51950 Federal Register / Vol. 74, No. 194 / Thursday, October 8, 2009 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2008–0260; FRL–8965–3] 

RIN 2060–AO57 

Standards of Performance for Coal 

Preparation and Processing Plants 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is promulgating 

amendments to the new source 

performance standards for coal 

preparation and processing plants. 

These final amendments include 

revisions to the emission limits for 

particulate matter and opacity standards 

for thermal dryers, pneumatic coal 

cleaning equipment, and coal handling 

equipment (coal processing and 

conveying equipment, coal storage 

systems, and coal transfer and loading 

systems) located at coal preparation and 

processing plants. These revised limits 

apply to affected facilities that 

commence construction, modification, 

or reconstruction after April 28, 2008. 

The amendments also establish a sulfur 

dioxide (SO2) emission limit and a 

combined nitrogen oxide (NOX) and 

carbon monoxide (CO) emissions limit 

for thermal dryers located at coal 

preparation and processing plants. In 

addition, the amendments establish 

work practice standards to control 

fugitive coal dust emissions from open 

storage piles located at coal preparation 

and processing plants. The SO2 limit, 

the NOX/CO limit, and the work 

practice standards apply to affected 

facilities that commence construction, 

modification, or reconstruction of which 

commences after May 27, 2009. We are 

also modifying the definition of thermal 

dryer to include both direct contact and 

indirect contact thermal dryers drying 

all coal ranks. We are modifying the 

definition of pneumatic coal-cleaning 

equipment to include equipment 

cleaning all coal ranks. We are also 

amending the definition of coal for 

purposes of subpart Y to include coal 

refuse. The modified definitions of 

thermal dryer, pneumatic coal cleaning 

equipment, and coal will be used to 

determine whether and how the 

standards apply to facilities that 

commence construction, modification, 

or reconstruction after May 27, 2009. 

DATES: This final rule is effective on 

October 8, 2009. The incorporation by 

reference of certain publications listed 

in the regulation is approved by the 

Director of the Federal Register as of 

October 8, 2009. 

ADDRESSES: EPA has established a 

docket for this action which is Docket 

ID No. EPA–HQ–OAR–2008–0260. All 

documents in the docket are listed in 

the http://www.regulations.gov index. 

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 EPA Docket Center, Standards of 

Performance for Coal Preparation and 

Processing Plants Docket, 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 Docket Center 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: The 

supplementary information presented in 

this preamble is organized as follows: 

I. General Information 

A. Does This Action Apply to Me? 

B. Where Can I Get a Copy of This 

Document? 

C. Judicial Review 

II. Background Information on Subpart Y 

III. Summary of the Final Amendments to 

Subpart Y and Changes Since Proposal 

A. Affected Facilities 

B. Emission Limits 

C. Emissions Testing and Monitoring 

Requirements 

D. Opacity Testing and Monitoring 

Requirements 

E. Recordkeeping and Reporting 

Requirements 

F. Electronic Reporting 

G. Additional Amendments 

IV. Summary of Significant Comments and 

Responses 

A. Regulated Pollutants 

B. Applicability and Definitions 

C. Subcategorization 

D. Coal Drying Standards 

E. Coal Processing and Conveying 

Equipment, Coal Storage Systems, 

Transfer and Loading Systems, and Open 

Storage Piles Standards 

F. Testing and Monitoring Requirements 

G. Recordkeeping and Reporting 

Requirements 

H. Assessment of Impacts 

V. Summary of Cost, Environmental, Energy, 

and Economic Impacts 

A. What Are the Primary Air Impacts? 

B. What Are the Water and Solid Waste 

Impacts? 

C. What Are the Energy Impacts? 

D. What Are the Secondary Air Impacts? 

E. What Are the Cost and Economic 

Impacts? 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork 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 

K. Congressional Review Act 

I. General Information 

A. Does This Action Apply to Me? 

Categories and entities potentially 

regulated by the final amendments to 

New Source Performance Standards 

(NSPS) for Coal Preparation and 

Processing Plants (40 CFR part 60, 

subpart Y) include: 

Category NAICS code 1 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. 

322121 ........................................... Paper (except Newsprint) Mills. 

324199 ........................................... All other petroleum and coal products manufacturing. 

325110 ........................................... Petrochemical Manufacturing. 


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Federal Register / Vol. 74, No. 194 / Thursday, October 8, 2009 / Rules and Regulations 51951 

Category NAICS code 1 Examples of regulated entities 

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

921150 ........................................... Fossil fuel-fired electric steam generating units in Indian Country. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by this final action. To 

determine whether your facility would 

be regulated by this final action, you 

should examine the applicability 

criteria in 40 CFR 60.250 and 

definitions in § 60.251 (subpart Y). If 

you have any questions regarding the 

applicability of this final action to a 

particular entity, contact the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 

B. Where Can I Get a Copy of This 

Document? 

In addition to being available in the 

docket, an electronic copy of this final 

action is available on the Worldwide 

Web (WWW) through the Technology 

Transfer Network (TTN). Following 

signature, a copy of this final action will 

be posted on the TTN’s 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. 

C. Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act (CAA), judicial review of this 

final rule is available only by filing a 

petition for review in the United States 

Court of Appeals for the District of 

Columbia Circuit by December 7, 2009. 

Under section 307(b)(2) of the CAA, the 

requirements established by this final 

rule may not be challenged separately in 

any civil or criminal proceedings 

brought by EPA to enforce these 

requirements. 

Section 307(d)(7)(B) of the CAA 

further provides that ‘‘[o]nly an 

objection to a rule or procedure which 

was raised with reasonable specificity 

during the period for public comment 

(including any public hearing) may be 

raised during judicial review.’’ This 

section also provides a mechanism for 

us to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, U.S. EPA, Room 3000, 

Ariel Rios Building, 1200 Pennsylvania 

Ave., NW., Washington, DC 20460, with 

a copy to both the person(s) listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), U.S. EPA, 

1200 Pennsylvania Ave., NW., 

Washington, DC 20460. 

II. Background Information on 

Subpart Y 

NSPS implement CAA section 111(b) 

and are issued for categories of sources 

which have been identified as causing, 

or contributing significantly to, air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare. The primary purpose of the 

NSPS are to help States attain and 

maintain ambient air quality by 

ensuring that the best demonstrated 

emission control technologies are 

installed as the industrial infrastructure 

is modernized. Since 1970, the NSPS 

have been successful in achieving longterm emissions reductions in numerous 

industries by assuring cost-effective 

controls are installed on new, 

reconstructed, and modified sources. 

CAA section 111 requires that the 

NSPS reflect the degree of emission 

limitation achievable through 

application of the best system of 

emissions reductions which (taking into 

consideration the cost of achieving such 

emissions reductions, any non-air 

quality health and environmental 

impact and energy requirements) the 

Administrator determines has been 

adequately demonstrated. This level of 

control is commonly referred to as best 

demonstrated technology (BDT). 

Standards of performance for coal 

preparation plants (40 CFR part 60, 

subpart Y) were promulgated in the 

Federal Register on January 15, 1976 

(41 FR 2232). The standards are 

applicable to facilities which process 

more than 181 megagrams (Mg) (200 

tons) of coal per day that commenced 

construction, reconstruction, or 

modification after October 24, 1974. 

CAA section 111(b)(1)(B) requires 

EPA to periodically review and revise 

the standards of performance, as 

necessary, to reflect improvements in 

methods for reducing emissions. The 

first review of the coal preparation 

plants NSPS was completed on April 

14, 1981 (46 FR 21769). The second 

review of the coal preparation plants 

NSPS was completed on April 3, 1989 

(54 FR 13384). EPA did not make 

changes to the NSPS as a result of either 

review. 

We proposed amendments to the coal 

preparation plants NSPS on April 28, 

2008 (73 FR 22901) as a result of the 

current review. We received a total of 42 

comments from coal preparation plants, 

industry trade associations, control 

technology vendors, environmental 

groups, and State environmental 

agencies during the comment period. 

After reviewing those comments and 

considering additional data, EPA 

decided to publish a supplemental 

proposal which revised some of the 

emission limits and monitoring 

requirements proposed on April 28, 

2008, added additional limits, and 

applied the requirements to additional 

affected facilities. The supplemental 

action was proposed on May 27, 2009 

(74 FR 25304). A total of 44 comments 

were received from coal preparation 

plants, other types of industrial 

facilities, industry associations, 

environmental groups, and State 

environmental agencies. This final rule 

reflects our consideration of all the 

comments we received regarding the 

April 2008 and May 2009 proposals. 

Detailed responses to the comments not 

included in this preamble are contained 

in the Summary of Public Comments 

and Responses document which is 

included in the docket for this 

rulemaking. 


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III. Summary of the Final Amendments 

to Subpart Y and Changes Since 

Proposal 

A. Affected Facilities 

Subpart Y regulates affected facilities 

located at coal preparation and 

processing plants which process more 

than 181 megagrams (Mg) (200 tons) of 

coal per day. A coal preparation and 

processing plant begins at the first 

hopper (i.e., drop point) used to unload 

coal and ends at the load-out (i.e., 

distribution) of the coal either to a 

method of transportation (e.g., truck, 

train) or to the end-use piece of 

equipment (e.g., boiler). 

The affected facilities regulated by 

this final rule are thermal dryers, 

pneumatic coal-cleaning equipment, 

coal processing and conveying 

equipment (including breakers and 

crushers), coal storage systems, transfer 

and loading systems, and open storage 

piles. This final rule expands 

applicability of the existing NSPS by 

revising the definitions of thermal 

dryers, pneumatic coal-cleaning 

equipment, and coal. It also establishes 

work practice standards for open storage 

piles. The final rule amends the 

definition of thermal dryer for units 

constructed, reconstructed, or modified 

after May 27, 2009, to include both 

direct and indirect dryers drying all coal 

ranks (i.e., bituminous, subbituminous, 

lignite, and anthracite coals) and coal 

refuse. The final rule regulates 

emissions of SO2 and NOX/CO only 

from thermal dryers that receive thermal 

input from the combustion of coal, coal 

refuse, or residual oil; PM and opacity 

are regulated from all thermal dryers. 

The emissions standards for thermal 

dryers apply to emissions from the heat 

source for an indirect thermal dryer 

only if those emissions are not 

otherwise regulated under another 

NSPS. Indirect thermal dryers use a heat 

transfer medium to supply heat and 

blow air over the coal to evaporate the 

water. If the source of heat (the source 

of combustion or furnace) is subject to 

another subpart of Part 60, then the 

furnace and the associated emissions are 

not considered part of the subpart Y 

affected facility (i.e., the thermal dryer). 

However, if the source of heat is not 

subject to another subpart of Part 60, 

then the furnace and the associated 

emissions are part of the subpart Y 

affected facility. In situations where the 

source of heat is part of the affected 

facility and its exhaust is combined 

with the dryer exhaust in a single stack, 

the combined exhaust is subject to all 

subpart Y requirements applicable to 

the thermal dryer exhaust. However, in 

situations where the furnace is part of 

the affected facility and its exhaust is 

not combined with the dryer exhaust, 

the subpart Y requirements for thermal 

dryers apply differently to the dryer 

exhaust and the combustion (i.e., heat 

source or furnace) exhaust. All of the 

thermal dryer requirements of subpart Y 

apply to the combustion exhaust, 

whereas, only a subset of the subpart Y 

requirements for thermal dryers apply to 

the dryer exhaust. In addition, thermal 

dryers that use residual or waste heat 

from the combustion of coal, coal refuse, 

or residual oil, or that obtain all of their 

thermal input from gaseous fuels (e.g., 

blast furnace gas, coke oven gas, natural 

gas) or distillate oil also are only be 

subject to certain subset of the subpart 

Y requirements for thermal dryers. 

Further, a thermal dryer that is part of 

an in-line coal mill at a Portland cement 

manufacturing plant where all of the 

thermal input is supplied by cement 

kiln exhaust or clinker cooler exhaust, 

is not subject to the requirements in 

subpart Y, but, rather, must meet the 

applicable requirements in the 

appropriate Portland Cement kiln 

regulations (40 CFR 60 subpart F and 40 

CFR 63 subpart LLL). The amended 

subpart Y emissions limits for thermal 

dryers apply to new, reconstructed, or 

modified thermal dryers at Portland 

cement manufacturing plants in 

situations where the thermal input is 

not supplied by cement kiln or clinker 

cooler exhaust. Other subpart Y affected 

facilities located at Portland cement 

manufacturing plants (e.g., storage 

systems, conveyors) are also subject to 

the requirements of subpart Y. 

Similarly, a coal thermal dryer at an 

integrated iron or steel manufacturing 

plant where all of the thermal input is 

provided by process gases is not 

regulated under subpart Y, but, rather, 

under 40 CFR part 60 standards for 

integrated iron and steel manufacturing 

plants. Again, the amended emissions 

limits apply to new, reconstructed, or 

modified thermal dryers at integrated 

iron and steel manufacturing plants 

only in situations where the thermal 

input is not supplied by process gases. 

Other subpart Y affected facilities 

located at integrated iron and steel 

manufacturing plants also are subject to 

subpart Y. If an affected facility under 

subpart Y uses waste-heat or process 

gases from a process that is subject to 

emission limits under another NSPS or 

national emission standard for 

hazardous air pollutant (NESHAP), the 

process using the waste-heat or process 

gases is not subject to requirements 

under subpart Y, but, rather, is subject 

to the other applicable NSPS or 

NESHAP. 

This final rule also amends the 

definition of pneumatic coal-cleaning 

equipment for units constructed after 

May 27, 2009, to include pneumatic 

coal-cleaning equipment cleaning all 

coal ranks. Finally, the final rule 

establishes work practice standards that 

apply to open storage coal piles 

constructed, reconstructed or modified 

after May 27, 2009. 

B. Emission Limits 

This action promulgates emission 

limits applicable to certain thermal 

dryers constructed, reconstructed, or 

modified after April 28, 2008. It also 

promulgates emission limits for 

additional pollutants applicable to 

certain thermal dryers constructed, 

reconstructed, or modified after May 27, 

2009. 

Direct-contact thermal dryers that use 

coal, coal refuse, or residual oil as the 

dryer heat source and are constructed, 

reconstructed, or modified after April 

28, 2008, are subject to emission limits 

for PM and opacity. Indirect thermal 

dryers constructed, reconstructed, or 

modified after May 27, 2009, are subject 

to the same PM and opacity limits as 

direct-contact thermal dryers. Both 

direct-contact thermal dryers and 

indirect thermal dryers constructed, 

reconstructed, or modified after May 27, 

2009, are subject to an SO2 emission 

limit and a combined NOX–CO 

emissions limit. In certain instances, 

thermal dryers are not subject to the SO2

and/or NOX–CO emission limits. 

Thermal dryers constructed, 

reconstructed or modified after May 27, 

2009, for which all of the thermal input 

is supplied from a source other than 

coal, coal refuse, or residual oil (i.e., 

thermal input is from gaseous fuels such 

as blast furnace gas, coke oven gas, or 

natural gas, or distillate oil) are not 

subject to SO2 or NOX–CO emission 

limits. Indirect thermal dryers 

constructed, reconstructed, or modified 

after May 27, 2009, that use residual or 

waste heat from the combustion of coal, 

coal refuse, or residual oil also are not 

subject to the emission limits for SO2 or 

NOX–CO. 

Indirect thermal dryers that receive all 

of their thermal input from a source 

subject to an SO2 limit, or NOX and/or 

CO limit, under another Part 60 NSPS 

are not subject to emission limits under 

subpart Y for those pollutants (e.g., 

indirect thermal dryers for which the 

source of heat is subject to a boiler 

NSPS (subpart Da, Db, or Dc)). In that 

instance, the furnace (i.e., source of 

thermal input) and the associated 

emissions are not considered part of the 

subpart Y thermal dryer facility. 

However, if the source of heat is not 


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Federal Register / Vol. 74, No. 194 / Thursday, October 8, 2009 / Rules and Regulations 51953 

subject to another Part 60 NSPS, then 

the furnace and the associated 

emissions are part of the subpart Y 

thermal dryer facility. In the instance 

where the furnace is part of the affected 

facility and its exhaust is combined 

with the thermal dryer exhaust, the 

combined exhaust contains all of the 

applicable pollutants (i.e., PM, opacity, 

SO2, NOX, and CO) and all of the 

subpart Y requirements regarding those 

emissions from thermal dryers apply. 

However, in the instance where the 

furnace is part of the affected facility, 

but its exhaust is not combined with the 

dryer exhaust, the furnace exhaust and 

dryer exhaust are subject to different 

requirements. The furnace exhaust is 

subject to emission limits for PM, 

opacity, SO2, and NOX–CO. The dryer 

exhaust, however, is only subject to the 

PM and opacity limits because the 

exhaust does not contain SO2, NO, and 

CO. 

1. PM and Opacity Limits for Thermal 

Dryers 

Thermal dryers constructed, 

reconstructed, or modified after April 

28, 2008, are subject to emission limits 

for PM and opacity. The PM and opacity 

limits in the final rule for new thermal 

dryers are the same as those proposed 

in May 2009. EPA determined that 

thermal dryers undergoing 

reconstruction could undergo the 

conversions necessary to also comply 

with the PM and opacity limits that 

reflect BDT for new thermal dryers (i.e., 

fabric filter-controlled recirculation 

thermal dryers and fabric filtercontrolled indirect thermal dryers). 

Thus, the final rule subjects new and 

reconstructed thermal dryers to a PM 

limit of 0.023 grams per dry standard 

cubic meter (g/dscm)(0.010 grains per 

dry standard cubic foot (gr/dscf)) and an 

opacity limit of less than 10 percent. 

The final rule requires modified thermal 

dryers to continue to comply with the 

1976 rule’s PM limit of 0.070 g/dscm 

(0.031 gr/dscf) and the 1976 rule’s 

opacity limit of less than 20 percent. 

These limits can be achieved using the 

technology that EPA determined 

constitutes BDT for modified thermal 

dryers (i.e., venturi scrubbers). 

2. SO2, NOX, and CO Limits for Thermal 

Dryers 

Thermal dryers constructed, 

reconstructed, or modified after May 27, 

2009, must either limit their SO2

emissions to 85 nanograms per Joule 

(ng/J) (0.20 pounds per million British 

thermal units (lb/MMBtu)), or achieve a 

90 percent reduction of potential SO2

emissions and limit their SO2 emissions 

to no more than 520 ng/J (1.2 lb/ 

MMBtu). The percent reduction 

requirement has been revised from the 

50 percent requirement proposed in 

May 2009 to 90 percent in the final rule. 

In the May 27, 2009, supplemental 

proposal, EPA concluded that dry 

sorbent injection into the thermal dryer 

and spraying caustic onto the coal prior 

to the thermal dryer were both BDT for 

SO2 reduction (74 FR 25310). We also 

indicated that we were considering an 

SO2 percent reduction requirement of 

between 50 and 90 percent for the final 

rule (74 FR 25311). We have reassessed 

the available SO2 data and believe that 

the limits established in the final rule 

are appropriate for new, reconstructed, 

and modified thermal dryers. Based on 

our reassessment, we determined that 

BDT for modified and reconstructed 

thermal dryers is a wet scrubber with a 

scrubbing reagent (e.g., an upgraded 

venturi scrubber with sodium hydroxide 

or packed bed scrubber with lime). For 

new thermal dryers, we determined that 

BDT for controlling SO2 emissions is the 

injection of sodium hydroxide directly 

to the venturi scrubber fluid or injection 

of a sodium-based sorbent into the 

combustion gases prior to the drying 

chamber. All three of these technologies 

are capable of achieving 90 percent SO2

reduction. 

In the May 27, 2009, supplemental 

proposal, EPA determined that BDT for 

controlling NOX emissions from new, 

reconstructed, and modified thermal 

dryers is combustion controls (e.g., low 

NOX burners, staged combustion, cofiring with natural gas or liquefied 

petroleum gas, and flue gas 

recirculation). BDT for controlling CO 

emissions was determined to be good 

combustion practices (e.g., ensuring that 

there is sufficient oxygen in the 

combustion zone, maintaining 

appropriate combustion zone 

temperature and gas residence time, and 

conducting proper operation and 

maintenance of the dryer). For affected 

thermal dryers that commence 

construction, reconstruction, or 

modification after May 27, 2009, the 

final NOX–CO emissions limits are the 

same as those proposed in May 2009. 

Reconstructed and modified thermal 

dryers are required to comply with a 

combined NOX–CO limit of 430 ng/J (1.0 

lb/MMBtu). New thermal dryers are 

required to comply with a NOX–CO 

limit of 280 ng/J (0.65 lb/MMBtu). 

3. PM and Opacity Limits for Pneumatic 

Coal-Cleaning Equipment, Coal 

Processing and Conveying Equipment, 

Coal Storage Systems, Transfer and 

Loading Systems, and Open Storage 

Piles 

The PM and opacity limits in the final 

rule for pneumatic coal-cleaning 

equipment are the same as those 

proposed in the May 2009 supplemental 

proposal. Pneumatic coal-cleaning 

equipment, cleaning all coal ranks, 

constructed, reconstructed, or modified 

after April 28, 2008, must comply with 

a PM limit of 0.023 g/dscm (0.010 gr/ 

dscf) and an opacity limit of equal to or 

less than 5 percent. 

For affected coal-handling equipment 

(coal processing and conveying 

equipment (including breakers and 

crushers), coal storage systems, and 

transfer and loading systems) 

constructed, reconstructed, or modified 

after April 28, 2008, that is 

mechanically vented to the atmosphere, 

the final rule requires compliance with 

the PM limit that was proposed in May 

2009. That is, mechanically vented coalhandling equipment constructed, 

reconstructed, or modified after April 

28, 2008, must comply with a PM limit 

of 0.023 g/dscm (0.010 gr/dscf). The 

final rule also requires affected coal 

handling equipment constructed, 

reconstructed, or modified after April 

28, 2008, to maintain opacity levels of 

less than 10 percent. In the May 27, 

2009, supplemental proposal, EPA 

requested comment on whether an 

opacity limit of less than 10 percent is 

more appropriate than a limit of 5 

percent as proposed in the 

supplemental action. We also requested 

comment on whether the 5 percent limit 

is achievable on a long-term basis and 

whether the limit provides an adequate 

compliance margin. As we pointed out 

in supporting documentation (see EPA– 

HQ–OAR–2008–0260–0083, pp. 3–4), 

the data used to establish the 

supplemental proposal’s 5 percent 

opacity level were primarily from initial 

compliance tests. Upon reconsideration 

of EPA’s data and consideration of 

public comments and additional 

supporting data, EPA has determined 

that an opacity limit of less than 10 

percent is more appropriate for all coal 

handling equipment. An opacity limit of 

10 percent will allow for control 

equipment degradation, adverse 

conditions, and variability that would 

not be reflected in initial compliance 

tests. Although we modified our 

conclusion regarding the opacity limit 

achievable by the application of BDT, 

we did not modify our prior conclusions 

regarding BDT for coal-handling 


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equipment. BDT for coal-handling 

equipment used on subbituminous and 

lignite coals consists of four 

technologies—fabric filters, passive 

enclosure containment systems (PECS), 

fogging systems, and wet extraction 

scrubbers. BDT for coal-handling 

equipment processing bituminous coal 

is the use of chemical suppressants. All 

of these emissions reduction measures 

can control PM emissions equally well. 

See EPA–HQ–OAR–2008–0260–0083, 

pp. 1–2. 

EPA also concluded that if a building 

in which affected coal processing and 

conveying equipment (e.g., breakers, 

crushers, screens, conveying systems), 

coal storage systems, and transfer 

system operations are enclosed is found 

to be in compliance with the subpart Y 

limits that apply to the affected facilities 

enclosed in the building, the affected 

facilities enclosed in that building also 

are in compliance. Thus, the final rule 

provides that buildings containing coal 

processing and conveying equipment, 

coal storage systems, and transfer 

system operations constructed, 

reconstructed, or modified on or before 

April 28, 2008, must not exhibit 20 

percent opacity or greater. Fugitive 

emissions from buildings that enclose 

coal processing and conveying 

equipment, coal storage systems, and 

coal transfer system operations 

constructed, reconstructed, or modified 

after April 28, 2008, must not exhibit 

opacity of 10 percent or more. For 

buildings enclosing coal processing and 

conveying equipment, coal storage 

systems, and transfer system operations 

constructed, reconstructed, or modified 

after April 28, 2008, that discharge 

emissions from a mechanical vent, 

emissions must not contain PM in 

excess of 0.023 g/dscm (0.010 gr/dscf). 

