer and 

Loading Systems 

E. Emissions Monitoring Requirements 

F. Opacity Monitoring Requirements for 

Pneumatic Coal-Cleaning Equipment, 

Coal Processing and Conveying 

Equipment, Coal Storage Systems, and 

Transfer and Loading Systems 

G. Electronic Reporting 

H. Addition of Petroleum Coke and Coal 

Refuse to the Definition of Coal 

I. Additional Amendments 

III. Rationale for the Proposed Amendments 

A. Additional Affected Facilities 

B. Selection of Thermal Dryer PM and 

Opacity Emissions Limits 

C. Selection of Thermal Dryer SO2, NOX, 

and CO Emissions Limits 

D. Selection of Pneumatic Coal-Cleaning 

Equipment, Coal Processing and 

Conveying Equipment, Coal Storage 

Systems, and Transfer and Loading 

System PM and Opacity Limits 

E. Selection of Monitoring Requirements 

F. Selection of Opacity Monitoring 

Requirements for Pneumatic CoalCleaning Equipment, Coal Processing 

and Conveying Equipment, Coal Storage 

Systems, and Transfer and Loading 

Systems 

G. Required Electronic Reporting 

H. Addition of Petroleum Coke and Coal 

Refuse to the Definition of Coal 

I. Additional Amendments 

J. Emissions Reductions 

IV. Modification and Reconstruction 

Provisions 

V. Summary of Costs, Environmental, Energy, 

and Economic Impacts 

VI. Request for Comment 

VII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paper Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Background 

On April 28, 2008 (73 FR 22901), we 

proposed amendments to the New 

Source Performance Standards (NSPS) 

for Coal Preparation and Processing 

Plants (40 CFR part 60, subpart Y). The 

Federal Register action for that original 

proposal included additional 

background information on the coal 

preparation NSPS. That information is 

not repeated in this action. EPA 

received numerous comments in 

response to the April 2008 proposal. 

After reviewing those comments and 

considering additional data, EPA 

decided to publish this supplemental 

proposal which contains proposed 

emission limits and monitoring 

requirements that differ from those in 

the original action and proposes to 

apply those requirements to additional 

affected facilities. 

II. Summary of Proposed Amendments 

In this supplemental action, we are 

proposing to establish emissions 

standards for both direct contact and 

indirect thermal dryers and pneumatic 

coal-cleaning equipment that process all 

coal ranks. We are also proposing to 

establish work practice standards to 

control coal dust emissions from open 

storage piles and roadways associated 

with coal preparation and processing 

plants. In addition, we are proposing to 

establish a sulfur dioxide (SO2) 

emission limit and a combined nitrogen 

oxide (NOX) and carbon monoxide (CO) 

emissions limit for thermal dryers. 

Finally, we are proposing particulate 

matter (PM) emission limits, opacity 

limits, and monitoring requirements 

that differ from those included in the 

April 2008 proposal. For all standards 

proposed in the April 2008 proposed 

rule, this supplemental proposal will 

not change the applicability date for 

determining whether a source 

constitutes a ‘‘new source’’ subject to 

the final version of such standards. All 

standards originally included in the 

April 2008 proposed rule, regardless of 

whether the level of the standard is 

modified in this supplemental proposal 

or in an eventual final rule, apply to 


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25306 Federal Register / Vol. 74, No. 100 / Wednesday, May 27, 2009 / Proposed Rules 

sources constructed, modified, or 

reconstructed after April 28, 2008. 

Standards, such as the SO2 and 

combined NOX and CO standards, 

proposed for the first time in this 

supplemental proposal, apply to all 

sources constructed, modified, or 

reconstructed after May 27, 2009. A 

summary of the proposed amendments 

is presented below. 

A. Affected Facilities 

The existing NSPS for coal 

preparation and processing plants in 40 

CFR part 60, subpart Y establishes 

emission limits for the following 

affected facilities located at coal 

preparation and processing plants 

which process more than 181 

megagrams (Mg) (200 tons) of coal per 

day: thermal dryers, pneumatic coalcleaning equipment (air tables), coal 

processing and conveying equipment 

(including breakers and crushers), coal 

storage systems, and transfer and 

loading systems. The terms ‘‘thermal 

dryer’’ and ‘‘pneumatic coal-cleaning 

equipment’’ are defined to include only 

facilities that process bituminous coal 

and ‘‘coal storage system’’ is defined to 

exclude open storage piles. 

In the April 2008 proposal, we did not 

propose any revisions to these 

provisions. Several commenters 

suggested that standards should also be 

developed for indirect thermal dryers, 

thermal dryers drying all coal ranks, 

open storage piles, and coal dust 

associated with roadways associated 

with coal preparation and processing 

plants. Commenters said EPA’s original 

rationale for limiting the applicability 

for thermal dryers was a lack of 

emissions data and thermal dryers, and 

pneumatic coal-cleaning equipment 

processing non-bituminous coals did 

not exist and that these reasons are no 

longer valid. Commenters said indirect 

thermal dryers and direct contact 

thermal dryers ‘‘upgrading’’ 

subbituminous and lignite will become 

more common in the future. Even 

though power plant emissions might be 

decreased, if emissions standards are 

not established on the pre-combustion 

process, they argued, there is no 

environmental benefit and potential net 

degradation to air quality from coal 

‘‘upgrading.’’ 

For open storage piles and roadways, 

commenters pointed out that both are 

significant sources of PM emissions for 

which control technology is available. 

One commenter pointed out that 

enclosures, wind fences and other 

barriers, and wet or chemical 

suppression are available control 

technologies. Potential controls for coal 

road dust include tire or truck wash 

systems, sweeper trucks, and wet 

suppression. 

Based on our review of public 

comments and subsequent analysis, we 

are proposing to amend the definition of 

thermal dryer for units constructed after 

May 27, 2009 to include both direct and 

indirect dryers drying all coal ranks. We 

are also proposing to amend the 

definition of pneumatic coal-cleaning 

equipment for units constructed after 

May 27, 2009 to include pneumatic 

coal-cleaning equipment cleaning all 

coal ranks. In addition, we are 

proposing to establish work practice 

standards that apply to open storage 

piles and roads associated with a coal 

preparation plant constructed after May 

27, 2009. 

B. PM and Opacity Limits for Thermal 

Dryers 

In the April 2008 proposed rule, we 

proposed a PM standard of 0.046 grams 

per dry standard cubic meter (g/dscm) 

(0.020 grains per dry standard cubic foot 

(gr/dscf)) and proposed to retain the 

existing 1976 rule’s opacity limit of less 

than 20 percent for thermal dryers 

constructed, modified, or reconstructed 

after April 28, 2008. We received 

comments that the PM limit would be 

prohibitively expensive for modified 

and reconstructed units to achieve, but 

that the limit should be lower for new 

units and should be based on the use of 

a fabric filter (baghouse). 

Based on our review of public 

comments and subsequent analysis, we 

are now proposing to revise our April 

2008 proposal regarding PM and opacity 

standards for thermal dryers. We are 

now proposing separate standards for 

new, reconstructed, and modified units. 

We are proposing to revise the limits for 

new units constructed after April 28, 

2008, to 0.023 g/dscm (0.010 gr/dscf) of 

PM and an opacity limit of less than 10 

percent. We are proposing to revise the 

PM limit for units reconstructed after 

April 28, 2008, to 0.045 g/dscm (0.020 

gr/dscf) and proposing to maintain the 

existing 1976 rule’s opacity limit of less 

than 20 percent. For units modified after 

April 28, 2008, we are proposing to 

maintain the existing 1976 rule’s PM 

limit of 0.070 g/dscm (0.031 gr/dscf) and 

the existing 1976 rule’s opacity limit of 

less than 20 percent. 

C. SO2, NOX, and CO Emission Limits 

for Thermal Dryers 

The existing NSPS does not limit 

emissions of SO2, NOX, or CO from coal 

preparation facilities, and in the April 

2008 proposed rule, we did not propose 

to add limits for these pollutants. A 

commenter suggested that standards 

should be established for each pollutant 

because thermal dryers emit these 

pollutants and can cause or contribute 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. The 

commenter also said using AP–42 

emission factors, a 2,000 ton/hr coal 

thermal dryer would emit 12,000 tons/ 

yr SO2 and 1,400 tons/yr NOX, and 

because cost-effective controls exist the 

EPA should base requirements on the 

use of those controls. 

Based on our review of public 

comments and subsequent analysis, for 

owners/operators of thermal dryers 

constructed, modified, or reconstructed 

after May 27, 2009 we are proposing to 

add the following emissions limits: for 

new, reconstructed, and modified units, 

an SO2 limit of 85 nanograms per Joule 

(ng/J) (0.20 pounds per million British 

thermal units (lb/MMBtu)), or 50 

percent reduction of potential SO2

emissions and no more than 520 ng/J; 

for new units, a combined NOX and CO 

limit of 280 ng/J (0.65 lb/MMBtu); for 

reconstructed units and modified units, 

a combined NOX and CO limit of 430 

ng/J (1.0 lb/MMBtu). 

D. PM and Opacity Limits for Pneumatic 

Coal-Cleaning Equipment, Coal 

Processing and Conveying Equipment, 

Coal Storage Systems, and Transfer and 

Loading Systems 

The original 1976 rulemaking treated 

each coal processing and conveying 

equipment, coal storage systems, and 

transfer and loading systems operation 

as a separate affected facility. However, 

it grouped them together for the purpose 

of establishing a single emissions 

standard. This was done because all of 

the affected facilities could use similar 

control devices and achieve comparable 

emissions rates. We have concluded that 

this is still an appropriate approach. 

While each operation is a separate 

affected facility, all are either fugitive 

sources or point sources of PM and 

similar control equipment can be used 

on each affected facility resulting in 

comparable emissions. If additional data 

is submitted during the comment period 

that justifies different opacity limits for 

different coal handling operations, we 

will consider that approach in the final 

rule. 

The original 1976 rulemaking did not 

include a PM limit for coal processing 

and conveying equipment, coal storage 

systems, and transfer and loading 

systems. However, the original 

rulemaking included an opacity limit of 

less than 20 percent for all of these 

affected facilities. For pneumatic coal 

cleaning equipment, the original 

rulemaking included both a PM limit of 


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0.040 g/dscm (0.017 gr/dscf) and an 

opacity limit of less than 10 percent. 

In the April 2008 proposed rule, we 

proposed a PM limit of 0.011 g/dscm 

(0.0050 gr/dscf) and an opacity limit of 

less than 5 percent for pneumatic coalcleaning equipment and coal processing 

and conveying equipment, coal storage 

systems, and transfer and loading 

systems processing subbituminous and 

lignite coals that commenced 

construction, reconstruction, or 

modification after April 28, 2008. We 

proposed the same limit for both 

pneumatic coal-cleaning equipment and 

coal handling operations because we 

determined that the best demonstrated 

technology (BDT) for both was a fabric 

filter. In addition, we proposed to 

establish a requirement that coal 

handling equipment processing 

subbituminous and lignite coals must be 

vented to a control device. Multiple 

commenters challenged the requirement 

that coal handling equipment 

processing subbituminous and lignite 

coals must vent to a control device, and 

the levels of the PM and opacity limits. 

Based on our review of public 

comments and subsequent analysis, we 

have concluded it is not appropriate to 

require coal handling equipment 

processing subbituminous and lignite 

coals be vented to a control device. In 

addition, after further analysis, we are 

proposing to revise the PM emission 

limits for pneumatic coal-cleaning 

equipment and mechanically vented 

coal handling equipment processing all 

coal ranks constructed, modified, or 

reconstructed after April 28, 2008, to 

0.023 g/dscm (0.010 gr/dscf). In 

addition, we are proposing to revise the 

opacity standard to no greater than 5 

percent for all pneumatic coal-cleaning 

equipment, coal processing and 

conveying equipment, coal storage 

systems, and transfer and loading 

systems that commenced construction, 

reconstruction, or modification after 

April 28, 2008. 

E. Emissions Monitoring Requirements 

In the April 2008 proposed rule, we 

proposed to require initial and annual 

performance tests for all new thermal 

dryers, pneumatic coal-cleaning 

equipment, and subbituminous and 

lignite coal handling equipment vented 

to a control device. Commenters 

suggested that annual performance 

testing is unduly burdensome for 

subpart Y affected facilities and 

suggested either eliminating PM 

performance testing completely for coal 

handling equipment or tiered testing 

requirements depending on the results 

of the most recent performance test. 

Based on our review of public 

comments and further analysis, we are 

proposing to amend the testing 

requirements as follows: first, owners/ 

operators of an affected facility with 

design potential emissions rates, 

considering controls, of 1.0 Mg (1.1 

tons) per year or less would be required 

to perform an initial performance test; 

however, annual performance testing 

would not be required as long as the 

design emissions rate is less than or 

equal to the applicable emissions limit 

(confirmed by the initial performance 

test), the manufacturer’s recommended 

maintenance procedures are followed, 

and the unit operates without 

significant visible emissions. In 

addition, for owners/operators with 

similar, separate affected facilities using 

identical control equipment with design 

potential emissions rates, considering 

controls, of 10 Mg (11 tons) per year or 

less, we are proposing to allow the 

permitting authority to authorize a 

single test as adequate demonstration 

for up to four other similar, separate 

affected facilities as long the following 

conditions are met: (1) The design 

emissions rate is less than or equal to 

the applicable emissions limit; (2) the 

individual performance test is 90 

percent or less of the applicable 

standard; (3) the manufacturer’s 

recommended maintenance procedures 

are followed for each control device; (4) 

each of the affected facilities operates 

without significant visible emissions; 

and (5) each affected facility conducts a 

performance test at least once every 5 

years. Finally, we are proposing that 

owners/operators of affected facilities 

are only required to conduct 

performance testing every 24 months, as 

opposed to every 12 months, if the most 

recent performance test shows the 

affected facility emits at 50 percent or 

less of the applicable standard. 

In the April 2008 proposal, we did not 

propose to require the use of PM 

continuous emission monitoring 

systems (CEMS), but added specific 

language directly to the regulatory text 

that allowed owners/operators to elect 

to use PM CEMS and provided 

incentives for them to do so by 

proposing to eliminate the opacity 

standard for owner/operators of affected 

facilities using a PM CEMS. 

Commenters suggested that by having 

the specific language directly in the 

regulatory text, we were encouraging 

State permitting authorities to require 

the use of PM CEMS, and that the costs 

are not justified for this source category. 

Other commenters suggested we require 

the use of PM CEMS for all units. 

Based on our review of public 

comments and further analysis, we are 

no longer proposing to include the PM 

CEMS-specific language in the 

regulatory text. Non-fugitive sources at 

coal preparation plants are generally not 

significant sources of PM emissions. 

Further, we are not aware of any 

application of PM CEMS to comparable 

emissions sources in the United States, 

and we have concluded that it is 

unlikely that an owner/operator of a 

coal preparation plant would elect to 

install PM CEMS. In addition, owners/ 

operators continue to have the option to 

request site-specific approval for the use 

of PM CEMS as an alternate monitoring 

technique. 

In the April 2008 proposed rule, we 

proposed to require bag leak detection 

systems for owners/operators of thermal 

dryers and pneumatic-coal cleaning 

equipment, if the dryer or equipment 

uses a fabric filter installed after April 

28, 2008. Based on further analysis, we 

are proposing to require a bag leak 

detection system for owners/operators 

of any subpart Y affected facilities with 

fabric filters, if the filter has a design 

controlled potential emissions rate of 25 

Mg (28 tons) or more. For this source 

category, the variable operation of fabric 

filters makes the likely actual emissions 

much less than the potential emissions 

rate and the added expense of a bag leak 

detection system for smaller sources is 

not justified. This requirement would 

apply to facilities constructed, modified, 

or reconstructed after April 28, 2008. 

F. Opacity Monitoring Requirements for 

Pneumatic Coal-Cleaning Equipment, 

Coal Processing and Conveying 

Equipment, Coal Storage Systems, and 

Transfer and Loading Systems 

In the April 2008 proposed rule, we 

proposed the following PM monitoring 

requirements. Each affected facility 

would be required to perform an initial 

EPA Method 9 of appendix A–4 of 40 

CFR part 60 performance test. Following 

the initial compliance test, three 1-hour 

EPA Method 22 of appendix A–7 of 40 

CFR part 60 observations would be 

required for each affected facility at 

least once per calendar month that the 

coal preparation plant operates. If the 

sum of visible emissions exceeded 5 

percent of the observation period, the 

owner/operator would be required to 

conduct a Method 9 performance test 

within 24 hours. Commenters suggested 

that three 1-hour observations are 

unduly burdensome and suggested that 

it would be appropriate to include a 

provision allowing for corrective action 

prior to requiring a Method 9 

performance test. In addition, a 

commenter suggested adding a 

provision for the use of a continuous 

opacity monitoring system (COMS) as 


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an alternative to the Method 9 and 

Method 22 approach. 

Based on our review of public 

comments and further analysis, we are 

proposing to change the April 2008 

proposed opacity monitoring 

requirements for pneumatic coalcleaning and coal handling equipment. 

First, we are proposing to allow the use 

of a COMS as an alternative to all other 

opacity monitoring requirements. 

Second, we are proposing to allow an 

owner/operator of an affected facility to 

decrease the observation period for a 

Method 9 performance test from 3 hours 

to 60 minutes if, during the initial 60 

minutes of the observation of a Method 

9 performance test, all the 6-minute 

averages are less than or equal to 3 

percent and all the individual 15-second 

observations are less than or equal to 20 

percent. Third, we are proposing to base 

the frequency of visible emissions 

monitoring on the results of the highest 

individual 15-second opacity observed 

during the most recent performance test. 

Owners/operators of affected facilities 

where the maximum 15-second opacity 

reading is greater than 5 percent would 

be required to conduct weekly Method 

9 performance testing; owners/operators 

of affected facilities where the 

maximum 15-second opacity reading is 

5 percent would be required to conduct 

monthly Method 9 performance testing; 

and owners/operators of affected 

facilities with no visible emissions 

would be required to conduct quarterly 

Method 9 performance testing. 