4. Open Storage Pile Requirements 

EPA’s May 27, 2009, supplemental 

action proposed to establish work 

practice standards for open storage piles 

and roadways. EPA determined that it 

was not feasible to establish opacity or 

PM limits for these types of affected 

facilities. At the current time, EPA 

believes 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 currently make the use of 

Method 9 opacity observations 

unreasonable in many situations. Based 

on that determination, we proposed to 

require owners or operators of open 

storage piles and roadways associated 

with coal preparation plants to develop 

and comply with a fugitive coal dust 

emissions control plan to control 

fugitive PM emissions. Commenters 

pointed out that the Surface Mining 

Control and Reclamation Act (SMCRA) 

covers fugitive dust emissions from 

roads at coal preparation and processing 

plants at mine sites and requires a 

fugitive dust plan. EPA believes that 

coal moving operations, once the coal 

enters the ‘‘coal preparation plant,’’ will 

be by conveyor rather than by truck. 

Therefore, we believe that the 

requirements of SMCRA are sufficient to 

address air emissions from roadways 

that may be found within a coal 

preparation and processing plant at 

mine sites. For coal preparation and 

processing plants at end-user facilities, 

we believe that, again, once the coal 

enters the ‘‘coal preparation plant,’’ coal 

moving operations will be by conveyor 

rather than by truck. Thus, EPA has 

decided not to finalize the proposed 

requirements for roadways. EPA also 

proposed to require that the fugitive 

coal dust emissions control plan include 

procedures for limiting emissions from 

all types of ‘‘coal processing and 

conveying equipment’’ at a coal 

preparation and processing plant. EPA 

agrees with commenters that subpart Y 

should specifically designate each type 

of affected facility subject to the fugitive 

dust emissions control plan and, 

therefore, we are not finalizing that 

proposed requirement. 

A fugitive coal dust emissions control 

plan is required for open storage piles, 

which include the equipment used in 

the loading, unloading and conveying 

operations of the affected facility, 

constructed, reconstructed or modified 

after May 27, 2009. The owner or 

operator is required to prepare and 

operate in accordance with a submitted 

fugitive coal dust emissions control plan 

that is appropriate for the site 

conditions. The fugitive coal dust 

emissions control plan must identify 

and describe the control measures the 

owner/operator will use to minimize 

fugitive coal dust emissions from each 

open storage pile. The owner or operator 

is also required to explain how the 

measures are applicable and appropriate 

for the site conditions. For open coal 

storage piles, the fugitive coal dust 

emissions plan must require that one or 

more of the following control measures 

will be used to minimize to the greatest 

extent practicable 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 (when additional 

provisions discussed below are met), 

use of a wind barrier, compaction, or 

use of a vegetative cover. The owner or 

operator must select, from the list 

provided, the control measures that are 

most appropriate for the site conditions. 

Where appropriate chemical dust 

suppression agents are selected by the 

owner/operator as a control measure to 

minimize fugitive coal dust emissions, 

only chemical dust suppressants with 

Occupational Safety and Health 

Administration (OSHA)-compliant 

material safety data sheets (MSDS) are 

allowed, the MSDS must be included in 

the fugitive coal dust emissions control 

plan, and the owner/operator must 

consider and document in the fugitive 

coal dust emissions control plan the 

site-specific impacts associated with the 

use of such chemical dust suppressants 

(e.g., water run-off, water quality 

concerns). 

An owner/operator may petition the 

Administrator requesting approval of a 

control measure other than those 

specified above. The petition process 

established in the final rule is similar to 

the process used in 40 CFR Part 60, 

subpart Db, to establish alternative NOX

limits for certain industrial boilers. The 

petition must demonstrate to the 

Administrator that the alternate control 

measure will provide equivalent overall 

environmental protection or that it is 

either economically or technically 

infeasible for the affected facility to use 

the control measures specified above. 

The owner/operator must operate in 

accordance with the plan including the 

alternative measures and, while 

operating in accordance with the plan 

submitted with the petition, is deemed 

to be in compliance with the fugitive 

coal dust emissions control plan 

requirements while the petition is 

pending. EPA decided to include this 

petition process in the final rule in 

response to comments objecting to 

provisions proposed in the May 2009 

supplemental proposal that would have 

provided for permitting authority 

approval of the fugitive coal dust 

emissions control plans and allowed the 

permitting authorities to approve the 

use of alternate technologies if it had 

been determined that the technology 

provides equivalent overall 

environmental protection. 

Each owner/operator must submit 

their fugitive coal dust emissions 

control plan to the Administrator or 

delegated authority to provide an 

opportunity for the Administrator or 

delegated authority to object to the 

fugitive coal dust emissions control 

plan. The fugitive coal dust emissions 

control plan must be submitted to the 

Administrator or delegated authority 

prior to the startup date for the affected 

facility. If an objection is raised, the 


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owner/operator has 30 days from receipt 

of the objection to submit a revised 

fugitive coal dust emissions control 

plan. The owner/operator must operate 

in accordance with the revised fugitive 

coal dust emissions control plan. The 

Administrator and delegated authority 

retain the ability to object to the revised 

fugitive coal dust emissions control 

plan. 

C. Emissions Testing and Monitoring 

Requirements 

Based on our review of public 

comments submitted in response to the 

May 27, 2009, supplemental proposal 

and further analysis, minor revisions 

were made to certain emissions testing 

and monitoring requirements included 

in that supplemental proposal. The 

testing and monitoring requirements of 

the final rule are described below. All 

affected facilities subject to emissions 

limits are required to conduct initial 

emissions testing to show compliance 

with the limits included in the final 

rule. PM emissions must be measured 

with EPA Method 5, 5B, or 5D of 40 CFR 

Part 60, appendix A–4, or EPA Method 

17 of 40 CFR Part 60, appendix A–7. 

EPA Method 6, 6A, or 6C of 40 CFR Part 

60, appendix A–4, must be used to 

measure SO2 emissions. NOX and CO 

emissions must be measured with EPA 

Method 7 or 7E, and Method 10, 

respectively, of 40 CFR Part 60, 

appendix A–4. In addition, CO and NOX

performance testing must be conducted 

concurrently, or within a 60-minute 

period. Initial testing for PM emissions 

is required for coal-handling equipment 

exhaust that is mechanically vented and 

for thermal dryer exhaust. Depending on 

the type of thermal dryer and its fuel 

type, initial testing for SO2, NOX, and 

CO may also be required. Following 

initial performance testing, the 

frequency of subsequent emissions 

testing is variable. If an affected facility, 

excluding thermal dryers, has a design 

controlled potential PM emissions rate, 

considering controls, of 1.0 Mg (1.1 

tons) per year or less, annual 

performance testing is not required as 

long as: (1) PM emissions, as 

determined by the initial performance 

test, are less than or equal to the 

applicable PM limit; (2) the 

manufacturer’s recommended 

maintenance procedures for each 

control device are followed; and (3) all 

6-minute average opacity readings from 

the most recent Method 9 performance 

test are equal to or less than half the 

applicable opacity limit. 

In addition, for similar, separate 

affected facilities using identical control 

equipment, the Administrator or 

delegated authority may authorize a 

single emissions test as adequate 

demonstration for up to four other 

similar, separate affected facilities as 

long as: (1) The most recent 

performance test for each affected 

facility shows that performance of each 

affected facility is 90 percent or less of 

the applicable emissions limit; (2) the 

manufacturer’s recommended 

maintenance procedures for each 

control device are followed; and (3) 

each affected facility conducts a 

performance test for each pollutant for 

which they are subject to a limit at least 

once every 5 years. Affected facilities 

that, based on their most recent 

performance test, emit at a level that is 

50 percent or less of an applicable 

emissions limit are only required to 

conduct performance testing every 24 

months, as opposed to every 12 months. 

Finally, an owner/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 performance test 

until 30 calendar days after the next 

operating day. 

The final rule requires the use of bag 

leak detection systems on subpart Y 

affected facilities with fabric filters that 

have a design controlled potential PM 

emissions rate of 25 Mg (28 tons) or 

more. This requirement applies to 

affected facilities constructed, 

reconstructed, or modified after April 

28, 2008. For affected facilities with 

venturi scrubbers, continuous 

measurement of the pressure loss 

through the venturi constriction of the 

scrubber and of the liquid flow rate to 

the scrubber is required. If the venturi 

scrubber is used to control SO2

emissions, pH of the scrubber liquor 

also must be continuously measured. 

For affected facilities using packed bed 

scrubbers with the addition of lime, the 

liquid flow rate to the scrubber and the 

scrubber liquor pH must be 

continuously measured. The final rule 

does not require continuous 

measurement of the temperature of the 

gas stream at the exit of the thermal 

dryer for affected facilities constructed, 

reconstructed, or modified after April 

28, 2008. In the supplemental proposal, 

EPA requested comment on the utility 

of collecting continuous temperature 

data and determined that the 

requirement can be eliminated without 

risk of a significant increase in 

emissions. 

D. Opacity Testing and Monitoring 

Requirements 

Numerous comments were submitted 

to EPA regarding the opacity testing and 

monitoring requirements included in 

the May 27, 2009, supplemental 

proposal. Commenters objected to the 

proposed procedures as being 

unreasonable, burdensome, too 

complex, and confusing. Based on our 

review of public comments and further 

analysis, we modified the proposed 

requirements where we determined the 

burden could be reduced without 

compromising the integrity of the 

overall testing and monitoring 

requirements. We also attempted to 

make the requirements in the final rule 

less complex than those included in the 

supplemental proposal. All affected 

facilities subject to emissions limits are 

required to conduct initial emissions 

testing to show compliance with the 

opacity limits included in the final rule. 

Opacity must be measured with EPA 

Method 9 of 40 CFR part 60, appendix 

A–4. The final rule allows the use of a 

continuous opacity monitoring system 

(COMS) as an alternative to all other 

opacity monitoring requirements. The 

final rule includes a 60-minute 

observation period for Method 9 

performance testing. The observation 

period may be decreased from 60 

minutes to 30 minutes if, during the 

initial 30 minutes of the observation of 

a Method 9 performance test, all the 6- 

minute averages are less than or equal 

to half the applicable opacity limit. In 

the final rule, the frequency of 

subsequent visible emissions testing is 

based on the 6-minute average opacity 

readings from the most recent 

performance test. Owners/operators of 

affected facilities where any 6-minute 

average opacity reading in the most 

recent Method 9 performance test 

exceeds half the applicable opacity limit 

are required to conduct a Method 9 

performance test within 90 days of the 

previous performance test. Owners/ 

operators of affected facilities where all 

6-minute average opacity readings in the 

most recent Method 9 performance test 

are equal to or less than half the 

applicable opacity limit are required to 

conduct a Method 9 performance test 

within 12 months of the previous 

performance test. Further, if a Method 9 

opacity performance test is conducted 

concurrently with (or within a 60- 

minute period of) a Method 5, 5B, or 5D 

PM performance test for affected sources 

with wet scrubbers that continuously 

monitor the specified scrubber 

parameters, no subsequent Method 9 

opacity performance testing is required. 

The final rule allows simultaneous 

Method 9 opacity performance testing 

for up to three emissions points as long 

as all three emissions points are within 

a 70-degree viewing sector or angle in 

front of the observer such that the 

proper sun position can be maintained 


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for all three points. 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), the observer must stop 

taking readings for the other two points 

and continue reading just that single 

point. 

As an alternative to subsequent 

Method 9 performance testing, the final 

rule allows owners/operators of affected 

facilities to elect to conduct monitoring 

as follows: (1) Monthly visual 

observations of process and control 

equipment must be conducted and, if 

any deficiencies are observed, the 

necessary maintenance must be 

performed as expeditiously as possible; 

and (2) daily walkthrough observations 

consisting of a single 15-second 

observation (i.e., visible emissions or no 

visible emissions) of each affected 

facility must be conducted and, if any 

visible emissions are observed, within 

24 hours corrective actions must be 

conducted and the owner/operator must 

demonstrate that there are no visible 

emissions. If visible emissions are still 

observed, a Method 9 performance test 

must be conducted within 45 operating 

days to show compliance with the 

applicable opacity limit. The final rule 

requires that Method 9 performance 

testing must be conducted at least once 

every 5 years for each affected facility 

complying with this alternative 

monitoring option. Each observer 

determining the presence of visible 

emissions is required to meet the 

training requirements of Method 22 of 

appendix A–7 of 40 CFR Part 60. The 

final rule also allows the use of a digital 

opacity monitoring system in lieu of 

subsequent Method 9 performance 

testing. The Administrator may approve 

opacity monitoring plans for owners/ 

operators that elect to use the digital 

opacity monitoring system to detect the 

presence of visible emissions. 

The final rule includes separate 

opacity testing and monitoring 

requirements for coal truck dump 

operations. EPA determined that a 

different approach for Method 9 opacity 

performance testing is warranted due to 

the intermittent nature of coal truck 

dumping. Coal truck dump operations 

are subject to the same opacity limits as 

other coal handling operations. The 

final rule specifies that compliance with 

the opacity limit is determined by 

averaging all Method 9 15-second 

opacity readings made during the 

duration of three separate truck dump 

events. A truck dump event commences 

when the truck bed begins to elevate 

and concludes when the truck bed 

returns to a horizontal position. The 

final rule requires monthly visual 

observations of the truck dump 

equipment and, if any deficiencies are 

observed, the necessary maintenance 

must be conducted as expeditiously as 

possible. Subsequent Method 9 opacity 

performance testing using the three 

truck dump procedure is required to be 

conducted every 90 days. 

E. Recordkeeping and Reporting 

Requirements 

The final rule requires that a logbook 

be maintained by each owner/operator 

of a coal preparation and processing 

plant that commences construction, 

reconstruction, or modification after 

April 28, 2008. The logbook must 

include records of subpart Y 

requirements regarding manufacturers’ 

recommended maintenance procedures 

for process and control equipment, 

visual observations of coal-handling 

equipment, the amount and type of coal 

processed, the amount of chemical 

stabilizer or water purchased, the 

operational status of dust suppressant 

systems, compliance with a fugitive coal 

dust emissions control plan, BLDS 

operation, and measurement of 

monitoring parameters (e.g., scrubber 

pressure loss, water supply flow rate, 

pH of scrubber fluid). 

F. Electronic Reporting 

The final rule requires owners/ 

operators of affected facilities at coal 

preparation and processing 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. 

Submittal to WebFIRE is required as of 

July 1, 2011. For performance tests not 

accepted by WebFIRE, owner/operators 

are required to mail summary results 

directly to EPA. 

G. Additional Amendments 

The final rule confirms the subpart Y 

title change from Coal Preparation 

Plants to Coal Preparation and 

Processing Plants. In addition to 

revising the definitions for coal, 

pneumatic coal-cleaning equipment, 

and thermal dryer as described in 

section III.A of this preamble, the final 

rule amends the definition for 

bituminous coal; adds definitions for 

anthracite, bag leak detection system, 

coal refuse, design controlled potential 

emissions rate, indirect thermal dryer, 

lignite, mechanical vent, operating day, 

potential combustion concentration, and 

subbituminous coal; and deletes the 

definition for cyclonic flow. The 

definition of coal refuse in the final rule 

has been modified to be consistent with 

the definition of coal refuse in 40 CFR 

part 60, subpart Da. Also, EPA is not 

finalizing the April 28, 2008, proposed 

revision to the definition of coal 

processing and conveying equipment, 

but is clarifying that equipment located 

at the mine face is not considered to be 

part of the coal preparation plant. In 

addition, the May 27, 2009, proposed 

revision to the definition of coal storage 

system is also not being promulgated. 

Rather, the final rule adds a definition 

for open storage pile. 

IV. Summary of Significant Comments 

and Responses 

As explained in Section II of this 

preamble, EPA proposed amendments 

to the coal preparation plants NSPS on 

April 28, 2008, (73 FR 22901) and 

received a total of 42 comments from 

coal preparation plants, industry trade 

associations, control technology 

vendors, environmental groups, and 

State environmental agencies. After 

reviewing those comments and 

considering additional data, EPA 

decided to publish a supplemental 

proposal (see 74 FR 25304, May 27, 

2009) which revised some of the 

requirements proposed on April 28, 

2008. A total of 44 comments regarding 

the supplemental proposal were 

received from coal preparation plants, 

other types of industrial facilities, 

industry associations, environmental 

groups, and State environmental 

agencies. Responses to comments 

regarding the April 28, 2008, proposal 

are not discussed in this preamble. In 

many instances, the May 27, 2009, 

supplemental proposal either addressed 

the comment or made revisions that 

negated the comment. Significant 

comments received regarding the May 

27, 2009, supplemental proposal and 

EPA’s responses to those comments are 

discussed below. Detailed responses to 

the comments not included in this 

preamble, including responses to the 

comments regarding the April 28, 2008, 

proposal, are contained in the Summary 

of Public Comments and Responses 

document which is included in the 

docket for this rulemaking. 

A. Regulated Pollutants 

Comment: Many commenters stated 

that EPA’s authority to promulgate 

NSPS requires an endangerment finding 

for the coal preparation plant source 

category and the pollutant(s) of interest. 

Because EPA has not made such a 

finding for SO2, NOX, or CO emissions 

from coal preparation plants, the 

commenters contend that emissions 

standards for SO2, NOX, or CO 


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applicable to coal preparation plants 

under subpart Y cannot be set. 

Response: CAA section 111(b)(1)(A) 

requires the Administrator to publish a 

list of categories of stationary sources 

and include a category of sources on 

that list if he finds that ‘‘in his judgment 

it causes, or contributes significantly to, 

air pollution which may reasonably be 

anticipated to endanger public health or 

welfare.’’ 42 U.S.C. 7411(b)(1)(A) (CAA 

section 111(b)(1)(A)). The plain 

language of section 111(b)(1)(A) 

provides that such findings are to be 

made for source categories, not for 

specific pollutants emitted by the source 

category. Therefore, once the 

Administrator determines that the 

source category causes or contributes 

significantly to air pollution which may 

endanger public health or welfare, the 

Administrator must add the source 

category to the section 111(b)(1)(A) list 

and subsequently establish standards of 

performance for the sources in that 

source category. Determinations 

regarding the specific pollutants to be 

regulated are made, not in the initial 

endangerment finding, but at the time 

the performance standards are 

promulgated. In addition, CAA section 

111(b)(1)(B) requires EPA to review and 

revise, if appropriate, the standards at 

least every eight years. In conducting 

that review, EPA has discretion to 

revisit its original determination 

regarding which pollutants emitted from 

the source category should be regulated. 

Neither the text of the CAA nor 

subsequent statements of EPA provide 

any support for the argument that an 

endangerment finding must be made for 

specific pollutants or for the argument 

that the scope of the revised NSPS must 

be limited to the pollutants (or affected 

facilities) regulated in the initial NSPS. 

The text of section 111(b)(1)(A) 

provides no support for the argument 

that section 111 endangerment findings 

must be made for each pollutant emitted 

by the source category before that 

pollutant can be regulated in the NSPS. 

In contrast, the statutory text calls for a 

list of ‘‘categories of stationary sources.’’ 

It does not require, at the time of listing, 

an identification of all the specific 

pollutants emitted by the source 

category that may endanger public 

health or welfare. Instead, it requires 

only a general determination that 

emissions from the category cause or 

contribute to air pollution that may 

endanger public health or welfare. The 

endangerment finding is used to 

identify categories of sources for 

regulation, not to dictate the substantive 

content of the required standards of 

performance. The endangerment finding 

neither requires regulation of each 

pollutant emitted by the source 

category, nor limits EPA’s discretion to 

determine (in the initial regulation or in 

subsequent revisions) which pollutants 

should be regulated. 

Instead, section 111(b)(1)(B) requires 

the Administrator, after publishing 

proposed regulations and providing an 

opportunity for comment, to promulgate 

such standards as the Administrator 

‘‘deems appropriate.’’ The statutory 

scheme thus provides EPA with 

significant discretion to determine 

which pollutant(s) should be regulated 

under the NSPS. The Agency has long 

interpreted section 111(b)(1)(B) as 

providing the Administrator with this 

flexibility. See National Lime Assoc. v. 

EPA, 627 F.2d 416, 426 n.27 (DC Cir. 

1980) (explaining reasons for not 

promulgating standards for NOX, SO2

and CO from lime plants); see also 

National Assoc. of Clean Air Agencies v. 

EPA, 489 F.3d 1221, 1228–1230 (DC Cir. 

2007) (finding that the ‘‘deems 

appropriate’’ language in CAA section 

231 provides a ‘‘delegation of authority’’ 

that is ‘‘both explicit and extraordinarily 

broad’’). 

EPA has, in prior NSPS rulemakings, 

exercised its discretion to identify 

pollutants for regulation. It has 

sometimes exercised this discretion to 

defer regulation of specific pollutants to 

a later date. See, e.g., 52 FR 36678, 

36682 (September 30, 1987) (noting in 

subpart DDD proposal that ‘‘standards 

development for this industry is 

focusing initially on limiting emissions 

of VOC’’); 49 FR 2656, 2659 (Jan 20, 

1984) (explaining why SO2 and VOC 

were the only pollutants in the natural 

gas production industry selected for 

regulation under subpart LLL ‘‘at this 

time.’’); 48 FR 37338, 37340–42 (Aug. 

17, 1983) (declining to regulate in 

subpart AAa, emissions of pollutants for 

which adequately demonstrated control 

technology was not currently available). 

EPA has also exercised this discretion to 

promulgate, during 8-year review 

rulemakings, new performance 

standards for pollutants not previously 

covered by the NSPS in question. See, 

e.g., 52 FR 24624, 24710 (July 1, 1987) 

(considering PM10 controls in future 

rulemakings); 71 FR 9866 (Feb. 27, 

2006) (establishing new PM standards 

for boilers); 73 FR 35838 (June 24, 2008) 

(adding NOX limits for fluid catalytic 

cracking units, NOX limits for fluid 

coking units and NOX limits for process 

heaters to the refineries NSPS). In 

addition, EPA has previously noted its 

disagreement with comments implying 

that an additional endangerment finding 

would be required to support regulation 

of a pollutant not previously regulated 

in that specific NSPS. See, e.g., 73 FR 

35838, 35859 n2 (June 24, 2008). 

Further, the argument that EPA must 

issue a separate endangerment finding 

before regulating a pollutant not 

previously regulated in the NSPS for a 

source category is illogical. Once EPA 

has determined that a source category 

causes, or contributes significantly to, 

air pollution which may reasonably be 

anticipated to endanger public health or 

welfare emissions from a source 

category, the recognition that the source 

has emissions above and beyond those 

discussed in the original endangerment 

finding could only serve to strengthen 

the basis for the endangerment finding 

for the source category. Further, the 

listing of the source category is only the 

first step in the process. Once the 

finding is made, the statute allows the 

more detailed analysis of which 

pollutants are actually emitted and 

should be regulated to be conducted in 

the rulemaking process used promulgate 

and revise the standards for the source 

category. 

Finally, it is worth noting that EPA 

previously addressed this topic in the 

context of the subpart Y NSPS for coal 

preparation and processing plants. Coal 

preparation plants were listed under 

section 111(b)(1)(A) on October 24, 

1974, pursuant to the Administrator’s 

determination that such plants ‘‘may 

contribute significantly to air pollution 

which causes or contributes to the 

endangerment of public health or 

welfare.’’ 39 FR 37,807 (Oct. 24, 1974). 

The Background Information Document 

for the subpart Y standards proposed at 

that time explains the process to be used 

for setting NSPS and explicitly notes 

that ‘‘[a]lthough a source category may 

be selected to be covered by a standard 

of performance, treatment of some of the 

pollutants of facilities within that 

source category may be deferred.’’ 

Background Information for Standards 

of Performance: Coal Preparation Plants 

Volume 1: Proposed Standards at ix. 

For these reasons, EPA disagrees with 

the comment suggesting that EPA 

cannot set SO2, NOX, or CO emissions 

standards applicable to coal preparation 

plants under subpart Y. 

Comment: One commenter stated that 

EPA should recognize its obligation to 

promulgate NSPS for emissions of 

carbon dioxide (CO2), nitric oxide 

(N2O), and black carbon (a component 

of PM) from coal preparation and 

processing plants. The commenter 

asserts that because these pollutants are 

the result of incomplete fuel 

combustion, they are emitted at coal 

prep plants, particularly by thermal 

dryers heated by coal or other fossil 

fuels. Emissions of each pollutant, the 


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commenter asserts, carries individual 

and distinct risks and is controlled by 

different technologies so EPA must fully 

analyze each pollutant and set separate 

NSPS for each. 

Response: At this time EPA is not 

aware of any emissions or mitigation 

data for the pollutants noted by the 

commenter for this source category. 

Hence, we lack sufficient information 

on which to base an NSPS for emissions 

of CO2, N2O, and black carbon from the 

source category at this time. Rough 

estimates of CO2 from this source 

category suggest that this source 

category would be among the smaller 

CO2-emitting NSPS categories. At this 

time, we are not making any final 

determination regarding whether it 

would be appropriate to set such 

standards. 

In addition, to the extent the comment 

suggests that EPA should utilize its 

authority under other provisions of the 

CAA to require sources to gather and 

report GHG emissions and to the extent 

it raises issues not opened for public 

comment in the supplemental proposal, 

it is beyond the scope of this 

rulemaking. 

Comment: One commenter asserts 

that CAA section 111 carries a mandate 

for EPA to set NSPS for the pollutants 

emitted by a source. The commenter 

cites to language in section 111(a)(3) 

that defines a stationary sources as any 

building, structure, facility or 

installation which emits or may emit 

any air pollution and language in 

section 111(b)(4) defining a 

modification as a physical or 

operational change which increases the 

amount of any air pollution emitted by 

the source. In addition, the commenter 

cites to the Supreme Court’s decision in 

Massachusetts v. EPA, 549 U.S. 497, 529 

(2007) and EPA’s April 2009 Proposed 

Endangerment and Cause or Contribute 

Findings for Greenhouse Gases (74 FR 

18886 (Apr. 24, 2009)). 

Response: The Agency has long 

exercised its discretion to regulate only 

a subset of the pollutants emitted by a 

source category or to defer regulation of 

certain pollutants to a later date. See 

e.g., National Lime Assoc. v. EPA, 627 

F.2d 416, 426 n.27 (DC Cir. 1980) 

(explaining reasons for not 

promulgating standards for NOX, SO2, 

and CO from lime plants); National 

Assoc. of Clean Air Agencies v. EPA, 

489 F.3d 1221, 1228–1230 (DC Cir. 

2007) (finding that the ‘‘deems 

appropriate’’ language in CAA section 

231 provides a ‘‘delegation of authority’’ 

that is ‘‘both explicit and extraordinarily 

broad’’); 52 FR 36678, 36682 (September 

30, 1987) (explaining Subpart DDD 

standards’ initial focus on limiting 

emissions of VOC); 49 FR 2656, 2659 

(January 20, 1984) (explaining Subpart 

LLL regulates only emissions of SO2 and 

VOC); 48 FR 37338, 37340–42 (August 

17, 1983) (explaining why Subpart AAa 

does not regulate emissions of 

pollutants for which adequately 

demonstrated control technology was 

not currently available). 

B. Applicability and Definitions 

Comment: Many commenters stated 

that EPA proposed to add ‘‘processing’’ 

to the title of subpart Y and, although 

EPA indicated in the preamble to the 

May 27, 2009, supplemental proposal, 

that it did not intend to change the 

applicability of subpart Y, the 

commenters are concerned that EPA has 

not adequately justified the need to 

make the change. Subpart Y already 

defines ‘‘processing equipment’’ as 

‘‘machinery used to reduce the size of 

coal or to separate coal from refuse.’’ 

Despite EPA’s stated intentions, 

commenters believe that the risk exists 

that EPA, in future applicability 

interpretations, will determine that 

additional, non-preparation operations 

meet the meaning of processing, and 

will thereby bring them under subpart Y 

purview. To avoid confusion, the 

commenters stated that EPA should 

remove ‘‘processing’’ from the title. 

Response: In the preamble to the 

supplemental proposal, EPA indicated 

that the proposed title change was for 

clarification purposes (i.e., to more 

accurately reflect the affected facilities 

subject to subpart Y). The affected 

facilities covered by subpart Y since its 

1976 promulgation include both 

preparation and processing units. We do 

not intend the title change to have any 

impact on the extent of EPA’s authority 

to regulate specific affected facilities 

now or in the future. The final action 

promulgates the proposed title change 

‘‘Standards of Performance for Coal 

Preparation and Processing Plants.’’ 

Comment: Many commenters 

acknowledged that in its May 27, 2009, 

supplemental action, EPA proposed to 

amend the definition of ‘‘coal’’ to 

include ‘‘coal refuse’’ and ‘‘petroleum 

coke.’’ These commenters objected to 

EPA’s proposed inclusion of ‘‘coal 

refuse’’ because its inclusion further 

expands the subpart Y applicability 

with no data specific to ‘‘coal refuse’’ on 

what constitutes adequately 

demonstrated technologies and their 

respective levels of achievable 

emissions. Specifically, one commenter 

is concerned that subpart Y’s definition 

of ‘‘coal refuse’’ could create the 

potential for the unintended application 

of such definition to the overburden 

from surface mines or to minedevelopment waste associated with 

underground mining. The commenter 

stated that the final rule must make 

clear that the definition of ‘‘coal refuse’’ 

does not apply to these types of 

operations and suggested using the 

SMCRA definition instead (Coal refuse 

is defined as ‘‘any waste coal, rock, 

shale, slurry, culm, gob, boney, slate, 

clay and related materials, associated 

with or near a coal seam, which are 

either brought aboveground or 

otherwise removed from a coal mine in 

the process of mining coal or which are 

separated from coal during the cleaning 

or preparation operations. The term 

includes underground development 

wastes, coal processing wastes, excess 

spoil, but does not mean overburden 

from surface mining activities’’). In 

contrast, several other commenters 

stated either that they support, or that 

they have no objections to, including 

‘‘coal refuse’’ in the definition of ‘‘coal’’ 

for subpart Y. 

Response: EPA is including ‘‘coal 

refuse’’ in the final rule’s definition of 

‘‘coal’’ for the purposes of subpart Y 

because it is handled in the same 

machinery as other types of coal at coal 

preparation and processing plants. 

‘‘Coal refuse’’ is separately defined, as 

well as included in the definition of 

‘‘coal’’ in other NSPS (e.g., 40 CFR part 

60 subparts Da and Db), and its 

inclusion here provides consistency 

with other EPA regulations. EPA has 

modified the definition of ‘‘coal refuse’’ 

in subpart Y to be consistent with the 

definition in 40 CFR subpart Da. Given 

the historical inclusion of ‘‘coal refuse’’ 

in these other NSPS and the fact that the 

constituents and emission 

characteristics of ‘‘coal’’ and ‘‘coal 

refuse’’ are believed to be the same, EPA 

has concluded that inclusion of ‘‘coal 

refuse’’ in subpart Y is appropriate. 

Comment: Many commenters objected 

to EPA extending the applicability of 

subpart Y to facilities producing 

petroleum coke by adding ‘‘petroleum 

coke’’ to the subpart Y definition of 

‘‘coal’’. They noted that the emission 

standards in the May 27, 2009, 

supplemental proposal appear to have 

been developed primarily for coal 

processing plants, and do not seem to 

reflect the differences between coal and 

petroleum coke, or contemplate the 

emissions associated with petroleum 

coke handling operations. Without more 

information on these emissions, the 

commenters contend that it is 

inappropriate for EPA to broaden the 

definition of ‘‘coal’’ to include 

‘‘petroleum coke’’ in this final 

rulemaking at this time. However, if 

‘‘petroleum coke’’ is included, several 

commenters recommended petroleum 


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coke operations that should be 

specifically exempted from being 

subject to subpart Y. Reasons cited by 

commenters include: (1) ‘‘Petroleum 

coke’’ is a petroleum product that 

should not be subject to a rule (i.e., 

NSPS subpart Y) intended to pertain to 

standards of performance for coal 

preparation and processing plants; (2) 

petroleum refining operations that 

include petroleum coke production are 

subject to numerous NSPS rules to 

ensure protection of public health and 

the environment, to two separate 

maximum achievable control 

technology (MACT) rules specific to air 

emissions from process units, including 

petroleum coke production, and to the 

NSR permitting process to ensure 

compliance with National Ambient Air 

Quality Standards (NAAQS) for PM; (3) 

EPA did not provide adequate notice 

that petroleum coke manufacturing 

equipment (e.g., refinery coker units) 

was being considered for new standards; 

(4) EPA neither gathered or requested 

data to determine if petroleum coke 

manufacturing equipment should be 

included in the affected sources subject 

to subpart Y; and (5) standards for coal 

processing and conveying equipment, 

coal storage systems, and transfer and 

loading system operations are not 

suitable for petroleum coke. 

Two commenters suggested that EPA 

change the approach to include enduser petroleum coke processing in the 

existing NSPS for Coal Preparation and 

Processing Plants by retaining the 

existing definition of ‘‘coal’’ and adding 

‘‘petroleum coke’’ as a separate material 

with associated provisions. If EPA 

expands the source category by 

including facilities that handle only 

‘‘petroleum coke’’ (and not ‘‘coal’’), the 

commenters believe it should do so only 

for end-users of ‘‘petroleum coke’’ used 

as fuel. Numerous commenters 

presented arguments that petroleum 

coke calciners are not same as coal 

thermal dryers and, therefore, believe it 

is inappropriate to apply the subpart Y 

thermal dryer standards to coke 

calciners. The commenters explained 

that the purpose and function of a 

petroleum coke calciner is to 

fundamentally change the material by 

rearranging carbon molecules and, thus, 

it acts as a reactor, not a ‘‘dryer’’. In 

addition, commenters noted that 

calciners in the petroleum industry 

operate at much higher temperatures 

than typical coal dryers, intuitively 

would have different emission profiles, 

and use different methods than coal 

thermal dryers to control PM emissions. 

Response: Based on a review of the 

comments received and because of the 

limited amount of currently available 

data, EPA has decided not to include 

‘‘petroleum coke’’ in the subpart Y 

definition of ‘‘coal’’ at this time. EPA 

plans on obtaining additional data on 

petroleum coking activities at petroleum 

refineries through current actions on the 

refinery NSPS review (40 CFR part 60 

subpart J). In addition, additional data 

will also be obtained on petroleum coke 

activities at end-user locations (e.g., 

coal-fired power plants). 

Comment: Several commenters 

supported EPA’s proposal to distinguish 

between indirect and direct contact 

thermal dryers. The commenters 

anticipate that more electric utilities 

will use indirect contact thermal dryers 

in the future. Commenters agreed with 

EPA’s decision to exclude indirect 

thermal dryers from the coal dryer SO2

and NOX/CO standards ‘‘[i]f the source 

of heat (the source of combustion or 

furnace) is subject to a boiler NSPS 

(subpart Da, Db, or Dc). However, one 

commenter stated that in the case of one 

facility, the waste heat being used for 

the facility’s coal dryer does not come 

from the exhaust gases of a boiler, but 

rather from the condensing water from 

steam turbines. In that case, there is no 

affected source to which the combustion 

pollutant emission limits can apply. 

Thus, the commenter agreed that the 

thermal dryer would only be subject to 

the PM limit, but not because it is 

subject to another NSPS. The 

commenter further stated their belief 

that subpart Y coal dryer emission 

limits should not apply to the source of 

heat for an indirect thermal dryer. 

Response: It is EPA’s intent to 

regulate, at this time, emissions from 

thermal dryers only in circumstances 

where coal, coal refuse, or residual oil 

are used to provide thermal input. 

Thermal dryers that use residual or 

waste heat from the combustion of these 

fuels are only subject to the PM and 

opacity standards. As pointed out by the 

commenters, indirect thermal dryers for 

which the source of heat is subject to a 

boiler NSPS are not subject to the 

emission limits for SO2 and NOX/CO 

because those pollutants would not be 

present in the thermal dryer exhaust. In 

addition, EPA has concluded that 

affected thermal dryers for which all of 

the thermal input is supplied by gaseous 

fuels (e.g., blast furnace gas, coke oven 

gas, natural gas) or distillate oil also 

should not be subject to the emission 

limits for SO2 and NOX/CO. Those 

pollutants are relatively small from 

these types of thermal dryers and the 

testing requirements will not result in 

any emissions reductions. As is the case 

with the facility described by the 

commenter, if there is no combustion 

process providing the heat for the dryer, 

then there is no practicality in having 

emission limits for SO2 and NOX/CO. 

Comment: Several commenters stated 

that emissions from thermal dryers 

integrated with in-line coal mills at 

cement manufacturing plants should not 

be subject to subpart Y and instead be 

subject to the standard for the affected 

facility as part of the cement 

manufacturing process. According to the 

commenters, the unique coal processing 

and handling systems found at Portland 

cement plants are best addressed by the 

Portland Cement NSPS (40 CFR part 60, 

subpart F) and NESHAP (40 CFR part 

63, subpart LLL). The commenters 

requested that the subpart Y definition 

of ‘‘thermal dryer’’ be revised to read 

‘‘Thermal dryer does not include drying 

of coal that occurs intentionally or 

incidentally in the manufacture of 

Portland cement through direct or 

indirect contact with hot gases 

generated by cement manufacturing 

process units, such as cement kilns, 

preheaters, precalciners, or clinker 

coolers.’’ Commenters explained that 

this approach would (a) clearly 

distinguish between separately fired, 

stand-alone thermal dryers that are 

located at a cement plant, versus 

thermal dryers or coal mills that are 

integrated into a cement manufacturing 

line, and (b) avoid any potential 

confusion about incidental drying of 

coal that occurs in the cement-making 

process. Reasons presented by 

commenters to support the requested 

exemption are summarized below. 

• In a 1995 determination, EPA stated 

that when ‘‘gases originate in one 

affected facility and pass through 

another affected facility as part of the 

manufacturing process, EPA applies the 

standard for the affected facility from 

which the gases are discharged directly 

into the atmosphere.’’ [Applicability 

Determination 9600082 ‘‘Alternative 

Monitoring and Opacity Limit 

Clarification for San Juan Cement 

Company,’’ John B. Rasnic (May 12, 

1995)]. However, a year later EPA 

qualified this guidance when it 

concluded that an in-line raw mill was 

subject to the 40 CFR part 60, subpart 

F, kiln standards, stating ’’This 

determination clarifies that for dry 

process Portland cement plants with an 

‘‘in-line’’ kiln/raw mill configuration, 

the raw mill does not exist as a separate 

affected facility and; hence, the 

appropriate emission limit is that which 

applies to the kiln.’’ [Applicability 

Determination 9600083; ‘‘Opacity 

Limitation for ‘In-line’ Portland Cement 

Plants,’’ John B. Rasnic (September 7, 

1996)]. 

• Just as emissions from the in-line 

raw mill in Applicability Determination 


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9600083 were subject to 40 CFR Part 60, 

subpart F, NSPS, PM mass and opacity 

limitations for cement kilns, so should 

emissions from an in-line coal mill at a 

cement plant where kiln gases are used 

to heat and dry the coal be treated as an 

extension of the kiln and subject to 

subpart F NSPS and 40 CFR Part 63, 

subpart LLL, NESHAP cement kiln PM 

and opacity limits. This approach is 

consistent with multiple different 

applicability determinations stating that 

kiln exhaust gases are subject to the 

Portland cement NESHAP (40 CFR part 

63, subpart LLL) regardless of whether 

they are routed through the coal mill 

prior to discharge to the atmosphere. It 

is also consistent with the data that EPA 

has reviewed in establishing the 

proposed subpart Y limits. In the 

absence of data related to emissions 

from in-line coal mills, EPA would not 

have a rational basis supported by 

evidence in the record for establishing 

limits that apply to these unique gas 

streams. 

• As Portland cement plants have 

striven to increase energy efficiency, a 

common plant configuration has been to 

employ kiln exhaust gas or heated gas 

from the plant’s clinker cooler to 

thermally dry coal before it is 

combusted. Cement kiln exhaust gas is 

extremely hot, and one of the primary 

means of improving energy efficiency 

has been to route this gas back through 

the process to extract as much heat as 

reasonably possible. Likewise, the 

product leaving the kiln (referred to as 

clinker) will enter a cooling area where 

gases are blown through the clinker to 

accelerate the cooling process. In some 

plants this heated gas is then used to 

heat the coal entering the combustion 

process. Both kilns and clinker coolers 

are affected facilities under 40 CFR part 

60, subpart F, NSPS. The use of waste 

heat from the kiln or the clinker cooler 

is highly energy efficient, driving down 

the combustion emissions, including 

GHG emissions, from the plant as a 

whole. 

• Some cement plants have standalone thermal dryers for coal, where the 

heat for drying is provided by a 

dedicated combustion source (e.g., coal 

or natural gas). Those thermal dryers 

generally should have similar 

emissions, and similar possibilities for 

emissions control, as comparable-size 

thermal coal dryers at other facilities. 

But where coal drying is integrated into 

the cement-making process, through 

direct or indirect exposure of the coal to 

heat in exhaust gases from units such as 

cement kilns, preheater/precalciners, or 

clinker coolers, the emissions from that 

coal drying, and the potential for 

controlling those emissions, is very 

different from a stand-alone thermal 

dryer. 

• To the extent that subpart Y may 

apply to coal drying that occurs using 

waste heat from the manufacture of 

Portland cement, EPA’s assessments of 

control technology and derivation of 

emission standards under subpart Y 

have not taken into account cementprocess-related loadings of SO2, NOX, 

and CO. EPA has not shown, for 

example, that it would be feasible for a 

cement plant to demonstrate 

compliance with SO2 mass limits or 

percent reduction requirements where 

exhaust gases from coal drying are 

combined with cement kiln gases, 

which include SO2 from fuel 

consumption and from raw materials. 

Similarly, NOX limits that may be 

achievable through combustion controls 

on a standalone thermal dryer may not 

be achievable in exhaust gases mixed 

with cement kiln gases containing both 

fuel NOX and thermal NOX from the 

cement-making process. 

• The supplemental proposal would 

not impose SO2, NOX, and CO limits on 

indirect thermal dryers where the 

source of the heat is subject to NSPS 

under 40 CFR Part 60, subpart Da, Db, 

or Dc. Although EPA has not really 

explained the basis for that exclusion, it 

is inferred that EPA believes the BDT 

determinations associated with the 

NSPS for the source of heat are more 

appropriate and should be applied. The 

same rationale should be applied to 

thermal drying that is incidental to 

cement manufacturing, and EPA should 

exclude exhaust gases that are subject to 

the 40 CFR part 60, subpart F, NSPS 

from being subject to the subpart Y SO2, 

NOX, and CO limits. 

Response: EPA agrees that in the case 

of a coal dryer at a cement 

manufacturing facility where all of the 

thermal input is supplied by cement 

kiln exhaust or clinker cooler exhaust, 

the dryer should be regulated under the 

appropriate Portland Cement kiln 

regulations (40 CFR part 60, subpart F, 

and 40 CFR part 63, subpart LLL). This 

would also imply that any emissions 

from the thermal dryer are considered as 

part of the kiln or clinker cooler 

emissions. The final rule’s emissions 

limits apply to new, reconstructed, or 

modified thermal dryers at Portland 

cement manufacturing plants in 

situations where the thermal input is 

not supplied by cement kiln or clinker 

cooler exhaust. Other subpart Y affected 

facilities located at Portland cement 

manufacturing plants (e.g., storage 

systems, conveyors) also are subject to 

subpart Y. 

Comment: One commenter requested 

that thermal dryers fired with process 

gases at integrated iron and steel plants 

be exempted from the subpart Y 

emission limits for SO2 and NOX/CO. 

Reasons presented by commenter to 

support the requested exemption are 

summarized below. 

• The pulverized coal injection 

systems at some integrated iron and 

steel plants also burn process gases (i.e., 

blast furnace gas or coke oven gas) as 

the primary fuel in thermal dryers. 

These process gases are valuable 

substitutes for other sources of 

purchased energy and are produced onsite. However, they have lower heating 

values than natural gas and must be 

consumed on-site to be utilized most 

effectively, or be flared. As is the case 

for waste heat, the use of these gases 

improves overall plant energy efficiency 

and reduces GHG emissions and should 

not be discouraged by applying 

unachievable emission limits when 

used for thermal drying of coal. 

• The use of these process gases for 

coal drying will not generate any more 

emissions than if the gases are 

combusted elsewhere or flared. Instead, 

if the process gases burned for coal 

drying were replaced entirely by 

burning natural gas, emissions (mainly 

NOX and CO) from the integrated iron 

and steel plant would actually increase. 

Establishing emission limits for thermal 

dryers using these process gas fuels will 

only serve to discourage their use. 

• The proposed subpart Y standards 

are based on the assumption that 

thermal dryers located at traditional 

mine sites and coal preparation plants 

are typically fired with coal, but in the 

examples noted above, other fuels are 

normally used. At the very least, the 

final rule should include a provision to 

allow operators of thermal dryers fired 

by natural gas, waste heat, or process 

gases to apply for a variance upon 

demonstration that emissions of SO2, 

NOX, CO and/or PM are well below the 

prescribed standards. Upon such a 

demonstration, monitoring requirements 

for these pollutants should be reduced 

or eliminated. 

Response: As previously noted, EPA 

has maintained that coal preparation 

and processing plants may be found at 

industrial sites such as those described 

by the commenter. In the Response to 

Comments document for the October 24, 

1974, proposal, EPA stated ‘‘[t]he 

specific coal processing operations 

regulated by these standards are affected 

regardless of whether they are located in 

coal liquefaction plants, power plants, 

coke ovens, etc.’’ (see ‘‘Background 

Information for Standards of 

Performance: Coal Preparation Plants; 

Volume 3: Supplemental Information. 

January 1976. p. 22). Thus, EPA has not 


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changed its interpretation. In addition, 

EPA has made no assumptions as to the 

source of the heat used in the thermal 

dryer as the commenter suggests. 

However, as noted above for Portland 

cement plants, EPA agrees that in the 

case of an affected source at an 

integrated iron and steel manufacturing 

facility, where the emissions from the 

thermal dryer would be considered as 

part of the blast furnace or coke oven 

emissions, the facility should be 

regulated under the appropriate steel 

mill or coke oven NSPS. As previously 

explained, EPA’s intent at this time is to 

regulate emissions from a thermal dryer 

only in circumstances where coal, coal 

refuse, or residual oil are used as 

thermal input. Thermal dryers that use 

residual or waste heat from the 

combustion of these fuels would only be 

subject to the PM and opacity standards. 

Indirect thermal dryers for which the 

source of heat is subject to SO2, NOX, 

and/or CO limits under another 40 CFR 

part 60 subpart would not be subject to 

the emission limits for SO2 and NOX/ 

CO. In addition, affected thermal dryers 

for which all of the thermal input is 

supplied by gaseous fuels (e.g., blast 

furnace gas, coke oven gas, natural gas) 

or distillate oil also would not be 

subject to the emission limits for SO2

and NOX/CO. 

C. Subcategorization 

Comment: Numerous commenters 

stated that when establishing standards 

of performance for new stationary 

sources under the CAA, section 

111(b)(2) authorizes the Administrator 

to ‘‘distinguish among classes, types and 

sizes within categories of new sources.’’ 

The commenters requested that the final 

amendments to subpart Y include a 

distinction between the regulatory 

requirements for coal preparation plants 

associated with coal mines (i.e., the 

‘‘producers’’) and for coal preparation 

plants at coal-fired power plants and 

large industrial sources such as cement 

manufacturing and coke ovens (i.e., the 

‘‘users’’). The commenters cited the 

following regulatory requirement and 

facility characteristics distinctions 

between coal producers and coal users 

to support their request. 

• Most new coal-fired power plants as 

well as large industrial coal-fired 

sources (i.e., the ‘‘users’’) in the future 

will be major sources of PM emissions 

and, therefore, be required to use stateof-the-art control technologies (i.e., best 

available control technology (BACT)). In 

contrast, surface coal mines with coal 

preparation facilities as well as standalone coal preparation facilities 

associated with coal mines (i.e., the 

‘‘producers’’) are typically minor 

sources and will not be subject to BACT 

under the Prevention of Significant 

Deterioration (PSD) program but rather 

to control technology requirements of 

Minor New Source Review (NSR) 

programs of individual States. Thus, 

adoption of industry sectors-based 

subcategorized emission standards for 

subpart Y should be considered so that 

a BACT level of control is not mandated 

as NSPS for ‘‘producers.’’ 