As an alternative, owners/operators of 

affected facilities where the maximum 

6-minute opacity reading from the most 

recent Method 9 performance test is less 

than or equal to 3 percent could elect to 

use either Method 22 or a digital opacity 

monitoring system in lieu of subsequent 

Method 9 performance testing. The 

April 2008 proposal would have 

required a total of three 1-hour 

observations monthly. We have 

concluded that for sources with low 

opacity, it is more protective to the 

environment and minimizes burden to 

industry to increase the frequency of 

opacity observations, but to decrease the 

length of each observation. When a 

control device is operating properly 

there should be minimal visible 

emissions and a 1-hour observation 

would not provide any significant 

additional useful information than a 10 

minute observation. In addition, by 

requiring more frequent observations we 

are decreasing the time period before a 

malfunctioning piece of control 

equipment is identified. Therefore, we 

have concluded it is appropriate to 

decrease the length of each observation 

to a minimum of 10 minutes, but to 

increase the frequency to daily 

observations. 

Further, we are proposing to base 

monitoring requirements for affected 

facilities, in part, on recent observations 

of visible emissions from the facilities. 

If no visible emissions are observed for 

7 consecutive operating days, 

observations could be reduced to once 

every 7 operating days. If an owner/ 

operator of an affected facility observes 

visible emissions in excess of 5 percent 

during any observation and is unable to 

take corrective action, they would be 

required to conduct a Method 9 

performance test with the previously 

specified frequency. Finally, to maintain 

consistency in the operation of the 

digital opacity monitoring system, the 

EPA Administrator would approve 

opacity monitoring plans for owners/ 

operators that elect to use the digital 

opacity monitoring system to detect the 

presence of visible emissions. 

G. Electronic Reporting 

We are proposing to take a step to 

improve data accessibility. We are 

proposing to require owners/operators 

of affected facilities at coal preparation 

plants to submit an electronic copy of 

all performance test reports to an EPA 

electronic data base (WebFIRE). Data 

entry requires access to the Internet and 

is expected to be completed by the stack 

testing company as part of the work that 

they are contracted to perform. This 

option would be required as of July 1, 

2011. For performance tests not 

accepted by WebFIRE, we are proposing 

to require owner/operators to mail 

summary results directly to EPA. 

H. Addition of Petroleum Coke and Coal 

Refuse to the Definition of Coal 

We are proposing to amend the 

definition of coal for purposes of 

subpart Y to include petroleum coke 

and coal refuse. The amended definition 

will be used to make applicability 

determinations for all facilities 

constructed, reconstructed, or modified 

after May 27, 2009. This change 

indicates our determination that the 

subpart Y regulations should apply to 

affected facilities that prepare and 

process these non-traditional materials 

that are processed like coal. 

I. Additional Amendments 

We are also proposing several 

additional amendments. First, we are 

proposing to change the title of subpart 

Y from Coal Preparation Plants to Coal 

Preparation and Processing Plants. In 

addition, we are proposing to amend the 

definitions for bituminous coal, coal, 

coal storage system, pneumatic coalcleaning equipment, and thermal dryer; 

to add definitions for anthracite, bag 

leak detection system, design controlled 

potential emissions rate, lignite, 

mechanical vent, operating day, 

potential combustion concentration, and 

subbituminous coal; and to delete the 

definition for cyclonic flow. Finally, we 

are proposing to exempt units that have 

been out of operation for at least 60 days 

prior to the time of the required 

performance test from conducting the 

required performance test until 30 days 

after the facility is brought back into 

operation. 

III. Rationale for the Proposed 

Amendments 

A. Additional Affected Facilities 

The existing NSPS for coal 

preparation and processing plants 

establishes PM and opacity limits for 

thermal dryers that dry bituminous coal 

where the exhaust gas comes in direct 

contact with the coal (direct contact 

thermal dryers). Thermal dryers that dry 

non-bituminous coals, and dryers that 

reduce the moisture content of the coal 

through indirect heating using a heat 

transfer medium, are not presently 

subject to any emission standards. In the 

April 2008 proposal, we proposed to 

amend the PM limit for direct contact 

thermal dryers drying bituminous coal, 

but did not propose to establish 

standards for other thermal dryers. We 

received comments suggesting that we 

include indirect thermal dryers and 

thermal dryers drying all coal ranks as 

affected facilities. In addition, 

commenters suggested we include limits 

for other criteria pollutants emitted from 

thermal dryers. 

Based on our review of public 

comments and subsequent analysis, in 

this supplemental proposal we are 

proposing emission standards that 

would apply to thermal dryers drying 

all ranks of coals and to both direct 

contact and indirect thermal dryers. We 

are proposing to amend the PM and 

opacity standards and to add both an 

SO2 standard and a combined NOX–CO 

standard for thermal dryers. 

For indirect thermal dryers, the 

affected facility will include the heat 

source for the thermal dryer unless that 

heat source is subject to a boiler NSPS 

(e.g., subpart Da, Db, or Dc). Indirect 

thermal dryers use a heat transfer 

medium to supply heat and blow air 

over the coal to evaporate the water. The 

high moisture content air is vented 

through a stack and the dryer exhaust 

contains entrained PM. If the source of 

heat (the source of combustion or 

furnace) is subject to a boiler NSPS 

(subpart Da, Db, or Dc) then the furnace 

and the associated emissions would not 


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be part of the subpart Y affected facility. 

However, if the source of heat is not 

subject to a boiler NSPS, then the heat 

source and the associated emissions are 

part of the subpart Y affected facility. 

In situations where the heat source is 

part of the subpart Y affected facility 

and the exhaust is combined with the 

dryer exhaust in a single stack, the 

combined exhaust stack will contain all 

of the applicable pollutants (i.e., PM, 

SO2, NOX, and CO) and all of the testing 

requirements would apply. However, in 

situations where the heat source is part 

of the subpart Y affected facility and the 

exhaust is not combined with the dryer 

exhaust, the subpart Y requirements 

would apply differently to the dryer 

exhaust stack and the combustion 

exhaust stack. The only applicable 

pollutant in the dryer exhaust would be 

PM. Therefore, the only performance 

test that would be required on the dryer 

exhaust would be for PM. However, all 

of the requirements of subpart Y, 

including the PM, SO2, and NOX–CO 

standards, would apply to the 

combustion exhaust stack and all of the 

testing requirements would apply. 

In situations where the heat source is 

not part of the subpart Y affected facility 

because it is a unit covered by a steam 

generating NSPS (e.g., 40 CFR part 60 

subparts Da, Db, or Dc), the only 

applicable pollutant contained in the 

thermal dryer stack exhaust would be 

PM. Because the thermal dryer stack 

exhaust would not contain SO2, NOX, or 

CO, the SO2 and combined NOX–CO 

testing requirements would not apply. 

We are proposing to establish 

standards that apply to direct contact 

and indirect thermal dryers drying all 

coal ranks of coal because the control 

technologies commonly used on thermal 

dryers—venturi scrubbers and fabric 

filters—control PM equally well 

regardless of the source of PM, and we 

have concluded that all coal thermal 

dryers using similar control 

technologies can achieve comparable 

emissions rates. In addition, subpart Y 

was originally promulgated in 1976 and 

additional pollution control 

technologies have become available 

since then. 

Open storage piles and dust 

associated with roadways are 

potentially significant sources of 

fugitive PM emissions. These sources 

are integral parts of coal preparation 

plants, located on contiguous or 

adjacent property, and under common 

control. Although part of the coal 

preparation plant and, thus, contained 

within the source category listed in 

1976, the existing subpart Y regulations 

do not set standards for emissions from 

open storage piles or from coal dust 

from roadways. In the April 2008 

proposal, we requested comment on 

including requirements for open storage 

piles. We received comments both in 

support of and opposed to including 

requirements for open storage piles. In 

addition, we received comments in 

support of including requirements for 

the coal dust disturbed by, or released 

from, vehicle tires as vehicles move 

within the coal preparation plant. Based 

on our review of public comments and 

subsequent analysis, we have concluded 

that both open storage piles and vehicle 

tires are significant sources of potential 

fugitive PM emissions; however, neither 

operation lends itself to an emissions 

standard. Therefore, in this 

supplemental proposal we are 

proposing to establish work practice 

standards instead of an opacity or PM 

limit for these types of affected 

facilities. 

B. Selection of Thermal Dryer PM and 

Opacity Emissions Limits 

In the April 2008 proposal, we 

proposed to revise the PM limit for 

thermal dryers that dry bituminous coal 

from 0.070 g/dscm (0.031 gr/dscf) to 

0.046 g/dscm (0.020 gr/dscf). We 

received comments that achieving this 

limit would be prohibitively expensive 

for modified and reconstructed units, 

but that the limit should be lower for 

new units. 

Based on our review of public 

comments and subsequent analysis, in 

this supplemental proposal we are 

proposing separate PM limits for new, 

reconstructed, and modified units. As 

discussed in the Thermal Dryer Memo 

in Docket EPA–HQ–OAR–2008–0260, 

the physical layout of existing thermal 

dryers makes it more expensive to 

reduce emissions from existing dryers 

than from new or reconstructed units. 

Therefore, we are proposing to maintain 

the PM limit for modified facilities at 

the existing 1976 limit of 0.070 g/dscm 

(0.031 gr/dscf). We continue to be 

interested in additional performance 

test data and information on the ability 

of modified units to achieve additional 

PM reductions beyond the present limit 

and are also considering establishing a 

lower PM standard between 0.045 g/ 

dscm (0.020 gr/dscf) and 0.070 g/dscm 

(0.031 gr/dscf) for the final rule. We 

specifically request comment on all this 

range of possible standards, including 

0.045 g/dscm (0.020 gr/dscf). 

Because reconstructed facilities could 

take design options into account during 

the reconstruction process, we are 

proposing a PM limit of 0.045 g/dscm 

(0.020 gr/dscf) for reconstructed 

facilities. This level of control has been 

demonstrated to be consistently 

achievable at several existing facilities, 

and we have concluded that a 

reconstructed facility could design a PM 

control strategy based on conventional 

wet scrubbing that could achieve this 

emissions rate at all evaporative load 

rates. 

As described in Thermal Dryer Memo 

in Docket EPA–HQ–OAR–2008–0260, 

new thermal dryers would likely be 

designed as either a coal-fired 

recirculation thermal dryer or an 

indirect thermal dryer. We have 

determined that BDT for controlling PM 

emissions from these types of dryers is 

a fabric filter. Data collected to date 

demonstrates that fabric filters on such 

facilities can achieve emission rates of 

0.004 to 0.0031 gr/dscf. As explained 

below, based on these data and recent 

permit limits for new thermal dryers 

using a baghouse, we are proposing a 

PM limit of 0.023 g/dscm (0.010 gr/dscf) 

and less than 10 percent opacity for new 

facilities. This limit would provide an 

adequate compliance margin for new 

units and is lower than the limit of 

0.046 g/dscm (0.020 gr/dscf) in the April 

2008 proposal. The April 2008 proposed 

limit, however, would have applied to 

new, reconstructed and modified 

facilities. 

It is important to note that although 

the standard is based on the use of a 

fabric filter, a new facility would not be 

required to use any specific control 

technology. Our analysis demonstrates 

that a new facility could use a oncethrough dryer design and achieve the 

proposed standard using a wet scrubber 

to control PM emissions. We identified 

two wet-control approaches that an 

owner/operator of a new facility could 

use to achieve this limit. The first 

approach is to use a high-energy venturi 

scrubber. We analyzed the incremental 

cost effectiveness of the increased 

pressure drop necessary to achieve the 

proposed PM limit for a model thermal 

dryer (see Thermal Dryer Memo in 

Docket EPA–HQ–OAR–2008–0260). The 

incremental control cost of using 

venturi scrubbers ranged from $3,100/ 

ton for an emission level of 0.020 gr/ 

dscf to $16,000/ton for an emission level 

of 0.0050 gr/dscf. 

Based on this analysis, we concluded 

that an emissions rate of 0.023 g/dscm 

(0.010 gr/dscf) would be cost effective 

for a new thermal dryer using a highenergy venturi scrubber to control PM 

emissions, even in the absence of a 

baghouse or electrostatic precipitator 

(ESP). We recognize that no recent coalfired thermal dryer has been constructed 

and that this level of control has not yet 

been demonstrated on a subpart Y 

affected facility with wet controls. This 

level of control, however, has been 


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demonstrated at comparable, recently 

constructed facilities (see Thermal Dryer 

Memo in Docket EPA–HQ–OAR–2008– 

0260). A venturi scrubber, moreover, is 

not the only wet control strategy an 

owner/operator could use to control PM 

emissions. To decrease power 

requirements, a low pressure tray 

scrubber could be used to remove the 

majority of the PM emissions, and then 

either a wet ESP or cloud chamber 

could be used to remove the remaining 

fine PM. Both a wet ESP and cloud 

chamber have demonstrated an ability 

to control PM emissions to below 0.023 

g/dscm (0.010 gr/dscf). Thus, although 

wet scrubbing is not considered BDT for 

controlling PM emissions from new 

thermal dryers, the proposed level of 

PM control would be achievable using 

wet control approaches, such as a wet 

scrubber. 

C. Selection of Thermal Dryer SO2, NOX, 

and CO Emissions Limits 

SO2 emissions from a thermal dryer 

are a function of the sulfur content of 

the fuel burned in the dryer. However, 

measured SO2 emissions are often less 

than what would be theoretically 

predicted based on the sulfur in the fuel 

burned assuming all of the sulfur in the 

fuel is emitted as SO2. There are two 

possible reasons for this discrepancy: 

Either SO2 emissions are reduced by the 

wet scrubber installed to control PM or 

a portion of the S02 is adsorbed as 

sulfuric acid into the pores of the coal 

being dried (due to the reaction of the 

SO2 with oxygen in the flue gas). 

Emissions data for SO2 controls from 

coal-fired thermal dryers are limited, 

and at this time it is not possible for us 

to determine the full extent to which 

each mechanism is reducing emissions. 

Based on the emissions data from other 

sources using venturi scrubbers 

primarily for PM control, it appears that 

the majority of SO2 control occurs as a 

co-benefit of the wet scrubber. The 

measurements of SO2 emissions from 

thermal dryers with wet scrubbers 

collected for this review range from 0.02 

to 1.9 lb/MMBtu and, for the sources 

reporting removal efficiencies, overall 

control efficiencies range from 50 to 98 

percent. 

Existing facilities presently use two 

techniques to specifically control SO2

emissions. The first approach is to spray 

a caustic solution (e.g., sodium 

hydroxide, NaOH) on the coal before it 

enters the drying chamber. The caustic 

reacts with the SO2 in the drying 

chamber and forms a salt (sodium 

sulfate, Na2SO4) that is collected in the 

PM control device. The other approach 

is to add caustic directly to the wet 

scrubber fluid and control SO2 along 

with PM. Wet scrubbers designed 

specifically for SO2 control are able to 

achieve greater than 95 percent 

reduction. However, the wet scrubbers 

used on existing thermal dryers are 

designed for PM control and not 

specifically for SO2 control. Therefore, 

high levels of SO2 control are likely to 

be difficult to achieve without redesign 

of the scrubber (e.g., different 

construction materials to handle the 

corrosion resulting from use of the 

caustic solution, scaling deposits, and 

plugging of liquid lines). Nonetheless, if 

scaling deposit and plugging of liquid 

lines were a concern, an owner/operator 

using a wet scrubber to control SO2

could switch to newer scrubbing agents 

with a higher solubility, such as calcium 

magnesium acetate. Based on the 

performance of one existing facility and 

analysis of other venturi scrubbers used 

to control SO2 emissions, we have 

concluded an existing thermal dryer 

with a wet scrubber could achieve 90 

percent reduction without a significant 

redesign. 

As discussed previously, we have 

concluded that BDT for controlling PM 

from a new thermal dryer is a fabric 

filter. PM has historically been the 

primary pollutant of concern for subpart 

Y affected facilities. Therefore, in 

analyzing BDT for SO2 control, we 

considered the incremental cost of 

controls to reduce SO2 emissions from 

thermal dryers with fabric filters. 

Adding a wet scrubber for the sole 

purpose of controlling SO2 emissions 

beyond 50 percent control (i.e., to 

achieve an additional 40 percent 

control) has an incremental cost of over 

$5,000/ton of SO2 controlled (see 

Thermal Dryer Memo in Docket EPA– 

HQ–OAR–2008–0260). This high cost is 

partially due to the fact that most 

thermal dryers are not typically large, 

ranging from 100 to 200 MMBtu/hr, and 

are not major sources of SO2 emissions; 

these factors result in the fixed costs of 

scrubbing units being high for smaller 

facilities. In addition to the high costs, 

facilities with wet scrubbers must 

dispose of the scrubber sludge. For these 

reasons, we have concluded that wet 

scrubbers are not a cost-effective control 

technology, and are not BDT for this 

source category. 

For a lower cost option, we evaluated 

the use of dry sorbent injection or 

spraying caustic on the coal prior to the 

drying chamber. The caustic approach is 

presently used at one facility, and the 

salt produced is removed by the PM 

control device. We do not have detailed 

information on the contribution of each 

mechanism on overall SO2 control. 

However, if we assume the same 

absolute amounts, in lb/MMBtu, are 

controlled by absorption onto the coal 

and as a co-benefit of the venturi 

scrubber, as described in the Thermal 

Dryer Memo in Docket EPA–HQ–OAR– 

2008–0260, the caustic spray is 

achieving approximately 50 percent 

reduction in theoretical SO2 emissions. 