• Resource requirements to maintain 

and demonstrate compliance with the 

subpart Y emission standards is a 

function of the number of affected 

facilities at a particular coal preparation 

plant. Coal preparation plants of 

‘‘producers’’ tend to have more sizing, 

cleaning and overall ‘‘handling’’ 

operations than the typical preparation 

plant at a coal-fired ‘‘user.’’ 

Consequently, as a general rule, the total 

number of affected facilities at a 

‘‘producer’s’’ coal preparation plant will 

be greater than the number of such 

facilities at the preparation plant of a 

‘‘user.’’ Moreover, a single affected 

facility associated with coal mining can 

frequently have multiple points of 

fugitive emissions. With more affected 

facilities per source and more emission 

points per affected facility, preparation 

plants associated with coal mining 

generally will have much greater 

monitoring/recordkeeping/reporting 

requirements than will its preparation 

counterparts at coal-fired ‘‘user’’ 

sources. 

• Fugitive dust from surface coal 

mines is already regulated by U.S. 

Department of the Interior regulations in 

30 CFR Parts 700–899 under authority 

of SMCRA, and the existing air 

pollution control requirements imposed 

on coal mines by SMCRA must be 

accounted for. Commenters believe that 

an EPA examination of SMCRA’s dust 

control requirements in the context of 

possible NSPS regulation of preparation 

facilities at coal mines would result in 

a conclusion that concurrent regulation 

with similar CAA requirements is not 

appropriate. 

Response: The subpart Y NSPS covers 

coal preparation and processing plants 

that may be found, as the commenter 

notes, both at mine sites (‘‘producers’’) 

and at industrial sites (‘‘users’’). In the 

Response to Comments document for 

the October 24, 1974, proposal, EPA 

stated ‘‘[t]he specific coal processing 

operations regulated by these standards 

are affected regardless of whether they 

are located in coal liquefaction plants, 

power plants, coke ovens, etc.’’ (See 

‘‘Background Information for Standards 

of Performance: Coal Preparation Plants; 

Volume 3: Supplemental Information.’’ 

January 1976. p. 22.) 

Commenters’ request that EPA create 

a separate category for coal preparation 

and processing facilities at ‘‘producers’’ 

appears to be based on the assertion that 

these facilities should not be required to 

install and operate emissions control 

technologies that are currently in use or 

will be used at coal preparation and 

processing facilities at ‘‘users.’’ A 

primary objective of CAA section 111, 

however, is to require new sources to be 

built using the best system of emissions 

reduction that has been adequately 

demonstrated. Under CAA section 111, 

EPA is required to set standards of 

performance (i.e., standards that reflect 

the degree of emission limitation 

achievable through the application of 

the best system of emission reduction). 

As the Court has noted, ‘‘Section 111 

looks toward what may fairly be 

projected for the regulated future, rather 

than the state of the art at present, since 

it is addressed to standards for new 

plants.’’ Portland Cement, 486 F.2d at 

391. In developing NSPS standards, 

EPA must identify all technologies in 

use or being developed for use to 

determine that the Administrator 

determinations have been adequately 

demonstrated. This analysis must take 

into account the cost of achieving the 

reductions and any nonair quality 

health and environmental impacts and 

energy requirements. This analysis is 

separate and distinct from any BACT 

analysis that may be done for an 

individual plant. Finally, EPA disagrees 

with the comment to the extent it 

suggests that EPA should not consider 

technologies determined to be BACT for 

an individual plant in its BDT analyses. 

Control technologies change and can 

improve over time and EPA does not 

believe that it would be appropriate for 

EPA to ignore these developments when 

evaluating what currently constitutes 

BDT for this source category. 

The commenters point out that 

preparation plants associated with coal 

mining generally have more affected 

facilities per source and more emission 

points per affected facility. Commenters 

have not suggested, however, and EPA 

has no reason to believe, that the types 

of emissions from coal preparation and 

processing sources associated with coal 

mines differ from the types of emissions 

from those same source types at ‘‘user’’ 

facilities. They further have not 

demonstrated, and EPA has no reason to 

believe, that emission control 

technologies that are adequately 

demonstrated for facilities at ‘‘user’’ 

facilities would not be adequately 

demonstrated for use at facilities located 

at mines. Thus, EPA continues to 

believe it is appropriate to regulate these 


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sources in the same manner and sees no 

need to establish subcategories at this 

point. Further, the comment could be 

read to suggest that a separate 

subcategory should be created for 

facilities at mines because these 

facilities are subject to differences in the 

degree of control required by other 

regulations or because these facilities 

are currently achieving different levels 

of control or using different emission 

control technologies. EPA does not 

believe it would be appropriate to create 

a separate subcategory on these bases. 

Further, these factors do not affect what 

technologies could be found to be 

‘‘adequately demonstrated’’ or the 

emission reductions available from 

those technologies. 

In addition, the regulation of fugitive 

dust from surface coal mines under 

SMCRA by the Department of Interior 

does not, as commenters suggest, result 

in a ‘‘conclusion that concurrent 

regulation with similar CAA 

requirements would not be 

appropriate.’’ 

The October 1974 Background 

Information Document stated that ‘‘Coal 

preparation’’ is a segment of the coal 

industry that encompasses operations 

between the mining of raw coal and the 

distribution of product coal. (See 

‘‘Background Information for Standards 

of Performance: Coal Preparation Plants; 

Volume 1: Proposed Standards. October 

1974. p. 1.) The support document for 

the April 1981 NSPS review states that 

‘‘[t]he first step in the coal preparation 

process is the delivery of ROM [run of 

mine] coal to the plant site.’’ (See ‘‘A 

Review of Standards of Performance for 

new Stationary Sources—Coal 

Preparation Plants. December 1980. p. 

2–3.) 

EPA’s Office of Water has included 

the following definitions in their 

regulations for the coal mining industry 

(at 40 CFR 434.11). 

(b) The term ‘‘active mining area’’ 

means the area, on and beneath land, 

used or disturbed in activity related to 

the extraction, removal, or recovery of 

coal from its natural deposits. This term 

excludes coal preparation plants, coal 

preparation plant associated areas and 

post-mining areas. 

(e) The term ‘‘coal preparation plant’’ 

means a facility where coal is subjected 

to cleaning, concentrating, or other 

processing or preparation in order to 

separate coal from its impurities and 

then is loaded for transit to a consuming 

facility. 

Thus, EPA, in both the air and water 

offices, has maintained a distinction 

between the ‘‘active mining area’’ and 

the ‘‘coal preparation plant.’’ The 

process of ‘‘coal preparation’’ generally 

involves, among other things, separation 

of coal from impurities (i.e., ‘‘breaking’’ 

or ‘‘crushing’’). As discussed in the 

response to comment 3.4.1.1.1 in the 

Response to Comments Document, EPA 

interprets the ‘‘beginning’’ of the ‘‘coal 

preparation plant’’ to be the first hopper 

(i.e., ‘‘drop point’’) for receipt of coal 

from any form of transportation. 

D. Coal Drying Standards 

Comment: Two commenters 

supported EPA’s decisions not to set 

separate limits for fine PM (FPM) (i.e., 

PM2.5 or PM10) or condensable PM 

(CPM). In contrast, another commenter 

rejected EPA’s rationale presented in the 

May 27, 2009, supplemental proposal 

that EPA cannot set limits applicable to 

PM10, PM2.5, and CPM emissions 

because EPA has insufficient data and 

lacks a consistent measurement 

methodology to collect the needed data. 

The commenter stated that EPA’s failure 

to gather such data does not excuse EPA 

from a statutory obligation, that FPM 

and CPM emissions standards can be set 

pending resolution of any measurement 

issues by a future date certain, and, 

should EPA conclude that an inability 

to accurately measure emissions of FPM 

and CPM from dryers renders the 

implementation of FPM or CPM 

standards of performance infeasible, 

EPA must impose a design, equipment, 

work practice, or operational standard, 

or combination thereof. 

Response: EPA stands by the rationale 

presented in the May 27, 2009, subpart 

Y supplemental proposal notice. That is, 

the available PM emissions data for 

thermal dryers collected by EPA were 

measured using EPA Method 5 (see 40 

CFR 60, appendix A–3). For this 

method, solid FPM is collected 

isokinetically on a filter media 

(typically glass or quartz fiber) and is 

then measured gravimetrically to 

determine FPM emissions. Method 5, 

when performed correctly, provides an 

accurate measurement of total FPM (for 

PM > 0.3 μ), but does not measure FPM 

emissions by particle size distribution 

(i.e., PM10 or PM2.5), nor does the 

method measure CPM. EPA is revising 

existing test methods, EPA Method 

201A—Determination of PM10

Emissions (Constant Sampling Rate 

Procedure) and EPA Method 202— 

Determination of Condensible 

Particulate Emissions from Stationary 

Sources, to provide test methods that 

will accurately measure PM10, PM2.5, 

and CPM from stationary sources such 

as coal thermal dryers. Amendments to 

these test methods were proposed on 

March 26, 2009 (see 74 FR 12970). The 

amendments to Method 201A add a 

particle-sizing device to allow for 

sampling of PM2.5, PM10, or both PM10

and PM2.5. The amendments to Method 

202 revise the sample collection and 

recovery procedures of the method to 

provide for more accurate and precise 

measurement of CPM. Methods 201A 

and 202 are not yet finalized and 

sufficient test data using these methods 

has not yet been collected for coal-fired 

thermal dryers. For these reasons, EPA 

is not currently able to determine 

whether or not it would be appropriate 

to add separate PM emission limits to 

subpart Y for PM2.5, PM10, or CPM 

emissions from coal-fired thermal dryers 

and would not currently be able to 

establish national standards to address 

PM2.5, PM10, or CPM emissions. 

Comment: One commenter disagreed 

with EPA’s rationale for not setting coal 

dryer VOC standards. Specifically, the 

commenter disagrees with (1) EPA’s 

decision to not set standards for VOC 

and CO that reflect use of a gas 

recirculation thermal dryers, although 

EPA asserts that VOC and CO emissions 

would be minimized because new 

thermal dryers are likely to use a gas 

recirculation design; (2) EPA’s assertion 

that not setting a standard for VOC is 

reasonable because by setting an 

emissions limit that contains a CO 

emissions rate, the VOC emissions that 

result from incomplete combustion also 

are minimized; and (3) EPA’s assertions 

that VOC standards cannot be 

established because a method of control 

beyond combustion controls has not 

been identified and the variability of 

VOC emissions from the coal bed 

preclude determination of a standard 

that would be achievable nationwide. 

Response: EPA has discretion to 

determine which pollutants are 

appropriate for regulation in a particular 

NSPS. In this case, for the reasons 

noted, EPA concluded that it was not 

appropriate or feasible to establish a 

standard of performance for VOC 

emissions from coal preparation and 

processing plants at this time. This 

conclusion does not prohibit EPA from 

establishing such a standard in a future 

rulemaking. EPA disagrees with the 

commenter’s suggestion that a standard 

could be based on oxidation of VOC in 

a recirculation thermal dryer. As noted 

elsewhere, EPA has concluded that 

there is no one thermal dryer design that 

will work in all situations found within 

the industries utilizing coal preparation 

and processing plants. Control of VOC 

emissions through activated carbon 

absorption or regenerative thermal 

oxidizers are not utilized on thermal 

dryers at coal preparation and 

processing plants; further, EPA did not 

have other information showing that 


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these technologies are adequately 

demonstrated for use on coal 

preparation and processing plant 

sources. VOC emissions vary, in part, 

due to the variability in volatile 

contents of the coals being processed; 

absent demonstrated control technology, 

this variability can not be addressed 

through add-on technology as it is with 

variable sulfur contents of coal. Thus, 

EPA believes its decision not to 

establish VOC emission limits under 

subpart Y at this time is appropriate. 

Comment: One commenter stated that 

the proposed standards for coal drying 

failed to meet the basic legislative 

requirements of CAA section 111. The 

commenter presented the following 

reasons to support the position that for 

EPA to comply with CAA section 111, 

EPA must set standards based on the 

best demonstrated technologies for 

drying coal not for the thermal drying of 

coal through the application of heat 

generated by coal combustion 

specifically for that purpose. 

• CAA section 111 defines ‘‘standard 

of performance’’ to mean ‘‘a standard for 

emissions of air pollutants which 

reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated’’ [42 U.S.C. 7411(a)(1))]. 

• Another provision in CAA section 

111 provides that standards of 

performance must represent the best 

‘‘technological system of continuous 

emission reduction,’’ see, e.g., 42 U.S.C. 

7411(g)(4), which is defined to include 

‘‘a technological process for production 

or operation by any source which is 

inherently low-polluting or 

nonpolluting’’ [42 U.S.C. 7411(a)(7)(A)]. 

This provision further demonstrates that 

EPA must evaluate mechanical, indirect, 

and recirculation dryers, as each is 

inherently low polluting, in comparison 

to once-through coal-fired thermal 

dryers. 

• CAA section 111 requires ‘‘specific 

and rigorous limits on the amounts of 

pollutants that may be emitted.’’ 

ASARCO, Inc. v. EPA, 578 F.2d 319, 322 

(DC Cir. 1978). The legislative history of 

this requirement confirms Congress’s 

determination that ‘‘[t]he maximum use 

of available means of preventing and 

controlling air pollution is essential to 

the elimination of new pollution 

problems * * *’’ S. Rep. No. 1196, 91st 

Cong., 2d Sess. at 16. In revising the 

standards of performance for coal 

preparation plants, EPA may not simply 

codify existing levels of performance. 

• Because NSPS apply only to new, 

modified, or reconstructed sources and 

must reflect application of the best 

demonstrated system of reduction, they 

do not have to be achievable for all 

types of existing sources. See Portland 

Cement, 486 F.2d at 391. Nor can EPA 

forego setting limits reflecting the best 

demonstrated system merely because 

some sources may prefer a different 

system, ASARCO, 578 F.2d at 322 

(‘‘NSPS are designed to force new 

sources to employ the best 

demonstrated systems of emission 

reduction.’’). The legislative history of 

CAA section 111 demonstrates that 

Congress intended for EPA to prescribe 

standards that override the design 

preferences of regulated sources: ‘‘[T]he 

emission standards shall provide that 

sources of such emissions shall be 

designed and equipped to prevent and 

control such emissions to the fullest 

extent compatible with the available 

technology and economic feasibility. 

* * * ’’ H.R. Rep. No. 1146, 91st Cong., 

2d Sess. at 10 (emphasis added). Thus, 

EPA’s assumption that NSPS must be 

set at levels lenient enough to 

accommodate all types of existing 

dryers is contrary to Congress’ plainly 

expressed intent. 

• CAA section 111 ‘‘looks toward 

what may fairly be projected for the 

regulated future, rather than the state of 

the art at present. * * *’’ Portland 

Cement Assn v. Ruckelshaus, 486 F.2d 

375, 391 (DC Cir. 1973). An ‘‘achievable 

standard is one * * * within the realm 

of the adequately demonstrated system’s 

efficiency and which, although not at a 

level that is purely theoretical or 

experimental, need not necessarily be 

routinely achieved within the industry 

prior to its adoption.’’ Essex Chemical 

Corporation v. Ruckelshaus, 486 F.2d 

427, 433–34 (DC Cir. 1973). Instead of 

looking toward a future of mechanical 

dryers and indirect thermal dryers, or 

even gas-fired recirculation thermal 

dryers, the proposed standards attempt 

to lock-in standards that reflect the 

performance of coal-fired once-through 

thermal dryers. 

• Even assuming for the sake of 

argument that it is permissible to set a 

standard for emissions from coal drying 

that presumes the use of thermal dryers, 

the proposed rule violates the 

straightforward intent of Congress. 

Congress purposefully chose the 

superlative ‘‘best’’ to describe the 

system of emissions reductions on 

which the NSPS were to be based [42 

U.S.C. 7411(a)(1)]. Moreover, one of the 

enumerated purposes of the NSPS was 

to create incentives for new technology. 

CAA Conference Report: Statement of 

Intent; Clarification of Select Provisions, 

123 Cong. Rec. 27071 (1977). However, 

instead of proposing standards based on 

the performance of the cleanest new 

coal drying technologies, the proposal 

sets lax standards and then allows a mix 

of coal drying technologies to meet 

those standards. 

Response: EPA followed the statutory 

requirements of CAA section 111 in its 

review of the existing standard of 

performance for thermal dryers at coal 

preparation and processing plants. The 

review was conducted pursuant to the 

requirement in section 111(b)(1)(B) that 

EPA review and revise, if appropriate, 

the previously promulgated standards of 

performance. Section 111(b)(1)(B) 

requires EPA, when revising the 

standards, to follow the procedure 

required for the promulgation of 

standards. Section 111b(1)(B) further 

requires publication of proposed 

regulations, an opportunity for written 

comment, and requires the 

Administrator to promulgate such 

standards as she ‘‘deems appropriate.’’ 

The commenter correctly noted that a 

standard of performance is defined as ‘‘a 

standard for emissions of air pollutants 

which reflects the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated.’’ 42 U.S.C. 7411(a)(1). 

The commenter, however, takes the 

language from 42 U.S.C. 7411(g)(4) out 

of context. CAA section 111(g)(4) 

provides that the Administrator shall 

revise a standard of performance upon 

application of the Governor of a State 

that meets certain criteria. The language 

quoted by the commenter appears in 

this section and describes what must be 

included in the application of the 

Governor, and does not modify the 

definition of a standard of performance 

in section 111(a)(1). 

To determine the appropriate level for 

a particular standard of performance, 

EPA conducts an analysis to determine 

what emission rates reflect application 

of ‘‘best demonstrated technology’’ or 

BDT. This BDT analysis includes 

consideration of available emission 

controls and technologies. In the BDT 

analysis for controlling PM emissions 

from coal dryers for this final rule, EPA 

explicitly considered alternate processes 

for drying coal as well as add-on 

emission control technologies. For 

modified facilities, EPA recognized the 

limitations that may be associated with 


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the physical layout of existing dryers. 

For reconstructed facilities and new 

facilities, however, we concluded that 

design options, and alternative 

replacement technologies, could be 

taken into account during the 

reconstruction or construction process. 

EPA concluded that recirculation 

thermal dryers and indirect thermal 

dryers are both adequately 

demonstrated and readily available 

technologies for drying coal. It did not 

restrict its analysis, or the definition of 

affected facility, to the once-through 

direct contact thermal dryers covered by 

the existing NSPS standards for thermal 

dryers. Contrary to the commenter’s 

assertions, EPA neither presumed the 

use of existing once-through direct 

contact thermal dryers nor merely 

codified existing levels of performance 

achieved by such dryers. Instead, EPA 

concluded that BDT for controlling PM 

emissions for new and reconstructed 

thermal dryers is fabric filters applied to 

recirculation thermal dryers and 

indirect thermal dryers. The PM 

standards in the final rule are based on 

these conclusions. 

Although mechanical coal drying 

technologies, because they do not burn 

fuel, may inherently produce lower air 

pollutant emissions compared to some 

thermal drying technologies, they may 

not be technically applicable, costeffective, or the most energy efficient for 

all possible coal drying applications that 

could be subject to subpart Y. EPA does 

not, at this time, have data to support a 

conclusion that standards based on an 

assumption that mechanical dryers are 

BDT would be achievable by the 

industry as a whole (see National Lime 

Ass’n v. EPA, 627 F.2d 416, 431 (1980)). 

Even though the ‘‘adequately 

demonstrated’’ requirement does not 

‘‘necessarily impl[y] that any [covered 

facility] now in existence be able to 

meet the proposed standards,’’ Portland 

Cement, 486 F.2d at 391, EPA must 

demonstrate that the standard is, in fact, 

achievable taking into consideration 

variables that may affect emissions in 

different circumstances and at different 

plants. National Lime, 627 F.2d at 433. 

In fact, the type of coal drying 

technology used at a given facility is 

influenced by a variety of factors, 

including type of facility, coal moisture 

reduction requirements, availability of 

waste heat sources at the coal 

processing location, and drying process 

energy requirements including electrical 

power consumption. Mechanical drying 

techniques are not suitable 

replacements for thermal dryers under 

all circumstances. Mechanical drying 

techniques can remove free moisture 

adsorbed onto the surface of the coal 

particles, as well as a portion of the 

hydroscopic moisture contained by 

capillary action within microfractures in 

the coal particles, but are ineffective at 

removing inherent moisture (and, thus, 

would only be applicable at preparation 

plants utilizing coal washing). Some 

type of thermal energy is required to 

remove the interstitial and molecular 

(inherent) moisture from the coal for 

applications where extremely low 

moisture content is desirable. Therefore, 

mechanical drying techniques are not 

suitable replacements for thermal dryers 

under all circumstances, and because 

waste heat is not available at all 

locations, thermal dryers using waste 

heat are not a technically possible 

substitute for thermal dryers in all 

situations. EPA will continue to follow 

the development of mechanical drying 

techniques. To the extent the 

commenter is suggesting that EPA 

should require use of a certain 

technology for drying coal and coal 

preparation plants, EPA notes that CAA 

section 111(h), 42 U.S.C. 7411(h)(1) only 

allows the Administrator to promulgate 

design, equipment, work practice, or 

operational standards if ‘‘in the 

judgment of the Administrator, it is not 

feasible to prescribe or enforce a 

standard of performance.’’ No such 

finding has been made here. 

In the BDT analysis for controlling 

SO2 emissions from coal dryers for the 

final rule, EPA determined that BDT for 

modified and reconstructed thermal 

dryers is a wet scrubber with a 

scrubbing reagent (e.g., an upgraded 

venturi scrubber with sodium hydroxide 

or packed bed scrubber with lime). The 

information that EPA has indicates that 

all of the once-through direct contact 

thermal dryers currently use venturi 

scrubbers for PM control. Thus, the 

upgraded venturi scrubber with sodium 

hydroxide or the packed bed scrubber 

with lime (would be in addition to the 

venturi scrubber) would provide SO2

control, along with additional PM 

control necessary for reconstructed 

thermal dryers to meet their PM and 

opacity limits. For new thermal dryers, 

we determined that BDT for controlling 

SO2 emissions is the injection of sodium 

hydroxide directly to the venturi 

scrubber fluid or injection of a sodiumbased sorbent into the combustion gases 

prior to the drying chamber. For a new 

once-through direct contact thermal 

dryer, the caustic injection into the 

scrubber fluid for SO2 control would be 

in addition to a high-energy venturi 

scrubber which is the likely control 

technology that would be used for PM 

and opacity control. For a new coal 

recirculation thermal dryer, sorbent 

injection into the combustion gases for 

SO2 control would be used in 

conjunction with a fabric filter which is 

the likely control technology that would 

be used for PM and opacity control. EPA 

determined that BDT for controlling 

NOX emissions from new, 

reconstructed, and modified thermal 

dryers is combustion controls. 

Combustion controls can be used across 

the range of thermal dryers currently in 

use. Combustion controls include low 

NOX burners, staged combustion, cofiring with natural gas or liquefied 

petroleum gas, and flue gas 

recirculation. BDT for controlling CO 

emissions was determined to be good 

combustion practices. Good combustion 

practices limit the formation of CO (and 

VOC) by providing sufficient oxygen in 

the combustion zone such that complete 

combustion can occur. Maintaining 

appropriate combustion zone 

temperature and gas residence time also 

are good combustion practices, as is 

proper operation and maintenance of 

the dryer. 

Comment: Several commenters stated 

that the proposed PM emission limit of 

0.010gr/dscf for new coal dryers does 

not reflect an adequate margin of 

compliance to the fabric filter test data 

used and that the proposed limit needs 

to be less stringent because the test data 

do not represent a demonstration of the 

performance of control technology over 

the life of the facility and over the range 

of operating conditions that may be 

encountered at thermal dryers. 

Therefore, the commenters 

recommended that the PM emission 

limit remain at the current NSPS 

emission rate of 0.031 gr/dscf. Other 

commenters presented an opposing 

argument that the proposed PM limit 

needs to be lower. The commenters 

asserted that the compliance margin of 

two to three times applied by EPA to 

fabric filter test data is unjustified in 

that EPA has not explained why use of 

a fabric filter to control PM emissions 

would require such a large margin of 

safety, given the demonstrated 

performance of fabric filters for the 

subject source as well as similar sources 

in numerous other industries. 

Response: EPA has reviewed the 

available PM emissions and permit data 

for thermal dryers; no additional PM 

data were provided during the public 

comment period. We believe that the 

proposed PM limit of 0.023 g/dscm 

(0.010 gr/dscf) for new thermal dryers is 

appropriate. We further believe that, in 

the presence of limited data showing 

actual emissions, permit information 

can be useful in determining whether a 

particular emission limit is achievable 


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by sources in the source category. EPA 

has available three emission test data 

points for fabric filters installed on 

thermal dryers, including two tests one 

year apart at one facility. We believe 

that these three data points provide 

adequate information on the 

performance of the technology. 

However, EPA also has examined the 

permit data which identifies emission 

limits agreed upon between State 

regulators and the regulated community 

and believe that the emission limits 

contained in permits constitute limits 

that could be achieved over the range of 

operating conditions to be found within 

the industry. Nat’l. Lime Ass’n. v. EPA, 

627 F.2d 416, 431 (DC Cir. 1980) 

requires EPA to show that the limit 

selected is achievable under different 

conditions at an individual plant and 

conditions at different plants. EPA 

believes that basing the emission limit 

on use of the data points from two 

facilities, including two data sets from 

one facility, in conjunction with the 

permit data, adequately accounts for the 

variability to be found within the 

industry. Therefore, the final rule 

reflects no changes to the proposed PM 

emission limit for new thermal dryers. 

Comment: Two commenters 

supported the proposal to revise the PM 

limit for units reconstructed after April 

28, 2008, to 0.045 g/dscm (0.020 gr/dscf) 

and to maintain the existing 1976 rule’s 

opacity limit of less than 20 percent. In 

contrast, a third commenter disagreed 

with the proposed PM standard for 

reconstructed dryers, which is twice as 

high as the proposed standard for new 

dryers (0.010 gr/dscf). The commenter 

stated that EPA must either require 

reconstructed dryers to meet the same 

PM standards as new dryers, or explain 

why such limits do not reflect BDT for 

reconstructed dryers. The commenter 

further stated that EPA has not 

explained why it would not also be 

feasible to further modify existing 

dryers, at the time of reconstruction, by 

converting them to recirculation dryers 

or by otherwise modifying them to use 

fabric filters, and that EPA must 

examine whether a fabric filter is a 

feasible option for control of PM 

emissions from reconstructed dryers. 

Another commenter recommended that 

the PM emission limitations not be 

changed from the current NSPS 

emission rate of 0.031 gr/dscf. The 

commenter believes that the limited 

data EPA has cited to justify reducing 

the limit by a third for reconstructed 

dryers using the same control 

technology is insufficient to conclude 

that thermal dryers with the specified 

control equipment would, throughout 

the life of the facility, be able to 

continuously meet a lower emission 

limit than the current NSPS provide. 

Response: EPA agrees that units 

undergoing reconstruction as defined in 

the CAA could undergo the conversions 

necessary to install BDT for PM 

emissions control for new thermal 

dryers and, thus, meet the PM and 

opacity limits of new facilities. Thus, 

the regulation has been changed 

accordingly. 

Comment: One commenter stated that 

information in the supplemental 

proposal preamble and support 

documentation show that the SO2

emissions limits for new and 

reconstructed coal dryers should be set 

lower than the proposed level. The 

commenter explained that the proposal 

preamble states that ‘‘[w]et scrubbers 

designed specifically for SO2 control are 

able to achieve greater than 95 percent 

reduction.’’ EPA, however, dismisses 

wet scrubbers from further 

consideration, as the wet scrubbers 

currently used on existing thermal 

dryers are designed for PM control and 

not specifically for SO2 controls, and 

high levels of SO2 control may be 

difficult to achieve without redesign of 

the wet scrubber. The commenter 

asserted that this is not a valid reason 

for eliminating a viable technology from 

consideration, and that wet scrubbers 

are widely used on similar sources and, 

as EPA recognizes, routinely achieve 

greater than 95 percent reduction. Even 

if EPA ultimately determines that wet 

scrubbers are not BDT for SO2 control 

for some coal dryers, the commenter 

stated that the subpart Y SO2 emission 

limit must be more stringent for those 

dryers. The commenter cited as support 

EPA’s assertion that sorbent injection 

controls that use sodium-based agents 

can meet removal efficiencies of 90 

percent. 

Response: EPA indicated in the May 

27, 2009, supplemental proposal that it 

was considering an SO2 percent 

reduction requirement of between 50 

and 90 percent for the final rule (74 FR 

25311). EPA has reviewed the available 

data and believes that a 90 percent 

removal requirement is appropriate for 

new, reconstructed, and modified 

thermal dryers. Affected facilities that 

meet the alternative SO2 emissions limit 

of 85 ng/J (0.20 lb/MMBtu) heat input 

are not required to meet this 

requirement. 

Comment: Many commenters stated 

that EPA’s proposal to set a combined 

NOX and CO emissions limit for coal 

dryers is inappropriate. Another 

commenter stated explicitly that 

separate NOX and CO emissions limits 

must be set for coal dryers. Reasons 

cited by individual commenters include 

the following. 

• A combined NOX/CO limit enables 

permitting authorities to trade off higher 

NOX emissions for lower CO emissions, 

and vice versa. EPA’s proposed 

approach of allowing States to trade 

NOX and CO emissions at essentially a 

1:1 ratio ignores that CO and NOX are 

different pollutants that do not have 

equivalent environmental impacts. 

• A combined NOX/CO limit violates 

CAA for the reason that the proposed 

combined limit is based on an assumed 

CO emissions rate that does not reflect 

application of the best system of 

emission reduction. EPA admits that the 

presumed levels of CO emissions (0.45 

lb/MMBtu for modified and 

reconstructed dryers and 0.25 lb/ 

MMBtu for new dryers) are levels that 

are already surpassed by nearly all 

existing industrial boilers and has not 

explained why industrial boilers would 

be capable of meeting more stringent CO 

limits than thermal dryers. 

• Test data provided in the docket 

indicates a wide variation in test results, 

especially for CO. Test data is almost 

exclusively based on bituminous coal 

drying operations, and these data do not 

support the conclusion that the 

proposed combined NOX/CO limit is 

applicable across all grades of coal. 

• Combustion controls currently 

represent BDT in use by the source 

category. Going beyond the 

demonstrated technologies for the 

source category (e.g., incorporating post 

combustion control technologies, 

specifically selective non-catalytic 

reduction (SNCR) on new thermal 

dyers) is not required in developing 

NSPS. 

• EPA does not have sufficient data to 

support the proposed NOX standards, 

and EPA has not demonstrated that 

thermal dryers with different design and 

function can meet the same limitations 

as coal-fired boilers. Also, EPA has 

identified combustion controls that may 

not be available as the basis for the 

proposed NOX standards, especially for 

existing thermal dryers. 

Response: EPA believes that the use of 

a combined NOX/CO limit is 

appropriate because it acknowledges the 

inherent trade-off between the two 

pollutants (i.e., a decrease in emissions 

of one often leads to an increase in 

emissions of the other). EPA has based 

the combined NOX/CO limit on what it 

believes to be adequate data from 

thermal dryers at subpart Y facilities; 

thus, the comparison to industrial 

boilers is misplaced. In addition, as the 

Court has noted, ‘‘[t]he ‘adequately 

demonstrated’ requirement does not 

imply that any [covered facility] now in 


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existence be able to meet the proposed 

standards. CAA section 111 looks 

toward what may be fairly be projected 

for the regulated future, rather than the 

state of the art at present.’’ Portland 

Cement Ass’n v. Ruckelshaus, 486 F.2d 

375, 391 (DC Cir. 1973). 

E. Coal Processing and Conveying 

Equipment, Coal Storage Systems, 

Transfer and Loading Systems, and 

Open Storage Piles Standards 

Comment: Many commenters 

acknowledged EPA’s decision in the 

supplemental proposal to add fogging 

systems and passive enclosure 

containment systems (PECS) to its list of 

BDT for coal processing and conveying 

equipment, but stated that EPA’s BDT 

determination still failed to meet the 

requirements of CAA § 111. Additional 

commenters also disagreed with EPA’s 

finding of chemical suppression to be 

BDT for coal handling equipment 

processing bituminous coal, stating that 

EPA’s current BDT approach of focusing 

only on emission control systems with 

the highest control efficiency is an 

inappropriate, unjustified departure 

from its prior technology assessments 

for coal preparation plants. Commenters 

stated that EPA’s evaluation of 

technologies for control of fugitive 

emissions from coal-handling should 

have included wet suppression. Further, 

commenters asserted that EPA must 

explain why it has either rejected or 

ignored Peabody Energy’s compelling 

comparison of wet suppression costs 

and chemical suppression costs. The 

commenters believe that the record 

demonstrates that cost considerations 

favor the use of wet suppression instead 

of chemical suppression for controlling 

fugitive emissions from preparation 

facilities at coal mines. 

Response: As pointed out by the 

commenters, EPA has added fogging 

systems and PECS as technologies 

representative of BDT for coal-handling 

equipment processing subbituminous 

and lignite coals (fabric filters and wet 

extraction scrubbers also are considered 

representative of BDT). As noted in the 

supporting documentation (see EPA– 

HQ–OAR–2008–0260–0083, pp. 1–2), 

EPA has reviewed our determination of 

chemical suppressants as BDT for coalhandling equipment processing 

bituminous coal. However, as also noted 

in the support document, an owner/ 

operator may use any combination of 

controls at a particular site as long as 

the requirements of subpart Y are met. 

With respect to Peabody Energy’s 

comparison of wet suppression and 

chemical suppression costs, their 

estimates indicate that the incremental 

cost of chemical suppression as 

compared to wet suppression is $4,400 

per ton of PM removed. 

Comment: Many commenters stated 

that the data used by EPA does not 

demonstrate the continuous 

achievability of the proposed opacity 

limit of 5 percent. Commenters further 

stated that the promulgation of NSPS 

based upon inadequate proof of 

achievability would defy the 

Administrative Procedure Act’s 

mandate against action that is arbitrary, 

capricious, an abuse of discretion, or 

otherwise not in accordance with the 

law. National Lime Ass’n v. EPA, 627 

F.2d 416, 430 (DC Cir. 1980). 

Response: In the May 27, 2009, 

supplemental proposal, EPA requested 

comment on whether an opacity limit of 

less than 10 percent is more appropriate 

than the proposed limit of 5 percent. We 

also requested comment on whether the 

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

conditions and whether the limit 

provides an adequate compliance 

margin. As we pointed out in 

supporting documentation (see EPA– 

HQ–OAR–2008–0260–0083, pp. 3–4), 

the data used to establish the 

supplemental proposal’s 5 percent 

opacity level were primarily from initial 

compliance tests, and the reported 

highest 6-minute average opacity 

reading was 5 percent for a recently 

installed facility. Data for coal handling 

facilities submitted by commenters in 

response to the supplemental proposal 

indicate that 60 percent of the highest 

6-minute average opacity readings are 

less than 10 percent. Upon 

reconsideration of EPA’s data and 

consideration of the public comments 

and supporting data, EPA has 

determined that an opacity limit of less 

than 10 percent is more appropriate for 

all coal-handling equipment. An opacity 

limit of 10 percent will allow for control 

equipment degradation, adverse 

conditions, and variability that would 

not be reflected in initial compliance 

tests. Thus, the final rule requires coal 

handling facilities to maintain opacity 

levels of less than 10 percent. 

Comment: Many commenters 

requested that subpart Y provide the 

same compliance alternative for affected 

sources located in enclosed buildings as 

that provided in 40 CFR part 60, subpart 

OOO. Under subpart OOO, performance 

standards and applicable monitoring 

techniques for the exhaust systems of 

these buildings have been specified as 

an appropriate alternative to individual 

compliance by each affected facility 

enclosed within the building. 

Commenters explained that building 

enclosure of certain coal handling and 

processing operations at coal 

preparation plants has become more 

commonplace throughout the industry 

for several reasons, including the ability 

to effectively control emissions and to 

protect personnel and equipment from 

the elements. These commenters urged 

EPA to extend this practical and 

achievable alternative to subpart Y and 

recognize within the rule the beneficial 

control technique of enclosing coal 

preparation facilities within buildings. 

Response: EPA has determined that if 

a building in which affected coal 

processing and conveying equipment 

(e.g., breakers, crushers, screens, 

conveying systems), coal storage 

systems, and coal transfer system 

operations are enclosed is found to be 

in compliance with the subpart Y limits 

applicable to the affected facilities 

enclosed in the building, then the 

affected facilities enclosed in that 

building also are in compliance. 

Because exhaust from a building that 

encloses affected facilities would be 

comprised of exhaust from the affected 

facilities, it follows that in order for the 

building to be able to meet a specific PM 

or opacity limit, each facility enclosed 

in the building also would have to meet 

that same PM or opacity limit. If the 

affected facilities enclosed in the 

building are subject to different 

emission limits, the affected facilities 

are deemed in compliance only if the 

building is in compliance with the most 

stringent of the limits applicable to the 

enclosed affected facilities. 

Comment: Many commenters stated 

that EPA does not have the authority to 

regulate coal storage piles under 40 CFR 

part 60. Section 60.1 provides that the 

provisions of 40 CFR part 60 ‘‘apply to 

the owner or operator of any stationary 

source which contains an affected 

facility * * * ’’ Stationary source is 

defined in section 60.2, consistent with 

42 U.S.C. 7411, as including any 

building, structure, facility or 

installation. Commenters asserted that 

although it is not clear that a coal pile 

constitutes a building, structure, facility 

or installation, if it does, under section 

60.1 the stationary source must also 

contain an affected facility. Further, 

affected facility is defined in section 

60.2 as ‘‘with reference to a stationary 

source, any apparatus to which a 

standard is applicable.’’ According to 

commenters, this latter definition 

presents a substantial problem in that if 

EPA wishes to regulate coal storage 

piles under 40 CFR part 60 as part of a 

stationary source, the coal storage piles 

must be an apparatus. At many facilities 

which manage coal, commenters 

explained that coal storage piles are 

nothing more than what the name 


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suggests: piles of coal, and these piles 

often have no walls, no floor surfaces, 

and no equipment associated with their 

use. Although the term ‘‘apparatus’’ is 

an undefined term under 40 CFR part 

60, commenters do not believe that a 

pile of minerals mined from the earth 

and stored on the earth constitutes an 

‘‘apparatus’’ which subjects the pile to 

regulation under 40 CFR part 60. 

Further, although the authority may not 

exist to regulate coal storage piles under 

40 CFR 60, commenters contend that 

this would not leave such storage piles 

unregulated. In many States, fugitive 

emissions from coal piles are regulated 

under State fugitive emissions 

limitations which are often incorporated 

into State implementation plans, and 

the commenters do not challenge those 

regulations. 

Response: EPA disagrees with 

commenters’ assertion that a coal pile 

cannot be an affected facility under 40 

CFR 60. Commenters correctly noted 

that the term ‘‘affected facility’’ is 

defined in section 60.2 to mean ‘‘with 

reference to a stationary source, any 

apparatus to which a standard is 

applicable.’’ The commenters also 

correctly note that the term ‘‘apparatus’’ 

is undefined in 40 CFR part 60, and an 

agency’s interpretation of its own 

regulation is granted substantial 

deference (see, e.g., Auer v. Robbins, 

519 U.S. 452, 461, 1997). 

The commenters do not offer a 

definition of ‘‘apparatus’’ but appear to 

suggest that to be an ‘‘apparatus’’ a coal 

pile would need to have ‘‘walls, floor 

surfaces, or equipment associated with 

their use.’’ The commenters, however, 

offer no support for this assertion, and 

EPA does not believe such a limited 

definition of ‘‘apparatus’’ would be 

reasonable or consistent with the plain 

English meaning of the word. Further, 

the Courts stated ‘‘In designating what 

will constitute a facility in each 

particular industrial context, EPA is 

guided by a reasoned application of the 

terms of the statute it is charged to 

enforce.’’ ASARCO Inc. v. EPA, 578 F.2d 

319, 324 n.17 (1978). In this case, 

because coal storage piles are significant 

sources of emissions and are physically 

located at coal preparation and 

processing plants, EPA believes it is 

reasonable in this context, to determine 

that they are facilities that can be 

subject to regulation. 

The dictionary definition of the word 

‘‘apparatus’’ also supports EPA’s 

approach. The word ‘‘apparatus’’ has a 

very broad meaning and can include 

tangible items such as equipment, tools 

and materials as well as intangible items 

such as activities and functions. The 

Random House College Dictionary: 

Revised Edition defines the word 

‘‘apparatus’’ as follows: 

1. A group or aggregate of instruments, 

machinery, tools, materials, etc. intended for 

a specific use. 2. any complex instrument or 

machine for a particular purpose. 3. any 

system of activities, functions etc. directed 

toward a specific goal: the apparatus of 

government. 4. a group of structurally 

different organs performing a particular 

function. 

Because a coal pile constitutes ‘‘a group 

or aggregate of * * * materials * * * 

intended for a specific use,’’ it qualifies 

as an ‘‘apparatus’’ under the first 

definition of the word. Furthermore, 

given the broad meaning of the term 

‘‘apparatus,’’ EPA believes it would not 

be reasonable to interpret this term to 

limit the scope of the definition of 

‘‘affected facility’’ to exclude a 

significant part of the coal preparation 

and processing plant that may have 

significant emissions. 

In addition, although commenters do 

not actually argue that a coal pile does 

not constitute a stationary source 

because it is not a building, structure, 

facility, or installation, EPA notes that 

there can be no doubt that a pile of coal 

does in fact qualify as a stationary 

source as that term is defined in 42 

U.S.C. 7411 and section 60.2. Stationary 

source is defined in 42 U.S.C. 7411 as 

including ‘‘any building, structure, 

facility or installation which emits or 

may emit any air pollutant.’’ This same 

definition appears in section 60.2. The 

terms building, structure, facility, or 

installation, are not defined although 

section 60.2 does contain definitions for 

‘‘affected facility’’ and ‘‘existing 

facility.’’ In some instances, the 

regulated affected facility may be a 

portion or a part of a stationary source, 

but not the entire source. In other 

circumstances, however, a stationary 

source may also be an affected facility. 

Because, as noted above a coal pile can 

be an affected facility it necessarily also 

can be a facility within the definition of 

stationary source. In addition, the terms 

installation and structure are very broad 

and not limited to things that have 

walls, floor surfaces or dedicated 

equipment. For these reasons, 

commenter’s assertion that coal piles 

cannot be regulated under 40 CFR part 

60 is without support. 

Comment: Several commenters stated 

that coal piles should not be regulated 

under subpart Y because of the diverse 

conditions affecting emissions from coal 

storage piles that could be encountered 

at each coal preparation plant site. 

Among the site-specific factors for open 

coal storage piles that will vary widely 

from site to site are the following: 

ambient temperature, precipitation, 

meteorology, wind speed, and 

geography. In addition, commenters 

stated that fugitive emissions will 

depend on coal properties and coal 

rank. Therefore, a uniform NSPS is not 

appropriate for coal piles and fugitive 

coal dust emissions from coal piles 

should be addressed by case-by-case 

determinations in individual permit 

proceedings. 

Response: EPA does not agree with 

the commenters that coal piles should 

not be regulated under subpart Y. Such 

sources were apparently included in the 

October 1974 proposed rule (i.e., there 

was no specific exclusion). A comment 

was received indicating that no fugitive 

dust control options were available for 

open storage piles other than water 

sprays and that these were not effective 

on windy days. EPA subsequently 

excluded open storage piles from 

regulation in the final rule (January 

1976). However, EPA has now identified 

additional control measures, beyond 

simple water sprays, that may be 

utilized on coal piles and that address 

the concerns noted by commenters. EPA 

is establishing work practice standards 

instead of standards of performance for 

coal piles. Owners/operators are 

required to develop a fugitive coal dust 

emissions control plan to control 

emissions from the coal piles, and the 

plan requirements established by EPA 

provide adequate flexibility for an 

owner/operator to tailor their plan to 

address site-specific factors. 

Comment: Several commenters stated 

that it is not feasible to establish 

emission standards for open storage 

piles or roadways, and if open storage 

piles are to be regulated by subpart Y 

then the only appropriate method for 

controlling PM emissions from such 

sources is by using work practice 

standards. Another commenter does not 

support establishing an opacity limit for 

open storage piles or roadways and 

concurred with the proposal to establish 

work practice standards instead of 

opacity or PM limits. If an opacity limit 

is established for storage piles, the 

commenter stated that it should be 

limited to stationary open storage piles 

not including piles of coal that have 

been loaded into trucks, railcars, and/or 

ships. An additional commenter 

disagreed that only work practices are 

suitable for controlling PM emissions 

open storage piles (and roadways). The 

commenter indicated that a 20 percent 

opacity limitation under subpart Y has 

been an existing applicable requirement 

for fugitive dust sources in the coalhandling system for decades, and it has 

not been proven infeasible to conduct 

opacity monitoring over all of those 

years. 


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Response: As explained in a later 

response, EPA is not finalizing its 

proposed requirements for roadways. 

EPA concurs that, at this time, it is not 

feasible to prescribe or enforce a 

standard of performance for open 

storage coal piles and has therefore 

promulgated work practice standards, 

which EPA believes provide the most 

effective method of limiting emissions 

from open storage piles. In addition, 

EPA believes that the size of open 

storage coal piles currently makes the 

use of Method 9 opacity observations 

unreasonable in many situations. 

Comment: Many commenters stated 

concerns about the inherent difficulties 

in determining when an open storage 

pile is ‘‘reconstructed’’ or ‘‘modified.’’ 

Commenters contend that there is 

simply no way that an ‘‘increase in the 

emission rate’’ of PM or any other 

pollutant could be measured with any 

certainty for an open coal storage pile. 

Unlike other ‘‘affected facilities’’ or 

plant equipment, commenters explained 

that open storage piles by their nature 

fluctuate in size and activity. As the 

subpart Y amendments were proposed, 

any time large coal inventory was added 

to an open storage pile and then 

reclaimed, subpart Y potentially could 

be triggered. Commenters stated that if 

EPA proceeds with the establishment of 

work practices for coal piles, EPA 

should provide clarification and 

guidance as to what constitutes a 

physical or operational change for an 

open storage pile through a subsequent 

rulemaking proposal that would allow 

public review and comment. 

Commenters requested that EPA limit 

the applicability of the subpart Y 

control requirements for coal storage 

piles to only new sources. 

Response: EPA agrees with the 

commenters that open storage piles are 

always changing (i.e., coal is being 

added and coal is being removed for 

processing) and, for purposes of subpart 

Y, we do not consider the routine 

addition and removal of coal to be a 

physical change or a change in the 

method of operation. A change to an 

open storage pile that requires the 

source’s operating permit be opened for 

revision may be a modification or 

reconstruction of the storage pile. 

Instances where a physical change or 

change in the method of operation of an 

open storage pile will result in an 

increase in emissions would be 

considered a modification or 

reconstruction (e.g., increasing the 

permitted size of the storage pile). 

Changes to the equipment used in 

loading, unloading, and conveying 

operations of open storage piles are 

among the things that can be assessed in 

order to determine when an open 

storage pile has been reconstructed or 

modified. Thus, in the final rule, EPA 

defines ‘‘open storage pile’’ to mean 

‘‘any facility, including storage area, 

that is not enclosed that is used to store 

coal, including the equipment used in 

the loading, unloading, and conveying 

operations of the facility.’’ The 

inclusion of a definition for ‘‘open 

storage pile’’ should provide additional 

clarification as requested by the 

commenters. In addition, 40 CFR 60.5 

provides that when requested to do so 

by an owner or operator, the 

Administrator will make a 

determination of whether action taken 

or intended to be taken by such owner 

or operator constitutes construction 

(including reconstruction) or 

modification or the commencement 

thereof within the meaning of this part. 