We have not identified any facilities 

which apply sorbent injection to a 

thermal dryer, but it has been applied to 

industrial and utility boilers, and the 

technology is directly transferable to 

coal-fired thermal dryers. Various 

companies supply calcium- and 

sodium-based sorbent reagents, and the 

technology can be used at any facility 

with injection locations, sufficient 

residence time, and a suitable 

temperature range. A new thermal dryer 

could be designed to include an 

injection site into the combustion gases 

above the burners and prior to the 

drying chamber. An advantage of using 

sorbent injection in combination with a 

baghouse is that the sorbent forms a 

cake on the bags and increases SO2

control. Sorbent SO2 control efficiencies 

vary between 30 and 60 percent for 

calcium-based agents and can be as high 

as 90 percent for sodium-based agents. 

Higher levels of control have been 

achieved in boilers with sorbent 

injection, but this control has not been 

applied to thermal dryers and we have 

concluded that 50 percent would be a 

reasonable expectation. Higher percent 

reductions would be technically 

achievable with the addition of more 

sorbent, but incremental costs would 

increase. The cost per ton of SO2

controlled using sorbent injection is 

approximately $1,000 per ton and is 

considered cost effective for this source 

category. 

For the reasons described above, we 

have concluded that dry sorbent 

injection into the thermal dryer and 

spraying caustic onto the coal prior to 

the thermal dryer are both BDT for SO2

reduction from new, modified, and 

reconstructed thermal dryers. Also for 

the reasons described above, we have 

concluded that a 50 percent SO2

reduction is the standard that can be 

achieved by the application of BDT for 

controlling SO2 emissions to a thermal 

dryer. This standard reflects the degree 

of emissions reduction achievable by 

the technology available and provides 

an adequate compliance margin for both 

sorbent injection into the thermal dryer 

and caustic spraying onto the coal prior 

to the drying chamber. 

We are also proposing to establish a 

maximum emission rate of 520 ng/J (1.2 

lb/MMBtu). We believe it is appropriate 

to establish this upper limit, in addition 

to the 50 percent reduction requirement, 

because control is easier and more costVerDate Nov<24>2008 15:26 May 26, 2009 Jkt 217001 PO 00000 Frm 00008 Fmt 4701 Sfmt 4702 E:\FR\FM\27MYP2.SGM 27MYP2

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effective at high pollutant 

concentrations. Adding a wet scrubber 

to strictly control SO2 emissions for 

thermal dryers with an actual stack 

emissions rate of 520 ng/J (1.2 lb/ 

MMBtu) or more has an incremental 

cost of less than $3,000/ton of SO2

controlled and is considered costeffective for this source category. 

Finally, our analysis also 

demonstrates that facilities with lower 

SO2 emission rates may not be able to 

consistently achieve design rate percent 

reduction efficiencies because control is 

more technically difficult at lower 

pollutant concentrations. For this reason 

we are setting a lower, alternate limit of 

85 ng/J (0.20 lb/MMBtu). A source that 

can meet the lower alternate limit does 

not also need to demonstrate that it is 

reducing SO2 emissions by a specified 

percent. This approach is consistent 

with the approach used in the NSPS for 

steam generating units, 40 CFR part 60, 

subparts Da, Db, and Dc. We continue 

to be interested in additional SO2

performance test data from thermal 

dryers and comparable facilities using 

caustic sprays, sorbent injection, and 

scrubbers to control SO2 emissions and 

are currently considering an SO2

percent reduction requirement of 

between 50 and 90 percent for the final 

rule. 

We are also proposing to add a 

combined NOX and CO emission limit 

for thermal dryers. As explained below, 

we have determined that advanced 

combustion controls are BDT for both 

NOX and CO emissions from thermal 

dryers. Such controls can achieve both 

low NOX and CO emissions. In addition, 

the pollutant emissions rates are related. 

NOX reduction techniques that rely on 

delayed combustion and lower 

combustion temperatures tend to 

increase incomplete combustion and 

result in a corresponding increase in CO 

and volatile organic compound (VOC) 

emissions. To account for variability in 

combustion properties and to provide 

additional compliance strategy options 

for the regulated community, while still 

providing an equivalent level of 

environmental protection, we are 

proposing to establish a combined NOX

and CO limit. The combined limit for 

modified and reconstructed units would 

be 520 ng/J (1.0 lb/MMBtu). This level 

has been demonstrated as being 

achievable for existing units (see 

Thermal Dryer Memo in Docket EPA– 

HQ–OAR–2008–0260). The combined 

limit for new sources would be 280 ng/ 

J (0.65 lb/MMBtu). For new units, we 

evaluated what emission limits could be 

achieved by application of BDT for both 

NOX and CO, and relied on this 

evaluation to develop the combined 

standard. We have previously 

established combined emissions limits 

for pollutants that are inversely related 

in the NSPS for stationary compression 

ignition internal combustion engines, 40 

CFR part 60, subpart IIII. 

We continue to be interested in 

additional NOX and CO performance 

test data from thermal dryers and 

comparable facilities using combustion 

controls to control both NOX and CO 

emissions and are also considering, and 

requesting comment on, a combined 

limit of between 390 ng/J (0.90 lb/ 

MMBtu) and 470 ng/J (1.1 lb/MMBtu) 

for modified and reconstructed units 

and between 200 ng/J (0.47 lb/MMBtu) 

and 300 ng/J (0.70 lb/MMBtu) for new 

units. In addition, we are continuing to 

consider separate limits and specifically 

request comment on whether a 

combined limit is appropriate. 

To determine the NOX and CO 

emission reductions achievable from the 

application of BDT to thermal dryers, 

we examined the nature of the 

emissions, demonstrated control 

technologies, and the removal 

efficiencies of those technologies. NOX

emissions from coal thermal dryers 

primarily occur via two mechanisms. 

The main source, thermal NOX, is 

formed when nitrogen and oxygen in 

the combustion air react at high 

temperatures. Fuel NOX is due to the 

reaction of fuel-bound nitrogen 

compounds with oxygen. NOX

emissions can be minimized through 

two general control strategies: 

combustion controls and postcombustion controls. Combustion 

controls limit the formation of NOX, 

whereas post-combustion controls 

convert NOX to nitrogen and oxygen 

prior to release to the atmosphere. We 

are not presently aware of any coal-fired 

thermal dryers that use post-combustion 

controls. 

Post-combustion controls include 

selective catalytic reduction (SCR), 

selective non-catalytic reduction 

(SNCR), non-selective catalytic 

reduction (NSCR), and catalytic 

oxidation/absorption (SCONOX). For 

reasons presented in the Thermal Dryer 

Memo in Docket EPA–HQ–OAR–2008– 

0260, none of these control options are 

technically feasible control options for a 

thermal dryer and they were not 

evaluated as viable control technologies. 

However, we continue to be interested 

in additional information that would 

indicate if SNCR could be successfully 

integrated into a new thermal dryer and 

specifically request comment on this 

issue. At this time, we have determined 

that combustion controls are the only 

viable NOX controls identified that 

could be used across the range of 

thermal dryers presently used in the 

United States and, thus, we have 

determined that combustion controls 

constitute BDT for NOX emissions from 

thermal dryers. Available combustion 

controls include low NOX burners 

(LNB), staged combustion, co-firing with 

natural gas or liquefied petroleum gas 

(LPG), and flue gas recirculation (FGR). 

These control options are described in 

the Thermal Dryer Memo in Docket 

EPA–HQ–OAR–2008–0260. 

The practical operating range of 

existing thermal dryers is relatively 

small, and redesign of the thermal dryer 

would be required to obtain significant 

NOX reductions. However, we have 

identified several existing thermal 

dryers that have demonstrated NOX

emissions of less than 0.60 lb/MMBtu. 

Our analysis demonstrates that existing 

facilities could achieve this limit 

through combustion controls alone. 

Our analysis demonstrates that new 

thermal dryers could be constructed to 

comply with a NOX limit of 170 ng/J 

(0.40 lb/MMBtu). Although utility-size 

units burning bituminous coal can 

achieve NOX limits of less than 130 ng/ 

J (0.30 lb/MMBtu), NOX-reducing 

technologies for smaller thermal dryers 

are more limited. We reviewed permits 

issued over the past decade and only 

found NOX requirements for boilers less 

than 250 MMBtu/hr for six new 

comparable small coal-fired boilers. 

Three were circulating fluidized bed 

(CFB) boilers, a design that is not 

generally used in dryers. Permit 

conditions for the other three boilers 

were 110, 170, and 300 ng/J (0.25, 0.40, 

and 0.70 lb/MMBtu). The highest permit 

limit had a corresponding low CO 

standard, which could explain the 

unusually high NOX standard. This NOX

emissions rate could be achieved for 

either a new stoker or pulverized coalbased thermal dryer using combustion 

controls alone. Furthermore, we 

reviewed data developed by State 

permitting authorities which list 

combustion controls as able to cost 

effectively achieve over 50 percent 

reduction for coal-fired industrial 

boilers from an uncontrolled emissions 

rate of 300 ng/J (0.70 lb/MMBtu). The 

cost per ton of NOX controlled using 

combustion controls is less than $2,000 

per ton and is considered cost effective 

for this source category. 

CO emissions are intermediate 

products produced by the incomplete 

combustion of hydrocarbons. The 

emissions are formed in hot, oxygendepleted regions of the combustion 

chamber and at the edges of the lean 

flame zone where the temperature is 

lower. Short residence times also 

contribute to CO formation. During 


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complete combustion, CO reacts with 

various oxidants to form carbon dioxide 

(CO2) through recombination reactions. 

However, these recombination reactions 

cannot proceed to completion if the 

combustion temperature is low or there 

is a deficient amount of oxidants in the 

combustion gas. VOC emitted from 

thermal dryers are a result of both 

incomplete fuel combustion and volatile 

matter released from the coal bed as it 

is heated and dried. 

Controls to minimize both CO and 

VOC include thermal oxidation and 

flaring, catalytic oxidation, catalytic 

incineration, and good combustion 

practices. For reasons presented in the 

Thermal Dryer Memo in Docket EPA– 

HQ–OAR–2008–0260, thermal oxidation 

and flaring, catalytic oxidation, and 

catalytic incineration are not technically 

feasible control options for a thermal 

dryer, and they were not evaluated as 

viable control technologies. In addition, 

high levels of excess air can be used to 

control CO emissions and VOC 

absorbers can be used to control VOC 

emissions. However, high levels of 

excess air increase NOX emissions and 

the PM emissions in a thermal dryer 

exhaust would plug the pores in the 

absorber bed; therefore, such controls 

are also not considered to be a viable 

control techniques. For these reasons, 

we conclude that good combustion 

practices constitute BDT for CO 

emissions from thermal dryers. 

Good combustion practices limit the 

formation of CO and VOC by providing 

sufficient oxygen in the combustion 

zone for complete combustion to occur. 

Based on a review of CO emissions rates 

from existing thermal dryers, we are 

basing the combined NOX and CO limit 

on a CO emissions rate of 190 ng/J (0.45 

lb/MMBtu) for modified and 

reconstructed thermal dryers. We have 

identified several existing thermal 

dryers that are achieving this emissions 

rate with combustion controls alone. 

Because we have not identified a 

method for control of VOC emissions 

beyond combustion controls, we are not 

proposing a separate limit for VOC 

emissions. However, by setting an 

emissions limit that contains a CO 

emissions rate, we are minimizing the 

VOC emissions that result from 

incomplete combustion. The VOC 

emissions from the coal bed itself are 

variable, and we concluded that we are 

unable to set a standard that would be 

achievable for variable coal types across 

the country. 

For new thermal dryers, we 

concluded that a CO emissions rate of 

110 ng/J (0.25 lb/MMBtu) is the 

appropriate rate to use as part of the 

basis for the combined NOX and CO 

limit. Although new utility-sized units 

can reduce CO emissions to 0.15 lb/ 

MMBtu, technologies are more limited 

for the smaller thermal dryers. However, 

because new thermal dryers would 

likely use a gas recirculation design, 

both VOC and CO emissions would be 

minimized. The exhaust gases would be 

recirculated to the high temperatures of 

the combustion chamber and would 

oxidize some of the emissions to CO2

and water. Of the three non-CFB permits 

for small coal-fired boilers, the 

requirements over the past decade were 

0.02, 0.21, 0.23 lb/MMBtu. We also 

reviewed information on coal-fired 

boilers developed for State permitting 

agencies, and the basis limit for CO is 

consistent with the values listed in 

those references. In addition, we 

reviewed the CO data collected for coalfired industrial boilers in support of the 

Clean Air Act (CAA) section 112 

maximum achievable technology 

(MACT) standards. Of the 60 industrial 

boilers with CO emissions listed in lb/ 

MMBtu, the average was 40 ng/J (0.095 

lb/MMBtu), and the range was 0.1 to 

230 ng/J (0.0002 to 0.54 lb/MMBtu). At 

this time, we do not have the 

corresponding NOX emissions data to 

determine if the low CO emissions rates 

have a corresponding high NOX

emissions rate. These data indicate that 

92 percent of existing small coal-fired 

boilers are achieving a rate of 110 ng/ 

J (0.25 lb/MMBtu) and 98 percent are 

achieving a rate of 190 ng/J (0.45 lb/ 

MMBtu). 

D. Selection of Pneumatic Coal-Cleaning 

Equipment, Coal Processing and 

Conveying Equipment, Coal Storage 

Systems, and Transfer and Loading 

System PM and Opacity Limits 

We are proposing standards for a wide 

variety of coal handling equipment. For 

open storage piles and roadways, we are 

proposing, consistent with CAA section 

111(h), to establish work practice 

standards. For other coal handling 

equipment, including pneumatic coalcleaning equipment, coal processing 

and conveying equipment, coal storage 

systems, and transfer and loading 

systems, we are establishing PM and/or 

opacity emission limits. 

1. Open Storage Piles and Roadways 

CAA section 111(h) provides that if, 

in the judgment of the Administrator, it 

is not feasible to prescribe or enforce a 

standard of performance, EPA may 

among other things, promulgate work 

practice, design, or equipment 

standards. A determination that the 

emissions from the sources cannot be 

measured due to technological or 

economic limitations may be used to 

support a determination that it is not 

feasible to establish standards of 

performance. It is difficult and 

prohibitively expensive to measure 

actual PM emissions from individual 

open storage piles or roadways. Further, 

the size of open storage piles and the 

mobile nature of coal dust from vehicle 

tires on roadways make the use of 

Method 9 opacity observations 

unreasonable in many situations. For 

these reasons, the Administrator is 

proposing to determine that it is not 

feasible to establish an emissions 

standard for open storage piles or the 

coal dust associated with roadways. 

This determination would support the 

proposed work practice standards 

outlined below. 

Based on that proposed 

determination, we are proposing to 

establish the following work practice 

standards for open storage piles and 

coal dust from roadways. We propose to 

require owners/operators of open 

storage piles and roadways associated 

with coal preparation plants to develop 

and comply with a fugitive dust 

emissions plan to control fugitive PM 

emissions. These fugitive dust plans 

would be required to contain the 

elements described below. 

For open storage piles, we are 

proposing to require the fugitive dust 

plan to prescribe the use of an 

enclosure, chemical suppressants 

(including encrusting agents), wet 

suppression, a wind barrier, or a 

vegetative cover to control emissions. 

We are also proposing to require that 

the fugitive dust plan include 

procedures for limiting emissions from 

all types of ‘‘coal processing and 

conveying equipment’’ at a coal 

preparation plant. Although the source 

category listing covers the entire coal 

preparation plant, we have not 

previously established emission limits 

for all facilities located at the plant. 

Because open storage piles were not 

previously considered affected facilities, 

unloading and conveying operations to 

an open storage pile were also not 

regulated. Only unloading operations 

that were directly loaded into receiving 

equipment were subject to an opacity 

limit. Because we are proposing to 

include open storage piles as an affected 

facility, the loading, unloading, and 

conveying operations of open storage 

piles would also be covered under the 

fugitive dust emissions control plan, but 

not subject to an opacity limit. 

Open storage piles also include piles 

of coal that have been loaded into 

trucks, railcars, and/or ships. At this 

time, we are not proposing to require 

that the fugitive dust emissions control 

plan address emissions from these piles. 


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We identified two potential control 

options for these piles: covers and 

chemical encrusting agents. However, 

we have determined it is not practical 

to require these controls. First, the 

majority of fugitive emissions occur 

while the coal is in transit outside the 

physical boundaries of the coal 

preparation plant. The emissions from 

the piles while they are at the coal 

preparation plant have not been shown 

to be significant. Second, it would not 

be economically feasible to require end 

users to cover the coal or spray chemical 

suppressants as the coal arrives on the 

property of the owner/operator and then 

proceed to unload the coal. 

We are also proposing to require that 

the permitting authority approve the 

fugitive dust plans required by this 

subpart and to grant specific authority 

to the permitting authority to approve 

alternate technologies to control fugitive 

emissions from open storage piles and 

coal dust from roadways. The 

permitting authority may approve the 

use of such alternative technologies in 

the fugitive dust plan if it has 

determined that the approved 

technology provides equivalent overall 

environmental protection. 

For roadways, we are proposing to 

require that the fugitive dust plan 

require the owner/operator to pave the 

roads, wet the road surface, sweep up 

excess coal dust, or install tire washes 

to remove entrained dust to control PM 

emissions. For roadways that do not 

leave the property (e.g., haul roads at 

coal mines), the owner/operator of the 

coal preparation plant would not have 

to include such requirements in the 

fugitive dust plan because of the 

particular impracticality of, for example, 

paving roadways that are frequently rerouted. 

2. Coal Handling Equipment 

In the April 2008 proposal, we 

concluded that a fabric filter was BDT 

for controlling PM emissions from coalhandling equipment processing 

subbituminous and lignite coals. That 

determination provided the basis for the 

proposed PM and opacity standards, 

and also for our proposal requiring that 

coal-handling equipment processing 

subbituminous and lignite coals be 

vented (i.e., connected to a duct or 

stack) such that a PM performance test 

could be conducted on the contained 

exhaust gas stream. As discussed more 

fully in the Coal Handling Memo in 

Docket EPA–HQ–OAR–2008–0260, 

multiple commenters disagreed with 

our BDT determination for several 

reasons. First, they noted that the use of 

baghouses to collect subbituminous coal 

dust presents potential safety concerns. 