Comment: Several commenters agreed 

that piles of coal that have been loaded 

into trucks, railcars, and/or ships should 

not be subject to the subpart Y control 

requirements for open storage piles. In 

contrast, several other commenters 

disagreed with EPA’s stated rationale for 

proposing the exclusion. Specifically, 

commenters provided the following 

reasons: (1) EPA has not identified any 

information or data to support its 

statement that fugitive dust emissions 

from these sources are not significant; 

(2) it is not economically infeasible to 

require covering the coal or chemical 

encrustation on loaded trucks, railcars, 

and ships because operators may choose 

to use these controls to comply with 

State and local regulations or the desire 

to minimize the loss of coal while in 

transit; and (3) EPA did not consider the 

use of alternate work practice standards 

already identified as appropriate for 

open piles, including the use of wet 

suppression. Commenters further stated 

that EPA should recognize that the 

owners/operators of coal preparation 

plants, as the ones who determine the 

placement of coal into trucks, railcars, 

and ships, and as the ones who initiate 

the use of any appropriate controls, are 

uniquely situated to take the steps most 

effective at reducing or limiting fugitive 

dust emissions from these sources once 

they leave the facility. Although some of 

the emissions from piles loaded into 

trucks, railcars, and ships may occur 

beyond the boundaries of the coal 

preparation plant, commenters stated 

that the extent of these emissions 

depends on actions taken at the coal 

preparation plant. 

Response: EPA is not addressing at 

this time emissions from the sources 

noted by the commenters because we 

found any such regulation to be 

impractical to enforce (particularly with 

regard to interstate shipments). Further, 

based on available data emissions from 

these sources while at the coal 

preparation and processing plant have 

not been shown to be significant and, at 

this time, EPA has no data on emissions 

from such sources while enroute. 

Comment: Many commenters 

requested clarification regarding the 

plant roadways to which EPA intends 

subpart Y to apply. Commenters stated 

that EPA should clarify that ‘‘roadways’’ 

such as haul roads that do not leave the 

plant property are not subject to subpart 

Y. Commenters also stated that EPA 

needs to clearly define where the coal 

preparation plant begins and where the 

coal mine ends, and that subpart Y is 

applicable only to affected facilities of a 

coal preparation plant. Other 

commenters disagreed with EPA’s 

proposal to exclude roadways that do 

not leave the property (e.g., haul roads 

at coal mines) from being subject to 

subpart Y. 

Response: As previously noted, EPA 

has decided not to finalize the work 

practice standards that were proposed 

for roadways. Emissions associated with 

roadways at both the ‘‘active mining 

area’’ and the ‘‘coal preparation plant’’ 

are also be subject to regulation under 

SMCRA. Under the definition of 

‘‘surface coal mining operations’’ 

contained in 30 CFR 70.5 (SMCRA), 

operations conducted within a coal 

preparation plant are covered under 

SMCRA: 

(a) Activities conducted on the surface of 

lands in connection with a surface coal mine 

* * * the products of which enter commerce 

or the operations of which directly or 

indirectly affect interstate commerce. Such 

activities include * * * the cleaning, 

concentrating, or other processing or 

preparation of coal. Such activities also 

include the loading of coal for interstate 

commerce at or near the mine site (emphasis 

added). 

Such operations also include roads 

(under 30 CFR 701.5). 30 CFR 780.15 

requires the following: 

(a) For all surface mining activities with 

projected production rates exceeding 

1,000,000 tons of coal per year and located 

west of the 100th meridian west longitude, 

the application shall contain an air pollution 

control plan which includes the following: 

(1) An air quality monitoring program to 

provide sufficient data to evaluate the 

effectiveness of the fugitive dust control 

practices proposed under paragraph (a)(2) of 

this section to comply with Federal and State 

air quality standards; and 

(2) A plan for fugitive dust control 

practices as required under 30 CFR 816.95. 

(b) For all other surface mining activities 

the application shall contain an air pollution 

control plan which includes the following: 

(1) An air quality monitoring program, if 

required by the regulatory authority, to 


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provide sufficient data to evaluate the 

effectiveness of the fugitive dust control 

practices under paragraph (b)(2) of this 

section to comply with applicable Federal 

and State air quality standards; and 

(2) A plan for fugitive dust control 

practices, as required under 30 CFR 816.95. 

30 CFR 816.95(a) specifies: 

All exposed surface areas shall be 

protected and stabilized to effectively control 

erosion and air pollution attendant to 

erosion. 

30 CFR 816.150 provides some 

additional requirements: 

(b) Performance standards. Each road shall 

be located, designed, constructed, 

reconstructed, used, maintained, and 

reclaimed so as to: 

(1) Control or prevent erosion, siltation, 

and the air pollution attendant to erosion, 

including road dust as well as dust occurring 

on other exposed surfaces, by measures such 

as vegetating, watering, using chemical or 

other dust suppressants, or otherwise 

stabilizing all exposed surfaces in accordance 

with current, prudent engineering practices 

* * * 

(e) Maintenance. (1) A road shall be 

maintained to meet the performance 

standards of this part and any additional 

criteria specified by the regulatory authority. 

Thus, SMCRA covers fugitive dust 

emissions from roads at coal preparation 

and processing plants at mine sites and 

requires a fugitive dust plan and other 

requirements to control air pollution 

from such sources (through similar 

measures as were included in the 

supplemental proposal for subpart Y). 

EPA believes that coal moving 

operations, once the coal enters the 

‘‘coal preparation plant,’’ will be by 

conveyor rather than by truck. 

Therefore, EPA believes that the 

requirements of SMCRA are sufficient to 

address air emissions from roadways 

that may be found within a coal 

preparation and processing plant at 

mine sites. For coal preparation plants 

at end-user facilities, EPA believes that, 

again, once the coal enters the ‘‘coal 

preparation plant,’’ coal moving 

operations will be by conveyor rather 

than by truck. Therefore, EPA has 

decided not to finalize the proposed 

requirements for roadways. 

Where fugitive coal dust emissions 

control plan requirements under subpart 

Y for open storage piles overlap 

requirements under SMCRA or State 

regulations, those sources may submit 

the more stringent of the required 

monitoring plans to the Administrator 

or delegated authority as required by 40 

CFR 60.254(c). 

Comment: One commenter requested 

that EPA delete the proposed fugitive 

emission control plan requirements 

from the final subpart Y amendments 

for the following reasons: (1) regulated 

entities have the right to know exactly 

what requirements apply to their 

facilities, particularly those applicable 

to new sources, and the proposed 

language does not provide any objective 

basis for determining what might have 

to be included or how to comply; (2) 

making fugitive emission control plan 

requirements subject to negotiation and 

air regulatory agency approval adds 

potentially significant delays in getting 

new sources approved and into 

operation; (3) fugitive emission control 

plans to minimize emissions from coal 

piles and roadways are commonly 

embodied in State implementation 

plans and existing air permits for iron 

and steel plants and coke plants; and (4) 

subpart Y should not duplicate and 

should not conflict with existing 

fugitive emission control requirements 

that have been in place for many years 

in the title V operating permits. 

Many commenters stated that EPA has 

failed to properly develop revisions to 

subpart Y in accordance with 

established procedures for developing 

NSPS that specifically designate each 

type of affected facility subject to 

proposed standards. The commenters 

contend that this failure to designate 

each type of facility appears to be an 

open-ended and indeterminate 

expansion of subpart Y. According to 

commenters, this intent is further 

reflected in preamble language 

indicating that proposed procedures for 

developing a ‘‘fugitive dust plan’’ must 

include procedures for limiting 

emissions from ‘‘all types’’ of coal 

processing and conveying equipment at 

coal preparation plants (74 FR 25312). 

The commenters stated that it is unclear 

what EPA means by ‘‘all types’’ of 

equipment when ‘‘coal processing and 

conveying equipment’’ has a wellsettled meaning within subpart Y. 

Further, the commenters noted that the 

proposed rule amendments do not, but 

should, make clear that an owner/ 

operator can choose from the methods 

stated in the rule or an alternative 

method, if one exists, approved by the 

permitting authority. As currently 

proposed, any alternative methods 

would have to be approved by the 

Administrator, and the commenters 

consider such a requirement to be 

unduly burdensome. Commenters 

contend that the regulation should 

acknowledge that fugitive emissions 

control measures might not be available 

when temperatures are below freezing, 

and that prevailing weather conditions 

may reduce the effectiveness of, or 

eliminate the need for, a particular 

control method on a given day. 

Response: EPA disagrees that fugitive 

coal dust emission control plans should 

not be required by the NSPS. The 

commenter states that such plans are 

‘‘commonly’’ embodied in State 

implementation plans but does not 

suggest that they are contained within 

all such plans. Adding to the NSPS a 

requirement that sources must control 

fugitive coal dust emissions from 

fugitive sources at the facility by 

operating according to a written fugitive 

coal dust emissions control establishes 

a uniform requirement that applies to all 

sources in the subpart Y source 

category. The final rule also provides 

very specific requirements regarding the 

control measures that must be included 

in the fugitive coal dust emissions 

control plans. The fugitive coal dust 

emissions control plan must identify 

and describe the control measures the 

owner/operator will use to minimize 

fugitive coal dust emissions from each 

affected facility addressed in the plan. 

The owner or operator is also required 

to explain how the measures are 

applicable and appropriate for the site 

conditions. The owner/operator may 

petition the Administrator requesting 

approval of a control measure other than 

those specified in the final rule. The 

petition must either demonstrate that 

the alternate control measure will 

provide equivalent overall 

environmental protection or 

demonstrate that it is either 

economically or technically infeasible 

for the affected facility to use the control 

measures specifically identified in the 

final rule. The final rule clarifies that 

the owner/operator must submit a 

fugitive coal dust emissions control plan 

that includes the alternative measures 

along with the petition and operate in 

accordance with that plan while the 

petition is pending. It further clarifies 

that while operating in accordance with 

the plan that includes the alternative 

control measures, the affected facility is 

considered to be in compliance with the 

fugitive coal dust emissions control plan 

requirements while the petition is 

pending. 

EPA has decided to omit, from the 

rule, the proposed requirement that the 

fugitive coal dust emissions control plan 

address ‘‘other site-specific sources of 

fugitive emissions that the 

Administrator or permitting authority 

determines need to be included.’’ EPA 

agrees with the commenters that subpart 

Y should specifically identify each type 

of affected facility that must be 

addressed in fugitive dust emissions 

control plan. As explained earlier in this 

preamble, EPA also has decided not to 

address roadways under subpart Y at 


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this time. Thus, open storage coal piles 

are currently the only affected facilities 

that must be addressed by the plan. As 

pointed out by the commenters, an 

owner/operator must either use one of 

the control measures specifically 

identified in subpart Y or, alternatively, 

seek approval from the Administrator to 

use an alternate control measure. 

Because the NSPS is a Federal standard, 

we believe it is appropriate for the 

Administrator to be the one who makes 

determinations regarding whether an 

alternative control measure achieves 

equivalent overall environmental 

protection. Weather-related issues such 

as those noted by the commenter should 

be addressed in the fugitive coal dust 

emissions control plan prepared by the 

owner/operator. 

Comment: One commenter stated that 

the proposed requirements that the 

permitting authority approve the sitespecific fugitive dust would be 

unnecessary. The better and less 

burdensome approach is to require 

owners or operators to submit their 

fugitive dust controls plans to the 

permitting authority, and those plans 

would automatically take effect unless 

the permitting authority objects to the 

terms of the plan. Another commenter 

stated that the proposed requirements 

do not specify which permitting 

authority will be required to approve 

fugitive dust emissions plans under the 

proposed regulation. It is entirely 

unclear, for instance, whether fugitive 

dust emissions plans will be required to 

be incorporated into a coal preparation 

plant’s title V permit. EPA must clarify 

these requirements for the preparation 

and approval of the fugitive dust 

emissions control plans. At a minimum, 

the commenter stated that EPA must 

require that these fugitive dust emission 

control plans be subject to public notice 

and comment, whether or not they are 

incorporated into a plant’s title V 

permit. 

Response: The requirement to control 

fugitive coal dust emissions by 

operating according to a written fugitive 

dust emissions control plan is a Federal 

requirement and is Federally 

enforceable. The final rule does not 

require approval of the plans by the 

Administrator or delegated authority. In 

addition, the commenter does not 

identify any provision of CAA section 

111 that would require the NSPS itself 

to establish a notice and comment 

process for the plans. However, this rule 

does require the owner/operator to 

submit the fugitive coal dust emissions 

control plan to the Administrator or 

delegated authority to provide an 

opportunity for the Administrator or 

delegated authority to object to the 

fugitive coal dust emissions control 

plan. The final rule requires the owner/ 

operator to submit the fugitive coal dust 

emissions control plan to the 

Administrator or delegated authority 

before startup of the new, reconstructed 

of modified facility. If an objection is 

raised, the owner/operator has 30 days 

from receipt of the objection to respond 

with a revised fugitive coal dust 

emissions control plan. The owner/ 

operator must operate in accordance 

with the revised fugitive coal dust 

emissions control plan. 

The requirement for the owner/ 

operator to prepare and operate 

according to a submitted fugitive coal 

dust emissions control plan that is 

appropriate for site conditions must be 

included in the title V operating permit 

for the source. This and other 

requirements for title V permits are 

addressed in 40 CFR part 70. 

Finally, to the extent the comment 

raises issues beyond the scope of the 

supplemental proposal, EPA has no 

obligation to respond in this 

rulemaking. 

Comment: Three commenters noted 

that EPA’s proposal requires submittal 

of the fugitive emissions control plan to 

the permitting authority 90 days prior to 

the compliance date. Commenters 

assumed this means the date for 

conducting the performance test under 

section 60.8, which is 60 days after 

reaching maximum production but not 

more than 180 days. If EPA finalizes its 

proposed approach and subjects existing 

units to fugitive emissions control 

plans, commenters requested guidance 

on how the 90-day requirement is 

applied with respect to the effective 

date of the final rule and the proposed 

April 2008 applicability date. The 

commenters explained that a modified 

open storage coal pile that is required to 

submit a fugitive dust plan may be 

required to comply with that 

requirement before the rule is effective 

and, therefore, could not meet the 90- 

day requirement. 

Response: The commenter’s statement 

that some open storage coal piles are 

required to comply before the rule is 

effective is not completely accurate. 

With respect to open storage piles, May 

27, 2009, is the date used to determine 

which sources qualify as ‘‘new sources’’ 

as that term is defined in CAA section 

111(a)(2). The rule requirements for 

open storage piles apply to any 

stationary open storage pile sources, the 

construction or modification of which is 

commenced after that date. The 

compliance obligation doesn’t arise 

until the effective date of the revised 

NSPS rule. However, because CAA 

section 111(b)(1)(B) provides that 

standards of performance or revisions 

thereof shall become effective upon 

promulgation, all sources that qualify as 

‘‘new sources’’ must be constructed in 

accordance with the regulations. Further 

because both the requirement that new 

sources include sources constructed or 

modified after the date of the proposed 

regulations and the requirement that the 

standards become effective upon 

promulgation are statutory 

requirements, EPA does not have 

authority to alter these requirements. 

The specific situation raised by the 

commenters is no longer relevant 

because the final rule does not require 

approval of the fugitive coal dust 

emissions control plan. 

F. Testing and Monitoring Requirements 

Comment: Several commenters stated 

that the proposed requirements for 

subsequent PM emissions performance 

tests after the initial compliance test are 

either not needed or are too frequent. 

Commenters suggested that for most 

units, repeat PM performance testing 

should be required no more often than 

every five years. One commenter stated 

that once a source has established, 

based on an initial performance test, 

that a PM control device is properly 

sized and installed to meet the 

applicable PM limit, stack testing is not 

necessary to ensure continued 

compliance. Rather, compliance can be 

determined through visible observations 

using procedures like Method 22 or 

other operating parameters, like BLDS. 

Another commenter noted that if EPA 

ultimately adopts the BLDS 

requirement; it should recognize that 

facilities that use such devices are likely 

to operate in compliance with EPA’s 

standards because deviations would be 

detected before any noncompliance 

occurs. According to the commenter, 

these facilities should, therefore, be 

exempt from ongoing opacity 

monitoring requirements, other than the 

initial and five-year performance tests. 

Response: The emissions testing 

requirements for PM, SO2, NOX, and CO 

accomplish two goals. First, emissions 

measurements are necessary to directly 

determine compliance with the 

applicable emissions limit. Direct 

measurement will also provide data 

necessary to verify the accuracy of the 

annual compliance certifications. The 

data will also augment the data 

supporting the regional and national 

emissions factors and emissions 

inventories. Second, periodic 

performance testing will verify the 

calibration and representativeness of the 

continuous monitoring system (e.g., 

BLDS, scrubber pressure drop) and, as 

necessary, indicate that readjustment is 


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required. EPA does not believe that 

these goals can be met with emissions 

testing for each separate source on a 5- 

year cycle. EPA has, however, provided 

a provision that, for affected facilities 

that emit at 50 percent or less of the 

applicable standard, repeat performance 

testing is required every 24 months (as 

opposed to every 12 months). Also, for 

well-performing (emitting at 90 percent 

or less of the applicable standard) 

similar, separate sources using identical 

control equipment, the final rule allows 

a single repeat performance test as 

adequate demonstration for up to four 

other similar, separate sources. Under 

this provision, a performance test for 

each of these similar affected sources is 

required to be conducted at at least once 

every 5 years (i.e., one similar source 

would be required to conduct repeat 

performance testing every 12 months). 

Comment: Many commenters restated 

concerns raised in comments on the 

April 28, 2008, subpart Y amendment 

proposal about the accuracy and 

limitations of the Method 9 test method 

at levels below 10 percent opacity. As 

long as EPA continues to propose a 

subpart Y opacity limit of less than 10 

percent, commenters contend that EPA 

must present compelling proof that an 

opacity standard below 10 percent can 

be accurately and reliably enforced by 

Method 9 observations. 

Response: We disagree with the 

implication that measurements made 

with Method 9 for opacity levels less 

than 10 percent are inaccurate or not 

suitable for compliance determinations. 

Foremost, the data used to establish the 

applicable opacity limit for the rule 

were collected using Method 9 in a 

manner consistent with the directions in 

the method. It is also worth noting that 

the method provides no restrictions on 

the use of the method for applicable 

limits less than 10 percent opacity. The 

introduction to the method 

acknowledges the potential for 

measurement error in applying Method 

9 and, in particular, the greater potential 

for negative bias than for positive bias 

if ambient contrasts between 

background and the emissions plume 

are less than ideal. In addition, we 

applied substantial allowance for 

measurement imprecision in 

establishing the limits. Thus, we believe 

that the relevant opacity limits 

established in the rule are reasonable 

and that Method 9 measurements may 

be used to determine compliance with 

those limits. 

Comment: Several commenters 

supported EPA’s proposal to allow the 

owner/operator of an affected facility to 

decrease the observation period for a 

Method 9 performance test from 3 hours 

to 60 minutes, but suggested EPA 

consider a 30-minute test. EPA has 

provided no rationale for requiring a 

longer observation period in this NSPS 

than it is requiring under the 40 CFR 

part 60, subpart OOO, NSPS. One 

commenter questioned EPA’s proposed 

provision that would allow the 

performance test observation time 

reduction only if all 6-minute average 

opacity readings are less than or equal 

to 3 percent and all the individual 15- 

second opacity observations are less 

than 20 percent during the initial 60 

minutes. The commenter also noted that 

the accuracy of Method 9 readings 

below 5 percent is very questionable. 

The commenter believes that a 60- 

minute test is still unnecessarily long, 

given the number of emission points 

and the low expected variability. The 

commenter noted that when EPA 

finalized its NSPS for subpart OOO, it 

required only 30 minutes of Method 9 

testing for compliance with the fugitive 

emissions standard in all cases (section 

60.675(b)(3), 74 FR 19313, column 3). 

Response: EPA continues to believe 

that a 60-minute observation period is 

reasonable and has decided that Method 

9 opacity testing for a duration of 60 

minutes should be required for all 

affected sources. However, an owner/ 

operator may decrease the observation 

period for a Method 9 performance test 

from 60 minutes to 30 minutes if, during 

the initial 30 minutes of the 

performance test, all 6-minute averages 

are less than or equal to half the 

applicable opacity limit. This is a 

significant reduction from the standard 

3-hour observation period for Method 9 

performance tests. We disagree with the 

commenters’ apparent assumption that 

subpart Y and subpart OOO are 

comparable and that the observation 

period should be the same in both rules. 

EPA believes that the Method 9 opacity 

testing observation period required by 

subpart Y is appropriate for coal 

preparation and processing operations. 

Comment: Many commenters stated 

concerns about the need for and 

requirements for EPA’s proposal to 

determine the frequency of repeat 

Method 9 performance testing for an 

affected source according to a schedule 

based on the ‘‘maximum 15-second 

opacity reading’’ during the most recent 

Method 9 performance test. According 

to commenters, that proposal would be 

incredibly burdensome and 

unnecessarily stringent for no 

discernible reason, and EPA provided 

insufficient justification for significantly 

increasing the frequency of monitoring. 

Specific reasons cited by commenters 

include: 

■ Although it is certainly possible for 

a Method 9 reader to calculate opacities 

below 5 percent by averaging 

observations recorded at zero with those 

recorded at higher opacities (like 5 and 

10 percent), the accuracy and precision 

of Method 9 readings at levels below 5 

(even below 10 percent) are 

questionable at best. Under EPA’s 

proposal, even a small bias in a single 

observation could make a facility 

ineligible for use of Method 22, or result 

in a requirement to repeat a 

performance test in 7 days, rather than 

30 days. Although basing testing 

frequency and eligibility for alternatives 

on a source’s margin of compliance may 

be a generally sound concept, EPA has 

not provided any basis for applying that 

concept to such small differences in 

opacity readings (e.g., 3 versus 4 or 5 

percent opacity), or to such low opacity 

levels. 

■ EPA’s proposal for determining the 

frequency of Method 9 testing would 

require extensive tracking, scheduling, 

and paperwork. Owners/operators 

would be required to track for each 

emission point (1) the alternative being 

used and the basis for eligibility, (2) the 

results of the required observation, and 

(3) the deadline for the next test. 

■ For each new Method 9 

performance test, the owner or operator 

would need to provide 30 days notice to 

the State or local regulatory authority 

and, for Method 9 tests that cannot be 

conducted on time due to weather 

conditions, provide notice of 

rescheduling and report a deviation 

from applicable testing requirements 

(potentially subjecting the facility to 

enforcement). 

■ One commenter believes there are 

no cost savings by using consultants to 

come out and read Method 9 or Method 

22 results. Because of mining 

regulations, a consultant would need to 

be accompanied by a certified coal 

miner, eliminating any cost reduction. 

■ The administrative burden and 

costs imposed, to implement the 

proposal cannot be justified considering 

the availability of simpler and more 

effective options. As with repeat PM 

performance testing, if the goal is to 

ensure that controls are maintained and 

that sources are identified and take 

action promptly to investigate and 

correct the cause of any visible 

emissions, then the same result could be 

accomplished with a combination of 

equipment inspection and Method 22 

readings. 

■ EPA proposed to provide an 

exemption from the repeat Method 9 

performance testing for thermal dryers 

that continuously monitor scrubber 

parameters, but only if Method 9 


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performance tests are conducted 

concurrently with each PM performance 

test. One commenter supported the 

exemption, but questioned why Method 

9 performance tests should be required. 

Response: The commenters are correct 

that the incentives to monitor less 

frequently provided to very well 

performing facilities will be predicated 

on demonstrations of very near zero 

visible emissions. Such conditions are 

consistent with findings made during 

the rule development that indicated that 

some facilities consistently reported no 

visible emissions. First, as previously 

explained, the final rule includes an 

opacity limit of less than 10 percent for 

coal handling facilities. The final rule 

includes a number of changes from the 

supplemental proposal’s opacity testing 

and monitoring requirements. The final 

rule bases subsequent Method 9 opacity 

testing frequency on 6-minute average 

opacity readings from the most recent 

performance test. As an alternative to 

subsequent Method 9 opacity testing, 

the final rule provides an option that 

includes daily walkthrough 

observations consisting of a single 15- 

second observation (visible emissions or 

no visible emissions) of each affected 

facility and requires that corrective 

actions be conducted when any visible 

emissions are observed. If visible 

emissions are still observed after 

corrective actions have been conducted, 

a Method 9 performance test is required 

within 45 operating days. EPA agrees 

that the monitoring provisions of the 

final rule will increase the 

recordkeeping and reporting burden to 

implement the rule. EPA rules require 

documentation of any measurements 

and the associated process operating 

conditions and regulatory compliance 

requirements; however, we disagree that 

this rule imposes any additional record 

keeping or reporting burden specifically 

in order to provide for the reduced 

monitoring frequency allowances. The 

subject provisions do not change those 

generic requirements. It is also worth 

noting that the PM and opacity limits 

are two distinct and separate applicable 

requirements of this rule. Opacity is an 

independent applicable requirement 

that is not necessarily a surrogate of the 

PM emissions limit or vice versa. 

Further, there is no potential for 

enforcement action for a test delayed by 

weather or other unforeseen conditions 

(see section 60.8(d)). 

Comment: Two commenters noted 

that EPA requested comment on 

whether requiring an annual average 

instantaneous opacity from 10 dumps is 

appropriate as an alternate to use of 

Method 22 for other affected facilities. 

The commenters clarified that the 

control effectiveness is not an annual 

average and the State of Wyoming 

Department of Environmental Quality 

(WDEQ) uses the 10 truck dump 

approach to evaluate whether BACT is 

being continuously maintained at any 

given truck dump. They further 

explained that the 10-truck evaluation 

currently in use in Wyoming is not a 

compliance determination. Rather, if 

WDEQ finds the 10-truck opacity greater 

than 20 percent, corrective action is 

required to return the dump to BACT 

requirements. The commenters do not 

support a rule mandating how a 

permitting authority determines the 

control effectiveness of truck dumps nor 

the trigger levels proposed for other 

coal-handling equipment. The 

commenters supported including truck 

dumps as part of the fugitive emissions 

control plan. Commenters explained 

that approach would allow the 

permitting agency to tailor the alternate 

monitoring to fit their source and type 

of controls employed. Commenters 

stated that one option for alternative 

monitoring would be the control 

effectiveness test using the 20 percent 

opacity limit, as determined by taking 

the maximum instantaneous opacity of 

fugitive emissions observed from each 

truck dump activity, averaged for ten 

trucks or less as determined by the 

permitting authority. According to 

commenters, truck dumps are 

intermittent sources and typically will 

always show compliance using Method 

9. Absent any other EPA methods for 

evaluating intermittent sources, the 

commenters support an opacity limit of 

no greater than 5 percent opacity. 

Four commenters stated that EPA 

misinterpreted the WDEQ method for 

monitoring truck-dump facilities and 

expressed the following concerns with 

applying the WDEQ method for the 

purpose of determining compliance 

with some, as yet unknown, opacity 

standard. 

■ The method is neither a Reference 

Method, nor an Equivalent Method, as 

defined by the Wyoming Air Quality 

Standards and Regulations. 

Furthermore, the existing opacity 

certification training protocol does not 

address the observation technique the 

State of Wyoming is using. The protocol 

defines a process to designate an 

appropriate averaging time for 15- 

second opacity readings taken during 

the part of the operation in which the 

largest amount of emissions are 

expected to occur. 

■ An opacity limit based solely on 

the small amount of time that the truck 

is dumping should not be comparable to 

a opacity limit on a continuous point 

source such as a stack. Opacity read 

only while the truck is dumping, 

inappropriately skews the results to 

read the worse-case scenario and 

doesn’t take into account the time when 

the emissions are non-existent due to 

the non-continuous nature of the source. 

■ Commenters recommended a better 

and more reasonable approach to 

monitoring truck-dump facilities. An 

initial compliance test using the visual 

observation protocol provided in 

Method 9. Compliance with the 15 

percent opacity standard would be 

determined by averaging the 15-second 

opacity readings made during the 

duration of three separate truck dump 

events. Each test would commence 

when the truck bed begins to elevate 

and conclude when the truck bed 

returns to a horizontal position. This 

would provide a reasonable evaluation 

of opacity during the actual dumping 

event, as opposed to the Method 9 

protocol that would allow for 

observations long after the dumping 

event terminates. Thereafter, an owner/ 

operator would conduct quarterly 

Method 9 compliance tests consistent 

with the above three truck-dump 

protocol. Owners/operators would 

supplement their quarterly Method 9 

compliance testing with monthly visual 

observations of the physical appearance 

of the equipment and the requirement to 

repair any deficiencies found. 

One commenter stated that the 

current standard utilized in Wyoming 

(6-minute Method 9 readings) has been 

criticized in the past, but it may be the 

most representative approach for noncontinuous or sporadic emissions 

sources. The commenter explained that, 

typically, the 6-minute Method 9 

readings have been taken quarterly. The 

time between truck dumps are times of 

zero potential emissions from the truck 

dump control system. According to the 

commenter, in some ways the 6-minute 

Method 9 reading is very appropriate 

because it reflects most activities: the 

dumping, the coal passing through the 

hopper, and the periods of time when 

no activity is occurring. The commenter 

believes that it is important to adopt an 

opacity standard that is associated with 

the methodology as required by Method 

9 procedures. The commenter further 

stated that if EPA wants to modify the 

existing requirement on truck dumps for 

Wyoming, an appropriate requirement 

would be to utilize the 6-minute Method 

9 and set the opacity standard at greater 

than 10 percent. The commenter 

believes that the standard would likely 

be appropriate for a variety of truck 

types (i.e. rear and belly dump) and 

control systems (i.e. stilling sheds, 

baghouses, and water spray bars). Two 

commenters stated that until the 


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necessary foundation for possible NSPS 

regulation can be established for coal 

unloading, any revision to subpart Y 

must expressly withdraw the Agency’s 

interpretation of the late-1990s that 

subpart Y applies to coal unloading at 

coal preparation and processing plants. 

Response: EPA continues to believe it 

is appropriate to require coal truck 

dump operations to be subject to the 

same opacity limit as other coalhandling facilities. Data indicate that 

the various control measures currently 

used on truck dump operations are 

capable of meeting the final rule’s 

opacity limit of less than 10 percent. 

However, due to the intermittent 

frequency of coal dumping, EPA has 

determined that it is inappropriate to 

require the same testing and monitoring 

of opacity emissions from coal truck 

dumps as are required for other affected 

coal-handling facilities subject to 

opacity limits. The variability in the 

number of coal trucks during any given 

period is likely to render Method 9 

opacity testing over a 60-minute period 

meaningless. EPA disagrees with 

commenters who believe that opacity 

read only while the truck is dumping, 

inappropriately skews the results to 

read the worse-case scenario because it 

doesn’t take into account the time when 

the emissions are non-existent due to 

the non-continuous nature of this truck 

dump operations. In fact, EPA believes 

that opacity measurements taken during 

truck dumping is the appropriate time 

to conduct Method 9 opacity testing. We 

agree with other commenters who 

believe that this approach would 

provide a reasonable evaluation of 

opacity during the actual dumping 

event, as opposed to Method 9 protocol 

that would allow for observations long 

after the dumping event terminates. In 

the supplemental proposal, EPA 

requested comment on whether 

requiring an annual average 

instantaneous opacity from 10 truck 

dumps is appropriate as an alternate to 

monitoring required for other affected 

facilities. After considering the public 

comments, we have decided to include 

in the final rule an approach to 

monitoring truck dump operations that 

was suggested by a commenter. Owners/ 

operators of all affected facilities would 

be required to conduct an initial 

compliance test using Method 9. 

Compliance with the less than 10 

percent opacity standard will be 

determined by averaging the 15-second 

opacity readings made during the 

duration of three separate truck dump 

events. A truck dump event begins 

when the truck bed begins to elevate 

and concludes when the truck bed 

returns to a horizontal position. The 

final rule also requires monthly visual 

observations of the equipment and 

expeditious maintenance if any 

deficiencies are observed. Finally, 

subsequent Method 9 opacity testing 

using the three-truck dump procedure is 

required every 90 days. 

G. Recordkeeping and Reporting 

Requirements 

Comment: Two commenters stated 

that they did not object to the proposed 

reporting requirement for affected 

owners/operators to be able to enter data 

from their performance evaluations 

conducted at their plants to demonstrate 

compliance with the applicable subpart 

Y standards electronically into an EPA 

database (identified as WebFIRE). 

Numerous other commenters 

specifically objected to the electronic 

reporting requirement. Commenters’ cite 

various reasons for opposing the 

requirement, including (1) the 

unnecessary burden of electronically 

reporting test results; (2) uncertainty 

regarding whether the proposed 

reporting requirement meets the 

requirements of the Cross-Media 

Electronic Reporting Rule (CROMERR), 

which is codified at 40 CFR Part 3; (3) 

the lack of sufficient justification for 

requiring that data be reported 

electronically, rather than merely 

standardizing where results are sent and 

in what form; (4) the lack of any 

mechanism for sources to confirm the 

authenticity of data submitted to the 

Web site for their facility by a stack 

testing company; (5) the inability of ERT 

to accept opacity data or continuous 

monitoring system (CMS) data; and (6) 

the finalizing of a regulatory 

requirement based on an ‘‘expectation’’ 

of WebFIRE and the ERT being 

operational in early 2011 and of the ERT 

being CROMERR compliant before 2011 

(EPA–HQ–OAR–2005–0031–0284, p. 9). 

The commenters stated that EPA should 

proceed with its plans for development 

of WebFIRE/ERT and allow sources the 

option to report electronically with 

those tools when they become available. 

If WebFIRE does become available in 

the future and EPA still believes that 

mandatory electronic reporting through 

WebFIRE is appropriate, EPA can repropose the requirement. However, in 

the meantime, commenters contend that 

EPA must provide sources the option of 

continuing to submit reports by mail 

after 2011, just as EPA did in 40 CFR 

Part 60, subpart Da (section 

60.49Da(v)(4), 74 FR 5072 and 5083, 

January 28, 2009). Other commenters 

stated that EPA should develop an 

electronic data exchange with the State/ 

local/Tribal agencies to get the 

necessary performance test data. 

Another commenter stated that by 

collecting data under CAA section 111, 

rather than CAA section 114, EPA is 

overstepping its authority. 

Response: The commenters are correct 

that the Agency does not intend to store 

visible emissions or CMS operating data 

used for compliance on WebFIRE. 

Source owners and testers need not 

submit visible emissions or CMS data to 

WebFIRE or any other national database. 

The source owners must address only 

those data reporting and record keeping 

requirements relevant to compliance 

determinations and certifications (e.g., 

operating permitting requirements). In 

this rule, EPA intends that owners/ 

operators submit to WebFIRE pollutant 

emissions data, particularly those data 

from performance tests for PM or other 

pollutants. The purpose of WebFIRE is 

to be the vehicle for making such data 

available for use in establishing the 

most representative emissions factors 

for use in developing effective national 

and regional emissions inventories and 

other purposes. With this provision, the 

Agency is exercising the authority 

provided under CAA section 114(a)(1) 

to have sources collect and submit 

environmental data needed to 

implement the CAA. 

H. Assessment of Impacts 

Comment: One commenter stated that 

the supplemental proposal continues 

the same inadequate approach to 

consideration of the costs and 

environmental, energy, and economic 

impacts of amendments to the subpart Y 

NSPS. The commenter noted that even 

though the supplemental proposal 

greatly expanded the coverage of the 

subpart Y NSPS, both in terms of 

operations covered and in terms of 

pollutants regulated, EPA asserted that 

it will not increase control costs or 

recordkeeping and reporting costs above 

those of the April 2008 proposal. The 

commenter believes that EPA should 

evaluate the costs and emission 

reduction benefits of the proposed 

standards. The commenter explained 

that because of the definitions of 

‘‘modification’’ and ‘‘reconstruction’’ as 

applied to NSPS, a coal preparation 

plant at a cement manufacturing facility 

may be considered ‘‘modified’’ or 

‘‘reconstructed,’’ and therefore subject 

to the amended subpart Y, even when 

the activity that constitutes a 

‘‘modification’’ or ‘‘reconstruction’’ 

results in little or no increase in actual 

emissions. 

Response: EPA has assessed the costs, 

environmental, energy, and economic 

impacts associated with the 

requirements of the final rule. Control 


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costs, testing and monitoring costs, and 

recordkeeping and reporting costs have 

been estimated for each coal preparation 

and processing operation anticipated to 

become subject to requirements of the 

final rule. As previously explained in 

this preamble, in-line coal mills at 

Portland cement manufacturing plants 

are not regulated by subpart Y. Impacts 

for coal-handling operations that would 

be regulated by subpart Y and are 

located at a Portland cement 

manufacturing plant have been 

estimated. 

Comment: Several comments were 

received regarding EPA’s approach to 

analyzing the information collection 

request (ICR) burden of affected owners/ 

operators that would result from the 

implementation of subpart Y 

amendments in the supplemental 

proposal notice. Commenters stated that 

EPA has grossly underestimated the 

annual monitoring, reporting, and 

recordkeeping burden for the effort of 

the increased monitoring and opacity 

performance testing for specified 

affected facilities. The commenters 

noted that the existing ICR estimates do 

not take into account the significant 

additional monitoring requirements 

contained in the proposed amendments. 

Commenters believe that EPA’s 

approach to analyzing the ICR burdens 

associated with the rulemaking is 

inconsistent with the directives of the 

Paperwork Reduction Act, and fails to 

address the actual burdens that will 

result from the amendments proposed 

in the supplemental action. Commenters 

requested that EPA prepare a new ICR 

that accurately projects the burden 

associated with the most recently 

proposed requirements for monitoring, 

recordkeeping and reporting. 

Response: EPA prepared and 

submitted a revised ICR to the Office of 

Management and Budget (OMB). The 

revised ICR addresses all revisions to 

the subpart Y NSPS made in the final 

rule—both those proposed in the April 

28, 2008, proposal and those proposed 

in the May 27, 2009, supplemental 

proposal. 

V. Summary of Cost, Environmental, 

Energy, and Economic Impacts 

In setting standards, the CAA requires 

EPA to consider costs and 

environmental, energy, and economic 

impacts. Those impacts are expressed as 

incremental differences between the 

impacts of coal preparation and 

processing facilities complying with the 

amendments and the current NSPS 

requirements of subpart Y (i.e., 

baseline). Impacts are presented for coal 

preparation and processing plants for 

which construction, modification, or 

reconstruction is expected to commence 

over the 5 years following promulgation 

of the revised NSPS. EPA estimates that 

22 new coal preparation and processing 

plants will comply with subpart Y in 

the next 5 years. These new plants are 

anticipated to consist of coal-handling 

operations (coal processing and 

conveying equipment, coal storage 

systems, and coal transfer and loading 

systems) and will be built at 2 

bituminous mines, 2 subbituminous 

mines, 1 coke production facility, 6 

utility plants, 10 cement manufacturing 

plants, and 1 industrial site. 

Conservative assumptions were used in 

assessing impacts associated with the 22 

new plants. For example, emissions 

from all affected facilities are assumed 

to be collected and vented through a 

fabric filter, whereas, owners/operators 

may opt to use another suitable and less 

costly control measure. Because a new 

thermal dryer has not been installed at 

a bituminous coal mine in the past 

decade, EPA does not anticipate there 

will be any new thermal dryers in the 

next 5 years. Thermal dryers are not, 

therefore, included in the assessment of 

economic impacts resulting from the 

amendments to subpart Y. Nonetheless, 

we have estimated costs and 

environmental and energy impacts for 4 

model thermal dryers that would result 

from the amended NSPS in the unlikely 

event that a new thermal dryer is 

constructed. Two of the model thermal 

dryers are direct contact, pulverized 

bituminous coal-fired dryers (with coal 

sulfur contents of 1.5 percent and 3.0 

percent) at two bituminous mines; one 

is a natural gas-fired recirculating dryer 

at an industrial facility; and one is a 

waste heat-fired indirect dryer at an 

electric utility power plant. See Docket 

ID No. EPA–HQ–OAR–2008–0260 for 

details regarding the impacts analyses. 

A. What Are the Primary Air Impacts? 

EPA estimated PM emissions 

reductions for coal-handling operations 

at each type of model coal preparation 

and processing plant (i.e., at bituminous 

mines, subbituminous mines, coke 

production facilities, utility plants, 

cement manufacturing plants, and 

industrial sites). We then determined 

approximate nationwide PM emissions 

reductions associated with the projected 

22 new coal preparation and processing 

plants by distributing the new plants by 

site type (e.g., 2 plants at bituminous 

mines, 2 plants at subbituminous mines, 

etc.). Nationwide PM emissions 

reduction is estimated to be 

approximately 7,600 tpy. We also 

estimated PM, SO2, NOX, and CO 

emissions reductions for each model 

thermal dryer to demonstrate the 

pollutant reductions that the NSPS 

would achieve if a new thermal dryer 

were built. PM emission reductions are 

estimated to range from approximately 

90 tpy to 14,214 tpy, with the greatest 

PM reduction coming from the model 

indirect dryer which, until 

promulgation of these amendments, has 

not been subject to subpart Y. SO2

emission reductions from the model 

direct contact thermal dryers are 

estimated to range from 526 tpy to 1,054 

tpy, based on coal sulfur contents of 1.5 

percent and 3.0 percent, respectively. 

The estimated NOX emission reductions 

of 108 tpy and CO emissions reductions 

of 19 tpy are the same for both model 

direct contact thermal dryers. Neither 

natural gas-fired recirculating dryers nor 

waste heat-fired indirect dryers are 

subject to the SO2, NOX, or CO emission 

limits. 

B. What Are the Water and Solid Waste 

Impacts? 

EPA estimates that for the 22 coal 

preparation and processing plants 

projected to be built, approximately 

7,600 tpy of additional solid waste will 

be generated as a result of operating 

systems that collect and vent exhaust 

gases through a fabric filter. There will 

be no waste water impacts. While EPA 

believes it is unlikely that any new 

thermal dryers will be constructed in 

the next 5 years, we estimate that 30 

million-gallons per year of waste water 

would be generated by each of the 

model thermal dryers using venturi 

scrubbers. The solid waste that would 

be generated by the model thermal 

dryers using fabric filters is estimated to 

range from 323 tpy to 14,365 tpy. 

C. What Are the Energy Impacts? 

EPA estimates that approximately 

11,800 megawatt-hours per year (MWh/ 

year) of additional electricity will be 

required to support the collection of, 

and venting through a fabric filter, 

exhaust gases from the 22 new coal 

preparation and processing plants that 

are projected to be constructed. While 

EPA believes it is unlikely that any new 

thermal dryers will be constructed in 

the next 5 years, we estimate that 23 

MWh/year to 4,200 MWh/year of 

additional electricity would be required 

by the control technologies associated 

with the four model thermal dryers. 

D. What Are the Secondary Air Impacts? 

Secondary air impacts are direct 

impacts that result from the increase in 

electricity use that we estimate may be 

required to enable facilities to achieve 

the requirements of a rule. We estimate 

that the rule’s requirements could result 

in emissions of 1 tpy of PM, 8 tpy of 


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SO2, 5 tpy of NOX, and 1 tpy of CO from 

the increased electricity useage by the 

22 new coal preparation and processing 

plants that are projected to be 

constructed. While EPA believes it is 

unlikely that any new thermal dryers 

will be constructed in the next 5 years, 

we estimate that the rule’s requirements 

for thermal dryers could result in 

emissions of 4 to 680 pounds per year 

(lb/yr) of PM, 40 to 5,880 lb/yr of SO2, 

20 to 3,780 lb/yr of NOX, and 4 to 840 

lb/yr of CO from the increased 

electricity usage by the four model 

thermal dryers. 

E. What Are the Cost and Economic 

Impacts? 

EPA estimates that the national total 

costs for the 22 new coal preparation 

and processing plants projected to be 

constructed to comply with 

requirements of the final rule would be 

approximately $7.9 million in each of 

the first 5 years of compliance. This 

estimate includes the costs of control 

technology, testing, monitoring, and 

recordkeeping and reporting. EPA 

assessed the economic impacts of the 

amendments to the NSPS for coal 

preparation and processing plants. An 

economic impact analysis focuses on 

changes in market prices and output 

levels. Both the magnitude of control 

costs needed to comply with the final 

rule and the distribution of these costs 

among affected facilities can have a role 

in determining how the market will 

change in response to the rule. The costs 

to comply with the final rule on a 

facility basis are all projected to be less 

than one percent of sales. These small 

costs are not expected to result in a 

significant market impact whether they 

are passed on to the purchaser or 

absorbed. 

While EPA believes it is unlikely that 

any new thermal dryers will be 

constructed, these amendments will 

protect the public health and 

environment by assuring that 

appropriate controls will be installed on 

future new thermal dryers should any 

be built. We estimate that the total costs 

for the model thermal dryers to comply 

with requirements of the final rule 

could range from $133,000 per year to 

$1.54 million per year, with the highest 

total cost representing a direct contact 

model thermal dryer using coal with a 

higher sulfur content (i.e., 3 percent) 

and that would be subject to PM, SO2, 

NOX, and CO emission limits. 

The majority of States that have 

requirements beyond the NSPS already 

require controls and work practice 

standards for coal preparation and 

processing plant operations. In addition, 

any coal preparation and processing 

plant that is subject to NSR would have 

control requirements significantly more 

stringent than those of the 1976 NSPS. 

Thus, a benefit of the amendments to 

subpart Y will be that affected facilities 

located in States that do not require 

controls beyond the existing NSPS will 

be required to comply with emission 

standards based on current BDT for coal 

preparation and processing plants. 

VI. 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 in this rule have been 

submitted for approval to the OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The information 

collection requirements are not 

enforceable until OMB approves them. 

The amendments to the existing 

standards of performance for coal 

preparation and processing plants add 

new monitoring, reporting, and 

recordkeeping requirements. All 

affected facilities constructed, 

reconstructed, or modified on or after 

April 28, 2008, are required to conduct 

initial performance testing. The 

amendments include a reduction in 

Method 9 test duration, and for 

subsequent Method 9 testing, a 

provision allowing simultaneous 

Method 9 testing for up to three 

emission points. Frequency of 

subsequent Method 9 testing is based on 

performance during the most recent test 

(i.e., subsequent testing is required 

within 90 days or 12 months of previous 

test). The amendments also provide an 

alternative to more frequent subsequent 

Method 9 testing that consists of 

monthly visual observations of process 

and control equipment, daily 15-second 

observations of each affected facility 

with a requirement to conduct 

corrective actions if any visible 

emissions are observed, and Method 9 

testing at least once every 5 years. 

Separate testing and monitoring 

requirements are provided for coal truck 

dump operations. Owners/operators of 

open storage coal piles constructed on 

or after May 27, 2009, are required to 

prepare, and operate in accordance 

with, a fugitive dust emissions control 

plan that addresses the types of control 

measures that will be used to minimize 

fugitive coal dust emissions from the 

source’s open storage piles. The 

information generated by the 

requirements described above will be 

used by EPA to ensure that any new 

affected facilities comply with the 

emission limits and other requirements. 

Records and reports are 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 

will decide which units and what 

records or processes should be 

inspected. The amendments do 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 

confidentiality is made will be 

safeguarded according to EPA policies 

in 40 CFR Part 2, subpart B, 

Confidentiality of Business Information. 

The nationwide monitoring, 

reporting, and recordkeeping burden for 

this collection over the first 3 years of 

this ICR is estimated to total 27,578 

labor-hours at a cost of $2,601,624. The 

nationwide 3-year average burden is 

estimated to be 9,193 labor-hours per 

year and $867,208 per year. Based on 14 

respondents, the average burden hours 

per respondent are estimated to be 657 

hours at an estimated cost of $61,943 

per respondent. Over the first 3 years of 

this ICR, the annualized total capital 

and start-up costs are estimated to be 

$674,528 and the total operation and 

maintenance costs are estimated to be 

$1,151,690. 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 currently valid OMB 

control number. EPA displays OMB 

control numbers various ways. For 

example, EPA lists OMB control 

numbers for EPA’s regulations in 40 

CFR Part 9, which we amend 

periodically. Additionally, we may 

display the OMB control number in 

another part of the CFR, or in a valid 

Federal Register notice, or by other 

appropriate means. The OMB control 

number display will become effective 


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the earliest of any of the methods 

authorized in 40 CFR Part 9. 

When this ICR is approved by OMB, 

the Agency will publish a Federal 

Register notice announcing this 

approval and displaying the OMB 

control number for the approved 

information collection requirements 

contained in this final rule. We will also 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

consolidate the display of the OMB 

control number with other approved 

information collection requirements. 

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 these final amendments to 40 CFR 

part 60, subpart Y, 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 final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

This final rule will not impose any 

requirements on small entities. We are 

not aware of any small entities in the 

coal preparation and processing 

regulated industry. The subpart Y 

standards are applicable to facilities that 

process (i.e., break, crush, screen, clean, 

or dry) more than 181 Mg (200 tons) of 

coal per day. 