For this reason alone, the commenters 

argued that EPA should not use a 

baghouse as the basis for the emissions 

rate. Second, their comments noted that 

although the use of baghouses 

frequently results in low stack grain 

loadings, the practice of returning the 

collected dust to the conveyor belt may 

cause potential problems with fine coal 

dust emissions later in the coal handling 

process, decreasing their overall 

effectiveness. Finally, commenters 

identified multiple State best available 

control technology (BACT) 

determinations that allow sources to 

remove existing baghouses and replace 

them with passive enclosure 

containment systems (PECS), fogging 

systems, or wet extraction scrubbers. 

Neither PECS nor fogging systems can 

be vented, so the requirement to 

conduct a PM performance test conflicts 

with such State BACT determinations. 

Based on our review of public 

comments and subsequent analysis, we 

have concluded that a baghouse is not 

the only technology that is BDT for coalhandling equipment used on 

subbituminous and lignite coals. 

Depending on the plant-specific 

circumstances, all four technologies 

(fabric filters, PECS, fogging systems, 

and wet extraction scrubbers) can 

control PM emissions equally well. 

They all provide equivalent levels of 

emissions reductions; in addition, 

fogging systems, PECS, and the wet 

extraction systems often have lower 

costs than baghouses. For this reason, 

we are no longer proposing to require 

that all emissions from such facilities be 

vented and are proposing PM and 

opacity limits for coal-handling 

operations based on the level of 

reduction achievable by these four 

technologies. 

In the April 2008 proposal, we also 

determined that the use of chemical 

suppressants was BDT for coal-handling 

equipment processing bituminous coal. 

This determination also provided a 

basis for the proposed PM and opacity 

limits. Multiple commenters disagreed 

with that determination, stating that wet 

suppression is often used to control 

fugitive PM from coal-handling 

operations processing bituminous coal 

and that this control approach results in 

limited visible emissions from the 

operation. 

Based on our review of public 

comments and subsequent analysis, we 

have reaffirmed our determination that 

BDT for coal-handling equipment 

processing bituminous coal is the use of 

chemical suppressants. The proposed 

opacity limit is based on that BDT 

determination. However, it is important 

to note that although our BDT analysis 

identifies a specific technology as BDT, 

the actual requirement in the rule is an 

opacity limit, and an owner/operator 

can use any combination of controls at 

a particular site as long as it 

demonstrates compliance with the 

opacity limit. The owner/operator is not 

obligated to use the specific technology 

identified as BDT. 

Since the April 2008 proposal, we 

have performed an extensive datagathering effort for both PM 

performance test data and opacity 

observations (both Method 9 and 

Method 22) on recently installed coalhandling equipment. This data 

gathering is discussed in more detail in 

the Coal Handling Memo in Docket 

EPA–HQ–OAR–2008–0260. 

In the April 2008 proposal, we 

proposed to establish a PM limit of 

0.011 g/dscm (0.0050 gr/dscf) for coalhandling equipment processing 

subbituminous and lignite coals. We 

also proposed to require that all such 

equipment vent emissions such that 

mass PM emissions from the facility 

could be measured. Multiple 

commenters disagreed with the PM 

limit, saying that it is technically 

difficult to achieve at some locations 

and is more stringent than the BACT 

determinations from multiple State 

permitting authorities. In addition, 

commenters suggested we collect more 

PM emissions data specific to coal 

handling operations. 

As described earlier, we have 

reconsidered our prior BDT 

determination and are now proposing a 

determination that any of four 

technologies—fabric filters, PECS, 

fogging systems, and wet extraction 

scrubbers—may be BDT, and we are 

establishing PM and opacity limits 

consistent with that determination. 

Only the fabric filter technology and wet 

extraction scrubbers are typically 

vented; PECS and fogging systems 

technologies rely on reduced air flow 

and as such could not be used if 

emissions are vented. Requiring venting 

of either PECS or fogging systems would 

conflict with the design criteria of both 

approaches. In this proposal, we are 

proposing to establish both PM and 

opacity limits that would apply to all 

emissions that are vented, and an 

opacity limit that would apply to all 

emissions that are not vented. 

Based on our review of public 

comments and subsequent analysis, we 

are proposing a change from the April 

2008 proposed PM limit of 0.011 g/dscm 

(0.0050 gr/dscf) to 0.023 g/dscm (0.010 

gr/dscf). The PM performance test data 

specific to coal-handling equipment 

ranged from 0.001 to 0.011 gr/dscf. 

Based on the performance test data, we 


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have concluded that although 0.011 g/ 

dscm (0.0050 gr/dscf) has been shown to 

be achievable, due to the limited data 

set, we are not convinced that such a 

limit would be achievable on a longterm basis for all affected facilities 

across the country. However, we have 

concluded that 0.023 g/dscm (0.010 gr/ 

dscf) is achievable for all sizes of 

affected facilities and provides an 

adequate compliance margin to be 

consistently achievable on a long-term 

basis for control technologies that are 

vented through a stack. As shown in 

docket entries EPA–HQ–OAR–2008– 

0260–0003.1 (‘‘Discussion of Particulate 

Matter Control Concepts for Coal 

Handling NSPS’’) and -0035.1 

(‘‘Comments of the Utility Air 

Regulatory Group’’), this standard is 

also consistent with the majority of 

recently issued permits. 

We continue to be interested in 

additional performance test data from 

recently installed fabric filters and wet 

extraction scrubbers and are requesting 

comment on a PM standard of 0.020 g/ 

dscm to 0.025 g/dscm (0.0090 gr/dscf to 

0.011 gr/dscf) for the final rule. All the 

PM performance test data collected for 

this supplemental proposal show 

emissions equal to or less than 0.025 g/ 

dscm (0.011 gr/dscf). However, the 

source with the highest PM emissions 

concentration has permit requirements 

in lb/hr of PM emissions and the design 

emissions rate of those fabric filters is 

unclear. All of the other PM 

performance test data, including the 

individual tests runs, are below 0.020 

g/dscm (0.0090 gr/dscf). 

In the April 2008 proposal, we 

proposed to amend the opacity limit for 

coal-handling equipment from the 

existing 1976 limit of less than 20 

percent to less than 5 percent. Multiple 

commenters opposed that proposal for 

several reasons. First, the data used for 

the proposal were largely based on data 

collected from the nonmetallic minerals 

processing industry. In addition, 

commenters noted that because 

individual Method 9 opacity 

observations are made in increments of 

5 percent, a less than 5 percent opacity 

limit would mean that the presence of 

any visible emissions would result in a 

violation. Commenters asserted that it 

would be difficult to guarantee that each 

affected facility will operate with no 

visible emissions at all times. Also, 

because the proposed standard is based 

on a 6-minute reading, there would be 

no opportunity for an owner/operator to 

fix a problem prior to being in violation 

of the standard. Further, because 

opacity from fugitive sources is more 

difficult to measure than from point 

sources, they argued that the less than 

5 percent limit was unreasonable. 

It is important to note that the April 

2008 proposed limit of less than 5 

percent opacity is not the same as a no 

visible emissions limit. A Method 9 

performance test is conducted by taking 

one or more sets of 24 observations at 

15-second intervals over a 6-minute 

period. Each observation is reported in 

5 percent increments. The 6-minute 

average is calculated by averaging all 

observations made over the 6-minute 

period. Thus, a 6-minute average based 

on both 0 and 5 percent opacity 

readings (or higher), would not exceed 

the 5 percent standard as long as the 

average is less than 5 percent. In 

contrast, a ‘‘no visible emissions’’ limit 

for a Method 9 performance test would 

require all opacity readings to be 0 

percent. 

Nonetheless, based on our review of 

public comments and subsequent 

analysis, in this supplemental proposal 

we are proposing to change the opacity 

limit for all subpart Y coal-handling 

facilities to no greater than 5 percent. 

We gathered data on coal-handling 

operations at 25 coal preparation plants, 

and the reported highest 6-minute 

average opacity reading was 5 percent 

for a recently installed facility. 

Therefore, we have concluded that this 

is an appropriate opacity limit for new 

sources. 

We are also specifically requesting 

comment on whether an opacity limit of 

less than 10 percent is more appropriate 

than a limit of no greater than 5 percent. 

The data we collected were primarily 

from initial compliance tests, and we 

are requesting comment on whether the 

5 percent limit is achievable on a longterm basis for all subpart Y coalhandling facilities under all operating 

conditions, including windy dry 

periods, and whether the limit provides 

an adequate compliance margin. We are 

also requesting comment on establishing 

different opacity limits for each type of 

coal-handling operation. 

Finally, we are proposing to require 

periodic Method 9 performance tests to 

assure compliance with the no greater 

than 5 percent standard. However, to 

create an incentive for sources to 

operate with minimal visible emissions 

(visible emissions readings less than 5 

percent of the time using Method 22) 

whenever possible, we are proposing to 

allow owners/operators of facilities with 

the most recent Method 9 performance 

test of 3 percent or less opacity to 

qualify for reduced monitoring 

requirements. Owners/operators of 

affected facilities operating with 

minimal visible emissions would be 

able to elect to perform periodic short 

opacity observations using Method 22 as 

an alternative to Method 9 performance 

tests. Facilities with visible emissions 

would have to perform periodic Method 

9 performance tests and, therefore, 

would have an incentive to operate 

without visible emissions. We believe it 

is important to provide these incentives 

because the data we have gathered 

suggest that many affected facilities 

should be able to operate with zero 

opacity much of the time if they are 

being properly operated and 

maintained. 

E. Selection of Monitoring Requirements 

In the April 2008 proposal, we 

proposed to require initial and annual 

PM performance testing for each subpart 

Y affected facility with an emissions 

limit. After further consideration, and 

for the reasons explained below, we 

have concluded that it would be more 

appropriate to require testing every 

other year of affected facilities operating 

at 50 percent or less of the applicable 

limit and reduced testing requirements 

for facilities with relatively low 

potential emissions. 

Reducing the frequency of compliance 

testing from annual to every other year 

for owner/operators of affected facilities 

operating at 50 percent or less of the 

applicable limit both reduces 

compliance costs and could provide 

benefits to the environment by 

recognizing the environmental benefit of 

owners/operators installing controls 

beyond what is required by the NSPS. 

By reducing monitoring requirements, 

we are recognizing the increased 

environmental benefit of control 

equipment that is both designed and 

operated in such a manner to exceed the 

new source performance requirements 

and are incentivizing the development 

of improved control technology. Also, if 

an affected facility is tested as operating 

well below the standard, there is less of 

a chance of exceeding the limit. 

For smaller facilities with lower 

potential emissions, we have concluded 

the cost of the testing proposed in the 

April 2008 proposal is not justified by 

the information that would be gained 

from the testing. In addition, we are not 

aware of an economically feasible way 

to measure PM emissions from vent 

filters. Vent filters are typically smaller 

than 2,000 actual cubic feet per minute 

(acfm), and the exemption for affected 

facilities with potential emissions of 

less than 1.0 Mg (1.1 tons) equates to 

2,800 standard cubic feet per minute 

(scfm) at a design emissions rate of 

0.010 gr/dscf. Furthermore, smaller 

baghouses often do not come equipped 

with sampling access. It would cost 

approximately $6,000 to add sampling 


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ports and sampling platforms to each 

baghouse. Considering that baghouse 

operations are often intermittent, 

potential emissions from deterioration 

over time are expected to be low. 

Instead of requiring annual performance 

tests, we are proposing to require that 

each baghouse be monitored for visible 

emissions on an ongoing basis. We have 

concluded that these visual observations 

should detect significant problems such 

as holes and tears in the filter medium 

or if the filter becomes unseated. Under 

these circumstances, visible emissions 

will increase dramatically because part 

of the exhaust gas is emitted directly to 

the atmosphere without any emissions 

reduction, resulting in readily apparent 

visible emissions. 

Similarly, for an owner/operator of up 

to five affected facilities of the same 

type using identical control equipment 

with potential annual emissions of less 

than 10 Mg each at a coal preparation 

plant, we are proposing to allow a 

performance test on a single affected 

facility as a check on the compliance of 

all of the affected facilities with the 

emissions standard. We are allowing 

this option only where performance test 

results are 90 percent of the standard, 

the design emissions rate of the control 

device is less than or equal to the 

applicable emission limit, and each 

affected facility is tested at least once 

every 5 years. The facilities must 

perform the applicable ongoing 

monitoring, and adhere to 

manufacturer’s recommended 

maintenance procedures. We concluded 

that for these sources the test results at 

one control device will likely be 

representative of other similar control 

devices, and that the additional 

compliance costs associated with testing 

each affected facility would not result in 

significant emissions reductions. 

We are proposing to require bag leak 

detection systems for large baghouses. 

We considered, but decided against, 

requiring installation and use of a bag 

leak detection system at each affected 

facility using a fabric filter to control 

PM. These detectors are useful and 

effective for early detection of bag leaks; 

however, the capital costs of a bag leak 

detection system can be as much as 

$24,000 and the annualized costs might 

be as much as $7,000 (including capital 

recovery). These costs are considered 

unjustifiably high for smaller baghouses 

with low potential emissions at subpart 

Y affected facilities. Because potential 

PM emissions from a bag leak are more 

significant for larger baghouses, we are 

proposing to require a bag leak detection 

system for owners/operators of 

baghouses with a potential annual 

emissions rate of 25 Mg (28 tons) or 

more. This equates to a baghouse of 

approximately 70,000 scfm with a 

design emissions rate of 0.010 gr/dscf, 

or 140,000 scfm with a design emissions 

rate of 0.0050 gr/dscf. 

F. Selection of Opacity Monitoring 

Requirements for Pneumatic CoalCleaning Equipment, Coal Processing 

and Conveying Equipment, Coal Storage 

Systems, and Transfer and Loading 

System 

In the April 2008 proposal, we 

proposed to require three 1-hour 

Method 22 observations to monitor for 

visible emissions at all coal-handling 

affected facilities. With this approach an 

owner/operator could perform the 

initial readings on the first day of the 

month and not perform a subsequent 

observation for 30 days. When a control 

device is operating properly there 

should be minimal visible emissions 

and a 1-hour observation would not 

provide any significant additional 

useful information than a 10-minute 

observation. In addition, allowing 

extended periods of operation between 

observations could allow as much as 30 

days before a malfunctioning piece of 

control equipment is identified. 

Therefore, we have concluded it is 

appropriate to decrease the length of 

each observation to a minimum of 10 

minutes, but to increase the frequency 

to daily observations. By taking more 

frequent observations, we assure that 

control equipment is consistently well 

operated. 

G. Required Electronic Reporting 

We are also proposing to require 

owners/operators to submit compliance 

test data electronically to EPA. 

Compliance test data are necessary for 

compliance determinations and for EPA 

to conduct 8-year reviews of CAA 

section 111 standards. The data are also 

used for many other purposes such as 

developing emission factors and 

determining annual emission rates. In 

conducting 8-year reviews, EPA has 

found it burdensome and timeconsuming to collect emission test data 

because the data are often stored at 

varied locations through differing 

storage methods. One improvement in 

recent years is the availability of stack 

test reports in electronic format as a 

replacement for paper copies. The 

proposed option to submit source test 

data electronically to EPA would not 

require any additional performance 

testing. In addition, when a facility 

submits performance test data to 

WebFIRE, there would be no additional 

requirements for data compilation; 

instead, we believe industry would 

greatly benefit from improved emissions 

factors, fewer information requests, and 

better regulation development as 

discussed below. Because the 

information that would be reported is 

already required in the existing test 

methods and is necessary to evaluate 

conformance to the test method, 

facilities would already be collecting 

and compiling these data. One major 

advantage of electing to submit source 

test data through the Electronic 

Reporting Tool (ERT), which was 

developed with input from stack testing 

companies (who already collect and 

compile performance test data 

electronically), is that it would provide 

a standardized method to compile and 

store all the documentation required by 

this rule. Another important benefit of 

submitting these data to EPA at the time 

the source test is conducted is that it 

will substantially reduce the effort 

involved in data collection activities in 

the future. Specifically, because we 

would already have adequate source 

category data to conduct NSPS reviews, 

there would be fewer data collection 

requests (e.g., letters issued under the 

authority of CAA section 114). This 

results in a reduced burden on both 

affected facilities (in terms of reduced 

manpower to respond to data collection 

requests) and EPA (in terms of preparing 

and distributing data collection 

requests). Finally, another benefit of 

electronic data submission is that these 

data will greatly improve the overall 

quality of existing and new emissions 

factors by supplementing the pool of 

emissions test data upon which a 

particular emission factor is based, and 

by ensuring that the data are more 

representative of current industry 

operational procedures. A common 

complaint from industry and regulators 

is that emissions factors are outdated or 

not representative of a particular source 

category. Additional performance tests 

results would ensure that emissions 

factors are updated more frequently and 

are more accurate. In summary, 

receiving the test data already collected 

for other purposes and using them in 

the emissions factors development 

program will save industry, State/local/ 

tribal agencies, and EPA time and 

money. 

Data would be submitted 

electronically to the EPA database 

WebFIRE, which is a Web site accessible 

through the EPA TTN. The WebFIRE 

Web site was constructed to store 

emissions test data for use in developing 

emission factors. A description of the 

WebFIRE database can be found at 

http://cfpub.epa.gov/oarweb/ 

index.cfm?action=fire.main. The ERT is 

an interface program that transmits the 


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electronic report through EPA’s Central 

Data Exchange (CDX) network for 

storage in the WebFIRE database. 

Although ERT is not the only electronic 

interface that can be used to submit 

source test data to the CDX for entry 

into WebFIRE, it is the most 

straightforward and easy way to submit 

data. A description of the ERT can be 

found at http://www.epa.gov/ttn/chief/ 

ert/ert_tool.html. The ERT can be used 

to document the conduct of stack tests 

data for various pollutants, including 

PM (EPA Method 5 in appendix A–3), 

SO2 (EPA Method 6C in appendix A–4), 

NOX (EPA Method 7E in appendix A– 

4), CO (EPA Method 10 in appendix A– 

4), cadmium (Cd) (EPA Method 29 in 

appendix A–8), lead (Pb) (Method 29), 

mercury (Hg) (Method 29), and 

hydrogen chloride (HCl) (EPA Method 

26A in appendix A–8). The ERT does 

not currently accept opacity data or 

CEMS data. 

H. Addition of Petroleum Coke and Coal 

Refuse to the Definition of Coal 

Petroleum coke and coal refuse are 

useful boiler fuels, have similar PM 

emissions as primary coals, and the 

same equipment is used to control PM 

emissions from the handling of primary 

coals, petroleum coke, and coal refuse. 

Therefore, we are proposing to amend 

the definition of coal in subpart Y to 

include petroleum coke and coal refuse 

(after May 27, 2009). The standards in 

the original 1976 subpart Y were based 

on data from coal preparation plants 

processing bituminous coal at mines. 

However, the original applicability of 

subpart Y was intentionally broad, and 

covered processing of all coal ranks and 

coal processing at end-user locations 

(owner/operators of boilers, coke ovens, 

etc.), as the mechanical processing of 

coal is the same regardless of location. 

Petroleum coke, a carbonaceous 

material, is a by-product residual from 

the thermal cracking of heavy residual 

oil during the petroleum refining 

process. Petroleum coke has a superior 

heating value and low ash content 

compared to coal. However, depending 

on the original crude feedstock, it may 

contain greater concentrations of sulfur 

and metals, making it less attractive as 

a boiler fuel. Historically, petroleum 

coke has been priced at a discount 

compared to coal. Because of the 

increased use of heavier crudes and 

more efficient processing of refinery 

residuals, U.S. and worldwide 

production of petroleum coke is 

increasing and is expected to continue 

to grow. 

Coal refuse, a by-product of coal 

mining and cleaning operations, is 

generally a high ash (non-combustible 

rock), low Btu material. It is costprohibitive to transport because of the 

weight per amount of energy that can be 

extracted, and is usually burned close to 

the point of generation. Large volumes 

of coal refuse began to accumulate at 

mining sites when mining first began in 

the Appalachians in the 1970s. Current 

mining operations continue to generate 

coal refuse; estimates show that up to 1 

billion tons of coal refuse were 

generated in 2007 alone. When subpart 

Y was originally published in 1976, 

there was no way to cost-effectively 

dispose of coal refuse. Also, laws 

requiring the stabilization and 

reclamation of mining sites were not 

established until the late 1970s, after 

subpart Y was originally promulgated. 

After the late 1970s, mining operations 

began to process coal refuse. With the 

development of fluidized beds, it is 

burned for energy and is used for other 

non-combustion products. 

Petroleum coke can be interchanged 

with primary coals in pulverized coal 

boilers, fluidized beds, and stoker 

boilers. Coal refuse can be substituted 

for primary coals in fluidized beds and 

stoker boilers. Petroleum coke and coal 

refuse are burned in the same boilers as 

primary coals at the coal preparation 

plant and are processed alongside the 

primary coals. The health impacts of PM 

from petroleum coke and primary coals 

are similar; coverage of petroleum coke 

would therefore further protect public 

health. 

The approach proposed is consistent 

with subparts Db and Dc, the large and 

small industrial boiler NSPS. Both 

subparts include petroleum coke and 

coal refuse under the definition of coal. 

Subpart Da, the utility boiler NSPS, was 

published prior to the industrial boiler 

NSPS, and only includes coal refuse in 

the definition of coal. At the time 

subpart Da was promulgated, petroleum 

coke was not considered to be ‘‘created 

for the purpose of creating useful heat’’ 

and hence was not used in the fossil 

fuel capacity as it is today. 

I. Additional Amendments 

We are proposing to change the title 

of subpart Y to more accurately reflect 

the affected facilities subject to subpart 

Y. The original applicability included 

affected facilities that some in the 

regulated community term ‘‘processing’’ 

facilities and would not call those 

operations ‘‘preparation’’ even though 

the original rulemaking used 

‘‘preparation’’ more broadly. The 

revision is strictly intended to clarify 

the rule and not change the 

applicability. 

The definitional amendments and 

additional amendments are intended to 

implement aspects of the rule discussed 

earlier and to update the American 

Society of Testing and Materials 

(ASTM) test methods for the different 

coal ranks. Also, because cyclonic flow 

is not used in subpart Y, its removal 

would not impact the rule. 

We have concluded that it is not 

appropriate or beneficial to the public 

health to require an affected facility that 

is not currently in operation to start up 

to demonstrate compliance with the 

NSPS. Commencing operation strictly 

for the purposes of demonstrating 

compliance is an unnecessary cost and 

increases emissions. 

J. Emissions Reductions 

EPA believes that the proposed 

amendments would not significantly 

impact the overall compliance costs 

estimated for the original proposal, $3 

million, and would continue to have an 

insignificant economic impact. 

However, EPA acknowledges that the 

overall emissions reductions that would 

result from the proposed amendments 

and associated costs of control are 

difficult to quantify precisely in 

advance. 

For thermal dryers and pneumatic 

coal-cleaning equipment, the proposed 

amendments would significantly tighten 

control requirements. Because these 

controls apply to new sources not yet in 

operation, it is difficult to quantify the 

aggregated emissions reductions or costs 

for those reductions in advance. 

However, we anticipate that there will 

be only a limited number of new 

sources with thermal dryers or 

pneumatic coal-cleaning equipment, so 

the overall costs associated with the 

proposed amendments will likewise be 

limited. As to benefits, EPA believes 

that the proposed amendments are 

necessary because they would help to 

protect the public health and the 

environment by assuring that 

appropriate controls would be installed 

on future new thermal dryers and 

pneumatic coal-cleaning equipment 

should any be built. 

The proposed pneumatic coalcleaning PM standard is 40 percent 

lower than the existing standard. For 

thermal dryers, the proposed PM 

standard is one-third of the existing 

limit. The proposed SO2 standard and 

combined NOX-CO standard for these 

sources would reduce emissions by 50 

percent from current uncontrolled 

levels. For the model thermal dryer used 

in the costing analysis, this equates to 

estimated annual reductions of 100 tons 

each of PM and SO2 and 200 tons of 

combined NOX and CO. 

For coal handling operations, the 

proposed amendments would reduce 


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the current opacity standard from less 

than 20 percent to no greater than 5 

percent. The proposal would thus 

reduce the opacity standard by 75 

percent. Opacity is an indirect means to 

address the presence of PM emissions 

and not an actual direct measurement of 

the mass of PM emissions. Thus, in 

order to determine the precise amount 

of PM reductions that would be 

associated with this change in the 

opacity standard, we would need actual 

baseline PM emissions data at 20 

percent opacity for a source, which are 

not available. Without these data, it is 

not possible for us to calculate the 

precise amount of PM reductions 

associated with the more stringent 

opacity limit with a high degree of 

certainty. We know, however, that 

lowering opacity from an affected 

facility generally results in a reduction 

in PM emissions, provided particle 

characteristics and size distribution 

remain similar for that facility. 

The existing subpart Y standards for 

coal handling equipment include only 

an opacity limit. The proposed 

amendments would establish a new PM 

standard of 0.023 g/dscm (0.010 gr/dscf) 

that would apply to all sources that are 

mechanically vented. At this time we, 

only expect end users processing 

bituminous coal to mechanically vent 

affected facilities, and, thus, only these 

facilities would be subject to the 

proposed new PM limit. Under the 

existing NSPS, affected facilities that are 

mechanically vented would already 

need to install some type of control 

device to comply with the 20 percent 

opacity limit. For coal handling 

facilities that are mechanically vented, 

EPA believes that a baghouse is the 

lowest cost option. If we assume that in 

the absence of the proposed revisions 

such affected facilities would have 

installed baghouses with an emissions 

limit equivalent to that of the pneumatic 

coal-cleaning equipment (0.040 g/dscm), 

the proposed amendments reduce 

emissions by an additional 40 percent. 

For the model bituminous power plant 

used in the costing analysis, this equates 

to approximately 5 tons of PM 

reductions annually. 

Based on public comment on the 

proposed amendments, we believe that 

the majority of new coal handling 

operations at mines are likely to be 

fugitive dust sources because they do 

not vent to a baghouse. In addition, end 

user locations that process 

subbituminous coal are moving toward 

PECS and fogging systems and would 

also be classified as fugitive dust 

sources. In both cases, only the opacity 

standard would apply. Thus, the 

aggregate costs of the new PM standard 

would be limited. 

Subpart Y has not been revised since 

it was originally promulgated in 1976 

and many States have more stringent 

control requirements. We believe it is 

appropriate to consider these existing 

State requirements when determining 

what is an appropriate baseline to 

compare against the proposed 

amendments. The majority of State 

permitting authorities that have more 

stringent control requirements require 

controls and work practice standards 

that maintain opacity well below 20 

percent. In addition, any coal 

preparation plant that is subject to New 

Source Review (NSR) would also 

already have control requirements 

significantly more stringent than the 

existing NSPS. Therefore, EPA believes 

that additional costs resulting from the 

proposed amendments should be 

negligible for these affected facilities, 

and recognizes that additional 

emissions reductions from such sources 

would be lower as well. 

IV. Modification and Reconstruction 

Provisions 

Existing affected facilities at coal 

preparation plants that are modified or 

reconstructed after the date on which 

standards applicable to the facility are 

proposed are subject to the standard as 

finalized. In revising the standards in 

subpart Y, we have considered whether 

existing facilities that are reconstructed 

or modified will be able to achieve the 

new standards. Where appropriate, we 

have proposed different standards for 

new, modified, and reconstructed 

facilities. We are not proposing any 

amendments to existing law regarding 

how a facility would conduct the 

modification and reconstruction 

analysis. 

V. Summary of Costs, Environmental, 

Energy, and Economic Impacts 

In setting NSPS, the CAA requires 

EPA to consider alternative emission 

control approaches, taking into account 

the estimated costs and benefits, as well 

as energy, solid waste, and other effects. 

We request comment on whether we 

have identified the appropriate 

alternatives and whether the proposed 

standards adequately take into 

consideration the incremental effects in 

terms of emission reductions, energy, 

and other effects of these alternatives. 

We will consider the available 

information in developing the final rule. 

The costs and environmental, energy, 

and economic impacts are expressed as 

incremental differences between the 

impacts of coal preparation facilities 

complying with the proposed 

amendments and the current common 

permitting authority requirements (i.e., 

baseline). We have concluded that the 

supplemental proposal adds additional 

compliance options and does not 

increase control costs or recordkeeping 

and reporting costs above those of the 

April 2008 proposal. The April 2008 

proposal economic impact analysis still 

holds; the amendments would result in 

minimal changes in prices and output 

for the industries affected by the final 

rule. The price increase for baseload 

electricity, cement prices, coke prices, 

and coal prices are insignificant. 

VI. Request for Comment 

We request comments on all aspects 

of the proposed amendments to NSPS 

subpart Y. All significant comments 

received will be considered in the 

development and selection of the final 

rule. We specifically solicit comments 

on additional amendments that are 

under consideration. These potential 

amendments are described below. 

1. Control Technologies for Controlling 

Emissions From Thermal Dryers 

No new thermal dryers have been 

installed at bituminous coal mines in 

the past decade, and as described 

previously, we have concluded that a 

new thermal dryer would likely use gas 

recirculation instead of a once-through 

design. Although present coal-fired 

thermal dryer designs use either stoker 

or pulverized coal burners, we are 

requesting comment on the cost and 

whether it would be technically feasible 

to use a fluidized bed design to generate 

the heat for the drying process. We are 

also requesting comment on whether 

SNCR could be successfully applied at 

a new thermal dryer for control of NOX

emissions. If either of these control 

technologies is determined to be 

possible for a new thermal dryer, we 

will consider basing the combined NOX

and CO, and SO2 limits for new thermal 

dryers on the use of these controls. 

Fluidized beds use limestone injection 

into the bed and can reduce potential 

SO2 emissions by over 90 percent; SNCR 

reduces NOX emissions by as much as 

50 percent. 

We are also requesting comment on 

whether it would be appropriate to set 

separate SO2 emissions standards for 

new, reconstructed, and modified 

thermal dryers depending on whether 

the dryer is a once-through design. As 

described earlier, once-though dryers 

typically use scrubbers to control PM 

emissions and could concurrently 

control SO2 emissions by 90 percent or 

more. If we decide to set separate 

standards for once-through and 

recirculation dryers, the once-through 


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SO2 limit for new, reconstructed, and 

modified thermal dryers would be 

changed to 85 ng/J (0.20 lb/MMBtu), or 

90 percent reduction in potential 

emissions and 520 ng/J (1.2 lb/MMBtu). 

The corresponding definition of a oncethrough thermal dryer would be a 

thermal dryer that does not recirculate 

any flue gas back to the furnace for 

temperature tempering. We request 

comment on this definition, as well as 

the standard discussed above. 

In addition, we are requesting 

comment on establishing separate SO2

limits based on the heat input capacity 

of the thermal dryer. For thermal dryers 

with heat input capacities of 250 

MMBtu/hr or greater the incremental 

costs of scrubbers for the sole purpose 

of reducing SO2 emissions is 

approximately $3,500 per ton and is 

considered cost effective for this source 

category. If we decide to set separate 

standards for larger thermal dryers, the 

large thermal dryer SO2 limit for new, 

reconstructed, and modified thermal 

dryers would be changed to 85 ng/J 

(0.20 lb/MMBtu), or 90 percent 

reduction in potential emissions and 

520 ng/J (1.2 lb/MMBtu). 

2. PM Standard 

We are considering, and requesting 

comment on, setting a more stringent 

PM limit for operations with a high 

volume of air vented from the affected 

facility. Larger control devices are more 

cost effective, and we are specifically 

requesting comment on setting the PM 

limit for coal handling and pneumatic 

coal cleaning equipment operations 

venting more than 2,000 dscm/min 

(70,000 dscf/min) at 0.012 g/dscm 

(0.0054 gr/dscf). Two-thirds of the post 

1995 PM performance test results we 

collected were below this limit, and 

those that were not had a lb/hr limit and 

not a concentration limit and the design 

criteria for those fabric filters are 

unknown. 

3. Rear Truck Dumps 

The physical size and operation 

characteristics of rear truck dumps make 

operation with low instantaneous 

opacity difficult to achieve. Several 

western subbituminous mining 

operations that began operation in the 

late 1970s and early 1980s originally 

used enclosures and fabric filters to 

control PM emissions from rear truck 

dumps. It was the only viable 

technology at the time, but while PM 

and opacity emissions from the fabric 

filter stack were relatively low, overall 

capture and control were not as high. 

With the advent of larger coal trucks 

and stilling sheds, the State of Wyoming 

has allowed for the replacement of 

enclosures that are vented to a fabric 

filter with stilling sheds. Stilling sheds 

provide a fairly high level of PM 

control. However, the coal is dumped 

rapidly and there are instantaneous 

periods of high opacity even when the 

6-minute opacity is low. The State of 

Wyoming determines if the still shed is 

working properly by averaging the 

highest instantaneous 15-second opacity 

of 10 truck dumps. As long as the 

average instantaneous opacity is less 

than 20 percent, the stilling shed is 

determined to be operating properly. We 

are requesting comment on whether 

requiring an annual average 

instantaneous opacity from 10 truck 

dumps is appropriate as an alternate to 

the Method 22 monitoring required for 

other affected facilities. 

4. Opacity Monitoring 

A single coal preparation plant can 

contain multiple similar affected 

facilities using similar control 

equipment configurations. To reduce 

the burden of the rulemaking while still 

maintaining an equivalent level of 

environmental protection, we are 

requesting comment on allowing the 

permitting authority to approve a single 

Method 22 observation as sufficient 

monitoring for up to 4 other similar 

affected facilities if the owner/operator 

agrees to site-specific equipment 

inspection and maintenance procedures 

approved by the permitting authority. If 

we include this approach in the final 

rule, the owner/operator would have to 

observe a different affected facility in 

the group each week and would still be 

required to conduct at least monthly 

observations for each piece of 

equipment. 

5. Thermal Dryer Monitoring 

We are requesting comment on 

several of the monitoring requirements 

for thermal dryers. First, owner/ 

operators of thermal dryers are required 

to continuously monitor the 

temperature of the gas stream at the exit 

of the thermal dryer. We are requesting 

comment on the utility of collecting this 

information. If we determine this 

requirement could be eliminated 

without risk of a significant increase in 

emissions, we will consider eliminating 

this requirement. 

Second, subpart Y requires owner/ 

operators of wet scrubbers to 

continuously monitor the pressure drop 

through the venturi constriction and the 

water supply pressure. However, there 

are no requirements specified in the rule 

to maintain these values within a 

specified range, nor requirements 

regarding what averaging period should 

be used when determining the 

appropriate value. We are considering, 

and requesting comment on, adding 

requirements that pressure drop and 

water pressure be maintained at a 

minimum of 90 percent of the values 

recorded during the most recent 

performance test, and that an operating 

day average be used to determine the 

values. 

Next, we are requesting comment on 

whether it is appropriate to replace the 

water supply pressure monitoring 

requirement with a requirement to 

monitor and maintain the water flow 

rate as determined from the most recent 

performance test. 