D. Unfunded Mandates Reform Act 

This final 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, 

testing and monitoring, and 

recordkeeping and reporting costs of the 

final rule at year five is $7.9 million. 

Thus, this final rule is not subject to the 

requirements of sections 202 or 205 of 

UMRA. 

This final 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. We 

are not aware of any coal preparation 

and processing plants owned by small 

governments. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It 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 final amendments will not 

impose substantial direct compliance 

costs on State or local governments and 

will not preempt State law. Thus, EO 

13132 does not apply to this action. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This final 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 and processing facilities 

owned by an Indian Tribe. Thus, 

Executive Order 13175 does not apply 

to this action. 

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 final 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 final 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. EPA 

estimates that the requirements in this 

final action will cause most coal 

preparation and processing operations 

that become subject to subpart Y to 

install new control devices, resulting in 

approximately 12,400 megawatt-hours 

per year of additional electricity being 

used. Given the negligible change in 

energy consumption resulting from this 

action, EPA does not expect significant 

adverse energy effects. Further, we have 

concluded that this final rule is not 

likely to have any adverse energy effects 

because 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

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 final rulemaking involves 

technical standards. EPA has decided 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 has decided 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 

final rulemaking. The use of these VCS 

would be impractical because they do 

not meet the objectives of the standards 

cited in this final rule. See the docket 

of this final rule for the reasons for these 

determinations on the standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 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 


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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 final 

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 final rule 

will assure that all new coal preparation 

and processing plants install 

appropriate controls to limit health 

impacts to nearby populations. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this final rule and 

other required information to the U.S. 

Senate, the U.S. House of 

Representatives, and the Comptroller 

General of the United States prior to 

publication of the rule in the Federal 

Register. A major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This final rule will be effective 

October 8, 2009. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping 

requirements. 

Dated: September 25, 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 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 

§§ 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: 

Sec. 

Subpart Y—Standards of Performance for 

Coal Preparation and Processing Plants 

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 

systems, transfer and loading systems, 

and open storage piles. 

60.255 Performance tests and other 

compliance requirements. 

60.256 Continuous monitoring 

requirements. 

60.257 Test methods and procedures. 

60.258 Reporting and recordkeeping. 

Subpart Y—Standards of Performance 

for Coal Preparation and Processing 

Plants 

§ 60.250 Applicability and designation of 

affected facility. 

(a) The provisions of this subpart 

apply to affected facilities in coal 

preparation and processing plants that 

process more than 181 megagrams (Mg) 

(200 tons) of coal per day. 

(b) The provisions in § 60.251, 

§ 60.252(a), § 60.253(a), § 60.254(a), 

§ 60.255(a), and § 60.256(a) of this 

subpart are applicable to any of the 

following affected facilities that 

commenced construction, 

reconstruction or modification after 

October 27, 1974, and on or before April 

28, 2008: Thermal dryers, pneumatic 

coal-cleaning equipment (air tables), 

coal processing and conveying 

equipment (including breakers and 

crushers), and coal storage systems, 

transfer and loading systems. 

(c) The provisions in § 60.251, 

§ 60.252(b)(1) and (c), § 60.253(b), 

§ 60.254(b), § 60.255(b) through (h), 

§ 60.256(b) and (c), § 60.257, and 

§ 60.258 of this subpart are applicable to 

any of the following affected facilities 

that commenced construction, 

reconstruction or modification after 

April 28, 2008, and on or before May 27, 

2009: Thermal dryers, pneumatic coalcleaning equipment (air tables), coal 

processing and conveying equipment 

(including breakers and crushers), and 

coal storage systems, transfer and 

loading systems. 

(d) The provisions in § 60.251, 

§ 60.252(b)(1) through (3), and (c), 

§ 60.253(b), § 60.254(b) and (c), 

§ 60.255(b) through (h), § 60.256(b) and 

(c), § 60.257, and § 60.258 of this 

subpart are applicable to any of the 

following affected facilities that 

commenced construction, 

reconstruction or modification after May 

27, 2009: Thermal dryers, pneumatic 

coal-cleaning equipment (air tables), 

coal processing and conveying 

equipment (including breakers and 

crushers), coal storage systems, transfer 

and loading systems, and open storage 

piles. 

§ 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. 

(a) 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). 


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(b) 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. 

(c) Bituminous coal means solid fossil 

fuel classified as bituminous coal by 

ASTM D388 (incorporated by 

reference—see § 60.17). 

(d) Coal means: 

(1) For units constructed, 

reconstructed, or modified on or before 

May 27, 2009, all solid fossil fuels 

classified as anthracite, bituminous, 

subbituminous, or lignite by ASTM 

D388 (incorporated by reference—see 

§ 60.17). 

(2) For units constructed, 

reconstructed, or modified after May 27, 

2009, all solid fossil fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by ASTM D388 (incorporated 

by reference—see § 60.17), and coal 

refuse. 

(e) 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. 

(f) 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 conveyor belts. 

Equipment located at the mine face is 

not considered to be part of the coal 

preparation and processing plant. 

(g) Coal refuse means waste products 

of coal mining, physical coal cleaning, 

and coal preparation operations (e.g. 

culm, gob, etc.) containing coal, matrix 

material, clay, and other organic and 

inorganic material. 

(h) Coal storage system means any 

facility used to store coal except for 

open storage piles. 

(i) 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)). 

(j) 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 another subpart 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 another subpart of this 

part, then the furnace and the associated 

emissions are part of the affected 

facility. 

(k) 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). 

(l) Mechanical vent means any vent 

that uses a powered mechanical drive 

(machine) to induce air flow. 

(m) Open storage pile means any 

facility, including storage area, that is 

not enclosed that is used to store coal, 

including the equipment used in the 

loading, unloading, and conveying 

operations of the facility. 

(n) Operating day means a 24-hour 

period between 12 midnight and the 

following midnight during which 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. 

(o) Pneumatic coal-cleaning 

equipment means: 

(1) For units constructed, 

reconstructed, or modified on or before 

May 27, 2009, any facility which 

classifies bituminous coal by size or 

separates bituminous coal from refuse 

by application of air stream(s). 

(2) For units constructed, 

reconstructed, or modified after May 27, 

2009, any facility which classifies coal 

by size or separates coal from refuse by 

application of air stream(s). 

(p) 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. 

(q) 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). 

(r) Thermal dryer means: 

(1) For units constructed, 

reconstructed, or modified on or before 

May 27, 2009, 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. 

(2) For units constructed, 

reconstructed, or modified after May 27, 

2009, any facility in which the moisture 

content of coal is reduced by either 

contact with a heated gas stream which 

is exhausted to the atmosphere or 

through indirect heating of the coal 

through contact with a heated heat 

transfer medium. 

(s) 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) Except as provided in paragraph 

(c) of this section, 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 and 

opacity, as specified in paragraph (b)(1) 

of this section. In addition, and except 

as provided in paragraph (c) of this 

section, 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 May 29, 

2009, subject to the provisions of this 

subpart must also meet the applicable 

standards for sulfur dioxide (SO2), and 

combined nitrogen oxides (NOX) and 

carbon monoxide (CO) as specified in 

paragraphs (b)(2) and (b)(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. 


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(i) For each thermal dryer constructed 

or reconstructed 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 modified 

after April 28, 2008, the owner or 

operator must meet the requirements of 

paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(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) Except as provided in paragraph 

(b)(2)(iii) of this section, 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 (b)(2)(ii) of 

this section. 

(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 contain SO2 in excess of 10 

percent of the potential combustion 

concentration (i.e., the facility must 

achieve at least a 90 percent reduction 

of the potential combustion 

concentration and may not exceed a 

maximum emissions rate of 1.2 lb/ 

MMBtu (520 ng/J)). 

(iii) Thermal dryers that receive all of 

their thermal input from a source other 

than coal or residual oil, that receive all 

of their thermal input from a source 

subject to an SO2 limit under another 

subpart of this part, or that use waste 

heat or residual from the combustion of 

coal or residual oil as their only thermal 

input are not subject to the SO2 limits 

of this section. 

(3) Except as provided in paragraph 

(b)(3)(iii) of this section, the owner or 

operator must meet the requirements for 

combined NOx and CO emissions in 

paragraph (b)(3)(i) or (b)(3)(ii) of this 

section, as applicable to the affected 

facility. 

(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. 

(iii) Thermal dryers that receive all of 

their thermal input from a source other 

than coal or residual oil, that receive all 

of their thermal input from a source 

subject to a NOX limit and/or CO limit 

under another subpart of this part, or 

that use waste heat or residual from the 

combustion of coal or residual oil as 

their only thermal input, are not subject 

to the combined NOX and CO limits of 

this section. 

(c) Thermal dryers receiving all of 

their thermal input from an affected 

facility covered under another 40 CFR 

Part 60 subpart must meet the 

applicable requirements in that subpart 

but are not subject to the requirements 

in this subpart. 

§ 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 or 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 

systems, transfer and loading systems, and 

open storage piles. 

(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 

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) Except as provided in paragraph 

(b)(3) of this section, the owner or 

operator must not cause to be 

discharged into the atmosphere from the 

affected facility any gases which exhibit 

10 percent opacity or greater. 

(2) The owner or operator must not 

cause to be discharged into the 

atmosphere from any mechanical vent 

on an affected facility gases which 

contain particulate matter in excess of 

0.023 g/dscm (0.010 gr/dscf). 

(3) Equipment used in the loading, 

unloading, and conveying operations of 

open storage piles are not subject to the 

opacity limitations of paragraph (b)(1) of 

this section. 

(c) The owner or operator of an open 

storage pile, which includes the 

equipment used in the loading, 

unloading, and conveying operations of 

the affected facility, constructed, 

reconstructed, or modified after May 27, 

2009, must prepare and operate in 


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accordance with a submitted fugitive 

coal dust emissions control plan that is 

appropriate for the site conditions as 

specified in paragraphs (c)(1) through 

(6) of this section. 

(1) The fugitive coal dust emissions 

control plan must identify and describe 

the control measures the owner or 

operator will use to minimize fugitive 

coal dust emissions from each open 

storage pile. 

(2) For open coal storage piles, the 

fugitive coal dust emissions control plan 

must require that one or more of the 

following control measures be used to 

minimize to the greatest extent 

practicable 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 (when the provisions of 

paragraph (c)(6) of this section are met), 

use of a wind barrier, compaction, or 

use of a vegetative cover. The owner or 

operator must select, for inclusion in the 

fugitive coal dust emissions control 

plan, the control measure or measures 

listed in this paragraph that are most 

appropriate for site conditions. The plan 

must also explain how the measure or 

measures selected are applicable and 

appropriate for site conditions. In 

addition, the plan must be revised as 

needed to reflect any changing 

conditions at the source. 

(3) Any owner or operator of an 

affected facility that is required to have 

a fugitive coal dust emissions control 

plan may petition the Administrator to 

approve, for inclusion in the plan for 

the affected facility, alternative control 

measures other than those specified in 

paragraph (c)(2) of this section as 

specified in paragraphs (c)(3)(i) through 

(iv) of this section. 

(i) The petition must include a 

description of the alternative control 

measures, a copy of the fugitive coal 

dust emissions control plan for the 

affected facility that includes the 

alternative control measures, and 

information sufficient for EPA to 

evaluate the demonstrations required by 

paragraph (c)(3)(ii) of this section. 

(ii) The owner or operator must either 

demonstrate that the fugitive coal dust 

emissions control plan that includes the 

alternate control measures will provide 

equivalent overall environmental 

protection or demonstrate that it is 

either economically or technically 

infeasible for the affected facility to use 

the control measures specifically 

identified in paragraph (c)(2). 

(iii) While the petition is pending, the 

owner or operator must comply with the 

fugitive coal dust emissions control plan 

including the alternative control 

measures submitted with the petition. 

Operation in accordance with the plan 

submitted with the petition shall be 

deemed to constitute compliance with 

the requirement to operate in 

accordance with a fugitive coal dust 

emissions control plan that contains one 

of the control measures specifically 

identified in paragraph (c)(2) of this 

section while the petition is pending. 

(iv) If the petition is approved by the 

Administrator, the alternative control 

measures will be approved for inclusion 

in the fugitive coal dust emissions 

control plan for the affected facility. In 

lieu of amending this subpart, a letter 

will be sent to the facility describing the 

specific control measures approved. The 

facility shall make any such letters and 

the applicable fugitive coal dust 

emissions control plan available to the 

public. If the Administrator determines 

it is appropriate, the conditions and 

requirements of the letter can be 

reviewed and changed at any point. 

(4) The owner or operator must 

submit the fugitive coal dust emissions 

control plan to the Administrator or 

delegated authority as specified in 

paragraphs (c)(4)(i) and (c)(4)(ii) of this 

section. 

(i) The plan must be submitted to the 

Administrator or delegated authority 

prior to startup of the new, 

reconstructed, or modified affected 

facility, or 30 days after the effective 

date of this rule, whichever is later. 

(ii) The plan must be revised as 

needed to reflect any changing 

conditions at the source. Such revisions 

must be dated and submitted to the 

Administrator or delegated authority 

before a source can operate pursuant to 

these revisions. The Administrator or 

delegated authority may also object to 

such revisions as specified in paragraph 

(c)(5) of this section. 

(5) The Administrator or delegated 

authority may object to the fugitive coal 

dust emissions control plan as specified 

in paragraphs (c)(5)(i) and (c)(5)(ii) of 

this section. 

(i) The Administrator or delegated 

authority may object to any fugitive coal 

dust emissions control plan that it has 

determined does not meet the 

requirements of paragraphs (c)(1) and 

(c)(2) of this section. 

(ii) If an objection is raised, the owner 

or operator, within 30 days from receipt 

of the objection, must submit a revised 

fugitive coal dust emissions control plan 

to the Administrator or delegated 

authority. The owner or operator must 

operate in accordance with the revised 

fugitive coal dust emissions control 

plan. The Administrator or delegated 

authority retain the right, under 

paragraph (c)(5) of this section, to object 

to the revised control plan if it 

determines the plan does not meet the 

requirements of paragraphs (c)(1) and 

(c)(2) of this section. 

(6) Where appropriate chemical dust 

suppression agents are selected by the 

owner or operator as a control measure 

to minimize fugitive coal dust 

emissions, (1) only chemical dust 

suppressants with Occupational Safety 

and Health Administration (OSHA)- 

compliant material safety data sheets 

(MSDS) are to be allowed; (2) the MSDS 

must be included in the fugitive coal 

dust emissions control plan; and (3) the 

owner or operator must consider and 

document in the fugitive coal dust 

emissions control plan the site-specific 

impacts associated with the use of such 

chemical dust suppressants. 

§ 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. 

Thereafter, a new performance test must 

be conducted according the 

requirements in paragraphs (b)(1)(i) 

through (iii) 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 


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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 to the 

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

through (iii) of this section, as 

applicable, except as provided for in 

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

Performance test and other compliance 

requirements for coal truck dump 

operations are specified in paragraph (h) 

of this section. 

(i) If any 6-minute average opacity 

reading in the most recent performance 

test exceeds half the applicable opacity 

limit, a new performance test must be 

conducted within 90 operating days of 

the date that the previous performance 

test was required to be completed. 

(ii) If all 6-minute average opacity 

readings in the most recent performance 

test are equal to or less than half the 

applicable opacity limit, a new 

performance test must be conducted 

within 12 calendar months of the date 

that the previous performance test was 

required to be completed. 

(iii) An owner or operator of an 

affected facility continuously 

monitoring scrubber parameters as 

specified in § 60.256(b)(2) is exempt 

from the requirements in paragraphs 

(b)(2)(i) and (ii) if opacity performance 

tests are conducted concurrently with 

(or within a 60-minute period of) PM 

performance tests. 

(c) If any affected coal processing and 

conveying equipment (e.g., breakers, 

crushers, screens, conveying systems), 

coal storage systems, or coal transfer 

and loading systems that commenced 

construction, reconstruction, or 

modification after April 28, 2008, are 

enclosed in a building, and emissions 

from the building do not exceed any of 

the standards in § 60.254 that apply to 

the affected facility, then the facility 

shall be deemed to be in compliance 

with such standards. 

(d) An owner or operator of an 

affected facility (other than a thermal 

dryer) that commenced construction, 

reconstruction, or modification after 

April 28, 2008, is subject to a PM 

emission standard and uses a control 

device with a design controlled 

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 conditions specified in paragraphs 

(d)(1) through (3) of this section. This 

exemption does not apply to thermal 

dryers. 

(1) PM emissions, as determined by 

the most recent performance test, are 

less than or equal to the applicable 

limit, 

(2) The control device manufacturer’s 

recommended maintenance procedures 

are followed, and 

(3) All 6-minute average opacity 

readings from the most recent 

performance test are equal to or less 

than half the applicable opacity limit or 

the monitoring requirements in 

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

followed. 

(e) For an owner or operator of a 

group of up to five of the same type of 

affected facilities that commenced 

construction, reconstruction, or 

modification after April 28, 2008, that 

are subject to PM emissions standards 

and use identical control devices, the 

Administrator or delegated 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 conditions specified in 

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

section. 

(1) PM emissions from the most recent 

performance test for each individual 

affected facility are 90 percent or less of 

the applicable PM standard; 

(2) The manufacturer’s recommended 

maintenance procedures are followed 

for each control device; and 

(3) A performance test is conducted 

on each affected facility at least once 

every 5 calendar years. 

(f) As an alternative to meeting the 

requirements in paragraph (b)(2) of this 

section, an owner or operator of an 

affected facility that commenced 

construction, reconstruction, or 

modification after April 28, 2008, may 

elect to comply with the requirements 

in paragraph (f)(1) or (f)(2) of this 

section. 

(1) Monitor visible emissions from 

each affected facility according to the 

requirements in paragraphs (f)(1)(i) 

through (iii) of this section. 

(i) Conduct one daily 15-second 

observation each operating day for each 

affected facility (during normal 

operation) when the coal preparation 

and processing plant is in operation. 

Each observation must be recorded as 

either visible emissions observed or no 

visible emissions observed. Each 

observer determining the presence of 

visible emissions must meet the training 

requirements specified in § 2.3 of 

Method 22 of appendix A–7 of this part. 

If visible emissions are observed during 

any 15-second observation, the owner or 

operator must adjust the operation of 

the affected facility and demonstrate 

within 24 hours that no visible 

emissions are observed from the affected 

facility. If visible emissions are 

observed, a Method 9, of appendix A– 

4 of this part, performance test must be 

conducted within 45 operating days. 

(ii) Conduct monthly visual 

observations of all process and control 

equipment. If any deficiencies are 

observed, the necessary maintenance 

must be performed as expeditiously as 

possible. 

(iii) Conduct a performance test using 

Method 9 of appendix A–4 of this part 

at least once every 5 calendar years for 

each affected facility. 

(2) Prepare a written site-specific 

monitoring plan for a digital opacity 

compliance system for approval by the 

Administrator or delegated authority. 

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 or delegated authority 

shall be implemented by the owner or 

operator. 

(g) As an alternative to meeting the 

requirements in paragraph (b)(2) of this 

section, an owner or operator of an 

affected facility that commenced 

construction, reconstruction, or 

modification after April 28, 2008, 

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 


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according to the requirements in 

paragraphs (g)(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 (g)(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. 

(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. 

(h) The owner or operator of each 

affected coal truck dump operation that 

commenced construction, 

reconstruction, or modification after 

April 28, 2008, must meet the 

requirements specified in paragraphs 

(h)(1) through (3) of this section. 

(1) Conduct an initial performance 

test using Method 9 of appendix A–4 of 

this part according to the requirements 

in paragraphs (h)(1)(i) and(ii). 

(i) Opacity readings shall be taken 

during the duration of three separate 

truck dump events. Each truck dump 

event commences when the truck bed 

begins to elevate and concludes when 

the truck bed returns to a horizontal 

position. 

(ii) Compliance with the applicable 

opacity limit is determined by averaging 

all 15-second opacity readings made 

during the duration of three separate 

truck dump events. 

(2) Conduct monthly visual 

observations of all process and control 

equipment. If any deficiencies are 

observed, the necessary maintenance 

must be performed as expeditiously as 

possible. 

(3) Conduct a performance test using 

Method 9 of appendix A–4 of this part 

at least once every 5 calendar years for 

each affected facility. 

§ 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) through (3) 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 design 

controlled potential PM emissions rates 

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) through (iv) 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 flow rate to the control 

equipment. The monitoring device is to 

be certified by the manufacturer to be 

accurate within ±5 percent of design 

water supply flow rate. 

(iii) A monitoring device for the 

continuous measurement of the pH of 

the wet scrubber liquid. The monitoring 

device is to be certified by the 

manufacturer to be accurate within ±5 

percent of design pH. 

(iv) An average value for each 

monitoring parameter must be 

determined during each performance 

test. Each monitoring parameter must 

then be maintained within 10 percent of 

the value established during the most 

recent performance test on an operating 

day average basis. 

(3) For mechanical vents with control 

equipment other than wet scrubbers, a 

monitoring device for the continuous 

measurement of the reagent injection 

flow rate to the control equipment, as 

applicable. The monitoring device is to 

be certified by the manufacturer to be 

accurate within ±5 percent of design 

injection flow rate. An average reagent 


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injection flow rate value must be 

determined during each performance 

test. The reagent injection flow rate 

must then be maintained within 10 

percent of the value established during 

the most recent performance test on an 

operating day average basis. 

(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 delegated 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 

Administrator or delegated authority for 

approval a site-specific monitoring plan 

for each bag leak detection system. This 

plan must be submitted to the 

Administrator or delegated authority 30 

days prior to startup of 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 

delegated 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. 

(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 

(3) 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, with the 

exceptions specified in paragraphs 

(a)(1)(i) and (ii). 

(i) The duration of the Method 9 of 

appendix A–4 of this part performance 

test shall be 1 hour (ten 6-minute 

averages). 

(ii) If, during the initial 30 minutes of 

the observation of a Method 9 of 

appendix A–4 of this part performance 

test, all of the 6-minute average opacity 

readings are less than or equal to half 

the applicable opacity limit, then the 

observation period may be reduced from 

1 hour to 30 minutes. 

(2) To determine opacity for fugitive 

coal dust emissions sources, the 

additional requirements specified in 

paragraphs (a)(2)(i) through (iii) 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 coal dust 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) 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)(3)(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 


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51984 Federal Register / Vol. 74, No. 194 / Thursday, October 8, 2009 / Rules and Regulations 

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 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 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 visual 

observations, noting those sources with 

visible emissions 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) Monthly certification that the 

fugitive coal dust emissions control plan 

was implemented as described. Any 

variance from the plan, if any, shall be 

noted. A copy of the applicable fugitive 

coal dust emissions control plan and 

any letters from the Administrator 

providing approval of any alternative 

control measures shall be maintained 

with the logbook. Any actions, e.g. 

objections, to the plan and any actions 

relative to the alternative control 

measures, e.g. approvals, shall be noted 

in the logbook as well. 

(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 the scrubber 

pressure loss, water supply flow rate, 

and pH of the wet scrubber liquid. 

(10) During a performance test of 

control equipment other than a wet 

scrubber, and each operating day 

thereafter, the owner or operator shall 

record the measurements of the reagent 

injection flow rate, as applicable. 

(b) For the purpose of reports required 

under section 60.7(c), any owner 

operator subject to the provisions of this 

subpart also shall report semiannually 

periods of excess emissions as follow: 

(1) The owner or operator of an 

affected facility with a wet scrubber 

shall submit semiannual reports to the 

Administrator or delegated authority of 

occurrences when the measurements of 

the scrubber pressure loss, water supply 

flow rate, or pH of the wet scrubber 

liquid vary by more than 10 percent 


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Federal Register / Vol. 74, No. 194 / Thursday, October 8, 2009 / Rules and Regulations 51985 

from the average determined during the 

most recent performance test. 

(2) The owner or operator of an 

affected facility with control equipment 

other than a wet scrubber shall submit 

semiannual reports to the Administrator 

or delegated authority of occurrences 

when the measurements of the reagent 

injection flow rate, as applicable, vary 

by more than 10 percent from the 

average determined during the most 

recent performance test. 

(3) 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 or delegated authority, 

consistent with the provisions of section 

60.8. The owner or operator who elects 

to comply with the reduced 

performance testing provisions of 

sections 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. The owner or operator electing 

to comply with section 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. E9–23783 Filed 10–7–09; 8:45 am] 

BILLING CODE 6560–50–P 


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