Finally, because we are adding 

additional standards for thermal dryers 

we are considering, and requesting 

comment on, possible monitoring 

requirements for SO2, NOX, and CO. We 

request comment on requiring CEMS for 

monitoring SO2, NOX, and CO 

emissions. If we do require CEMS, we 

would use the same numerical 

emissions rate but the averaging period 

would be 30 days. We also request 

comment on alternative continuous 

monitoring options. In the event we do 

not require CEMS, we would require 

other continuous monitoring and 

require that the relevant parameters are 

maintained within 10 percent of the 

value recorded during the performance 

test on an operating day average. With 

regard to monitoring for SO2, we are 

also considering, and requesting 

comment on, whether pH and water 

flow rate monitoring are appropriate for 

owner/operators of thermal dryers with 

a wet scrubber. In addition, for owner/ 

operators of thermal dryers without a 

wet scrubber, we are considering, and 

requesting comment on, whether 

reagent injection flow rate and airflow 

rate are the appropriate monitoring 

parameters. For NOX and CO, we are 

considering, and requesting comment 

on, requiring an O2 monitor prior to 

temperature tempering to verify that the 

appropriate air-to-fuel ratio is 

maintained. 

6. Opacity Standard for Open Storage 

Piles and Roadways 

We are considering, and requesting 

comment on, both the feasibility of 

establishing an opacity standard for 

open storage piles and roadways and 

what opacity standard would be 

appropriate. 

7. Work Practice Standards for Haul 

Roads 

As an alternative to our proposal to 

exempt an owner/operator of roadways 

that do not leave the property of the 

affected facility from work practice 

standards directly, we request comment 


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on whether permitting authorities 

should be required to include other 

fugitive dust prevention measures (e.g., 

wetting of the road surface, sweeping of 

excess dust, tire washes) in the fugitive 

dust plan for such roadways. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993), this 

action is a ‘‘significant regulatory 

action’’ because it may raise novel legal 

or policy issues arising out of legal 

mandates, the President’s priorities, or 

the principles set forth in the EO. 

Accordingly, EPA submitted this action 

to the OMB for review under EO 12866, 

and any changes made in response to 

OMB recommendations have been 

documented in the docket for this 

action. 

B. Paperwork Reduction Act 

The information collection 

requirements associated with the April 

2008 proposed rule have been submitted 

for approval to the OMB under the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The Information Collection 

Request (ICR) document prepared by 

EPA has been assigned EPA ICR number 

1062.10. Because this supplemental 

proposal does not result in additional 

recordkeeping and reporting 

requirements, a new ICR document was 

not prepared. 

The proposed amendments to the 

existing standards of performance for 

Coal Preparation Plants would add new 

monitoring, reporting, and 

recordkeeping requirements. The 

information would be used by EPA to 

ensure that any new affected facilities 

comply with the emission limits and 

other requirements. Records and reports 

would be necessary to enable EPA or 

States to identify new affected facilities 

that may not be in compliance with the 

requirements. Based on reported 

information, EPA would decide which 

units and what records or processes 

should be inspected. 

The proposed amendments would not 

require any notifications or reports 

beyond those required by the General 

Provisions. The recordkeeping 

requirements require only the specific 

information needed to determine 

compliance. These recordkeeping and 

reporting requirements are specifically 

authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted 

to EPA for which a claim of 

confidentially is made will be 

safeguarded according to EPA policies 

in 40 CFR part 2, subpart B, 

Confidentially of Business Information. 

The annual monitoring, reporting, and 

recordkeeping burden for this collection 

averaged over the first 3 years of this 

ICR is estimated to total 32,664 labor 

hours per year at an average annual cost 

of $2,957,707. This estimate includes 

performance testing, excess emission 

reports, notifications, and 

recordkeeping. There are no capital/ 

start-up costs or operational and 

maintenance costs associated with the 

monitoring requirements over the 3-year 

period of the ICR. Burden is defined at 

5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a current valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, EPA has established 

a public docket for this rule, which 

includes this ICR, under Docket ID 

number EPA–HQ–OAR–2008–0260. 

Submit any comments related to the ICR 

to EPA and OMB. See ADDRESSES

section at the beginning of this action 

for where to submit comments to EPA. 

Send comments to OMB at the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 725 

17th Street, NW., Washington, DC 

20503, Attention: Desk Office for EPA. 

Because OMB is required to make a 

decision concerning the ICR between 30 

and 60 days after May 27, 2009, a 

comment to OMB is best assured of 

having its full effect if OMB receives it 

by June 26, 2009. The final rule will 

respond to any OMB or public 

comments on the information collection 

requirements contained in this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of the proposed amendments on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

This proposed rule will not impose any 

requirements on small entities. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. 

The total annual control and monitoring 

costs of the proposed amendments, 

compared to a baseline of no control, at 

year five is $2 million. Thus, this rule 

is not subject to the requirements of 

sections 202 or 205 of UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

E. Executive Order 13132: Federalism 

EO 13132, entitled ‘‘Federalism’’ (64 

FR 43255, August 10, 1999), requires 

EPA to develop an accountable process 

to ensure ‘‘meaningful and timely input 

by State and local officials in the 

development of regulatory policies that 

have federalism implications.’’ ‘‘Policies 

that have federalism implications’’ is 

defined in the EO to include regulations 

that have ‘‘substantial direct effects on 

the States, on the relationship between 

the national government and the States, 

or on the distribution of power and 

responsibilities among the various 

levels of government.’’ 

These proposed amendments do not 

have federalism implications. They will 

not have substantial direct effects on the 

States, on the relationship between the 

national government and the States, or 

on the distribution of power and 

responsibilities among the various 

levels of government, as specified in EO 

13132. These proposed amendments 

will not impose substantial direct 

compliance costs on State or local 

governments; they will not preempt 

State law. Thus, EO 13132 does not 


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25320 Federal Register / Vol. 74, No. 100 / Wednesday, May 27, 2009 / Proposed Rules 

apply to these proposed amendments. In 

the spirit of EO 13132, and consistent 

with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicits comment on these proposed 

amendments from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). We are not aware of any coal 

preparation facilities owned by an 

Indian tribe. Thus, Executive Order 

13175 does not apply to this action. 

EPA specifically solicits additional 

comment on this proposed action from 

tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This proposed action is not 

subject to EO 13045 because it is based 

solely on technology performance. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed action is not a 

‘‘significant energy action’’ as defined in 

EO 13211 (66 FR 28355, May 22, 2001) 

because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. Further, 

we have concluded that this proposed 

action is not likely to have any adverse 

energy effects. 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law No. 

104–113 (15 U.S.C. 272 note) directs 

EPA to use voluntary consensus 

standards (VCS) in its regulatory 

activities unless to do so would be 

inconsistent with applicable law or 

otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures, and business practices) that 

are developed or adopted by voluntary 

consensus standards bodies. NTTAA 

directs EPA to provide Congress, 

through OMB, explanations when the 

Agency decides not to use available and 

applicable VCS. 

This proposed rulemaking involves 

technical standards. EPA proposes to 

use ASME PTC 19.10–1981, ‘‘Flue and 

Exhaust Gas Analyses,’’ for its manual 

methods of measuring the oxygen, 

carbon dioxide, sulfur dioxide or 

nitrogen dioxide content of the exhaust 

gas. These parts of ASME PTC 19.10– 

1981 are acceptable alternatives to EPA 

Method 3B of appendix A–2 and EPA 

Methods 6, 6A, and 7 of appendix A– 

4 of 40 CFR part 60. This standard is 

available from the American Society of 

Mechanical Engineers (ASME), Three 

Park Avenue, New York, NY 10016– 

5990. 

EPA also proposes to use EPA 

Methods 1, 1A, 2, 2A, 2C, 2D, 2F, 2G, 

3, 3A, 3B, 4, 5, 5B, 5D, 6, 6A, 6C, 7, 7E, 

9, 10, 17, and 22 (40 CFR part 60, 

appendices A–1 through A–7). While 

the Agency has identified 20 VCS as 

being potentially applicable, we do not 

propose to use these standards in this 

proposed rulemaking. The use of these 

VCS would be impractical because they 

do not meet the objectives of the 

standards cited in this proposed rule. 

The search and review results are in the 

docket for this rule. 

EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable VCS and 

to explain why such standards should 

be used in this regulation. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

EO 12898 (59 FR 7629, February 16, 

1994) establishes Federal executive 

policy on environmental justice. Its 

main provision directs Federal agencies, 

to the greatest extent practical and 

permitted by law, to make 

environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

EPA has determined that this 

proposed rule will not have 

disproportionately high adverse human 

health or environmental effects on 

minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high adverse human 

health or environmental effects on any 

populations, including any minority or 

low-income population. The proposed 

amendments would assure that all new 

coal preparation plants install 

appropriate controls to limit health 

impacts to nearby populations. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

Dated: May 15, 2009. 

Lisa P. Jackson, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, part 60, of 

the Code of the Federal Regulations is 

proposed to be amended as follows: 

PART 60—[AMENDED] 

1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

2. Section 60.17 is amended: 

a. By revising paragraph (a)(13); 

b. By removing paragraph (a)(14); 

c. By redesignating paragraphs (a)(15) 

through (a)(93) as paragraphs (a)(14) 

through (a)(92); and 

d. By revising paragraph (h)(4) to read 

as follows. 

§ 60.17 Incorporations by reference. 

* * * * * 

(a) * * * 

(13) ASTM D388–77, 90, 91, 95, 98a, 

99 (Reapproved 2004)ε1, Standard 

Specification for Classification of Coals 

by Rank, IBR approved for 

§§ 60.24(h)(8), 60.41 of subpart D of this 

part, 60.45(f)(4)(i), 60.45(f)(4)(ii), 

60.45(f)(4)(vi), 60.41Da of subpart Da of 

this part, 60.41b of subpart Db of this 

part, 60.41c of subpart Dc of this part, 

60.251 of subpart Y of this part, and 

60.4102. 

* * * * * 

(h) * * * 

(4) ANSI/ASME PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [part 10, 

Instruments and Apparatus], IBR 

approved for § 60.106(e)(2) of subpart J, 

§§ 60.104a(d)(3), (d)(5), (d)(6), (h)(3), 

(h)(4), (h)(5), (i)(3), (i)(4), (i)(5), (j)(3), 

and (j)(4), 60.105a(d)(4), (f)(2), (f)(4), 

(g)(2), and (g)(4), 60.106a(a)(1)(iii), 

(a)(2)(iii), (a)(2)(v), (a)(2)(viii), (a)(3)(ii), 

and (a)(3)(v), and 60.107a(a)(1)(ii), 

(a)(1)(iv), (a)(2)(ii), (c)(2), (c)(4), and 

(d)(2) of subpart Ja, § 60.257(b)(3) of 

subpart Y, tables 1 and 3 of subpart 

EEEE, tables 2 and 4 of subpart FFFF, 

table 2 of subpart JJJJ, and 


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§§ 60.4415(a)(2) and 60.4415(a)(3) of 

subpart KKKK of this part. 

* * * * * 

Subpart Y—[Amended] 

3. Part 60 is amended by revising 

subpart Y to read as follows: 

Subpart Y—Standards of Performance 

for Coal Preparation and Processing 

Plants 

Sec. 

60.250 Applicability and designation of 

affected facility. 

60.251 Definitions. 

60.252 Standards for thermal dryers. 

60.253 Standards for pneumatic coalcleaning equipment. 

60.254 Standards for coal processing and 

conveying equipment, coal storage 

system, and coal transfer system 

operations. 

60.255 Performance tests and other 

compliance requirements. 

60.256 Continuous monitoring 

requirements. 

60.257 Test methods and procedures. 

60.258 Reporting and recordkeeping. 

§ 60.250 Applicability and designation of 

affected facility. 

(a) The provisions of this subpart are 

applicable to any of the following 

affected facilities in coal preparation 

and processing plants which process 

more than 181 megagrams (Mg) (200 

tons) per day of coal: Thermal dryers, 

pneumatic coal-cleaning equipment (air 

tables), coal processing and conveying 

equipment (including breakers and 

crushers), coal storage systems, and 

transfer and loading systems. 

(b) Any affected facility under 

paragraph (a) of this section that 

commences construction, 

reconstruction, or modification after 

October 24, 1974, is subject to the 

requirements of this subpart. 

§ 60.251 Definitions. 

As used in this subpart, all terms not 

defined herein have the meaning given 

them in the Clean Air Act (Act) and in 

subpart A of this part. 

Anthracite means coal that is 

classified as anthracite according to the 

American Society of Testing and 

Materials in ASTM D388 (incorporated 

by reference, see § 60.17). 

Bag leak detection system means a 

system that is capable of continuously 

monitoring relative particulate matter 

(dust loadings) in the exhaust of a fabric 

filter to detect bag leaks and other upset 

conditions. A bag leak detection system 

includes, but is not limited to, an 

instrument that operates on 

triboelectric, light scattering, light 

transmittance, or other effect to 

continuously monitor relative 

particulate matter loadings. 

Bituminous coal means solid fossil 

fuel classified as bituminous coal by 

ASTM D388 (incorporated by referencesee § 60.17). 

Coal for units constructed, 

reconstructed, or modified on or before 

May 27, 2009 means all solid fossil fuels 

classified as anthracite, bituminous, 

subbituminous, or lignite by ASTM 

D388 (incorporated by reference-see 

§ 60.17). For units constructed, 

reconstructed, or modified after May 27, 

2009, coal means all solid fossil fuels 

classified as anthracite, bituminous, 

subbituminous, or lignite by ASTM 

D388 (incorporated by reference-see 

§ 60.17), coal refuse, and petroleum 

coke. 

Coal preparation and processing 

plant means any facility (excluding 

underground mining operations) which 

prepares coal by one or more of the 

following processes: breaking, crushing, 

screening, wet or dry cleaning, and 

thermal drying. 

Coal processing and conveying 

equipment means any machinery used 

to reduce the size of coal or to separate 

coal from refuse, and the equipment 

used to convey coal to or remove coal 

and refuse from the machinery. This 

includes, but is not limited to, breakers, 

crushers, screens, and conveying 

systems. 

Coal refuse means debris product of 

coal mining or coal preparation and 

processing operations (e.g., culm, gob, 

boney, slate dumps, etc.) containing 

coal, matrix material, clay, and other 

organic and inorganic material. 

Coal storage system for units 

constructed, reconstructed, or modified 

on or before May 27, 2009 means any 

facility used to store coal except for 

open storage piles. For units 

constructed, reconstructed, or modified 

after May 27, 2009, coal storage system 

means any facility used to store coal. 

Design controlled potential PM 

emissions rate means the theoretical 

particulate matter (PM) emissions (Mg) 

that would result from the operation of 

a control device at its design emissions 

rate (grams per dry standard cubic meter 

(g/dscm)), multiplied by the maximum 

design flow rate (dry standard cubic 

meter per minute (dscm/min)), 

multiplied by 60 (minutes per hour 

(min/hr)), multiplied by 8,760 (hours 

per year (hr/yr)), divided by 1,000,000 

(megagrams per gram (Mg/g)). 

Indirect thermal dryer means a 

thermal dryer that reduces the moisture 

content of coal through indirect heating 

of the coal through contact with a heat 

transfer medium. If the source of heat 

(the source of combustion or furnace) is 

subject to either subpart Da, Db, or Dc 

of this part then the furnace and the 

associated emissions are not part of the 

affected facility. However, if the source 

of heat is not subject to either subpart 

Da, Db, or Dc of this part, then the 

furnace and the associated emissions are 

part of the affected facility. 

Lignite means coal that is classified as 

lignite A or B according to the American 

Society of Testing and Materials in 

ASTM D388 (incorporated by reference, 

see § 60.17). 

Mechanical vent means a vent using 

a powered mechanical drive (machine) 

to induce air flow. 

Operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which and 

coal is prepared or processed at any 

time by the affected facility. It is not 

necessary that coal be prepared or 

processed the entire 24-hour period. 

Petroleum Coke also known as 

petcoke means a carbonization product 

of high-boiling hydrocarbon fractions 

obtained in petroleum processing 

(heavy residues). Petroleum coke is 

typically derived from oil refinery coker 

units or other cracking processes. 

Pneumatic coal-cleaning equipment 

for units constructed, reconstructed, or 

modified on or before May 27, 2009 

means any facility which classifies 

bituminous coal by size or separates 

bituminous coal from refuse by 

application of air stream(s). For units 

constructed, reconstructed, or modified 

after May 27, 2009, pneumatic coalcleaning equipment means any facility 

which classifies coal by size or separates 

coal from refuse by application of air 

stream(s). 

Potential combustion concentration 

means the theoretical emissions 

(nanograms per joule (ng/J) or pounds 

per million British thermal units (lb/ 

MMBtu) heat input) that would result 

from combustion of a fuel in an 

uncleaned state without emission 

control systems, as determined using 

Method 19 of appendix A–7 of this part. 

Subbituminous coal means coal that 

is classified as subbituminous A, B, or 

C according to the American Society of 

Testing and Materials in ASTM D388 

(incorporated by reference, see § 60.17). 

Thermal dryer for units constructed, 

reconstructed, or modified on or before 

May 27, 2009 means any facility in 

which the moisture content of 

bituminous coal is reduced by contact 

with a heated gas stream which is 

exhausted to the atmosphere. For units 

constructed, reconstructed, or modified 

after May 27, 2009, thermal dryer means 

any facility in which the moisture 

content of coal is reduced by either 

contact with a heated gas stream which 


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is exhausted to the atmosphere or 

through indirect heating of the coal 

through contact with a heated heat 

transfer medium. 

Transfer and loading system means 

any facility used to transfer and load 

coal for shipment. 

§ 60.252 Standards for thermal dryers. 

(a) On and after the date on which the 

performance test is conducted or 

required to be completed under § 60.8, 

whichever date comes first, an owner or 

operator of a thermal dryer constructed, 

reconstructed, or modified on or before 

April 28, 2008, subject to the provisions 

of this subpart must meet the 

requirements in paragraphs (a)(1) and 

(a)(2) of this section. 

(1) The owner or operator shall not 

cause to be discharged into the 

atmosphere from the thermal dryer any 

gases which contain PM in excess of 

0.070 g/dscm (0.031 grains per dry 

standard cubic feet (gr/dscf)); and 

(2) The owner or operator shall not 

cause to be discharged into the 

atmosphere from the thermal dryer any 

gases which exhibit 20 percent opacity 

or greater. 

(b) On and after the date on which the 

performance test is conducted or 

required to be completed under § 60.8, 

whichever date comes first, an owner or 

operator of a thermal dryer constructed, 

reconstructed, or modified after April 

28, 2008, subject to the provisions of 

this subpart must meet the applicable 

standards for PM, sulfur dioxide (SO2), 

and combined nitrogen oxides (NOX) 

and carbon monoxide (CO) as specified 

in paragraphs (b)(1) through (3) of this 

section. 

(1) The owner or operator must meet 

the requirements for PM emissions in 

paragraphs (b)(1)(i) through (iii) of this 

section, as applicable to the affected 

facility. 

(i) For each thermal dryer constructed 

after April 28, 2008, the owner or 

operator must meet the requirements of 

(b)(1)(i)(A) and (b)(1)(i)(B). 

(A) The owner or operator must not 

cause to be discharged into the 

atmosphere from the thermal dryer any 

gases that contain PM in excess of 0.023 

g/dscm (0.010 grains per dry standard 

cubic feet (gr/dscf)); and 

(B) The owner or operator must not 

cause to be discharged into the 

atmosphere from the thermal dryer any 

gases that exhibit 10 percent opacity or 

greater. 

(ii) For each thermal dryer 

reconstructed after April 28, 2008, the 

owner or operator must meet the 

requirements of paragraph (b)(1)(ii)(A) 

and (b)(1)(ii)(B) of this section. 

(A) The owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases that contain PM in excess of 

0.045 g/dscm (0.020 gr/dscf); and 

(B) The owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases that exhibit 20 percent opacity 

or greater. 

(iii) For each thermal dryer modified 

after April 28, 2008, the owner or 

operator must meet the requirements of 

paragraphs (b)(1)(iii)(A) and (b)(1)(iii)(B) 

of this section. 

(A) The owner or operator must not 

cause to be discharged to the 

atmosphere from the affected facility 

any gases which contain PM in excess 

of 0.070 g/dscm (0.031 gr/dscf); and 

(B) The owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases which exhibit 20 percent 

opacity or greater. 

(2) For each thermal dryer 

constructed, reconstructed, or modified 

after May 27, 2009, the owner or 

operator must meet the requirements for 

SO2 emissions in either paragraph 

(b)(2)(i) or (ii) of this section, except for 

indirect thermal dryers where the 

source of the heat is subject to either 

subpart Da, Db, or Dc of this part. 

(i) The owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases that contain SO2 in excess of 

85 ng/J (0.20 lb/MMBtu) heat input; or 

(ii) The owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases that either contain SO2 in 

excess of 520 ng/J (1.20 lb/MMBtu) heat 

input or exceed 50 percent of the 

potential combustion concentration (i.e., 

achieve at least a 50 percent reduction 

of the potential combustion 

concentration and do not exceed a 

maximum emissions rate of 1.2 lb/ 

MMBtu (520 ng/J)). 

(3) The owner or operator must meet 

the requirements for combined NOX and 

CO emissions in paragraph (b)(3)(i) or 

(ii) of this section, as applicable to the 

affected facility, except for indirect 

thermal dryers where the source of the 

heat is subject to either subpart Da, Db, 

or Dc of this part. 

(i) For each thermal dryer constructed 

after May 27, 2009, the owner or 

operator must not cause to be 

discharged into the atmosphere from the 

affected facility any gases which contain 

a combined concentration of NOX and 

CO in excess of 280 ng/J (0.65 lb/ 

MMBtu) heat input. 

(ii) For each thermal dryer 

reconstructed or modified after May 27, 

2009, the owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases which contain combined 

concentration of NOX and CO in excess 

of 430 ng/J (1.0 lb/MMBtu) heat input. 

§ 60.253 Standards for pneumatic coalcleaning equipment. 

(a) On and after the date on which the 

performance test is conducted or 

required to be completed under § 60.8, 

whichever date comes first, an owner or 

operator of pneumatic coal-cleaning 

equipment constructed, reconstructed, 

or modified on or before April 28, 2008, 

must meet the requirements of 

paragraphs (a)(1) and (a)(2) of this 

section. 

(1) The owner or operator must not 

cause to be discharged into the 

atmosphere from the pneumatic coalcleaning equipment any gases that 

contain PM in excess of 0.040 g/dscm 

(0.017 gr/dscf); and 

(2) The owner or operator must not 

cause to be discharged into the 

atmosphere from the pneumatic coalcleaning equipment any gases that 

exhibit 10 percent opacity or greater. 

(b) On and after the date on which the 

performance test is conducted or 

required to be completed under § 60.8, 

whichever date comes first, an owner or 

operator of pneumatic coal-cleaning 

equipment constructed, reconstructed, 

or modified after April 28, 2008, must 

meet the requirements in paragraphs 

(b)(1) and (b)(2) of this section. 

(1) The owner of operator must not 

cause to be discharged into the 

atmosphere from the pneumatic coalcleaning equipment any gases that 

contain PM in excess of 0.023 g/dscm 

(0.010 gr/dscf); and 

(2) The owner or operator must not 

cause to be discharged into the 

atmosphere from the pneumatic coalcleaning equipment any gases that 

exhibit greater than 5 percent opacity. 

§ 60.254 Standards for coal processing 

and conveying equipment, coal storage 

system, and coal transfer system 

operations. 

(a) On and after the date on which the 

performance test is conducted or 

required to be completed under § 60.8, 

whichever date comes first, an owner or 

operator shall not cause to be 

discharged into the atmosphere from 

any coal processing and conveying 

equipment, coal storage system, or coal 

transfer and loading system processing 

coal constructed, reconstructed, or 

modified on or before April 28, 2008, 

gases which exhibit 20 percent opacity 

or greater. 

(b) On and after the date on which the 

performance test is conducted or 


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required to be completed under § 60.8, 

whichever date comes first, an owner or 

operator of any coal processing and 

conveying equipment, coal storage 

system, or coal transfer and loading 

system processing coal constructed, 

reconstructed, or modified after April 

28, 2008, must meet the requirements in 

paragraphs (b)(1) through (3) of this 

section, as applicable to the affected 

facility. 

(1) The owner or operator must not 

cause to be discharged into the 

atmosphere from the affected facility 

any gases which exhibit greater than 5 

percent opacity. 

(2) The owner or operator must not 

cause to be discharged into the 

atmosphere from any mechanical vent at 

the facility gases which contain 

particulate matter in excess of 0.023 g/ 

dscm (0.010 gr/dscf). 

(3) The owner or operator must 

control fugitive coal dust emissions 

from fugitive sources at the facility by 

operating according to a written fugitive 

emissions control plan that has been 

approved by the permitting authority. 

The fugitive emissions control plan 

must address the fugitive emissions 

sources specified in paragraph (b)(3)(i) 

of this section, as applicable to the 

affected facility, and include the 

information specified in paragraph 

(b)(3)(ii) of this section. 

(i) The fugitive emissions control plan 

must address each of the fugitive 

emissions sources listed in paragraphs 

(b)(3)(i)(A) through (C) of this section 

that are located at the facility. 

(A) Open storage piles used for 

storage of coal. 

(B) Roadways associated with and 

within the same contiguous property as 

the coal preparation and processing 

plant. 

(C) Other site-specific sources of 

fugitive emissions that the 

Administrator or permitting authority 

determines need to be included in your 

fugitive emissions control plan. 

(ii) The fugitive emissions control 

plan must describe the control measures 

the owner or operator shall use to 

minimize fugitive emissions from each 

source addressed in the plan, and 

explain how the measures are 

applicable and appropriate for the site 

conditions. For open storage piles, the 

fugitive emissions plan must specify 

how one or more of the following 

control measures will be used to 

minimize fugitive coal dust: locating the 

source inside a partial enclosure, 

installing and operating a water spray or 

fogging system, applying appropriate 

chemical dust suppression agents on the 

source, use of a wind barrier, or use of 

a vegetative cover. For roadways, the 

fugitive emissions plan must specify 

how one or more of the following 

control measures will be used to 

minimize fugitive dust: paving, 

sweeping excess coal dust, wetting of 

the road surface, or tire washes. The 

permitting authority may approve a 

fugitive emissions plan that includes 

control technologies other than those 

specified above only if the owner or 

operator has demonstrated to the 

Administrator that the alternate control 

technology will provide equivalent 

overall environmental protection or if it 

has determined to the Administrator 

that it is either economically or 

technically infeasible for the affected 

facility to use the control options 

specifically identified in this paragraph. 

(iii) If the owner or operator of the 

affected facility is part of a source which 

is subject to title V permitting, then the 

requirement for the owner or operator to 

operate according to a written fugitive 

emissions control plan which has been 

approved by the permitting authority 

must be incorporated into the title V 

operating permit for the source. 

Additionally, a copy of the fugitive 

emissions control plan must be 

submitted to the permitting authority 90 

days prior to the compliance date for the 

affected facility. Any revisions to the 

fugitive emissions control plan are not 

effective until approved by the 

permitting authority. All of the 

requirements in this paragraph are to be 

specified in any title V permit which 

covers the affected facility. 

§ 60.255 Performance tests and other 

compliance requirements. 

(a) An owner or operator of each 

affected facility that commenced 

construction, reconstruction, or 

modification on or before April 28, 

2008, must conduct all performance 

tests required by § 60.8 to demonstrate 

compliance with the applicable 

emission standards using the methods 

identified in § 60.257. 

(b) An owner or operator of each 

affected facility that commenced 

construction, reconstruction, or 

modification after April 28, 2008, must 

conduct performance tests according to 

the requirements of § 60.8 and the 

methods identified in § 60.257 to 

demonstrate compliance with the 

applicable emissions standards in this 

subpart as specified in paragraphs (b)(1) 

and (2) of this section. 

(1) For each affected facility subject to 

a PM, SO2, or combined NOX and CO 

emissions standard, an initial 

performance test must be performed 

except as provided for in paragraph (d) 

of this section. Thereafter, a new 

performance test must be conducted 

according to the requirements in 

paragraphs (b)(1)(i) and (ii) of this 

section, as applicable. 

(i) If the results of the most recent 

performance test demonstrate that 

emissions from the affected facility are 

greater than 50 percent of the applicable 

emissions standard, a new performance 

test must be conducted within 12 

calendar months of the date that the 

previous performance test was required 

to be completed. 

(ii) If the results of the most recent 

performance test demonstrate that 

emissions from the affected facility are 

50 percent or less of the applicable 

emissions standard, a new performance 

test must be conducted within 24 

calendar months of the date that the 

previous performance test was required 

to be completed. 

(iii) An owner or operator of an 

affected facility that has not operated for 

the 60 calendar days prior to the due 

date of a performance test is not 

required to perform the subsequent 

performance test until 30 calendar days 

after the next operating day. 

(2) For each affected facility subject to 

an opacity standard, an initial 

performance test must be performed. 

Thereafter, a new performance test must 

be conducted according the 

requirements in paragraphs (b)(2)(i) 

through (iv) of this section, as 

applicable, except as provided for in 

paragraphs (e) and (f) of this section. 

(i) If the maximum 15-second opacity 

reading in the most recent performance 

test is greater than 5 percent, a new 

performance test must be conducted 

within 7 operating days of the date that 

the previous performance test was 

required to be completed. 

(ii) If the maximum 15-second opacity 

reading in the most recent performance 

test is 5 percent, a new performance test 

must be conducted within 30 operating 

days of the date that the previous 

performance test was required to be 

completed. 

(iii) If no visible emissions are 

observed in the most recent 

performance test, a new performance 

test must be conducted within 120 

operating days of the date of the 

previous performance test was required 

to be completed. 

(iv) An owner or operator of affected 

facilities continuously monitoring 

scrubber parameters as specified in 

§ 60.256 is exempt from the 

requirements in paragraphs (b)(2)(i) 

through (iii) if opacity performance tests 

are conducted concurrently (or within a 

60-minute period) with PM performance 

tests. 

(c) An owner or operator of an 

affected facility subject to a PM 


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emission standard (other than a thermal 

dryer) that uses a control device with a 

design control potential PM emissions 

rate of 1.0 Mg (1.1 tons) per year or less 

is exempted from the requirements of 

paragraphs (b)(1)(i) and (ii) of this 

section provided that the owner or 

operator meets all of the following 

conditions specified in paragraphs (c)(1) 

through (4) of this section. This 

exemption does not apply to thermal 

dryers. 

(1) The design emissions limit is less 

than or equal to the applicable PM 

emissions standard and the results of 

the most recent performance test were 

less than or equal to the applicable 

limit, 

(2) The control device manufacturer’s 

recommended maintenance procedures 

are followed, and 

(3) The monitoring requirements in 

paragraphs (e) or (f) of this section are 

followed. 

(d) An owner or operator of a group 

of up to five of the same type of affected 

facilities that are subject to PM 

emissions standards and use identical 

control devices each with a design 

potential PM emissions rate of 10 Mg 

(11 tons) per year or less, the permitting 

authority may allow the owner or 

operator to use a single PM performance 

test for one of the affected control 

devices to demonstrate that the group of 

affected facilities is in compliance with 

the applicable emissions standards 

provided that the owner or operator 

meets all of the following conditions 

specified in paragraphs (d)(1) through 

(4) of this section. 

(1) The design emissions limit for 

each individual affected facility is less 

than or equal to the applicable PM 

emissions limit and the performance 

test for each individual affected facility 

is 90 percent or less of the applicable 

PM standard; 

(2) The manufacturer’s recommended 

maintenance procedures are followed 

for each control device; 

(3) The monitoring requirements in 

paragraph (e) or (f) of this section are 

used for each affected facility; and 

(4) A performance test is conducted 

on each affected facility at least once 

every 5 calendar years. 

(e) As an alternative to meeting the 

requirements in paragraph (b)(2)(i) 

through (iii) of this section, an owner or 

operator of an affected facility for which 

the maximum 6-minute opacity reading 

from the most recent Method 9 of 

appendix A–4 of this part performance 

test is less than 3 percent may elect to 

comply with the requirements in 

paragraph (e)(1) or (2) of this section. 

(1) Monitor visible emissions from 

each affected facility according to the 

requirements in either paragraph 

(e)(1)(i) or (ii) of this section. 

(i) Conduct daily observations each 

operating day for a period of at least 10 

minutes (during normal operation) 

when the coal preparation and 

processing plant is in operation using 

EPA Method 22 of appendix A–7 of this 

part and demonstrate that the sum of the 

occurrences of any visible emissions is 

not in excess of 5 percent of the 

observation period (i.e., 30 seconds per 

10-minute period). If the sum of the 

occurrence of any visible emissions is 

greater than 30 seconds during the 

initial 10-minute observation, 

immediately conduct a 30-minute 

observation. If the sum of the 

occurrence of visible emissions is 

greater than 5 percent of the observation 

period (i.e., 90 seconds per 30-minute 

period) the owner or operator shall 

either document and adjust the 

operation of the facility and 

demonstrate within 24 hours that the 

sum of the occurrence of visible 

emissions is equal to or less than 5 

percent during a 30-minute observation 

(i.e., 90 seconds) or conduct a new 

Method 9 of appendix A–4 of this part 

performance test within 30 calendar 

days unless a waiver is granted by the 

permitting authority. 

(ii) If no visible emissions are 

observed for 7 consecutive operating 

days, observations can be reduced to 

once every 7 operating days. If any 

visible emissions are observed, daily 

observations shall be resumed. 

(2) Prepare a written site-specific 

monitoring plan for a digital opacity 

compliance system for approval by the 

Administrator. The plan shall require 

observations of at least one digital image 

every 15 seconds for 10-minute periods 

(during normal operation) every 

operating day. An approvable 

monitoring plan must include a 

demonstration that the occurrences of 

visible emissions are not in excess of 5 

percent of the observation period. For 

reference purposes in preparing the 

monitoring plan, see OAQPS 

‘‘Determination of Visible Emission 

Opacity From Stationary Sources Using 

Computer-Based Photographic Analysis 

Systems.’’ This document is available 

from the U.S. Environmental Protection 

Agency (U.S. EPA); Office of Air Quality 

and Planning Standards; Sector Policies 

and Programs Division; Measurement 

Group (D243–02), Research Triangle 

Park, NC 27711. This document is also 

available on the Technology Transfer 

Network (TTN) under Emission 

Measurement Center Preliminary 

Methods. The monitoring plan approved 

by the Administrator shall be 

implemented by the owner or operator. 

(f) As an alternative to meeting the 

requirements in paragraph (b)(2) of this 

section, an owner or operator of an 

affected facility subject to a visible 

emissions standard under this subpart 

may install, operate, and maintain a 

continuous opacity monitoring system 

(COMS). Each COMS used to comply 

with provisions of this subpart must be 

installed, calibrated, maintained, and 

continuously operated according to the 

requirements in paragraphs (f)(1) and (2) 

of this section. 

(1) The COMS must meet Performance 

Specification 1 in 40 CFR part 60, 

appendix B. 

(2) The COMS must comply with the 

quality assurance requirements in 

paragraphs (f)(2)(i) through (v) of this 

section. 

(i) The owner or operator must 

automatically (intrinsic to the opacity 

monitor) check the zero and upscale 

(span) calibration drifts at least once 

daily. For particular COMS, the 

acceptable range of zero and upscale 

calibration materials is as defined in the 

applicable version of Performance 

Specification 1 in 40 CFR part 60, 

appendix B. 

(ii) The owner or operator must adjust 

the zero and span whenever the 24-hour 

zero drift or 24-hour span drift exceeds 

4 percent opacity. The COMS must 

allow for the amount of excess zero and 

span drift measured at the 24-hour 

interval checks to be recorded and 

quantified. The optical surfaces exposed 

to the effluent gases must be cleaned 

prior to performing the zero and span 

drift adjustments, except for systems 

using automatic zero adjustments. For 

systems using automatic zero 

adjustments, the optical surfaces must 

be cleaned when the cumulative 

automatic zero compensation exceeds 4 

percent opacity. 

(iii) The owner or operator must apply 

a method for producing a simulated zero 

opacity condition and an upscale (span) 

opacity condition using a certified 

neutral density filter or other related 

technique to produce a known 

obscuration of the light beam. All 

procedures applied must provide a 

system check of the analyzer internal 

optical surfaces and all electronic 

circuitry including the lamp and 

photodetector assembly. 

(iv) Except during periods of system 

breakdowns, repairs, calibration checks, 

and zero and span adjustments, the 

COMS must be in continuous operation 

and must complete a minimum of one 

cycle of sampling and analyzing for 

each successive 10-second period and 

one cycle of data recording for each 

successive 6-minute period. 


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(v) The owner or operator must 

reduce all data from the COMS to 6- 

minute averages. Six-minute opacity 

averages must be calculated from 36 or 

more data points equally spaced over 

each 6-minute period. Data recorded 

during periods of system breakdowns, 

repairs, calibration checks, and zero and 

span adjustments must not be included 

in the data averages. An arithmetic or 

integrated average of all data may be 

used. 

§ 60.256 Continuous monitoring 

requirements. 

(a) The owner or operator of each 

affected facility constructed, 

reconstructed, or modified on or before 

April 28, 2008, must meet the 

monitoring requirements specified in 

paragraphs (a)(1) and (2) of this section, 

as applicable to the affected facility. 

(1) The owner or operator of any 

thermal dryer shall install, calibrate, 

maintain, and continuously operate 

monitoring devices as follows: 

(i) A monitoring device for the 

measurement of the temperature of the 

gas stream at the exit of the thermal 

dryer on a continuous basis. The 

monitoring device is to be certified by 

the manufacturer to be accurate within 

±1.7 °C (±3 °F). 

(ii) For affected facilities that use wet 

scrubber emission control equipment: 

(A) A monitoring device for the 

continuous measurement of the pressure 

loss through the venturi constriction of 

the control equipment. The monitoring 

device is to be certified by the 

manufacturer to be accurate within 

±1 inch water gauge. 

(B) A monitoring device for the 

continuous measurement of the water 

supply pressure to the control 

equipment. The monitoring device is to 

be certified by the manufacturer to be 

accurate within ±5 percent of design 

water supply pressure. The pressure 

sensor or tap must be located close to 

the water discharge point. The 

Administrator shall have discretion to 

grant requests for approval of alternative 

monitoring locations. 

(2) All monitoring devices under 

paragraph (a) of this section are to be 

recalibrated annually in accordance 

with procedures under § 60.13(b). 

(b) The owner or operator of each 

affected facility constructed, 

reconstructed, or modified after April 

28, 2008, that has one or more 

mechanical vents must install, calibrate, 

maintain, and continuously operate the 

monitoring devices specified in 

paragraphs (b)(1) and (2) of this section, 

as applicable to the mechanical vent 

and any control device installed on the 

vent. 

(1) For mechanical vents with fabric 

filters (baghouses) with the design 

controlled potential PM emissions rate 

of 25 Mg (28 tons) per year or more, a 

bag leak detection system according to 

the requirements in paragraph (c) of this 

section. 

(2) For mechanical vents with wet 

scrubbers, monitoring devices according 

to the requirements in paragraphs 

(b)(2)(i) and (ii) of this section. 

(i) A monitoring device for the 

continuous measurement of the pressure 

loss through the venturi constriction of 

the control equipment. The monitoring 

device is to be certified by the 

manufacturer to be accurate within 

±1 inch water gauge. 

(ii) A monitoring device for the 

continuous measurement of the water 

supply pressure to the control 

equipment. The monitoring device is to 

be certified by the manufacturer to be 

accurate within ±5 percent of design 

water supply pressure. The pressure 

sensor or tap must be located close to 

the water discharge point. 

(c) Each bag leak detection system 

used to comply with provisions of this 

subpart must be installed, calibrated, 

maintained, and continuously operated 

according to the requirements in 

paragraphs (c)(1) through (3) of this 

section. 

(1) The bag leak detection system 

must meet the specifications and 

requirements in paragraphs (c)(1)(i) 

through (viii) of this section. 

(i) The bag leak detection system must 

be certified by the manufacturer to be 

capable of detecting PM emissions at 

concentrations of 1 milligram per dry 

standard cubic meter (mg/dscm) 

(0.00044 grains per actual cubic foot 

(gr/acf)) or less. 

(ii) The bag leak detection system 

sensor must provide output of relative 

PM loadings. The owner or operator 

shall continuously record the output 

from the bag leak detection system using 

electronic or other means (e.g., using a 

strip chart recorder or a data logger). 

(iii) The bag leak detection system 

must be equipped with an alarm system 

that will sound when the system detects 

an increase in relative particulate 

loading over the alarm set point 

established according to paragraph 

(c)(1)(iv) of this section, and the alarm 

must be located such that it can be 

heard by the appropriate plant 

personnel. 

(iv) In the initial adjustment of the bag 

leak detection system, the owner or 

operator must establish, at a minimum, 

the baseline output by adjusting the 

sensitivity (range) and the averaging 

period of the device, the alarm set 

points, and the alarm delay time. 

(v) Following initial adjustment, the 

owner or operator must not adjust the 

averaging period, alarm set point, or 

alarm delay time without approval from 

the Administrator or permitting 

authority except as provided in 

paragraph (c)(2)(vi) of this section. 

(vi) Once per quarter, the owner or 

operator may adjust the sensitivity of 

the bag leak detection system to account 

for seasonal effects, including 

temperature and humidity, according to 

the procedures identified in the sitespecific monitoring plan required by 

paragraph (c)(2) of this section. 

(vii) The owner or operator must 

install the bag leak detection sensor 

downstream of the fabric filter. 

(viii) Where multiple detectors are 

required, the system’s instrumentation 

and alarm may be shared among 

detectors. 

(2) The owner or operator must 

develop and submit to the permitting 

authority for approval a site-specific 

monitoring plan for each bag leak 

detection system. This plan must be 

submitted to the permitting authority 90 

days prior to the compliance date for the 

affected facility. The owner or operator 

must operate and maintain the bag leak 

detection system according to the sitespecific monitoring plan at all times. 

Each monitoring plan must describe the 

items in paragraphs (c)(2)(i) through (vi) 

of this section. 

(i) Installation of the bag leak 

detection system; 

(ii) Initial and periodic adjustment of 

the bag leak detection system, including 

how the alarm set-point will be 

established; 

(iii) Operation of the bag leak 

detection system, including quality 

assurance procedures; 

(iv) How the bag leak detection 

system will be maintained, including a 

routine maintenance schedule and spare 

parts inventory list; 

(v) How the bag leak detection system 

output will be recorded and stored; and 

(vi) Corrective action procedures as 

specified in paragraph (c)(3) of this 

section. In approving the site-specific 

monitoring plan, the Administrator or 

permitting authority may allow the 

owner and operator more than 3 hours 

to alleviate a specific condition that 

causes an alarm if the owner or operator 

identifies in the monitoring plan this 

specific condition as one that could lead 

to an alarm, adequately explains why it 

is not feasible to alleviate this condition 

within 3 hours of the time the alarm 

occurs, and demonstrates that the 

requested time will ensure alleviation of 

this condition as expeditiously as 

practicable. 


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(3) For each bag leak detection 

system, the owner or operator must 

initiate procedures to determine the 

cause of every alarm within 1 hour of 

the alarm. Except as provided in 

paragraph (c)(2)(vi) of this section, the 

owner or operator must alleviate the 

cause of the alarm within 3 hours of the 

alarm by taking whatever corrective 

action(s) are necessary. Corrective 

actions may include, but are not limited 

to the following: 

(i) Inspecting the fabric filter for air 

leaks, torn or broken bags or filter 

media, or any other condition that may 

cause an increase in PM emissions; 

(ii) Sealing off defective bags or filter 

media; 

(iii) Replacing defective bags or filter 

media or otherwise repairing the control 

device; 

(iv) Sealing off a defective fabric filter 

compartment; 

(v) Cleaning the bag leak detection 

system probe or otherwise repairing the 

bag leak detection system; or 

(vi) Shutting down the process 

producing the PM emissions. 

§ 60.257 Test methods and procedures. 

(a) The owner or operator must 

determine compliance with the 

applicable opacity standards as 

specified in paragraphs (a)(1) through 

(4) of this section. 

(1) Method 9 of appendix A–4 of this 

part and the procedures in § 60.11 must 

be used to determine opacity. 

(2) To determine opacity for fugitive 

emissions sources, the additional 

requirements specified in paragraphs 

(a)(2)(i) through (iii) of this section must 

be used. 

(i) The minimum distance between 

the observer and the emission source 

shall be 5.0 meters (16 feet), and the sun 

shall be oriented in the 140-degree 

sector of the back. 

(ii) The observer shall select a 

position that minimizes interference 

from other fugitive emissions sources 

and make observations such that the 

line of vision is approximately 

perpendicular to the plume and wind 

direction. 

(iii) The observer shall make opacity 

observations at the point of greatest 

opacity in that portion of the plume 

where condensed water vapor is not 

present. Water vapor is not considered 

a visible emission. 

(3) If during the initial 60 minutes of 

the observation of a Method 9 of 

appendix A–4 of this part performance 

test all of the individual 15-second 

observations are less than or equal to 20 

percent and all of the resulting 6-minute 

averages are less than or equal to 3 

percent or half the applicable limit, 

whichever is greater, then the 

observation period may be reduced from 

3 hours to 60 minutes. 

(4) A visible emissions observer may 

conduct visible emission observations 

for up to three fugitive, stack, or vent 

emission points within a 15-second 

interval if the following conditions 

specified in paragraphs (a)(4)(i) through 

(iii) of this section are met. 

(i) No more than three emissions 

points may be read concurrently. 

(ii) All three emissions points must be 

within a 70-degree viewing sector or 

angle in front of the observer such that 

the proper sun position can be 

maintained for all three points. 

(iii) If an opacity reading for any one 

of the three emissions points is within 

5 percent opacity from the applicable 

standard (excluding readings of zero 

opacity), then the observer must stop 

taking readings for the other two points 

and continue reading just that single 

point. 

(b) The owner or operator must 

conduct all performance tests required 

by § 60.8 to demonstrate compliance 

with the applicable emissions standards 

specified in § 60.252 according to the 

requirements in § 60.8 using the 

applicable test methods and procedures 

in paragraphs (b)(1) through (8) of this 

section. 

(1) Method 1 or 1A of appendix A–4 

of this part shall be used to select 

sampling port locations and the number 

of traverse points in each stack or duct. 

Sampling sites must be located at the 

outlet of the control device (or at the 

outlet of the emissions source if no 

control device is present) prior to any 

releases to the atmosphere. 

(2) Method 2, 2A, 2C, 2D, 2F, or 2G 

of appendix A–4 of this part shall be 

used to determine the volumetric flow 

rate of the stack gas. 

(3) Method 3, 3A, or 3B of appendix 

A–4 of this part shall be used to 

determine the dry molecular weight of 

the stack gas. The owner or operator 

may use ANSI/ASME PTC 19.10–1981, 

‘‘Flue and Exhaust Gas Analyses’’ 

(incorporated by reference—see § 60.17) 

as an alternative to EPA Method 3B of 

appendix A–2 of this part. 

(4) Method 4 of appendix A–4 of this 

part shall be used to determine the 

moisture content of the stack gas. 

(5) Method 5, 5B or 5D of appendix 

A–4 of this part or Method 17 of 

appendix A–7 of this part shall be used 

to determine the PM concentration as 

follows: 

(i) The sampling time and sample 

volume for each run shall be at least 60 

minutes and 0.85 dscm (30 dscf). 

Sampling shall begin no less than 30 

minutes after startup and shall 

terminate before shutdown procedures 

begin. A minimum of three valid test 

runs are needed to comprise a PM 

performance test. 

(ii) Method 5 of appendix A of this 

part shall be used only to test emissions 

from affected facilities without wet flue 

gas desulfurization (FGD) systems. 

(iii) Method 5B of appendix A of this 

part is to be used only after wet FGD 

systems. 

(iv) Method 5D of appendix A–4 of 

this part shall be used for positive 

pressure fabric filters and other similar 

applications (e.g., stub stacks and roof 

vents). 

(v) Method 17 of appendix A–6 of this 

part may be used at facilities with or 

without wet scrubber systems provided 

the stack gas temperature does not 

exceed a temperature of 160 °C (320 °F). 

The procedures of sections 8.1 and 11.1 

of Method 5B of appendix A–3 of this 

part may be used in Method 17 of 

appendix A–6 of this part only if it is 

used after a wet FGD system. Do not use 

Method 17 of appendix A–6 of this part 

after wet FGD systems if the effluent is 

saturated or laden with water droplets. 

(6) Method 6, 6A, or 6C of appendix 

A–4 of this part shall be used to 

determine the SO2 concentration. A 

minimum of three valid test runs are 

needed to comprise an SO2 performance 

test. 

(7) Method 7 or 7E of appendix A–4 

of this part shall be used to determine 

the NOX concentration. A minimum of 

three valid test runs are needed to 

comprise an NOX performance test. 

(8) Method 10 of appendix A–4 of this 

part shall be used to determine the CO 

concentration. A minimum of three 

valid test runs are needed to comprise 

a CO performance test. CO performance 

tests are conducted concurrently (or 

within a 30- to 60-minute period) with 

NOX performance tests. 

§ 60.258 Reporting and recordkeeping. 

(a) The owner or operator of a coal 

preparation and processing plant that 

commenced construction, 

reconstruction, or modification after 

April 28, 2008, shall maintain in a 

logbook (written or electronic) on-site 

and make it available upon request. The 

logbook shall record the following: 

(1) The manufacturer’s recommended 

maintenance procedures and the date 

and time of any maintenance and 

inspection activities and the results of 

those activities. Any variance from 

manufacturer recommendation, if any, 

shall be noted. 

(2) The date and time of periodic coal 

preparation and processing plant 

opacity observations noting those 

sources with emissions above the action 


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Federal Register / Vol. 74, No. 100 / Wednesday, May 27, 2009 / Proposed Rules 25327 

level (visible emissions in excess of 5 

percent of the observation period) along 

with corrective actions taken to reduce 

visible emissions. Results from the 

actions shall be noted. 

(3) The amount and type of coal 

processed each calendar month. 

(4) The amount of chemical stabilizer 

or water purchased for use in the coal 

preparation and processing plant. 

(5) Monthly certification that the dust 

suppressant systems were operational 

when any coal was processed and that 

manufacturer’s recommendations were 

followed for all control systems. Any 

variance from the manufacturer’s 

recommendations, if any, shall be noted. 

(6) A copy of any applicable fugitive 

dust emissions control plan and 

monthly certification that the plan was 

implemented as described. Any 

variance from plan, if any, shall be 

noted. 

(7) For each bag leak detection 

system, the owner or operator must keep 

the records specified in paragraphs 

(a)(7)(i) through (iii) of this section. 

(i) Records of the bag leak detection 

system output; 

(ii) Records of bag leak detection 

system adjustments, including the date 

and time of the adjustment, the initial 

bag leak detection system settings, and 

the final bag leak detection settings; and 

(iii) The date and time of all bag leak 

detection system alarms, the time that 

procedures to determine the cause of the 

alarm were initiated, the cause of the 

alarm, an explanation of the actions 

taken, the date and time the cause of the 

alarm was alleviated, and whether the 

cause of the alarm was alleviated within 

3 hours of the alarm. 

(8) A copy of any applicable 

monitoring plan for a digital opacity 

compliance system and monthly 

certification that the plan was 

implemented as described. Any 

variance from plan, if any, shall be 

noted. 

(9) During a performance test of a wet 

scrubber, and each operating day 

thereafter, the owner or operator shall 

record the measurements of both the 

scrubber pressure loss and water supply 

pressure. 

(b) For the purpose of reports required 

under § 60.7(c), any owner/operator 

subject to the provisions of this subpart 

shall report semiannually periods of 

excess emissions as follows: 

(1) The owner or operator of an 

affected facility with a wet scrubber 

shall submit semiannual reports to the 

Administrator of occurrences when the 

measurements of the scrubber pressure 

loss and water supply pressure decrease 

by more than 10 percent from the 

average determined during the most 

recent performance test. 

(2) All 6-minute average opacities that 

exceed the applicable standard. 

(c) The owner or operator of an 

affected facility shall submit the results 

of initial performance tests to the 

Administrator, consistent with the 

provisions of § 60.8. The owner or 

operator who elects to comply with the 

reduced performance testing provisions 

of §§ 60.255(c) or (d) shall include in the 

performance test report identification of 

each affected facility that will be subject 

to the reduced testing, and the design 

emissions limit of each associated 

control device. The owner or operator 

electing to comply with § 60.255(d) 

shall also include information which 

demonstrates that the control devices 

are identical. 

(d) After July 1, 2011, within 60 days 

after the date of completing each 

performance evaluation conducted to 

demonstrate compliance with this 

subpart, the owner or operator of the 

affected facility must submit the test 

data to EPA by successfully entering the 

data electronically into EPA’s WebFIRE 

data base available at http:// 

cfpub.epa.gov/oarweb/ 

index.cfm?action=fire.main. For 

performance tests that cannot be entered 

into WebFIRE (i.e., Method 9 of 

appendix A–4 of this part opacity 

performance tests) the owner or operator 

of the affected facility must mail a 

summary copy to United States 

Environmental Protection Agency, 

Energy Strategies Group, 109 TW 

Alexander DR, mail code: D243–01, 

RTP, NC 27711. 

[FR Doc. E9–11912 Filed 5–26–09; 8:45 am] 

BILLING CODE 6560–50–P 


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